Network protection and automation guide Alstom

-i i. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this Alstom Grid copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Network Protection & Automation Guide Network Protection & Automation Guide NETWORK PROTECTION & AUTOMATION GUIDE, EDITION MAY 2011 Previously called Protective Relays Application Guide First Edition June 1966 Reprinted January 1967 August 1968 November 1970 September 1971 February 1973 January 1974 Second Edition March 1975 Reprinted November 1977 December 1979 November 1982 October 1983 October 1985 Third Edition June 1987 Reprinted September 1990 March 1995 Network Protection & Automation Guide First Edition July 2002 © MAY 2011 2011 ALSTOM GRID ISBN: 978-0-9568678-0-3 Published by Alstom Grid Alstom Grid Worldwide Contact Centre www.alstom.com/grid/contactcentre Tel: +44(0) 1785 250 070 www.alstom.com/grid/sas All rights reserved. Celebrating 45 years of PRAG/NPAG and 54th APPS course. -ii © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Network Protection & Automation Guide CONTENTS 1 Introduction 2 Fundamentals of Protection Practice 3 Fundamental Theory 4 Fault Calculations 5 Equivalent Circuits and Parameters of Power System Plant 6 Current and Voltage Transformers 7 Relay Technology 8 Protection: Signalling and Intertripping 9 Overcurrent Protection for Phase and Earth Faults 10 Unit Protection of Feeders 11 Distance Protection 12 Distance Protection Schemes 13 Protection of Complex Transmission Circuits 14 Auto-Reclosing 15 Busbar Protection 16 Transformer and Transformer-Feeder Protection 17 Generator and Generator-Transformer Protection 18 Industrial and Commercial Power System Protection 19 A.C. Motor Protection 20 System Integrity Protection Schemes 21 Relay Testing and Commissioning 22 Power System Measurements 23 Power Quality 24 The Digital Substation 25 Substation Control and Automation Appendix A Terminology Appendix B IEEE/IEC Relay Symbols Appendix C Typical Standards Applicable to Protection and Control Numerical Devices Appendix D Company Data and Nomenclature Index © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. -iii © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 1 Introduction . Since 1966, the Network Protection and Automation Guide (formerly the Protective Relays Application Guide) has been the definitive reference textbook for protection engineers and technicians. For 2011, Alstom has capitalised on its pool of experts at the St Leonards Centre of Excellence in Stafford UK to launch a new edition. Michael Bamber New chapters treat topics such as system integrity protection and remedial action schemes, phasor measurements and wide area schemes. The digital substation, including IEC 61850, Ethernet station bus, GOOSE, process bus, and precision time synchronising is also detailed. Advancements in protection and control application engineering have assisted the authors in exploring and integrating the new techniques and philosophies in this edition, whilst retaining vendorindependence – as we continue to deliver the genuine, impartial, reference textbook. Graham Elliott This book is a précis of the Application and Protection of Power Systems (APPS) training course, an intensive programme, which Alstom (and its predecessor companies at Stafford) has been running for over 50 years. This course, by the ingenuity and dedication of the trainers, is vibrant and evolving. As APPS progresses, the Network Protection and Automation Guide advances too, whilst never losing sight of the key basic principles and concepts. Beginners and experts alike will each feel satisfied in their search for relaying, measurement, communication and control knowledge. In the list opposite, we name a mix of new authors for this edition, and key historical figures at Stafford who have contributed significantly to the advancement of APPS and NPAG, and hence the quality and integrity of our book. We sincerely hope that this book assists your navigation through a challenging and rewarding career in electrical power engineering. Protection and control has long been termed an art, rather than a precise science - this book offers a mix of both. Michael Bergstrom Andrew Darby Susan Darby Peter Harding Graeme Lloyd Alan Marshall Allen Millard Andrew Myatt Philip Newman Anthony Perks Steve Pickering Stephen Potts Simon Richards Jack Royle Peter Rush Brendan Smith Mark Stockton Paul Wilkinson Alan Wixon John Wright We acknowledge and thank Alstom colleagues in the wider Alstom Grid and Alstom Power organisations for photographs used within this book. Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 1-1 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 2 Fundamentals of Protection Practice 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 2.9 2.10 2.11 2.12 Introduction Protection Equipment Zones of Protection Reliability Selectivity Stability Speed Sensitivity Primary and Back-up Protection Relay Output Devices Tripping Circuits Trip Circuit Supervision 2.1 INTRODUCTION The purpose of an electrical power system is to generate and supply electrical energy to consumers. The system should be designed to deliver this energy both reliably and economically. Frequent or prolonged power outages result in severe disruption to the normal routine of modern society, which is demanding ever-increasing reliability and security of supply. As the requirements of reliability and economy are largely opposed, power system design is inevitably a compromise. A power system comprises many diverse items of equipment. Figure 2.1 illustrates the complexity of a typical power station Figure 2.2 shows a hypothetical power system. Figure 2.1: Modern power station Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 2-1 Network Protection & Automation Guide Hydro power station Key GS: Generator T: Transformer R: Resistor L: Line G1 GS G2 GS R1 R2 T1 T2 380kV A L2 L1A L1B 380kV 380kV C L4 L3 T5 T6 110kV T4 T3 33kV C' Steam power station GS B B' CCGT power station G3 G4 GS R3 R5 R4 G5 G6 GS T7 T11 T10 GS 220kV D L7A R6 G7 GS T8 T9 E 380kV T14 L6 G 380kV Grid L7B T15 T12 L5 Substation F T16 T13 T17 L8 33kV D' Grid F' 110kV 380kV Figure 2.2: Example power system 2-2 R7 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. G' Chapter 2˜Fundamentals of Protection Practice Figure 2.4: Possible consequence of inadequate protection 2.2 PROTECTION EQUIPMENT The definitions that follow are generally used in relation to power system protection: x Protection System: a complete arrangement of protection equipment and other devices required to achieve a specified function based on a protection principle (IEC 60255-20) x Protection Equipment: a collection of protection devices (relays, fuses, etc.). Excluded are devices such as Current Transformers (CTs), Circuit Breakers (CBs) and contactors Figure 2.3: Onset of an overhead line fault Many items of equipment are very expensive, and so the complete power system represents a very large capital investment. To maximise the return on this outlay, the system must be utilised as much as possible within the applicable constraints of security and reliability of supply. More fundamental, however, is that the power system should operate in a safe manner at all times. No matter how well designed, faults will always occur on a power system, and these faults may represent a risk to life and/or property. Figure 2.3 shows the onset of a fault on an overhead line. The destructive power of a fault arc carrying a high current is very large; it can burn through copper conductors or weld together core laminations in a transformer or machine in a very short time – some tens or hundreds of milliseconds. Even away from the fault arc itself, heavy fault currents can cause damage to plant if they continue for more than a few seconds. The provision of adequate protection to detect and disconnect elements of the power system in the event of fault is therefore an integral part of power system design. Only by doing this can the objectives of the power system be met and the investment protected. Figure 2.4 provides an illustration of the consequences of failure to provide adequate protection. This shows the importance of protection systems within the electrical power system and of the responsibility vested in the Protection Engineer. x Protection Scheme: a collection of protection equipment providing a defined function and including all equipment required to make the scheme work (i.e. relays, CTs, CBs, batteries, etc.) In order to fulfil the requirements of protection with the optimum speed for the many different configurations, operating conditions and construction features of power systems, it has been necessary to develop many types of relay that respond to various functions of the power system quantities. For example, simple observation of the fault current magnitude may be sufficient in some cases but measurement of power or impedance may be necessary in others. Relays frequently measure complex functions of the system quantities, which may only be readily expressible by mathematical or graphical means. Relays may be classified according to the technology used: x electromechanical x static x digital x numerical The different types have varying capabilities, according to the limitations of the technology used. They are described in more detail in Chapter 7. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 2-3 Network Protection & Automation Guide In many cases, it is not feasible to protect against all hazards with a relay that responds to a single power system quantity. An arrangement using several quantities may be required. In this case, either several relays, each responding to a single quantity, or, more commonly, a single relay containing several elements, each responding independently to a different quantity may be used. The terminology used in describing protection systems and relays is provided in Appendix A. Different symbols for describing relay functions in diagrams of protection schemes are used, the three most common methods (IEC, IEEE/ANSI and IEC61850) are provided in Appendix B. 2.3 section between the current transformers and the circuit breaker A is not completely protected against faults. A fault at F would cause the busbar protection to operate and open the circuit breaker but the fault may continue to be fed through the feeder. If the feeder protection is of the type that responds only to faults within its own zone (see section 2.5.2), it would not operate, since the fault is outside its zone. This problem is dealt with by intertripping or some form of zone extension, to ensure that the remote end of the feeder is also tripped. These methods are explained extensively in chapters 11 and 12. Busbar protection ZONES OF PROTECTION To limit the extent of the power system that is disconnected when a fault occurs, protection is arranged in zones. The principle is shown in Figure 2.5. Ideally, the zones of protection should overlap, so that no part of the power system is left unprotected. This is shown in Figure 2.6(a), the circuit breaker being included in both zones. Feeder protection (a) CTs on both sides of circuit breaker A GS Busbar protection Zone 1 F Zone 2 Zone 3 Feeder protection (b)CTs on circuit side of circuit breaker Figure 2.6: CT locations The point of connection of the protection with the power system usually defines the zone and corresponds to the location of the current transformers. Unit type protection results in the boundary being a clearly defined closed loop. Figure 2.7 shows a typical arrangement of overlapping zones. Zone 4 Zone 5 Feeder 1 Zone 7 Feeder 2 Feeder 3 Zone 6 Figure 2.5: Division of power systems into protection zones For practical physical and economic reasons, this ideal is not always achieved, accommodation for current transformers being in some cases available only on one side of the circuit breakers, as shown in Figure 2.6(b). In this example, the 2-4 Figure 2.7: Overlapping zones of protection systems Alternatively, the zone may be unrestricted; the start will be defined but the extent (or ‘reach’) will depend on measurement of the system quantities and will therefore be subject to variation, owing to changes in system conditions and measurement errors. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 2˜Fundamentals of Protection Practice 2.4 RELIABILITY The need for a high degree of reliability has already been discussed briefly. Reliability is dependent on the following factors: x incorrect design/settings recognised standards is carried out during design and production and this fulfils many of these requirements, but it will still be necessary to test the complete protection scheme (relays, current transformers and other ancillary items). The tests must realistically simulate fault conditions. x incorrect installation/testing 2.4.5 Deterioration in Service x deterioration in service Subsequent to installation, deterioration of equipment will take place and may eventually interfere with correct functioning. For example: contacts may become rough or burnt due to frequent operation, or tarnished due to atmospheric contamination, coils and other circuits may become opencircuited, electronic components and auxiliary devices may fail, and mechanical parts may seize up. 2.4.1 Design The design of a protection scheme is of paramount importance. This is to ensure that the system will operate under all required conditions, and refrain from operating when so required. This includes being restrained from operating for faults external to the zone being protected, where necessary. Due consideration must be given to the nature, frequency and duration of faults likely to be experienced, all relevant parameters of the power system and the type of protection equipment used. Of course, the design of the protection equipment used in the scheme is just as important. No amount of effort at this stage can make up for the use of badly designed protection equipment. 2.4.2 Settings It is essential to ensure that settings are chosen for protection relays and systems which take into account the parameters of the primary system, including fault and load levels, and dynamic performance requirements, etc. The characteristics of power systems change with time, due to changes in loads, location, type and amount of generation, etc. Therefore, setting values of relays may need to be checked at suitable intervals to ensure that they are still appropriate. Otherwise, unwanted operation or failure to operate when required may occur. 2.4.3 Installation The need for correct installation of protection systems is obvious, but the complexity of the interconnections of many systems and their relationship to the remainder of the system may make checking the installation difficult. Site testing is therefore necessary. Since it will be difficult to reproduce all fault conditions correctly, these tests must be directed towards proving the installation itself. At the installation stage, the tests should prove the correctness of the connections, relay settings, and freedom from damage of the equipment. No attempt should be made to ‘type test’ the equipment or to establish complex aspects of its technical performance. 2.4.4 Testing Testing should cover all aspects of the protection scheme, reproducing operational and environmental conditions as closely as possible. Type testing of protection equipment to The time between operations of protection relays may be years rather than days. During this period, defects may have developed unnoticed until revealed by the failure of the protection to respond to a power system fault. For this reason, relays should be periodically tested in order to check they are functioning correctly. Testing should preferably be carried out without disturbing permanent connections. This can be achieved by the provision of test blocks or switches. The quality of testing personnel is an essential feature when assessing reliability and considering means for improvement. Staff must be technically competent and adequately trained, as well as self-disciplined to proceed in a systematic manner to achieve final acceptance. Important circuits that are especially vulnerable can be provided with continuous electrical supervision; such arrangements are commonly applied to circuit breaker trip circuits and to pilot circuits. Modern digital and numerical relays usually incorporate self-testing/diagnostic facilities to assist in the detection of failures. With these types of relay, it may be possible to arrange for such failures to be automatically reported by communications link to a remote operations centre, so that appropriate action may be taken to ensure continued safe operation of that part of the power system and arrangements made for investigation and correction of the fault. 2.4.6 Protection Performance Protection system performance is frequently assessed statistically. For this purpose each system fault is classed as an incident and only those that are cleared by the tripping of the correct circuit breakers are classed as 'correct'. The percentage of correct clearances can then be determined. This principle of assessment gives an accurate evaluation of the protection of the system as a whole, but it is severe in its judgement of relay performance. Many relays are called into © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 2-5 Network Protection & Automation Guide operation for each system fault, and all must behave correctly for a correct clearance to be recorded. Complete reliability is unlikely ever to be achieved by further improvements in construction. If the level of reliability achieved by a single device is not acceptable, improvement can be achieved through redundancy, e.g. duplication of equipment. Two complete, independent, main protection systems are provided, and arranged so that either by itself can carry out the required function. If the probability of each equipment failing is x/unit, the resultant probability of both equipments failing simultaneously, allowing for redundancy, is x2. Where x is small the resultant risk (x2) may be negligible. Where multiple protection systems are used, the tripping signal can be provided in a number of different ways. The two most common methods are: x all protection systems must operate for a tripping operation to occur (e.g. ‘two-out-of-two’ arrangement) x only one protection system need operate to cause a trip (e.g. ‘one-out-of two’ arrangement) The former method guards against false tripping due to maloperation of a protection system. The latter method guards against failure of one of the protection systems to operate, due to a fault. Occasionally, three main protection systems are provided, configure in a ‘two-out-of three’ tripping arrangement, to provide both reliability of tripping, and security against unwanted tripping. It has long been the practice to apply duplicate protection systems to busbars, both being required to operate to complete a tripping operation. Loss of a busbar may cause widespread loss of supply, which is clearly undesirable. In other cases, important circuits are provided with duplicate main protection systems, either being able to trip independently. On critical circuits, use may also be made of a digital fault simulator to model the relevant section of the power system and check the performance of the relays used. 2.5 SELECTIVITY When a fault occurs, the protection scheme is required to trip only those circuit breakers whose operation is required to isolate the fault. This property of selective tripping is also called 'discrimination' and is achieved by two general methods. 2.5.1 Time Grading Protection systems in successive zones are arranged to operate in times that are graded through the sequence of protection devices so that only those relevant to the faulty zone complete the tripping function. The others make incomplete operations and then reset. The speed of response will often depend on the severity of the fault, and will generally be slower than for a unit 2-6 system. 2.5.2 Unit Systems It is possible to design protection systems that respond only to fault conditions occurring within a clearly defined zone. This type of protection system is known as 'unit protection'. Certain types of unit protection are known by specific names, e.g. restricted earth fault and differential protection. Unit protection can be applied throughout a power system and, since it does not involve time grading, it is relatively fast in operation. The speed of response is substantially independent of fault severity. Unit protection usually involves comparison of quantities at the boundaries of the protected zone as defined by the locations of the current transformers. This comparison may be achieved by direct hard-wired connections or may be achieved via a communications link. However certain protection systems derive their 'restricted' property from the configuration of the power system and may be classed as unit protection, e.g. earth fault protection applied to the high voltage delta winding of a power transformer. Whichever method is used, it must be kept in mind that selectivity is not merely a matter of relay design. It also depends on the correct co-ordination of current transformers and relays with a suitable choice of relay settings, taking into account the possible range of such variables as fault currents, maximum load current, system impedances and other related factors, where appropriate. 2.6 STABILITY The term ‘stability’ is usually associated with unit protection schemes and refers to the ability of the protection system to remain unaffected by conditions external to the protected zone, for example through-load current and faults external to the protected zone. 2.7 SPEED The function of protection systems is to isolate faults on the power system as rapidly as possible. One of the main objectives is to safeguard continuity of supply by removing each disturbance before it leads to widespread loss of synchronism and consequent collapse of the power system. As the loading on a power system increases, the phase shift between voltages at different busbars on the system also increases, and therefore so does the probability that synchronism will be lost when the system is disturbed by a fault. The shorter the time a fault is allowed to remain in the system, the greater can be the loading of the system. Figure 2.8 shows typical relations between system loading and fault clearance times for various types of fault. It will be noted that phase faults have a more marked effect on the stability of the system than a simple earth fault and therefore require faster © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 2˜Fundamentals of Protection Practice clearance. System stability is not, however, the only consideration. Rapid operation of protection ensures minimisation of the equipment damage caused by the fault. The damaging energy liberated during a fault is proportional to the time that the fault is present, thus it is important that the protection operate as quickly as possible. Speed of operation must be weighed against economy, however. Distribution circuits, which do not normally require a fast fault clearance, are usually protected by time-graded systems. On the other hand, generating plant and EHV systems require protection systems of the highest attainable speed and reliability, therefore unit systems are normal practice. Load power Phase-earth Phase-phase Phase-phase-earth Three-phase Time Figure 2.8: Typical power/time relationship for various fault types 2.8 SENSITIVITY Sensitivity is a term frequently used when referring to the minimum operating level (current, voltage, power etc.) of relays or complete protection schemes. Relays or protection schemes are said to be sensitive if their primary operating parameters are low. With older electromechanical relays, sensitivity was considered in terms of the measuring movement and was measured in terms of its volt-ampere consumption to cause operation. With modern digital and numerical relays the achievable sensitivity is seldom limited by the device design but by its application and associated current and voltage transformer parameters. 2.9 PRIMARY AND BACK-UP PROTECTION that detects an un-cleared primary system fault at its own location, which then trips its own circuit breakers; e.g. time graded overcurrent relays. Remote back-up protection is provided by protection that detects an un-cleared primary system fault at a remote location and then issues a trip command to the relevant relay; e.g. the second or third zones of a distance relay. In both cases the main and back-up protection systems detect a fault simultaneously, operation of the back-up protection being delayed to ensure that the primary protection clears the fault if possible. Normally being unit protection, operation of the primary protection will be fast and will result in the minimum amount of the power system being disconnected. Operation of the back-up protection will be, of necessity, slower and will result in a greater proportion of the primary system being lost. The extent and type of back-up protection applied will naturally be related to the failure risks and relative economic importance of the system. For distribution systems where fault clearance times are not critical, time delayed remote back-up protection may be adequate. For EHV systems, where system stability is at risk unless a fault is cleared quickly, multiple primary protection systems, operating in parallel and possibly of different types (e.g. distance and unit protection), will be used to ensure fast and reliable tripping. Back-up overcurrent protection may then optionally be applied to ensure that two separate protection systems are available during maintenance of one of the primary protection systems. Back-up protection systems should, ideally, be completely separate from the primary systems. For example, a circuit protected by a current differential relay may also have timegraded overcurrent and earth fault relays added to provide circuit breaker tripping in the event of failure of the main primary unit protection. Ideally, to maintain complete redundancy, all system components would be duplicated. This ideal is rarely attained in practice. The following compromises are typical: x Separate current transformers or duplicated secondary cores are often provided. This practice is becoming less common at distribution voltage levels if digital or numerical relays are used, because the extremely low input burden of these relay types allows relays to share a single CT The reliability of a power system has been discussed earlier, including the use of more than one primary (or ‘main’) protection system operating in parallel. In the event of failure or non-availability of the primary protection some other means of ensuring that the fault is isolated must be provided. These secondary systems are referred to as ‘back-up protection schemes’. x Voltage transformers are not duplicated because of cost and space considerations. Each protection relay supply is separately protected (fuse or MCB) and continuously supervised to ensure security of the VT output. An alarm is given on failure of the supply and where appropriate, unwanted operation of the protection is prevented Back-up protection may be considered as either being ‘local’ or ‘remote’. Local back-up protection is achieved by protection x Trip power supplies to the two protection types should be separately protected (fuse or MCB). Duplication of © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 2-7 Network Protection & Automation Guide tripping batteries and of circuit breaker trip coils may be provided. Trip circuits should be continuously supervised. x It is desirable that the main and back-up protections (or duplicate main protections) should operate on different principles, so that unusual events that may cause failure of the one will be less likely to affect the other Digital and numerical relays may incorporate suitable back-up protection functions (e.g. a distance relay may also incorporate time-delayed overcurrent protection elements as well). A reduction in the hardware required to provide back-up protection is obtained, but at the risk that a common relay element failure (e.g. the power supply) will result in simultaneous loss of both main and back-up protection. The acceptability of this situation must be evaluated on a case-bycase basis. 2.10 RELAY OUTPUT DEVICES In order to perform their intended function, relays must be fitted with some means of providing the various output signals required. Contacts of various types usually fulfil this function. 2.10.1 Contact Systems Relays may be fitted with a variety of contact systems for providing electrical outputs for tripping and remote indication purposes. The most common types encountered are as follows: x Self-reset: The contacts remain in the operated condition only while the controlling quantity is applied, returning to their original condition when it is removed x Hand or electrical reset: These contacts remain in the operated condition after the controlling quantity has been removed. The majority of protection relay elements have self-reset contact systems, which, if so desired, can be modified to provide hand reset output contacts by the use of auxiliary elements. Hand or electrically reset relays are used when it is necessary to maintain a signal or lockout condition. Contacts are shown on diagrams in the position corresponding to the un-operated or de-energised condition, regardless of the continuous service condition of the equipment. For example, an undervoltage relay, which is continually energised in normal circumstances, would still be shown in the de-energised condition. A 'make' contact is one that is normally open, but closes on energisation. A 'break' contact is one that is normally closed, but opens on energisation. Examples of these conventions and variations are shown in Figure 2.9. 2-8 Figure 2.9: Contact types A 'changeover' contact generally has three terminals; a common, a make output, and a break output. The user connects to the common and other appropriate terminal for the logic sense required. A protection relay is usually required to trip a circuit breaker, the tripping mechanism of which may be a solenoid with a plunger acting directly on the mechanism latch or an electrically operated valve. The power required by the trip coil of the circuit breaker may range from up to 50 W for a small 'distribution' circuit breaker, to 3 kW for a large, EHV circuit breaker. The relay may energise the tripping coil directly, or through the agency of another multi-contact auxiliary relay, depending on the required tripping power. The basic trip circuit is simple, being made up of a hand-trip control switch and the contacts of the protection relays in parallel to energise the trip coil from a battery, through a normally open auxiliary switch operated by the circuit breaker. This auxiliary switch is needed to open the trip circuit when the circuit breaker opens since the protection relay contacts will usually be quite incapable of performing the interrupting duty. The auxiliary switch will be adjusted to close as early as possible in the closing stroke, to make the protection effective in case the breaker is being closed on to a fault. Where multiple output contacts or contacts with appreciable current-carrying capacity are required, interposing contactor type elements will normally be used. Modern numerical devices may offer static contacts as an ordering option. Semiconductor devices such as IGBT transistors may be used instead of, or in parallel with, conventional relay output contacts to boost: x The speed of the 'make' (typically 100Ps time to make is achieved) © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 2˜Fundamentals of Protection Practice x Interrupting duty (allowing the contacts to break trip coil current. In general, static, digital and numerical relays have discrete measuring and tripping circuits, or modules. The functioning of the measuring modules is independent of operation of the tripping modules. Such a relay is equivalent to a sensitive electromechanical relay with a tripping contactor, so that the number or rating of outputs has no more significance than the fact that they have been provided. For larger switchgear installations the tripping power requirement of each circuit breaker is considerable, and further, two or more breakers may have to be tripped by one protection system. There may also be remote signalling requirements, interlocking with other functions (for example auto-reclosing arrangements), and other control functions to be performed. These various operations may then be carried out by multi-contact tripping relays, which are energised by the protection relays and provide the necessary number of adequately rated output contacts. 2.10.2 Operation Indicators Protection systems are invariably provided with indicating devices, called ‘flags’, or ‘targets’, as a guide for operations personnel. Not every relay will have one, as indicators are arranged to operate only if a trip operation is initiated. Indicators, with very few exceptions, are bi-stable devices, and may be either mechanical or electrical. A mechanical indicator consists of a small shutter that is released by the protection relay movement to expose the indicator pattern. Electrical indicators may be simple attracted armature elements, where operation of the armature releases a shutter to expose an indicator as above, or indicator lights (usually light emitting diodes). For the latter, some kind of memory circuit is provided to ensure that the indicator remains lit after the initiating event has passed. The introduction of numerical relays has greatly increased the number of LED indicators (including tri-state LEDs) to enhance the indicative information available to the operator. In addition, LCD text or graphical displays, which mimic the electrical system provide more in-depth information to the operator. 2.11 TRIPPING CIRCUITS There are three main circuits in use for circuit breaker tripping: x series sealing x shunt reinforcing x shunt reinforcement with sealing These are illustrated in Figure 2.10. PR 52a TC 52a TC 52a TC (a) Series sealing PR (b) Shunt reinforcing PR (c) Shunt reinforcing with series sealing Figure 2.10: Typical relay tripping circuits For electromechanical relays, electrically operated indicators, actuated after the main contacts have closed, avoid imposing an additional friction load on the measuring element, which would be a serious handicap for certain types. Care must be taken with directly operated indicators to line up their operation with the closure of the main contacts. The indicator must have operated by the time the contacts make, but must not have done so more than marginally earlier. This is to stop indication occurring when the tripping operation has not been completed. With modern digital and numerical relays, the use of various alternative methods of providing trip circuit functions is largely obsolete. Auxiliary miniature contactors are provided within the relay to provide output contact functions and the operation of these contactors is independent of the measuring system, as mentioned previously. The making current of the relay output contacts and the need to avoid these contacts breaking the trip coil current largely dictates circuit breaker trip coil arrangements. Comments on the various means of providing tripping arrangements are, however, included below as a historical reference applicable to earlier electromechanical relay designs. 2.11.1 Series sealing The coil of the series contactor carries the trip current initiated by the protection relay, and the contactor closes a contact in parallel with the protection relay contact. This closure relieves the protection relay contact of further duty and keeps the tripping circuit securely closed, even if chatter occurs at the main contact. The total tripping time is not affected, and the indicator does not operate until current is actually flowing through the trip coil. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 2-9 Network Protection & Automation Guide The main disadvantage of this method is that such series elements must have their coils matched with the trip circuit with which they are associated. The coil of these contacts must be of low impedance, with about 5% of the trip supply voltage being dropped across them. When used in association with high-speed trip relays, which usually interrupt their own coil current, the auxiliary elements must be fast enough to operate and release the flag before their coil current is cut off. This may pose a problem in design if a variable number of auxiliary elements (for different phases and so on) may be required to operate in parallel to energise a common tripping relay. importance of the circuit, result in a requirement in many cases to monitor the integrity of the circuit. This is known as trip circuit supervision. The simplest arrangement contains a healthy trip lamp or LED, as shown in Figure 2.11(a). The resistance in series with the lamp prevents the breaker being tripped by an internal short circuit caused by failure of the lamp. This provides supervision while the circuit breaker is closed; a simple extension gives pre-closing supervision. Figure 2.11(b) shows how, the addition of a normally closed auxiliary switch and a resistance unit can provide supervision while the breaker is both open and closed. 2.11.2 Shunt reinforcing Here the sensitive contacts are arranged to trip the circuit breaker and simultaneously to energise the auxiliary unit, which then reinforces the contact that is energising the trip coil. Two contacts are required on the protection relay, since it is not permissible to energise the trip coil and the reinforcing contactor in parallel. If this were done, and more than one protection relay were connected to trip the same circuit breaker, all the auxiliary relays would be energised in parallel for each relay operation and the indication would be confused. The duplicate main contacts are frequently provided as a three-point arrangement to reduce the number of contact fingers. 2.11.3 Shunt reinforcement with sealing This is a development of the shunt reinforcing circuit to make it applicable to situations where there is a possibility of contact bounce for any reason. Using the shunt reinforcing system under these circumstances would result in chattering on the auxiliary unit, and the possible burning out of the contacts, not only of the sensitive element but also of the auxiliary unit. The chattering would end only when the circuit breaker had finally tripped. The effect of contact bounce is countered by means of a further contact on the auxiliary unit connected as a retaining contact. This means that provision must be made for releasing the sealing circuit when tripping is complete; this is a disadvantage, because it is sometimes inconvenient to find a suitable contact to use for this purpose. 2.12 TRIP CIRCUIT SUPERVISION The trip circuit includes the protection relay and other components, such as fuses, links, relay contacts, auxiliary switch contacts, etc., and in some cases through a considerable amount of circuit wiring with intermediate terminal boards. These interconnections, coupled with the 2-10 Figure 2.11: Trip circuit supervision circuit In either case, the addition of a normally open push-button contact in series with the lamp will make the supervision indication available only when required. Schemes using a lamp to indicate continuity are suitable for locally controlled installations, but when control is exercised from a distance it is necessary to use a relay system. Figure © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 2Fundamentals of Protection Practice 2.11(c) illustrates such a scheme, which is applicable wherever a remote signal is required. With the circuit healthy either or both of relays A and B are operated and energise relay C. Both A and B must reset to allow C to drop-off. Relays A, B and C are time delayed to prevent spurious alarms during tripping or closing operations. The resistors are mounted separately from the relays and their values are chosen such that if any one component is inadvertently short-circuited, tripping will not take place. The alarm supply should be independent of the tripping supply so that indication will be obtained in case of failure of the tripping supply. The above schemes are commonly known as the H4, H5 and H7 schemes, arising from the diagram references of the utility specification in which they originally appeared. Figure 2.11(d) shows implementation of scheme H5 using the facilities of a modern numerical relay. Remote indication is achieved through use of programmable logic and additional auxiliary outputs available in the protection relay. Figure 2.12: Menu interrogation of numerical relays © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 2-11 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 3 Fundamental Theory 3.1 3.2 3.3 3.4 3.5 3.6 3.7 Introduction Vector Algebra Manipulation of Complex Quantities Circuit Quantities and Conventions Theorems and Network Reduction Impedance Notation References 3.1 INTRODUCTION The Protection Engineer is concerned with limiting the effects of disturbances in a power system. These disturbances, if allowed to persist, may damage plant and interrupt the supply of electric energy. They are described as faults (short and open circuits) or power swings, and result from natural hazards (for instance lightning), plant failure or human error. To facilitate rapid removal of a disturbance from a power system, the system is divided into 'protection zones'. Protection relays monitor the system quantities (current and voltage) appearing in these zones. If a fault occurs inside a zone, the relays operate to isolate the zone from the remainder of the power system. The operating characteristic of a protection relay depends on the energising quantities fed to it such as current or voltage, or various combinations of these two quantities, and on the manner in which the relay is designed to respond to this information. For example, a directional relay characteristic would be obtained by designing the relay to compare the phase angle between voltage and current at the relaying point. An impedance-measuring characteristic, on the other hand, would be obtained by designing the relay to divide voltage by current. Many other more complex relay characteristics may be obtained by supplying various combinations of current and voltage to the relay. Relays may also be designed to respond to other system quantities such as frequency and power. In order to apply protection relays, it is usually necessary to know the limiting values of current and voltage, and their relative phase displacement at the relay location for various types of short circuit and their position in the system. This normally requires some system analysis for faults occurring at various points in the system. The main components that make up a power system are generating sources, transmission and distribution networks, and loads. Many transmission and distribution circuits radiate from key points in the system and these circuits are controlled by circuit breakers. For the purpose of analysis, the power system is treated as a network of circuit elements contained in branches radiating from nodes to form closed loops or meshes. The system variables are current and voltage, and in steady state analysis, they are regarded as time varying quantities at a single and constant frequency. The network parameters are impedance and admittance; these are assumed to be linear, bilateral (independent of current direction) and constant for a constant frequency. Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 3-1 Network Protection & Automation Guide 3.2 A vector represents a quantity in both magnitude and direction. In Figure 3.1 the vector OP has a magnitude Z at an angle x2  y2 Z VECTOR ALGEBRA T with the reference axis OX: T tan 1 y x Z cos T y Z sin T x Equation 3.2 From Equations 3.1 and 3.2: Z cos T  j sin T Z Equation 3.3 and since cosT and sinT may be expressed in exponential form by the identities: Figure 3.1: Vector OP The quantity may be resolved into two components at right angles to each other, in this case x and y. The magnitude or scalar value of vector Z is known as the modulus Z , whilst the angle T is the argument and is written as arg Z . The conventional method of expressing a vector Z write Z ‘T . is to This form completely specifies a vector for graphical representation or conversion into other forms. It is useful to express vectors algebraically. In Figure 3.1, the vector Z is the resultant of adding x in the x-direction and y in the y direction. This may be written as: Z x  jy Equation 3.1 where the operator j indicates that the component y is perpendicular to component x. The axis OC is the 'real' axis, and the vertical axis OY is called the 'imaginary' axis. If a quantity is considered positive in one direction, and its direction is reversed, it becomes a negative quantity. Hence if the value +1 has its direction reversed (shifted by 180°), it becomes -1. The operator j rotates a vector anti-clockwise through 90°. If a vector is made to rotate anti-clockwise through 180°, then the operator j has performed its function twice, and since the vector has reversed its sense, then: j2 1 giving j 1 The representation of a vector quantity algebraically in terms of its rectangular co-ordinates is called a 'complex quantity'. Therefore, x  jy is a complex quantity and is the rectangular sin T e jT  e  jT 2j cos T e jT  e  jT 2j By expanding and simplifying this equation, it follows that: Z Z e jT Equation 3.4 A vector may therefore be represented both trigonometrically and exponentially. 3.3 MANIPULATION OF COMPLEX QUANTITIES In the above section, we have shown that complex quantities may be represented in any of the four co-ordinate systems given below: x Polar Z‘T x Rectangular x+jy x Trigonometric |Z|(cosT+jsinT) x Exponential |Z|e j˥ The modulus |Z| and the argument T are together known as 'polar co-ordinates', and x and y are described as 'cartesian co-ordinates'. Conversion between co-ordinate systems is easily achieved. As the operator j obeys the ordinary laws of algebra, complex quantities in rectangular form can be manipulated algebraically, as can be seen by the following: Z1  Z 2 x1  x 2  j y1  y 2 Equation 3.5 form of the vector Z ‘T where: 3-2 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 3˜Fundamental Theory Z1  Z 2 x1  x 2  j y1  y 2 such variables in differential equations it is useful to express the complex quantity in exponential form. Equation 3.6 Z1 Z 2 Z1 Z2 3.3.2 The 'a' Operator Z1 Z 2 ‘T1  T 2 We have seen that the mathematical operator j rotates a quantity anti-clockwise through 90°. Another useful operator is one which moves a quantity anti-clockwise through 120°, commonly represented by the symbol 'a'. Z1 ‘T1  T 2 Z2 Equation 3.7 Using De Moivre's theorem, the nth root of unity is given by solving the expression. 1 1 cos 2Sm  j sin 2Sm n 1 n where m is any integer. Hence: 1 1 cos n 2Sm 2Sm  j sin n n where m has values 1, 2, 3, ... (n - 1) From the above expression ‘j’ is found to be the 4th root and ‘a’ the 3rd root of unity, as they have four and three distinct values respectively. Below are some useful functions of the 'a' operator. Figure 3.2: Addition of vectors 3.3.1 Complex Variables In the diagrams shown in Figure 3.1 and Figure 3.2, we have shown that complex variables are represented on a simple chart, where the y-axis is perpendicular to the x-axis displaced by 90°. The argument, or angle of incidence with respect to the x-axis is also known as the phase. So a quantity lying along the y-axis is 90° out of phase with a quantity lying along the xaxis. Because we are rotating in an anti-clockwise direction, the quantity y is then leading the quantity x by 90°. If we take a simple sinusoidal waveform of frequency f, where one cycle of the waveform (360°) takes T seconds (1/f) we can see that the phase angle can be represented by the angular velocity multiplied by the time taken to reach that angle. At this point, we should move away from using degrees to measure angles and move over to radians. There are 2˭ radians in one cycle so: x 360° = 2 radians x 180° =  radians x 90° = /2 radians Thus Z cos T  j sin T 1 3   j 2 2 1 3  j 2 2 a2 1 1  j0 e j0 1 a  a2 0 1 a j 2S 3 e j 4S 3 j 3a 2 1 a2  j 3a a  a2 j 3 j e a  a2 3 3.4 CIRCUIT QUANTITIES AND CONVENTIONS x 270° = 3/2 radians Z ‘T a Z cos Zt  j sin Zt where T is the angle moved in time t, of a quantity moving at Z radians per second. Some complex quantities vary with time. When manipulating Circuit analysis may be described as the study of the response of a circuit to an imposed condition, for example a short circuit, where the circuit variables are current and voltage. We know that current flow results from the application of a driving voltage, but there is complete duality between the variables and either may be regarded as the cause of the other. Just as the current flowing through the primary winding of transformer is as a result of the voltage applied across the primary terminals, the voltage appearing at the secondary © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 3-3 Network Protection & Automation Guide terminals of the same transformer is as a result of current flowing through the secondary winding. Likewise, the current flowing through a resistor is caused by a voltage applied to either side of the resistor. But we can just as well say that the voltage developed across the resistor is as a result of the current flowing through it. L V AC R It is possible to represent any circuit with five circuit elements: x Voltage source Figure 3.3: Simple RL circuit x Current source When the voltage is changing, the inductive component L inhibits the subsequent change of current. So in addition to the resistance, the circuit offers reactance to the changing voltage according to the equation: x Resistance x Capacitance x Inductance When a circuit exists, there is an interchange of energy between these elements. A circuit may be described as being made up of 'sources' and 'sinks' for energy. For example, voltage and current sources are energy sources, resistors are energy sinks, whereas capacitors and inductors (in their pure form) are neither sinks nor sources, but are energy stores. They merely borrow energy from the circuit then give it back. The elements of a circuit are connected together to form a network having nodes (terminals or junctions) and branches (series groups of elements) that form closed loops (meshes). In steady state a.c. circuit theory, the ability of a circuit to impede a current flow resulting from a given driving voltage is called the impedance (Z) of the circuit. The impedance parameter has an inverse equivalent (1/Z), known as admittance (Y). The impedance of a circuit is made up its resistance (R) from resistors and its reactance (X) from inductors and capacitors. Likewise the admittance of a circuit comprises the conductance (G) from resistors and susceptance (B) from inductors and capacitors. Impedance L di dt where VL is the instantaneous voltage across the inductor The equation that defines the voltage of the circuit is thus: V iR  L di dt It can be seen that in this circuit, the higher the frequency the higher the impedance. As a series inductance offers impedance to alternating current flow, a series capacitance will offer admittance. Consider the following circuit: C V AC R Figure 3.4: Simple RC circuit If a steady state dc voltage is applied to a circuit, a current will flow, which depends only on the resistance of the circuit according to ohms law V=IR. The circuit’s reactive components will not play a part in the long term. However if a changing voltage source is applied, the subsequent flow in current depends not only on the resistance of the circuit, but also the reactance of the circuit, according to the equation: V VL IZ When the current is changing, the series capacitance C inhibits the voltage build-up on the capacitor. The reactance of the series capacitor is given by: VC 1 idt C³ where VC is the instantaneous voltage across the capacitor In this circuit, the complete voltage equation is as follows: where Z is the circuit impedance consisting of the resistive part R and the reactive part X: Consider the following circuit: V iR  1 idt C³ It can be seen that in this circuit, the lower the frequency the higher the impedance. If the voltage waveform applied to an inductor is 3-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 3˜Fundamental Theory Vm sin Zt Vt where V(t) is the voltage as a function of time, Vm is the maximum voltage, Z is the angular velocity and t is the time, then: Vm sin( Zt ) L di dt and the angle is: ‘Z tan 1 X R The impedance of a resistor in series with a capacitor in series with an inductor is: therefore Vm sin( Zt ) L di dt R2  X 2 Z Z R  jZL  1 jZ C 1 · § R  j ¨ ZL  ¸ ZC ¹ © and I 3.4.1 Circuit Variables V  m cos( Zt ) ZL AC current and voltage are (in the ideal case) sinusoidal functions of time, varying at a single and constant frequency. They can be regarded as rotating vectors. The reactance X is defined as the voltage across the reactive component divided by the current flowing through the reactive component, therefore X V( t ) I( t ) = For example, the instantaneous value, e of a voltage varying sinusoidally with time is: e Vm sin( Zt )  Vm cos( Zt ) ZL Em sin Zt  G Equation 3.8 where: Em = the maximum amplitude of the waveform therefore Z = the angular velocity, measured in radians per second ZL X G = the phase of the vector at time t = 0 Likewise, it can be shown that the reactance of a capacitor is:  X 1 ZC Phase Angle At t=0, the actual value of the voltage is EmsinG . So if Em is regarded as the modulus of a vector, whose argument is G, then EmsinG is the imaginary component of the vector |Em|‘G. Figure 3.5 illustrates this quantity as a vector and as a sinusoidal function of time. It has been explained that in an inductor, the current lags the voltage. When one considers a sinusoidal waveform, the current lags the voltage by 90° (This assumes a pure inductor with zero resistive component). Likewise in a pure capacitor, the current leads the voltage by 90°. As the reactive components introduce a 90° phase shift between the current and the voltage, the waveforms can be represented by the impedance by a complex number, such that: Z R  jX where Z is the overall impedance, R is the resistive (or real) component and X is the reactive (or imaginary) component. The modulus of the impedance is: Figure 3.5: Representation of a sinusoidal function The current resulting from applying a voltage to a circuit depends upon the circuit impedance. If the voltage is a sinusoidal function at a given frequency and the impedance is constant the current will also vary harmonically at the same frequency, so it can be shown on the same vector diagram as the voltage vector, and is given by the equation © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 3-5 Network Protection & Automation Guide i Em sin Zt  G  I Z Equation 3.9 where: Z R2  X 2 X 1 · § ¸ ¨ ZL  ZC ¹ © I tan 1 X R Equation 3.10 From Equations 3.9 and 3.10 it can be seen that the angular displacement I between the current and voltage vectors and the current magnitude |Im| is dependent upon the impedance Z . In complex form the impedance may be written Z R  jX . The 'real component', R, is the circuit potential difference in more exact terms. For this reason, the terms voltage rise and voltage drop are used to define more accurately the nature of the potential difference. Voltage rise is a rise in potential measured in the direction of current flow between two points in a circuit. Voltage drop is the converse. A circuit element with a voltage rise across it acts as a source of energy. A circuit element with a voltage drop across it acts as a sink of energy. Voltage sources are usually active circuit elements, while sinks are usually passive circuit elements. The positive direction of energy flow is from sources to sinks. Kirchhoff's first law states that the sum of the driving voltages must equal the sum of the passive voltages in a closed loop. This is illustrated by the fundamental equation of an electric circuit: e iR  L di 1  idt dt C ³ Equation 3.12 resistance, and the 'imaginary component', X, is the circuit reactance. When the circuit reactance is inductive (that is, ZL ! 1 / ZC ), the current 'lags' the voltage by an angle I, and when it is capacitive (that is, 1 / ZC ! ZL ) it 'leads' the voltage by an angle I. where the terms on the left hand side of the equation are voltage drops across the circuit elements. Expressed in steady state terms Equation 3.12 may be written: Root Mean Square and this is known as the equated-voltage equation [3.1]. Sinusoidally varying quantities are described by their 'effective' or 'root mean square' (r.m.s.) values; these are usually written using the relevant symbol without a suffix. It is the equation most usually adopted in electrical network calculations, since it equates the driving voltages, which are known, to the passive voltages, which are functions of the currents to be calculated. Thus: I ¦ IZ Equation 3.13 In describing circuits and drawing vector diagrams, for formal analysis or calculations, it is necessary to adopt a notation which defines the positive direction of assumed current flow, and establishes the direction in which positive voltage drops and increases act. Two methods are available; one, the double suffix method, is used for symbolic analysis, the other, the single suffix or diagrammatic method, is used for numerical calculations. Im 2 and E ¦E Em 2 Equation 3.11 The 'root mean square' value is that value which has the same heating effect as a direct current quantity of that value in the same circuit, and this definition applies to non-sinusoidal as well as sinusoidal quantities. 3.4.2 Sign Conventions In describing the electrical state of a circuit, it is often necessary to refer to the 'potential difference' existing between two points in the circuit. Since wherever such a potential difference exists, current will flow and energy will either be transferred or absorbed, it is obviously necessary to define a 3-6 In the double suffix method the positive direction of current flow is assumed to be from node ‘a’ to node ‘b’ and the current is designated I ab . With the diagrammatic method, an arrow indicates the direction of current flow. The voltage rises are positive when acting in the direction of current flow. It can be seen from Figure 3.6 that E1 and Ean are positive voltage rises and E2 and Ebn are negative voltage rises. In the diagrammatic method their direction of action is simply indicated by an arrow, whereas in the double suffix method, Ean and Ebn indicate that there is a potential © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 3˜Fundamental Theory rise in directions na and nb. supplied or absorbed it is necessary to take the average power over one whole cycle. If Z3 I Z1 e Z2 E2 Im sin( Zt  G  I ) , then the power equation is: p E1 Em sin( Zt  G ) and i ei P [ 1  cos 2( Zt  G )]  Q sin 2( Zt  G ) Equation 3.15 where: E1  E2 Z1  Z2  Z3 I (a) Diagrammatic Z ab a I ab Z an E I cos I Q E I sin I and b Zbn Ean P Ebn From Equation 3.15 it can be seen that the quantity P varies from 0 to 2P and quantity Q varies from -Q to +Q in one cycle, and that the waveform is of twice the periodic frequency of the current voltage waveform. n Ean  Ebn Z an  Z ab  Zbn I ab (b) Double suffix Figure 3.6: Methods of representing a circuit Voltage drops are also positive when acting in the direction of current flow. From Figure 3.6(a) it can be seen that Z1  Z 2  Z 3 is the total voltage drop in the loop in the direction of current flow, and must equate to the total voltage rise E1  E2 . In Figure 3.6(b) the voltage drop between nodes a and b designated Vab indicates that point b is at a lower potential than a, and is positive when current flows from a to b. Conversely Vba is a negative voltage drop. Symbolically: The average value of the power exchanged in one cycle is a constant, equal to quantity P, and as this quantity is the product of the voltage and the component of current which is 'in phase' with the voltage it is known as the 'real' or 'active' power. The average value of quantity Q is zero when taken over a cycle, suggesting that energy is stored in one half-cycle and returned to the circuit in the remaining half-cycle. Q is the product of voltage and the quadrature component of current, and is known as 'reactive power'. As P and Q are constants specifying the power exchange in a given circuit, and are products of the current and voltage vectors, then if S is the product EI it follows that: S Vab Van  Vbn Vba Vbn  Van (where n is a common reference point) P  jQ Equation 3.16 The quantity S is described as the 'apparent power', and is the term used in establishing the rating of a circuit. S has units of VA. Equation 3.14 3.4.4 Single and Polyphase Systems 3.4.3 Power The product of the potential difference across and the current through a branch of a circuit is a measure of the rate at which energy is exchanged between that branch and the remainder of the circuit. If the potential difference is a positive voltage drop the branch is passive and absorbs energy. Conversely, if the potential difference is a positive voltage rise the branch is active and supplies energy. The rate at which energy is exchanged is known as power, and by convention, the power is positive when energy is being absorbed and negative when being supplied. With a.c. circuits the power alternates, so, to obtain a rate at which energy is A system is single or polyphase depending upon whether the sources feeding it are single or polyphase. A source is single or polyphase according to whether there are one or several driving voltages associated with it. For example, a threephase source is a source containing three alternating driving voltages that are assumed to reach a maximum in phase order, A, B, C. Each phase driving voltage is associated with a phase branch of the system network as shown in Figure 3.7(a). If a polyphase system has balanced voltages, that is, equal in magnitude and reaching a maximum at equally displaced time intervals, and the phase branch impedances are identical, it is © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 3-7 Network Protection & Automation Guide called a 'balanced' system. It will become 'unbalanced' if any of the above conditions are not satisfied. Calculations using a balanced polyphase system are simplified, as it is only necessary to solve for a single phase, the solution for the remaining phases being obtained by symmetry. The power system is normally operated as a three-phase, balanced, system. For this reason the phase voltages are equal in magnitude and can be represented by three vectors spaced 120° or 2S/3 radians apart, as shown in Figure 3.7(b). A A' Ean Phase branches N N' Ecn analysing initial values, it is necessary to study the behaviour of a circuit in the transient state. This can be achieved using operational methods. In some problems, which fortunately are rare, the assumption of linear, bilateral circuit parameters is no longer valid. Such problems are solved using advanced mathematical techniques that are beyond the scope of this book. 3.5.1 Circuit Laws In linear, bilateral circuits, there are three basic network laws. These laws apply, regardless of the state of the circuit, and at any particular instant of time. These laws are the branch, junction and mesh laws, derived from Ohm and Kirchhoff, and are stated below, using steady state a.c. nomenclature. Ebn C B C' B' Branch law I in a given branch of impedance Z is proportional to the potential difference V appearing across the The current branch, that is: (a) Three-phase system V Ea Direction of rotation 120° IZ Junction law The algebraic sum of all currents entering any junction (or node) in a network is zero, that is: 120° ¦I 0 Mesh law Ec Eb 120° aEa a2 Ea (b) Balanced system of vectors Figure 3.7: Three phase systems Since the voltages are symmetrical, they may be expressed in terms of one, that is: ¦ IZ Ea Alternatively, the total change in potential around a closed loop is zero. Eb a 2 Ea 3.5.2 Circuit Theorems Ec aEa From the above network laws, many theorems have been derived for the rationalisation of networks, either to reach a quick, simple, solution to a problem or to represent a complicated circuit by an equivalent. These theorems are divided into two classes: those concerned with the general properties of networks and those concerned with network reduction. j 2S 3 where a is the vector operator e . Further, if the phase branch impedances are identical in a balanced system, it follows that the resulting currents are also balanced. THEOREMS AND NETWORK REDUCTION Most practical power system problems are solved by using steady state analytical methods. These methods make the assumption that circuit parameters are linear, bilateral, and constant for constant frequency circuit variables. When 3-8 ¦E Ea Equation 3.17 3.5 The algebraic sum of all the driving voltages in any closed path (or mesh) in a network is equal to the algebraic sum of all the passive voltages (products of the impedances and the currents) in the component branches, that is: Of the many theorems that exist, the three most important are given. These are: the Superposition Theorem, Thévenin's Theorem and Kennelly's Star/Delta Theorem. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 3˜Fundamental Theory 3.5.2.1 Superposition Theorem (general network theorem) The resultant current that flows in any branch of a network due to the simultaneous action of several driving voltages is equal to the algebraic sum of the component currents due to each driving voltage acting alone with the remainder shortcircuited. 3.5.2.2 Thévenin's Theorem (active network reduction theorem) study the effect of opening a breaker at A or B during normal system operations or of a fault at A or B. Thus the identity of nodes A and B must be retained together with the sources, but the branch ON can be eliminated, simplifying the study. Proceeding, A, B, N, forms a star branch and can therefore be converted to an equivalent delta. 2.55: 0.4: 1.6: Any active network that may be viewed from two terminals can be replaced by single driving voltage acting in series with single impedance. The driving voltage is the open-circuit voltage between the two terminals and the impedance is the impedance of the network viewed from the terminals with all sources short-circuited. 0.75: 0.45: 18.85: Figure 3.9: Typical power system 3.5.2.3 Kennelly's Star/Delta Theorem (passive network reduction theorem) Any three-terminal network can be replaced by a delta or star impedance equivalent without disturbing the external network. The formulae relating the replacement of a delta network by the equivalent star network is as follows: Z10 Z12 Z 31 Z12  Z 23  Z 31 and so on. Z AO  Z NO  Z AN 0.75  18.85  Z AO Z BO Z BO 0.75 u 18.85 0.45 51: Z BO  Z NO  Z BN 0.45  18.85  Z BO Z BO Z AO 0.45 u 18.85 0.75 30.6: Figure 3.8: Star/Delta network reduction The impedance of a delta network corresponding to and replacing any star network is: Z12 Z10  Z 20  Z10 Z 20 Z 30 and so on. Z AO  Z BO  Z AB Z AO Z BO Z NO 1.2: (since ZNO >> ZAOZBO) 2.5: 1.6: 3.5.3 Network Reduction The aim of network reduction is to reduce a system to a simple equivalent while retaining the identity of that part of the system to be studied. For example, consider the system shown in Figure 3.9. The network has two sources E' and E" , a line AOB shunted by an impedance, which may be regarded as the reduction of a further network connected between A and B, and a load connected between O and N. The object of the reduction is to 0.4: 1.2: 51: 30.6: Figure 3.10: Reduction using star/delta transform The network is now reduced as shown in Figure 3.10. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 3-9 Network Protection & Automation Guide By applying Thévenin's theorem to the active loops, these can be replaced by a single driving voltage in series with impedance, as shown in Figure 3.11. 1.6×51 : 52.6 1.6: x decide on the information required, for example the branch currents in the network for a fault at a particular location x reduce all passive sections of the network not directly involved with the section under examination x reduce all active meshes to a simple equivalent, that is, to a simple source in series with a single impedance 51 E' ' 52.6 51: 0.4×30.6 : 31 0.4: 30.6 E' ' 31 30.6: With the widespread availability of computer-based power system simulation software, it is now usual to use such software on a routine basis for network calculations without significant network reduction taking place. However, the network reduction techniques given above are still valid, as there will be occasions where such software is not immediately available and a hand calculation must be carried out. In certain circuits, for example parallel lines on the same towers, there is mutual coupling between branches. Correct circuit reduction must take account of this coupling. Three cases are of interest. These are: x Case a: two branches connected together at their nodes x Case b: two branches connected together at one node only Figure 3.11: Reduction of active meshes: Thévenin's theorem x Case c: two branches that remain unconnected The network shown in Figure 3.9 is now reduced to that shown in Figure 3.12 with the nodes A and B retaining their identity. Further, the load impedance has been completely eliminated. Considering each case in turn: Case a Consider the circuit shown in Figure 3.13(a). The network shown in Figure 3.12 may now be used to study system disturbances, for example power swings with and without faults. Ia Ib 2.5: 0.39: 1.55: 1.2: 2 Z 0.97 E' 0.99 E' ' Z Z aaZ bb  Z ab Z aa  Z bb  2 Z ab 1 Z  Z bb 2 aa Figure 3.12: Reduction of typical power system Most reduction problems follow the same pattern as the example above. The rules to apply in practical network reduction are: x decide on the nature of the disturbance or disturbances to be studied Figure 3.13: Reduction of two branches with mutual coupling The application of a voltage V between the terminals P and Q gives: V I a Z aa  I b Z ab V I a Z ab  I b Z bb where Ia and Ib are the currents in branches a and b, 3-10 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 3˜Fundamental Theory respectively and I = Ia + Ib , the total current entering at terminal P and leaving at terminal Q. Solving for Ia and Ib : Z bb  Z ab V 2 Z aa Z bb  Z ab Ia Za  Zc Zb  Zc Z a  Zb from which Z aa  Z ab V 2 Z aa Z bb  Z ab Ib The assumption is made that an equivalent star network can replace the network shown. From inspection with one terminal isolated in turn and a voltage V impressed across the remaining terminals it can be seen that: Solving these equations gives: and I I a  Ib V Z aa  Z bb  2 Z ab 2 Z aa Z bb  Z ab so that the equivalent impedance of the original circuit is: Z aa Z bb  Z ab Z aa  Z bb  2 Z ab 2 Z Equation 3.18 (Figure 3.13(b)), and, if the branch impedances are equal, the usual case, then: Z Z aa Z bb Z aa  Z bb  2Z ab 1 Z aa  Z ab 2 Equation 3.19 (see Figure 3.13c) Case b Consider the circuit in Figure 3.14(a). Za Z aa  Z ab Zb Z bb  Z ab Zc Z ab  Z ab Equation 3.20 - see Figure 3.14(b). Case c Consider the four-terminal network given in Figure 3.15(a), in which the branches 11' and 22' are electrically separate except for a mutual link. The equations defining the network are: V1 Z11 I1  Z12 I 2 V2 Z 21 I1  Z 22 I 2 I1 Y11V1  Y12V2 I2 Y21V1  Y22V2 where Z12 = Z21 and Y12 = Y21, if the network is assumed to be reciprocal. Further, by solving the above equations it can be shown that: Y11 Z 22 / ' Y22 Z11 / ' Y12 Z12 / ' ' Z11Z 22  Z12 2 Equation 3.21 There are three independent coefficients, namely Z12, Z11, Z22 so the original circuit may be replaced by an equivalent mesh containing four external terminals, each terminal being connected to the other three by branch impedances as shown in Figure 3.15(b). Figure 3.14: Reduction of mutually-coupled branches with a common terminal © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 3-11 Network Protection & Automation Guide 1 1' Z1'2 Z12 Z22 2' Z2'1 Z22' (a) Actual circuit 1 Z 22' 1 Y22 Z12 1 Y12 Z12 Z1' 2' 2' (b) Equivalent circuit Z11 1 1' Z12 Z12 1 Y11 Z1'2' 2 Z11' Z11' 1' Z12 2 Z11' 1 Z11 Z12' C -Z12 Z22 2 (c) Equivalent with commoned nodes Z12 (d) Equivalent circuit Y11V1 I2 Y12V1 If the same conditions are applied to the equivalent mesh, then: I1  V1 Z11' I2  V1 Z12 V1 Z12' These relations follow from the fact that the branch connecting nodes 1 and 1' carries current I1 and the branches connecting nodes 1 and 2' and 1' and 2 carry current I2. This must be true since branches between pairs of commoned nodes can carry no current. By considering each node in turn with the remainder commoned, the following relationships are found: 2 Z11' Z11Z 22  Z12 Z 22 Z 22' Z11Z 22  Z12 Z11 Z12 Z11Z 22  Z12 Z12 2' Figure 3.15: equivalent circuits for four terminal network with mutual coupling I1  Z12' Hence: -Z12 In order to evaluate the branches of the equivalent mesh let all points of entry of the actual circuit be commoned except node 1 of circuit 1, as shown in Figure 3.15(c). Then all impressed voltages except V1 will be zero and:  Z 21' 2 2 Equation 3.22 A similar but equally rigorous equivalent circuit is shown in Figure 3.15(d). This circuit [3.2] follows from the reasoning that since the self-impedance of any circuit is independent of all other circuits it need not appear in any of the mutual branches if it is lumped as a radial branch at the terminals. So putting Z11 and Z22, equal to zero in Equation 3.22, defining the equivalent mesh in Figure 3.15(b), and inserting radial branches having impedances equal to Z11 and Z22 in terminals 1 and 2, results in Figure 3.15(d). 3.6 IMPEDANCE NOTATION It can be seen by inspection of any power system diagram that: x several voltage levels exist in a system x it is common practice to refer to plant MVA in terms of per unit or percentage values x transmission line and cable constants are given in ohms/km Before any system calculations can take place, the system parameters must be referred to ‘base quantities’ and represented as a unified system of impedances in either ohmic, percentage, or per unit values. The base quantities are power and voltage. Normally, they are given in terms of the three-phase power in MVA and the line voltage in kV. The base impedance resulting from the above base quantities is: 2 Zb kV : MVA Equation 3.23 3-12 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 3˜Fundamental Theory and, provided the system is balanced, the base impedance may be calculated using either single-phase or three-phase quantities. The per unit or percentage value of any impedance in the system is the ratio of actual to base impedance values. Hence: Z ( p.u .) Z ( : ) u MVAb 2 kVb Z (%) Z ( p .u .) u 100 Figure 3.16: Selection of base voltages Equation 3.24 where: MVAb=baseMVA kVAb=basekV Transferring per unit quantities from one set of base values to another can be done using the equation: Z p .u .2 MVAb 2 § kVb1 · ¨ ¸ Z p .u .1 u MVAb1 ¨© kVb 2 ¸¹ 2 where: x suffix b1 denotes the value to the original base x suffix b2 denotes the value to new base The choice of impedance notation depends upon the complexity of the system, plant impedance notation and the nature of the system calculations envisaged. If the system is relatively simple and contains mainly transmission line data, given in ohms, then the ohmic method can be adopted with advantage. However, the per unit method of impedance notation is the most common for general system studies since: x impedances are the same referred to either side of a transformer if the ratio of base voltages on the two sides of a transformer is equal to the transformer turns ratio x confusion caused by the introduction of powers of 100 in percentage calculation is avoided x by a suitable choice of bases, the magnitudes of the data and results are kept within a predictable range, and hence errors in data and computations are easier to spot Most power system studies are carried out using software in per unit quantities. Irrespective of the method of calculation, the choice of base voltage, and unifying system impedances to this base, should be approached with caution, as shown in the following example. From Figure 3.16 it can be seen that the base voltages in the three circuits are related by the turns ratios of the intervening transformers. Care is required as the nominal transformation ratios of the transformers quoted may be different from the turns ratios- e.g. a 110/33kV (nominal) transformer may have a turns ratio of 110/34.5kV. Therefore, the rule for hand calculations is: 'to refer impedance in ohms from one circuit to another multiply the given impedance by the square of the turn’s ratio (open circuit voltage ratio) of the intervening transformer'. Where power system simulation software is used, the software normally has calculation routines built in to adjust transformer parameters to take account of differences between the nominal primary and secondary voltages and turns ratios. In this case, the choice of base voltages may be more conveniently made as the nominal voltages of each section of the power system. This approach avoids confusion when per unit or percent values are used in calculations in translating the final results into volts, amps, etc. For example, in Figure 3.17, generators G1 and G2 have a subtransient reactance of 26% on 66.6MVA rating at 11kV, and transformers T1 and T2 a voltage ratio of 11/145kV and an impedance of 12.5% on 75MVA. Choosing 100MVA as base MVA and 132kV as base voltage, find the percentage impedances to new base quantities. x generator reactances to new bases are: 26 u 100 112 u 66.6 132 2 0.27% x transformer reactances to new bases are: 12.5 u 100 1452 u 75 132 2 20.1% NOTE: The base voltages of the generator and circuits are 11kV and 145kV respectively, that is, the turns ratio of the transformer. The corresponding per unit values can be found by dividing by 100, and the ohmic value can be found by using Equation 3.19. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 3-13 Network Protection & Automation Guide Figure 3.17: Section of a power system 3.7 REFERENCES [3.1] Power System Analysis. J. R. Mortlock and M. W. Humphrey Davies. Chapman & Hall. [3.2] Equivalent Circuits I. Frank M. Starr, Proc. A.I.E.E. Vol. 51. 1932, pp. 287-298. 3-14 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 3˜Fundamental Theory © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 3-15 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 4 Fault Calculations 4.1 4.2 4.3 4.4 4.5 4.6 4.7 Introduction Three-phase Fault Calculations Symmetrical Component Analysis of A ThreePhase Network Equations and Network Connections for Various Types of Faults Current and Voltage Distribution in a System due to a Fault Effect of System Earthing on Zero Sequence Quantities References 4.1 INTRODUCTION A power system is normally treated as a balanced symmetrical three-phase network. When a fault occurs, the symmetry is normally upset, resulting in unbalanced currents and voltages appearing in the network. The only exception is the threephase fault, where all three phase equally at the same location. This is described as a symmetrical fault. By using symmetrical component analysis and replacing the normal system sources by a source at the fault location, it is possible to analyse these fault conditions. For the correct application of protection equipment, it is essential to know the fault current distribution throughout the system and the voltages in different parts of the system due to the fault. Further, boundary values of current at any relaying point must be known if the fault is to be cleared with discrimination. The information normally required for each kind of fault at each relaying point is: x maximum fault current x minimum fault current x maximum through fault current To obtain this information, the limits of stable generation and possible operating conditions, including the system earthing method, must be known. Faults currents are always assumed to be through zero fault impedance. 4.2 THREE-PHASE FAULT CALCULATIONS Three-phase faults are unique in that they are balanced, that is, symmetrical in the three phases, and can be calculated from the single-phase impedance diagram and the operating conditions existing prior to the fault. A fault condition is a sudden abnormal alteration to the normal circuit arrangement. The circuit quantities, current and voltage, will alter, and the circuit will pass through a transient state to a steady state. In the transient state, the initial magnitude of the fault current will depend upon the point on the voltage wave at which the fault occurs. The decay of the transient condition, until it merges into steady state, is a function of the parameters of the circuit elements. The transient current may be regarded as a d.c. exponential current superimposed on the symmetrical steady state fault current. In a.c. machines, owing to armature reaction, the machine reactances pass through 'sub transient' and 'transient' stages Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 4-1 Network Protection & Automation Guide before reaching their steady state synchronous values. For this reason, the resultant fault current during the transient period, from fault inception to steady state also depends on the location of the fault in the network relative to that of the rotating plant. In a system containing many voltage sources, or having a complex network arrangement, it is tedious to use the normal system voltage sources to evaluate the fault current in the faulty branch or to calculate the fault current distribution in the system. A more practical method [Reference 4.1] is to replace the system voltages by a single driving voltage at the fault point. This driving voltage is the voltage existing at the fault point before the fault occurs. Consider the circuit given in Figure 4.1 where the driving voltages are E ' and E ' ' , the impedances on either side of currents circulating in the system due to the fault, to give the total current in any branch of the system at the time of fault inception. However, in most problems, the load current is small in comparison to the fault current and is usually ignored. In a practical power system, the system regulation is such that the load voltage at any point in the system is within 10% of the declared open-circuit voltage at that point. For this reason, it is usual to regard the pre-fault voltage at the fault as being the open-circuit voltage, and this assumption is also made in a number of the standards dealing with fault level calculations. The section on Network Reduction in chapter 3, provided an example of how to reduce a three-phase network. We will use this circuit for an example of some practical three-phase fault calculations. With the network reduced as shown in Figure 4.2, the load voltage at A before the fault occurs is: fault point F are Z1 ' and Z1" , and the current through point 2.5 : F before the fault occurs is I . 0.39 : 1.55 : Z1" Z1' 1.2 : 0.97 E' I E' V 0.99 E' ' E" Figure 4.2: Reduction of typical power system network N Figure 4.1: Network with fault at F The voltage V at F before fault inception is: V E'  IZ ' E"  I Z " For V 0.97 E ' 1.55I V § 1.2 u 2.5 ·  0.39 ¸ I 0.99 E" ¨ © 2.5  1.2 ¹ practical working conditions, 0.99 E" 1.2 I E ' !!! 1.55 I and Assuming zero fault impedance, the fault voltage V will be zero after the fault inception, and a large fault current will flow to earth. The change in voltage at the fault point is therefore Replacing the driving voltages E ' and E '' by the load voltage  V . The change in the current flowing into the network from V between A and N modifies the circuit as shown in Figure F is thus: 4.3(a). 'I  V Z1 V E' ' !!! 1.2 I . Hence E ' # E '' # V Z1'  Z 1" Z1' Z 1" and, since no current was flowing into the network from F prior to the fault, the fault current flowing from the network into the fault is: If 'I V Z1'  Z1" Z1' Z1" By applying the principle of superposition, the load currents circulating in the system prior to the fault may be added to the 4-2 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 4 ˜ Fault Calculations 2.5 : 0.39 : 1.55 : A B 1.2 : V N (a) Three-phase fault diagram for a fault at node A Busbar Circuit Breaker A X (b) Typical physical arrangement of node A with a fault shown at X Figure 4.3: Network with fault at node A The node A is the junction of three branches. In practice, the node would be a busbar, and the branches are feeders radiating from the bus via the closed circuit breakers, as shown in Figure 4.3(b). There are two possible locations for a fault at A; the busbar side of the breakers or the line side of one of the breakers. In this example, let us assumed that the fault is at X, and we wish to calculate the current flowing from the bus to X. The network viewed from AN has a driving point impedance: Z1 1.5 u 1.201 1.5  1.201 The current in the fault is: 0.68: Figure 4.4: Impedances viewed from fault The currents from Figure 4.4(a) are as follows: From the right: 1.55 1.55  1.201 1.55 2.751 From the left: 1.201 1.55  1.201 1.201 0.437 p.u . 2.751 0.563 p .u . There is a parallel branch to the right of A. The current in the 2.5 ohm branch is: V V = Z1 0.68 Let this current be 1.0 per unit. It is now necessary to find the fault current distribution in the various branches of the network and in particular the current flowing from A to X on the assumption that a relay at X is to detect the fault condition. The equivalent impedances viewed from either side of the fault are shown in Figure 4.4(a). 1.2 u 0.562 2.5  1.2 0.182 p.u. and the current in 1.2 ohm branch 2.5 u 0.562 2.5  1.2 0.38 p.u. The total current entering from A to X, is 0.437+0.182 = 0.62 p.u. and from B to X is 0.38p.u. The equivalent network as viewed from the relay is as shown in Figure 4.4(b). The impedances on either side are: 0.68 0.68 1.1: and 1.79: 0.62 0.38 The circuit of Figure 4.4(b) has been included because the Protection Engineer is interested in these equivalent parameters when applying certain types of protection relay. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 4-3 Network Protection & Automation Guide 4.3 SYMMETRICAL COMPONENT ANALYSIS OF A THREE-PHASE NETWORK It is necessary to consider the fault currents due to many different types of fault. The most common type of fault is a single-phase to earth fault, which in LV systems, can produce a higher fault current than a three-phase fault. A method of analysis that applies to unbalanced faults is required. By applying the 'Principle of Superposition', any general threephase system of vectors may be replaced by three sets of balanced (symmetrical) vectors; two sets being three-phase but having opposite phase rotation and one set being cophasal. These vector sets are described as the positive, negative and zero sequence sets respectively. The equations between phase and sequence voltages are given below: Ea E1  E2  E0 Eb a E1  aE2  E0 Ec aE1  a 2 E2  E0 2 Equation 4.1 E1 1 Ea  aEb  a 2 Ec 3 E2 1 Ea  a 2 Eb  aEc 3 E0 1 E a  Eb  E c 3 Equation 4.2 where all quantities are referred to the reference phase A. A similar set of equations can be written for phase and sequence currents. Figure 4.5 illustrates the resolution of a system of unbalanced vectors. Eo Eo a 2 E2 E2 Ea Ec E1 aE1 a 2 E1 Eb aE2 Eo Figure 4.5: Resolution of a system of unbalanced vectors When a fault occurs in a power system, the phase impedances are no longer identical (except in the case of three-phase faults) and the resulting currents and voltages are unbalanced, the point of greatest unbalance being at the fault point. We have shown in Chapter 3 that the fault may be studied by short-circuiting all normal driving voltages in the system and replacing the fault connection by a source whose driving voltage is equal to the pre-fault voltage at the fault point. Hence, the system impedances remain symmetrical, viewed from the fault, and the fault point may now be regarded as the point of injection of unbalanced voltages and currents into the system. This is a most important approach in defining the fault conditions since it allows the system to be represented by sequence networks [4.3] using the method of symmetrical components 4.3.1 Positive Sequence Network During normal balanced system conditions, only positive sequence currents and voltages can exist in the system, and therefore the normal system impedance network is a positive sequence network When a fault occurs the current in the fault branch changes from O to I 1 and the positive sequence voltage across the branch changes from V to V 1 ; replacing the fault branch by a source equal to the change in voltage and short-circuiting all normal driving voltages in the system results in a current ' I flowing into the system, and: 4-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 4 ˜ Fault Calculations 'I  V  V1 Z1 under normal conditions, then negative sequence quantities can only exist during an unbalanced fault. Equation 4.3 If no negative sequence quantities are present in the fault branch prior to the fault, then, when a fault occurs, the change where Z1 is the positive sequence impedance of the system viewed from the fault. in voltage is V 2 , and the resulting current I 2 flowing from the network into the fault is: As before the fault no current was flowing from the fault into the system, it follows that I1 , the fault current flowing from the system into the fault must equal  ' I . Therefore: Equation 4.5 V  I 1 Z1 V1  V2 Z2 I2 The impedances in the negative sequence network are generally the same as those in the positive sequence network. Equation 4.4 is the relationship between positive sequence currents and voltages in the fault branch during a fault. In Figure 4.6, which represents a simple system, the voltage drops I '1 Z '1 and I"1 Z "1 are equal to ( V  V1 ) where the currents I1 ' and I1' ' enter the fault from the left and right In machines Z1 z Z 2 , but the difference is generally ignored, particularly in large networks. The negative sequence diagrams, shown in Figure 4.7, are similar to the positive sequence diagrams, with two important differences; no driving voltages exist before the fault and the negative sequence voltage V2 is greatest at the fault point. respectively and impedances Z1 ' and Z1 ' ' are the total system impedances viewed from either side of the fault branch. The voltage V is equal to the open-circuit voltage in X ' Z1c I 2c Z S1 the system, and it has been shown that V # E' # E' ' (see chapter 3). So the positive sequence voltages in the system due to the fault are greatest at the source, as shown in the gradient diagram, Figure 4.6(b). ' Z1c V2 Z1cc F Z1cc I2 Z1c X Z S1 I 2cc F I 1cc I 1c N I1 Z1c E' ~ V1 ~ (a) Negative sequence network E" F N (a) System diagram X I 1c N X V2 I 1c Z1c V 2  I 2c ' Z1c V V1  I 1c ' Z1c F V1 N' N (b) Gradient diagram Figure 4.6: Fault at F: Positive sequence diagrams (b) Gradient diagram Figure 4.7: Fault at F: Negative sequence diagrams 4.3.2 Negative Sequence Network If only positive sequence quantities appear in a power system © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 4-5 Network Protection & Automation Guide 4.3.3 Zero Sequence Network The zero sequence current and voltage relationships during a fault condition are the same as those in the negative sequence network. Hence: V0 I0Z0 Equation 4.6 Single-phase-earth (A-E) Ib 0 Ic 0 Va 0 Equation 4.7 Also, the zero sequence diagram is that of Figure 4.7, substituting I 0 for I 2 , and so on. The currents and voltages in the zero sequence networks are co-phasal, that is, all the same phase. For zero sequence currents to flow in a system there must be a return connection through either a neutral conductor or the general mass of earth. Note must be taken of this fact when determining zero Phase-phase (B-C) Ia 0 Ib Ic Vb Vc sequence equivalent circuits. Further, in general Z1 z Z 0 Equation 4.8 and the value of Z 0 varies according to the type of plant, the Phase-phase-earth (B-C-E) winding arrangement and the method of earthing. 4.4 EQUATIONS AND NETWORK CONNECTIONS FOR VARIOUS TYPES OF FAULTS The most important types of faults are as follows: x single-phase to earth x phase to phase x phase-phase-earth x three-phase (with or without earth) The above faults are described as single shunt faults because they occur at one location and involve a connection between one phase and another or to earth. In addition, the Protection Engineer often studies two other types of fault: x single-phase open circuit x cross-country fault By determining the currents and voltages at the fault point, it is possible to define the fault and connect the sequence networks to represent the fault condition. From the initial equations and the network diagram, the nature of the fault currents and voltages in different branches of the system can be determined. For shunt faults of zero impedance, and neglecting load current, the equations defining the first four of the above faults (using phase-neutral values) can be written down as follows: 4-6 Ia 0 Vb 0 Vc 0 Equation 4.9 Three-phase (A-B-C or A-B-C-E) I a  Ib  Ic Va Vb Vb Vc 0 Equation 4.10 It should be noted from the above that for any type of fault there are three equations that define the fault conditions. When there is fault impedance, this must be taken into account when writing down the equations. For example, with a single-phase earth fault through fault impedance Z f , the equations are re-written: Ib 0 Ic 0 Va IaZ f Equation 4.11 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 4 ˜ Fault Calculations Va F A Ia F2 F1 From network Equation 4.4, Equation 4.5 and Equation 4.16 can be re-written: Fo Vb B Ib Z1 Vc C Z2 N2 Ic V  I 1 Z1 Z0 No V and substituting for I 2 from Equation 4.15: N1 Ib 0 Ic 0 Va 0 I1 Z1  Z 2 V Equation 4.17 (b) Definition of fault (b) Equivalent circuit Figure 4.8: Single-phase-earth fault at F 4.4.1 Single-phase-earth Fault (A-E) The constraints imposed by Equations 4.15 and 4.17 indicate that there is no zero sequence network connection in the equivalent circuit and that the positive and negative sequence networks are connected in parallel. Figure 4.9 shows the defining and equivalent circuits satisfying the above equations Consider a fault defined by Equation 4.7 and by Figure 4.8(a). Converting Equation 4.7 into sequence quantities by using Equation 4.1 and Equation 4.2, then: I1 I2 Va Ia Vb 1 Ia 3 I0 Vc  V2  V0 0 Equation 4.13 Ib  Ic Substituting for V1 , V2 and V0 in Equation 4.13 from Vb Vc Equation 4.4, Equation 4.5 and Equation 4.6: V  I1 Z1 I2 V Zo V Ic Ia but, I 1 Z2 Z1 Ib Equation 4.12 V1 I 2 Z 2 I2Z2  I0Z0 I 0 , therefore: Figure 4.9: Phase-phase fault at F 4.4.3 Phase-phase-earth Fault (B-C-E) Again, from Equation 4.9 and Equations 4.1 and 4.2: I1 Z1  Z 2  Z 3 I1  I2  Io Equation 4.14 Equation 4.18 The constraints imposed by Equation 4.12 and Equation 4.14 and indicate that the equivalent circuit for the fault is obtained by connecting the sequence networks in series, as shown in Equation 4.8(b) and 4.4.2 Phase-phase Fault (B-C) Substituting for V2 and V0 using Equation 4.5 and Equation From Equation 4.8 and using Equation 4.1 and Equation 4.2: 4.6: I1 V2 V0 Equation 4.19 I2Z2 I 2 I0Z0 Thus, using Equation 4.18: Equation 4.15 I0 0 V1 V2 Equation 4.16 V1 I0  Z 2 I1 Z0  Z2 Equation 4.20 and © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 4-7 Network Protection & Automation Guide I2  Z 0 I1 Z0  Z2 I0 Equation 4.24 Equation 4.21 Substituting V2 Now equating V1 and V2 and using Equation 4.4 gives: V  I 1 Z1 0 I2 I 2 Z 2 0 in Equation 4.5 gives: 0 Equation 4.25 or and substituting V1 V I 1 Z1  I 2 Z 2 0 V  I1 Z1 Substituting for I 2 from Equation 4.21: V 0 in Equation 4.4 gives: or ª Z0Z2 º « Z1  » I1 Z0  Z2 ¼ ¬ V I1 Z1 Equation 4.26 or Further, since from Equation 4.24 I 0 I1 V Z0  Z2 Z1 Z 0  Z1 Z 2  Z 0 Z 2 0 , it follows from Equation 4.6 that V0 is zero when Z 0 is finite. The equivalent sequence connections for a three-phase fault are shown in Figure 4.11. Equation 4.22 From the above equations it follows that connecting the three sequence networks in parallel as shown in Equation 4.10(b) may represent a phase-phase-earth fault Va Vb Z1 Z2 Z0 Vc Va Ia Vb Vc Ic Z1 Z2 Ic 0 Vb 0 Vc 0 Assuming that the fault includes earth, then, from Equation 4.1 Equation 4.2 and Equation 4.10, it follows that: V1 V2 0 Va  Vb  Vc 0 4.4.5 Single-phase Open Circuit Fault 4.4.4 Three-phase Fault (A-B-C or A-B-C-E) VA Ia  Ib  Ic Figure 4.11: Three-phase-earth fault at F Figure 4.10: Phase-phase-earth fault V0 V Zo Ib Ia Ia Ib The single-phase open circuit fault is shown diagrammatically in Figure 4.12(a). At the fault point, the boundary conditions are: Ia 0 Vb Vc 0 Equation 4.27 0 Hence, from Equation 4.2, Equation 4.23 and 4-8 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 4 ˜ Fault Calculations V0 Ia V1 V2 1 Va 3 I1  I 2  I 0 b) at point F’’ 0 Equation 4.28 I 'a I 'c V 'b 0 0 Equation 4.31 From Equation 4.8, it can be concluded that the sequence networks are connected in parallel, as shown in Figure 4.12(b). and therefore: I 'b1 I 'b 2 I 'b 0 Equation 4.32 To solve, it is necessary to convert the currents and voltages at point F’ to the sequence currents in the same phase as those at point F. From Equation 4.32, a 2 I ' a1 aI ' a 2 I 'a 0 or I ' a1 a 2 I 'a 2 aI ' a 0 Equation 4.33 and, for the voltages V 'b1 V 'b 2 V 'b 0 0 Converting: Figure 4.12: Open circuit on phase A 4.4.6 Cross-Country Faults A cross-country fault is one where there are two faults affecting the same circuit, but in different locations and possibly involving different phases. Figure 4.13(a) illustrates this. The constraints expressed in terms of sequence quantities are as follows: a 2 V ' a1  aV ' a 2 V ' a 0 0 V ' a1  a 2 V ' a 2  aV ' a 0 0 or Equation 4.34 The fault constraints involve phase shifted sequence quantities. To construct the appropriate sequence networks, it is necessary to introduce phase-shifting transformers to couple the sequence networks. This is shown in Figure 4.13(b). a) at point F Ib  Ic VA 0 0 Equation 4.29 Therefore: I a1 Ia2 I a0 Va1  Va 2  Va 0 0 Equation 4.30 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 4-9 Network Protection & Automation Guide F ~ x with faults assumed to occur at each relaying point in turn, maximum and minimum fault currents are calculated for each type of fault F’ a-e b'-e ~ NOTE: The fault is assumed to be through zero impedance (a) 'A' phase to earth at F and 'B' phase to earth at F' I a1 x by calculating the current distribution in the network for faults applied at different points in the network the maximum through fault currents at each relaying point are established for each type of fault c I a1 F1c F1 c V a1 V a1 N1c N1 I a2 c D 2 I a2 c I a2 1 F2c F2 c D 2V a2 c V a2 Va 2 N 2c N2 I ao D2 c D I ao c I ao 1 Foc Fo c V ao V ao No D c D V ao N oc (b) Equivalent circuit Figure 4.13: Cross-country fault: phase A to phase B 4.5 CURRENT AND VOLTAGE DISTRIBUTION IN A SYSTEM DUE TO A FAULT Practical fault calculations involve the examination of the effect of a fault in branches of network other than the faulted branch, so that protection can be applied correctly to isolate the section of the system directly involved in the fault. It is therefore not enough to calculate the fault current in the fault itself; the fault current distribution must also be established. Further, abnormal voltage stresses may appear in a system because of a fault, and these may affect the operation of the protection. Knowledge of current and voltage distribution in a network due to a fault is essential for the application of protection. The approach to network fault studies for assessing the application of protection equipment may be summarised as follows: x from the network diagram and accompanying data, assess the limits of stable generation and possible operating conditions for the system NOTE: When full information is not available assumptions may have to be made x at this stage more or less definite ideas on the type of protection to be applied are formed. Further calculations for establishing voltage variation at the relaying point, or the stability limit of the system with a fault on it, are now carried out in order to determine the class of protection necessary, such as high or low speed, unit or non-unit, etc. 4.5.1 Current Distribution The phase current in any branch of a network is determined from the sequence current distribution in the equivalent circuit of the fault. The sequence currents are expressed in per unit terms of the sequence current in the fault branch. In power system calculations, the positive sequence and negative sequence impedances are normally equal. Thus, the division of sequence currents in the two networks will also be identical. The impedance values and configuration of the zero sequence network are usually different from those of the positive and negative sequence networks, so the zero sequence current distribution is calculated separately. If C0 and C1 are described as the zero and positive sequence distribution factors then the actual current in a sequence branch is given by multiplying the actual current in the sequence fault branch by the appropriate distribution factor. For this reason, if I 1 , I 2 and I 0 are sequence currents in an arbitrary branch of a network due to a fault at some point in the network, then the phase currents in that branch may be expressed in terms of the distribution constants and the sequence currents in the fault. These are given below for the various common shunt faults, using Equation 4.1 and the appropriate fault equations: a. Single-phase-earth (A-E) I 'a 2C1  C0 I 0 I 'b  C1  C0 I 0 I 'c  C1  C0 I 0 Equation 4.35 4-10 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 4 ˜ Fault Calculations b. Phase-phase (B-C) I 'a 0 I 'b a 2  a C1 I1 I 'c a  a 2 C1 I1 Equation 4.36 c. Phase-phase-earth (B-C-E) I 'a  C1  C0 I 0 I 'b ª º Z0 2  a 2 C1  C 0 » I 0 « a  a C1 Z1 ¬ ¼ I'c ª 2 º Z0  aC1  C 0 » I 0 « a  a C1 Z1 ¬ ¼ Equation 4.37 d. Three-phase (A-B-C or A-B-C-E) I 'a C1 I1 I 'b a 2C1 I1 I 'c aC1 I1 Equation 4.38 As an example of current distribution technique, consider the system in Figure 4.14(a). The equivalent sequence networks are given in Figure 4.14(b) and Figure 4.14(c), together with typical values of impedances. A fault is assumed at A and it is desired to find the currents in branch OB due to the fault. In each network, the distribution factors are given for each branch, with the current in the fault branch taken as 1.0p.u. From the diagram, the zero sequence distribution factor C0 in branch OB is 0.112 and the positive sequence factor C1 is 0.373. For an earth fault at A the phase currents in branch OB from Equation 4.35 are: I 'a 0.746  0.112 I 0 0.858I 0 By using network reduction methods and assuming that all impedances are reactive, it can be shown that Z1 j 0.68: . Z0 Therefore, from Equation 4.14, the current in the fault branch is I a V . 0.68 Assuming that |V| = 63.5V, then: I0 1 Ia 3 63.5 3 u 0.68 31.2 A If V is taken as the reference vector, then: And I 'b Figure 4.14: Typical power system I 'c  0.373  0.112 I 0 0.261I 0 I' a 26.8‘  90q A I' b I' c 81.5‘90q A The vector diagram for the above fault condition is shown in Figure 4.15. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 4-11 Network Protection & Automation Guide V 'c and 61.5‘116.4q  I 2 >Z1  j 0.464@ V'2 From the zero sequence distribution diagram Figure 4.8(b): I 'b I 0 >Z 0  j 0.165 u 2.6  0.112 u 1.6 V '0 I 'c 8.15‘90q @ therefore V 63.5‘0q I 0 >Z 0  j 0.608@ V '0 For earth faults, at the fault I1 V 'a 47.8‘0q V I2 I0 j 31.2 A , when 63.5 volts and is taken as the reference vector. Further, j 0.68: Z1 Z0 V '1 63.5  0.216 u 31.2 V '2 6.74‘180qV V '0 2.25‘180qV Hence: I'a V 'b 26.8‘  90q 61.5‘  116.4q Figure 4.15: Vector diagram: Fault currents and voltages in branch OB due to Phase-to-Earth (P-E) fault at bus A 4.5.2 Voltage Distribution and, using Equation 4.1: The voltage distribution in any branch of a network is determined from the sequence voltage distribution. As shown by Equation 4.5, Equation 4.6 and Equation 4.7 and the gradient diagrams Figure 4.6(b) and Figure 4.7(b), the positive sequence voltage is a minimum at the fault, whereas the zero and negative sequence voltages are a maximum. Thus, the sequence voltages in any part of the system may be given generally as: V'a V '1 V '2 V '0 n · § V  I1 ¨ Z1  ¦ C1n 'Z1n ¸ 1 ¹ © n · §  I 2 ¨ Z1  ¦ C1n 'Z1n ¸ 1 ¹ © n · §  I 0 ¨ Z 0  ¦ C0 n 'Z 0 n ¸ 1 ¹ © Equation 4.39 Using the above equation, the fault voltages at bus B in the previous example can be found. From the positive sequence distribution diagram Figure 4.8(c): V '1 V  I 1 >Z1  j 0.395 u 0.75  0.373 u 0.45 @ V  I1 >Z1  j 0.464@ 4-12 V '1  V ' 2  V ' 0 Therefore V ' a V 'b V 'c 56.76  6.74  2.25 47.8‘0qV a 2 V '1  aV ' 2  V ' 0 Therefore V 'b 56.76a 2  6.74a  2.25 61.5‘  116.4qV aV '1  a 2 V ' 2  V ' 0 Therefore V ' c 56.76‘0qV 56.75a  6.74a 2  2.25 61.5‘116.4qV These voltages are shown on the vector diagram, Figure 4.15. 4.6 EFFECT OF SYSTEM EARTHING ON ZERO SEQUENCE QUANTITIES It has been shown previously that zero sequence currents flow in the earth path during earth faults, and it follows that the nature of these currents will be influenced by the method of earthing. Because these quantities are unique in their association with earth faults they can be utilised in protection, provided their measurement and character are understood for all practical system conditions. 4.6.1 Residual Current and Voltage Residual currents and voltages depend for their existence on © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 4 ˜ Fault Calculations two factors: Ia a. a system connection to earth at two or more points Ib b. a potential difference between the earth points resulting in a current flow in the earth paths Under normal system operation there is a capacitance between the phases and between phase and earth; these capacitances may be regarded as being symmetrical and distributed uniformly through the system. So even when (a) above is satisfied, if the driving voltages are symmetrical the vector sum of the currents will equate to zero and no current will flow between any two earth points in the system. When a fault to earth occurs in a system, an unbalance results in condition (b) being satisfied. From the definitions given above it follows that residual currents and voltages are the vector sum of phase currents and phase voltages respectively. A B Ic C Vae Vbe V ce A V (a) Residual current (b) Residual voltage Figure 4.16: Measurement of residual quantities Hence: IR 4.6.2 System Ratio I a  Ib  Ic The system Z 0 And VR sequence and positive sequence impedances viewed from the fault; it is a variable ratio, dependent upon the method of earthing, fault position and system operating arrangement. Vae  Vbe  Vce Equation 4.40 When assessing the distribution of residual quantities through a system, it is convenient to use the fault point as the reference as it is the point of injection of unbalanced quantities into the system. The residual voltage is measured in relation to the normal phase-neutral system voltage and the residual current is compared with the three-phase fault current at the fault point. It can be shown [4.4/4.5] that the character of these Also, from Equation 4.2: IR 3I 0 VR 3V0 Z1 ratio is defined as the ratio of zero Equation 4.41 It should be further noted that: quantities can be expressed in terms of the system Z 0 Z1 Vae Van  Vne ratio. Vbe Vbn  Vne Vce Vcn  Vne The positive sequence impedance of a system is mainly reactive, whereas the zero sequence impedance being affected by the method of earthing may contain both resistive and reactive components of comparable magnitude. Thus the Equation 4.42 expression for the Z 0 and since Vbn a Van and Vcn 2 aVan then: VR 3Vne Z0 Z1 Z1 ratio approximates to: R0 X0 j X1 X1 Equation 4.44 Expressing the residual current in terms of the three-phase Equation 4.43 where Vne is the neutral displacement voltage. Measurements of residual quantities are made using current and voltage transformer connections as shown in Figure 4.16. If relays are connected into the circuits in place of the ammeter and voltmeter, earth faults in the system can be detected. current and Z 0 Z1 ratio: a. Single-phase-earth (A-E) © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 4-13 Network Protection & Automation Guide where K 3V 2Z 1  Z 0 3 V 2  K Z1 Z0 and I 3I Z1 V Z1 3 2 K Equation 4.45 b. Phase-phase-earth (B-C-E) IR I1 3I 0  3Z1 I1 Z1  Z 0 V Z1  Z 0 2 2Z 1 Z 0  Z 1  2 3 V  2K  1 Z 1 Therefore: IR I 3I  3 2K  1 Similarly, the residual voltages are found by multiplying Equation 4.45 and Equation 4.46 by  K V . c. Single-phase-earth (A-E)  3K V 2 K Equation 4.47 d. Phase-phase-earth (B-C-E) VR 1.5 Residual voltage for Double-Phase-Earth fault 1.0 0.5 Residual current for Double-Phase-Earth fault 1 2 3  3K V 2K  1 5 Figure 4.17: Variation of residual quantities at fault point The curves in Figure 4.17 illustrate the variation of the above Z1 ratio. The residual current in any part of the system can be obtained by multiplying the current from the curve by the appropriate zero sequence distribution factors. Similarly, the residual voltage is calculated by subtracting from the voltage curve three times the zero sequence voltage drops between the measuring point in the system and the fault. 4.6.3 Variation of Residual Quantities The variation of residual quantities in a system due to different earth arrangements can be most readily understood by using vector diagrams. Three examples have been chosen, namely solid fault-isolated neutral, solid fault-resistance neutral, and resistance fault-solid neutral. These are illustrated in Figure 4.18, Figure 4.19 and Figure 4.20 respectively. Equation 4.48 4-14 4 Z0 · ¸ Z1 ¹ residual quantities with the Z 0 Equation 4.46 VR 2.0 § K ¨ © 3V Z1 2Z 1 Z 0  Z 1 Residual voltage for Single-Phase-Earth fault 0 Hence: IR Residual current for Double-Phase-Earth fault 2.5 Thus: IR I 3I 3.0 V R and I R as mul t i pl es of V and I 3I IR © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 4 ˜ Fault Calculations short-circuited by the fault and the neutral current combines I ab  I ac with the sound phase capacitive currents to give I a in the I ab faulted phase. I ac Ia X I ab I ab  I ac ZL F A I ac I ab B N I ac C I an I ac I ab Ia V cF Eac V bF V bF I ab I ab Eab V cF (a) Circuit diagram VR I ac c Figure 4.18: Solid fault - isolated neutral V cF 4.6.3.1 Solid fault-isolated neutral V cX From Figure 4.18 it can be seen that the capacitance to earth of the faulted phase is short circuited by the fault and the resulting unbalance causes capacitance currents to flow into the fault, returning via sound phases through sound phase capacitances to earth. VaF V bF x (b) Vector diagram VbF  VcF 3Ean V cF VR V bF (At source) V aX At source: 3Vne I an V bX V cX VR I ab b 0 and VR I ac  I aZ L VXn I ab At the fault point: Ia a(F) n VR 3Ean (At fault) V bX (c) Residual voltage diagram Since Figure 4.19: Solid fault - resistance neutral Ean  Ebn  Ecn 0 Thus, with an isolated neutral system, the residual voltage is three times the normal phase-neutral voltage of the faulted phase and there is no variation between VR at source and VR at fault. In practice, there is some leakage impedance between neutral and earth and a small residual current would be detected at X if a very sensitive relay were employed. 4.6.3.2 Solid fault-resistance neutral Figure 4.19 shows that the capacitance of the faulted phase is With a relay at X, residually connected as shown in Figure 4.16, the residual current will be I an , that is, the neutral earth loop current. At the fault point: VR since VFe VbF  VcF 0 At source: VR VaX  VbX  VcX From the residual voltage diagram it is clear that there is little © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 4-15 Network Protection & Automation Guide variation in the residual voltages at source and fault, as most residual voltage is dropped across the neutral resistor. The degree of variation in residual quantities is therefore dependent on the neutral resistor value. Capacitance can be neglected because, since the capacitance of the faulted phase is not short-circuited, the circulating capacitance currents will be negligible. At the fault point: VFn  Vbn  Vcn At relaying point X: V Xn  Vbn  Vcn VR X ZS ZL IF zero, that is, the fault becomes solid, then VFn approaches zero and the voltage drops in Z S and Z L become greater. The ultimate value of VFn will depend on the effectiveness of 4.6.3.3 Resistance-fault-solid neutral VR reduces towards the source. If the fault resistance approaches F A B the earthing, and this is a function of the system Z 0 ratio. 4.7 REFERENCES [4.1] Circuit Analysis of A.C. Power Systems, Volume I. Edith Clarke. John Wiley & Sons. [4.2] Method of Symmetrical Co-ordinates Applied to the Solution of Polyphase Networks. C.L. Fortescue. Trans. A.I.E.E.,Vol. 37, Part II, 1918, pp 1027-40. [4.3] Power System Analysis. J.R. Mortlock and M.W. Humphrey Davies. Chapman and Hall. [4.4] Neutral Groundings. R Willheim and M. Waters. Elsevier. [4.5] Fault Calculations. F.H.W. Lackey. Oliver & Boyd C IF IF (a) Circuit diagram c V cF V cn V an n a  I FZ s V Xn V Fn Vbn X  I FZ L F IF V bF b VR V cn (b) Vector diagram VR V Fn Vbn (c) Residual voltage at fault V cn V Xn V bn (d) Residual voltage at relaying point Figure 4.20: Resistance fault -solid neutral From the residual voltage diagrams shown in Figure 4.20, it is apparent that the residual voltage is greatest at the fault and 4-16 Z1 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 4 ˜ Fault Calculations © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 4-17 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 Equivalent circuits and parameters of power system plant 5.1 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 5.9 5.10 5.11 5.12 5.13 5.14 5.15 5.16 5.17 5.18 5.19 5.20 5.21 5.22 5.23 5.24 5.25 Introduction Synchronous Machines Armature Reaction Steady State Theory Salient Pole Rotor Transient Analysis Asymmetry Machine Reactances Negative Sequence Reactance Zero Sequence Reactance Direct and Quadrature Axis Values Effect of Saturation on Machine Reactances Transformers Transformer Positive Sequence Equivalent Circuits Transformer Zero Sequence Equivalent Circuits Auto-Transformers Transformer Impedances Overhead Lines and Cables Calculation of Series Impedance Calculation of Shunt Impedance Overhead Line Circuits With or Without Earth Wires OHL Equivalent Circuits Cable Circuits Overhead Line and Cable Data References INTRODUCTION Knowledge of the behaviour of the principal electrical system plant items under normal and fault conditions is a prerequisite for the proper application of protection. This chapter summarises basic synchronous machine, transformer and transmission line theory and gives equivalent circuits and parameters so that a fault study can be successfully completed before the selection and application of the protection systems described in later chapters. Only what might be referred to as ‘traditional’ synchronous machine theory is covered because calculations for fault level studies generally only require this. Readers interested in more advanced models of synchronous machines are referred to the numerous papers on the subject, of which reference [5.1] is a good starting point. Power system plant can be divided into two broad groups: static and rotating. The modelling of static plant for fault level calculations provides few difficulties, as plant parameters generally do not change during the period of interest after a fault occurs. The problem in modelling rotating plant is that the parameters change depending on the response to a change in power system conditions. 5.2 SYNCHRONOUS MACHINES There are two main types of synchronous machine: cylindrical rotor and salient pole. In general, the former is confined to 2 and 4 pole turbine generators, while salient pole types are built with 4 poles upwards and include most classes of duty. Both classes of machine are similar in that each has a stator carrying a three-phase winding distributed over its inner periphery. The rotor is within the stator bore and is magnetised by a d.c. current winding. The main difference between the two classes of machine is in the rotor construction. The cylindrical rotor type has a cylindrical rotor with the excitation winding distributed over several slots around its periphery. This construction is not suited to multi-polar machines but it is very mechanically sound. It is therefore particularly well suited for the highest speed electrical machines and is universally used for 2 pole units, plus some 4 pole units. The salient pole type has poles that are physically separate, each carrying a concentrated excitation winding. This type of Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-1 Network Protection & Automation Guide construction is complementary to that of the cylindrical rotor and is used in machines of 4 poles or more. Except in special cases its use is exclusive in machines of more than 6 poles. Figure 5.1 shows a typical large cylindrical rotor generator installed in a power plant. Two and four pole generators are most often used in applications where steam or gas turbines are used as the driver. This is because the steam turbine tends to be suited to high rotational speeds. Four pole steam turbine generators are most often found in nuclear power stations as the relative wetness of the steam makes the high rotational speed of a two-pole design unsuitable. Most generators with gas turbine drivers are four pole machines to obtain enhanced mechanical strength in the rotor - since a gearbox is often used to couple the power turbine to the generator, the choice of synchronous speed of the generator is not subject to the same constraints as with steam turbines. unity p.f., the voltage and current in the stator are in phase, the stator current producing a cross magnetising magnetomotive force (m.m.f.) which interacts with that of the rotor, resulting in a distortion of flux across the pole face. As can be seen from Figure 5.2(a) the tendency is to weaken the flux at the leading edge or distort the field in a manner equivalent to a shift against the direction of rotation. If the power factor is reduced to zero lagging, the current in the stator reaches its maximum 90° after the voltage. The rotor is then in the position shown in Figure 5.2(b) and the stator m.m.f. is acting in direct opposition to the field. Similarly, for operation at zero leading power factor, the stator m.m.f. directly assists the rotor m.m.f. This m.m.f. arising from current flowing in the stator is known as ‘armature reaction’. Generators with diesel engine drivers are invariably of four or more pole design, to match the running speed of the driver without using a gearbox. Four-stroke diesel engines usually have a higher running speed than two-stroke engines, so generators having four or six poles are most common. Twostroke diesel engines are often derivatives of marine designs with relatively large outputs (circa 30MW is possible) and may have running speeds of the order of 125rpm. This requires a generator with a large number of poles (48 for a 125rpm, 50Hz generator) and consequently is of large diameter and short axial length. This is a contrast to turbine-driven machines that are of small diameter and long axial length. Strong Weak Weak N Strong S Direction of rotation (a) N S N (b) Figure 5.2: Distortion of flux due to armature reaction 5.4 STEADY STATE THEORY The vector diagram of a single cylindrical rotor synchronous machine is shown in Figure 5.3, assuming that the magnetic circuit is unsaturated, the air-gap is uniform and all variable quantities are sinusoidal. The resistance of these machines is much smaller than the reactance and is therefore neglected. Figure 5.1: Large synchronous generator 5.3 ARMATURE REACTION Armature reaction has the greatest effect on the operation of a synchronous machine with respect both to the load angle at which it operates and to the amount of excitation that it needs. The phenomenon is most easily explained by considering a simplified ideal generator with full pitch winding operating at unity p.f., zero lag p.f. and zero lead p.f. When operating at 5-2 The excitation ampere-turns ATe produces a flux  across the air-gap which induces a voltage Et in the stator. This voltage drives a current I at a power factor cos  and produces an armature reaction m.m.f. ATar in phase with it. The m.m.f. ATf resulting from the combination of these two m.m.f. vectors (see Figure 5.3(a)) is the excitation which must be provided on the rotor to maintain flux  across the air gap. Rotating the rotor m.m.f. diagram, Figure 5.3(a), clockwise until ATe coincides with Et and changing the scale of the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant diagram so that ATe becomes the basic unit, where ATe=Et=1 results in Figure 5.3(b). The m.m.f. vectors therefore become voltage vectors. For example ATar /ATe is a unit of voltage that is directly proportional to the stator load current. This vector can be fully represented by a reactance and in practice this is called 'armature reaction reactance' and is denoted by Xad. Similarly, the remaining side of the triangle becomes ATf /ATe which is the per unit voltage produced on open circuit by ampere-turns ATf. It can be considered as the internal generated voltage of the machine and is designated E0 . M ) IXL is exactly in phase with the voltage drop due to Xad as shown on the vector diagram Figure 5.3(c). Xad and XL can be combined to give a simple equivalent reactance; known as the ‘synchronous reactance'and denoted by Xd. The power generated by the machine is given by: P VI cos I VEo sin G Xd Equation 5.1 where G is the angle between the internal voltage and the terminal voltage and is known as the load angle of the machine. It follows from the above analysis that, for steady state performance, the machine may be represented by the equivalent circuit shown in Figure 5.4, where XL is a true reactance associated with flux leakage around the stator winding and Xad is a fictitious reactance, being the ratio of armature reaction and open-circuit excitation magneto-motive forces. M ) Figure 5.4: Equivalent circuit of elementary synchronous machine In practice, due to necessary constructional features of a cylindrical rotor to accommodate the windings, the reactance Xa is not constant irrespective of rotor position, and modelling proceeds as for a generator with a salient pole rotor. However, the numerical difference between the values of Xad and Xaq is small, much less than for the salient pole machine. 5.5 G M SALIENT POLE ROTOR The preceding theory is limited to the cylindrical rotor generator. For a salient pole rotor, the air gap cannot be considered as uniform.. The effect of this is that the flux produced by armature reaction m.m.f. depends on the position of the rotor at any instant, as shown in Figure 5.5. Figure 5.3: Vector diagram of synchronous machine The true leakage reactance of the stator winding which gives rise to a voltage drop or regulation has been neglected. This reactance is designated XL (or Xa in some texts) and the voltage drop occurring in it IXL is the difference between the terminal voltage V and the voltage behind the stator leakage reactance EL. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-3 Network Protection & Automation Guide Lag Iq Xq Lead Armature reaction M.M.F. Id Xd E0 Flux IXd Flux Quadrature axis Direct axis pole E’0 V G Figure 5.5: Variation of armature reaction m.m.f. with pole position M When a pole is aligned with the assumed sine wave m.m.f. set up by the stator, a corresponding sine wave flux is set up but when an inter-polar gap is aligned very severe distortion is caused. The difference is treated by considering these two axes, that is those corresponding to the pole and the interpolar gap, separately. They are designated the 'direct' and 'quadrature' axes respectively, and the general theory is known as the 'two axis' theory. The vector diagram for the salient pole machine is similar to that for the cylindrical rotor except that the reactance and currents associated with them are split into two components. The synchronous reactance for the direct axis is Xd=Xad+XL, while that in the quadrature axis is Xq=Xaq+XL. The vector diagram is constructed as before but the appropriate quantities in this case are resolved along two axes. The resultant internal voltage is E0, as shown in Figure 5.6. Note that E’0 is the internal voltage which would be given, in cylindrical rotor theory, by vectorially adding the simple vectors IXd and V. There is very little difference in magnitude between E’0 and E0 but there is a substantial difference in internal angle. The simple theory is perfectly adequate for calculating excitation currents but not for stability considerations where load angle is significant. I Iq Id Pole axis Figure 5.6: Vector diagram for salient pole machine 5.6 TRANSIENT ANALYSIS For normal changes in load conditions, steady state theory is perfectly adequate. However, there are occasions when almost instantaneous changes are involved, such as faults or switching operations. When this happens new factors are introduced within the machine and to represent these adequately a corresponding new set of machine characteristics is required. The generally accepted and most simple way to appreciate the meaning and derivation of these characteristics is to consider a sudden three-phase short circuit applied to a machine initially running on open circuit and excited to normal voltage E0. This voltage is generated by a flux crossing the air-gap. It is not possible to confine the flux to one path exclusively in any machine so there is a leakage flux L that leaks from pole to pole and across the inter-polar gaps without crossing the main air-gap as shown in Figure 5.7. The flux in the pole is +L . 5-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant )L 2 )L 2 It might be expected that the fault current would be given by E0/(XL+Xad) equal to E0/Xd, but this is very much reduced, and the machine is operating with no saturation. For this reason, the value of voltage used is the value read from the air-gap line corresponding to normal excitation and is higher than the normal voltage. The steady state current is given by: Id Eg Xd Equation 5.2 where Eg = voltage on air gap line Figure 5.7: Flux paths of salient pole machine If the stator winding is then short-circuited, the power factor in it is zero. A heavy current tends to flow as the resulting armature reaction m.m.f. is demagnetising. This reduces the flux and conditions settles until the armature reaction nearly balances the excitation m.m.f., the remainder maintaining a very much reduced flux across the air-gap which is just sufficient to generate the voltage necessary to overcome the stator leakage reactance (resistance neglected). This is the simple steady state case of a machine operating on short circuit and is fully represented by the equivalent of Figure 5.8(a); see also Figure 5.4. Between the initial and final conditions there has been a severe reduction of flux. The rotor carries a highly inductive winding which links the flux so the rotor flux linkages before the short circuit are produced by +L. In practice the leakage flux is distributed over the whole pole and all of it does not link all the winding. L is an equivalent concentrated flux imagined to link all the winding and of such a magnitude that the total linkages are equal to those actually occurring. It is a fundamental principle that any attempt to change the flux linked with such a circuit causes current to flow in a direction that opposes the change. In the present case the flux is being reduced and so the induced currents tend to sustain it. For the position immediately following the application of the short circuit, it is valid to assume that the flux linked with the rotor remains constant, this being brought about by an induced current in the rotor which balances the heavy demagnetising effect set up by the short-circuited armature. So +L remains constant, but owing to the increased m.m.f. involved, the flux leakage increases considerably. With a constant total rotor flux, this can only increase at the expense of that flux crossing the air-gap. Consequently, this generates a reduced voltage, which, acting on the leakage reactance XL, gives the short circuit current. It is more convenient for machine analysis to use the rated voltage E0 and to invent a fictitious reactance that gives rise to the same current. This reactance is called the 'transient reactance' X’d and is defined by the equation: Transient current I ' d E0 X 'd Equation 5.3 It is greater than XL and the equivalent circuit is represented by Figure 5.8(b) where: X 'd Figure 5.8: Synchronous machine reactances X ad X f X ad  X f  XL Equation 5.4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-5 Network Protection & Automation Guide and Xf is the leakage reactance of the field winding or X "d Equation 5.4 may also be written as: X 'd XL  X 'f X L  X 'kd and where: Xkd = leakage reactance of damper winding(s) X’f = effective leakage reactance of field winding X’kd = effective leakage reactance of damper winding(s) The flux is only be sustained at its relatively high value while the induced current flows in the field winding. As this current decays, conditions approach the steady state. Consequently the duration of this phase is determined by the time constant of the excitation winding. This is usually one second or less hence the term 'transient' applied to characteristics associated with it. A further point now arises. All synchronous machines have what is usually called a ‘damper winding’ or windings. In some cases, this may be a physical winding (like a field winding, but of fewer turns and located separately), or an ‘effective’ one (for instance, the solid iron rotor of a cylindrical rotor machine). Sometimes, both physical and effective damper windings may exist (as in some designs of cylindrical rotor generators, having both a solid iron rotor and a physical damper winding located in slots in the pole faces). It is greater than XL but less than X’d and the corresponding equivalent circuit is shown in Figure 5.8(c). Again, the duration of this phase depends upon the time constant of the damper winding. In practice this is approximately 0.05 seconds - very much less than the transient - hence the term 'sub-transient'. Figure 5.9 shows the envelope of the symmetrical component of an armature short circuit current indicating the values described in the preceding analysis. The analysis of the stator current waveform resulting from a sudden short circuit test is traditionally the method by which these reactances are measured. However, the major limitation is that only direct axis parameters are measured. Detailed test methods for synchronous machines are given in references [5.2] and [5.3], and include other tests that are capable of providing more detailed parameter information. The damper winding(s) is subjected to the full effect of flux transfer to leakage paths and carries an induced current tending to oppose it. As long as this current can flow, the airgap flux is held at a value slightly higher than would be the case if only the excitation winding were present, but still less than the original open circuit flux . Current Under short circuit conditions there is a transfer of flux from the main air-gap to leakage paths. To a small extent this diversion is opposed by the excitation winding and the main transfer is experienced towards the pole tips. I dcc As before, it is convenient to use rated voltage and to create another fictitious reactance that is considered to be effective over this period. This is known as the 'sub-transient reactance' X”d and is defined by the equation: Sub-transient current I "d E0 X "d Eo X ccd I dc EO X cd Id Eai r gap Xd Time Figure 5.9: Transient decay envelope of short-circuit current Equation 5.5 5.7 where: X "d 5-6 XL  X ad X f X kd X ad X f  X kd X f  X ad X kd ASYMMETRY The exact instant at which the short circuit is applied to the stator winding is of significance. If resistance is negligible compared with reactance, the current in a coil lags the voltage by 90°, that is, at the instant when the voltage wave attains a maximum, any current flowing through would be passing through zero. If a short circuit were applied at this instant, the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant resulting current would rise smoothly and would be a simple a.c. component. However, at the moment when the induced voltage is zero, any current flowing must pass through a maximum (owing to the 90° lag). If a fault occurs at this moment, the resulting current assumes the corresponding relationship; it is at its peak and in the ensuing 180° goes through zero to maximum in the reverse direction and so on. In fact the current must actually start from zero so it follows a sine wave that is completely asymmetrical. Intermediate positions give varying degrees of asymmetry. This asymmetry can be considered to be due to a d.c. component of current which dies away because resistance is present. more costly machine. It is also worth noting that XL normally changes in sympathy with Xad but that it is completely overshadowed by it. The value 1/Xd has a special significance as it approximates to the short circuit ratio (S.C.R.), the only difference being that the S.C.R. takes saturation into account whereas Xd is derived from the air-gap line. Cylindrical rotor turbine generators Type of machine Salient pole synchronous condensers Air Cooled Salient pole generators Hydrogen Cooled Hydrogen or Water Cooled 4 Pole Multipole The d.c. component of stator current sets up a d.c. field in the stator which causes a supply frequency ripple on the field current, and this alternating rotor flux has a further effect on the stator. This is best shown by considering the supply frequency flux as being represented by two half magnitude waves each rotating in opposite directions at supply frequency relative to the rotor. So, as viewed from the stator, one is stationary and the other rotating at twice supply frequency. The latter sets up second harmonic currents in the stator. Further development along these lines is possible but the resulting harmonics are usually negligible and normally neglected. Short circuit ratio 0.5-0.7 1.0-1.2 0.4-0.6 0.4-0.6 0.4-0.6 0.4-0.6 0.6-0.8 Direct axis synchronous reactance Xd (p.u.) 1.6-2.0 0.8-1.0 2.0-2.8 2.1-2.4 2.1-2.6 1.753.0 Quadrature axis synchronous reactance Xq (p.u.) 1.01.23 0.50.65 1.8-2.7 1.9-2.4 2.0-2.5 0.9-1.5 0.8-1.0 Direct axis transient reactance X'd (p.u.) 0.3-0.5 0.20.35 0.2-0.3 0.27-0.33 0.3-0.36 0.260.35 0.24-0.4 Direct axis sub-transient reactance X''d (p.u.) 0.2-0.4 0.120.25 0.15-0.23 0.19-0.23 0.21-0.27 0.190.25 0.16-0.25 Quadrature axis subtransient reactance X''q (p.u.) 0.250.6 0.150.25 0.16-0.25 0.19-0.23 0.21-0.28 0.190.35 0.18-0.24 Negative sequence reactance X2 (p.u.) 0.250.5 0.140.35 0.16-0.23 0.19-0.24 0.21-0.27 0.160.27 0.16-0.23 5.8 Zero sequence reactance 0.12X0 (p.u.) 0.16 0.060.10 0.06-0.1 0.1-0.15 0.1-0.15 0.010.1 0.0450.23 MACHINE REACTANCES Table 5.1 gives values of machine reactances for salient pole and cylindrical rotor machines typical of latest design practice. Also included are parameters for synchronous compensators – such machines are now rarely built, but significant numbers can still be found in operation. 5.8.1 Synchronous Reactance Xd=XL+Xad The order of magnitude of XL is normally 0.1-0.25p.u., while that of Xad is 1.0-2.5p.u. The leakage reactance XL can be reduced by increasing the machine size (derating), or increased by artificially increasing the slot leakage, but XL is only about 10% of the total value of Xd and does not have much influence. The armature reaction reactance can be reduced by decreasing the armature reaction of the machine, which in design terms means reducing the ampere conductor or electrical (as distinct from magnetic) loading - this often means a physically larger machine. Alternatively the excitation needed to generate open-circuit voltage may be increased; this is simply achieved by increasing the machine air-gap, but is only possible if the excitation system is modified to meet the increased requirements. In general, control of Xd is obtained almost entirely by varying Xad and in most cases a reduction in Xd means a larger and 1.4-1.9 Direct axis short circuit transient time constant T'd (s) 1.5-2.5 1.0-2.0 0.6-1.3 0.7-1.0 0.75-1.0 0.4-1.1 0.25-1 Direct axis open circuit transient time constant T'd (s) 5-10 3-7 6-12 6-10 6-9.5 3.0-9.0 1.7-4.0 Direct axis short circuit sub-transient- time constant T''d (s) 0.040.9 0.050.10 0.0130.022 0.017-0.025 0.022-0.03 0.020.04 Direct axis open circuit sub-transient time constant T''d' (s) 0.070.11 0.080.25 0.0180.03 0.023-0.032 0.025-0.035 0.0350.03-0.1 0.06 Quadrature axis short circuit sub-transient time constant T''q (s) 0.04- 0.05- 0.0130.6 0.6 0.022 0.018-0.027 0.02-0.03 0.025- 0.0250.04 0.08 0.03-0.05 0.130.2 Quadrature axis open 0.026circuit sub-transient time 0.1-0.2 0.2-0.9 0.045 constant T''q (s) 0.04-0.065 0.02-0.06 0.1-0.35 Table 5.1: Typical values of machine characteristics (all reactance values are unsaturated) 5.8.2 Transient Reactance X’d=XL+X’f The transient reactance covers the behaviour of a machine in the period 0.1-3.0 seconds after a disturbance. This generally corresponds to the speed of changes in a system and therefore X’d has a major influence in transient stability studies. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-7 Network Protection & Automation Guide Generally, the leakage reactance XL is equal to the effective field leakage reactance X’f , about 0.1-0.25p.u. The principal factor determining the value of X’f is the field leakage. This is largely beyond the control of the designer, in that other considerations are at present more significant than field leakage and hence take precedence in determining the field design. XL can be varied as already outlined and, in practice, control of transient reactance is usually achieved by varying XL. In practice an empirical method is used, based on the fact that a given type of machine is capable of carrying, for short periods, an amount of heat determined by its thermal capacity, and for a long period, a rate of heat input which it can dissipate continuously. Synchronous machines are designed to operate continuously on an unbalanced system so that with none of the phase currents exceeding the rated current, the ratio of the negative sequence current I2 to the rated current IN does not exceed the values given in Table 5.2. Under fault conditions, the machine can also operate with the product of 5.8.3 Sub-Transient Reactance X’’d=XL+X’kd § I2 ¨¨ © IN The sub-transient reactance determines the initial current peaks following a disturbance and in the case of a sudden fault is of importance for selecting the breaking capacity of associated circuit breakers. The mechanical stresses on the machine reach maximum values that depend on this constant. The effective damper winding leakage reactance X’kd is largely determined by the leakage of the damper windings and control of this is only possible to a limited extent. X’kd normally has a value between 0.05 and 0.15p.u. The major factor is XL which, as indicated previously, is of the order of 0.1-0.25p.u., and control of the sub-transient reactance is normally achieved by varying XL. Good transient stability is obtained by keeping the value of X’d low, which therefore also implies a low value of X”d. The fault rating of switchgear, etc. is therefore relatively high. It is not normally possible to improve transient stability performance in a generator without adverse effects on fault levels, and vice versa. 5.9 NEGATIVE SEQUENCE REACTANCE Negative sequence currents can arise whenever there is any unbalance present in the system. Their effect is to set up a field rotating in the opposite direction to the main field generated by the rotor winding, so subjecting the rotor to double frequency flux pulsations. This gives rise to parasitic currents and heating; most machines are quite limited in the amount of such current which they are able to carry, both in the steady–state and transiently. An accurate calculation of the negative sequence current capability of a generator involves consideration of the current paths in the rotor body. In a turbine generator rotor, for instance, they include the solid rotor body, slot wedges, excitation winding and end-winding retaining rings. There is a tendency for local over-heating to occur and, although possible for the stator, continuous local temperature measurement is not practical in the rotor. Calculation requires complex mathematical techniques to be applied, and involves specialist software. 5-8 2 · ¸¸ and time in seconds (t) not exceeding the values ¹ given. Rotor construction Rotor Cooling indirect Maximum (I2/IN)2t for operation during faults 0.1 20 generators 0.08 20 synchronous condensers 0.1 20 motors 0.08 15 generators 0.05 15 synchronous condensers 0.08 15 indirectly cooled all (air) 0.1 15 indirectly cooled all (hydrogen) 0.1 10 directly cooled <=350 0.08 8 351-900 Note 1 Note 2 direct Note 1: Calculate as Maximum I2/IN for continuous operation motors Salient Cylindrical Machine Type/Rating (SN) (MVA) I2 IN ªI Note 2: Calculate as «« 2 ¬ IN 901-1250 Note 1 5 1251-1600 0.05 5 S  350 0.08  N 3u10 4 2 º » t » ¼ 8  0.00545 S N 350 Table 5.2: Unbalanced operating conditions for synchronous machines (with acknowledgement to IEC 60034-1) 5.10 ZERO SEQUENCE REACTANCE If a machine operates with an earthed neutral, a system earth fault gives rise to zero sequence currents in the machine. This reactance represents the machines’ contribution to the total impedance offered to these currents. In practice it is generally low and often outweighed by other impedances present in the circuit. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant 5.11 DIRECT AND QUADRATURE AXIS VALUES machine excited to rated voltage. The transient reactance is associated with the field winding and since on salient pole machines this is concentrated on the direct axis, there is no corresponding quadrature axis value. The value of reactance applicable in the quadrature axis is the synchronous reactance, that is X’q = Xq. In some cases, the test may be made from a suitably reduced voltage so that the initial current is approximately full load value. This may be the case where the severe mechanical strain that occurs when the test is performed at rated voltage has to be avoided. Saturation is very much reduced and the reactance values measured are virtually unsaturated values. They are also known as 'rated current' values, for obvious reasons. The damper winding (or its equivalent) is more widely spread and hence the sub-transient reactance associated with this has a definite quadrature axis value X”q, which differs significantly in many generators from X”d. 5.12 EFFECT OF SATURATION ON MACHINE REACTANCES In general, any electrical machine is designed to avoid severe saturation of its magnetic circuit. However, it is not economically possible to operate at such low flux densities as to reduce saturation to negligible proportions, and in practice a moderate degree of saturation is accepted. Since the armature reaction reactance Xad is a ratio ATar /ATe it is evident that ATe does not vary in a linear manner for different voltages, while ATar remains unchanged. The value of Xad varies with the degree of saturation present in the machine, and for extreme accuracy should be determined for the particular conditions involved in any calculation. All the other reactances, namely XL, X’d and X”d, are true reactances and actually arise from flux leakage. Much of this leakage occurs in the iron parts of the machines and hence must be affected by saturation. For a given set of conditions, the leakage flux exists as a result of the net m.m.f. which causes it. If the iron circuit is unsaturated its reactance is low and leakage flux is easily established. If the circuits are highly saturated the reverse is true and the leakage flux is relatively lower, so the reactance under saturated conditions is lower than when unsaturated. Most calculation methods assume infinite iron permeability and for this reason lead to somewhat idealised unsaturated reactance values. The recognition of a finite and varying permeability makes a solution extremely laborious and in practice a simple factor of approximately 0.9 is taken as representing the reduction in reactance arising from saturation. It is necessary to distinguish which value of reactance is being measured when on test. The normal instantaneous shortcircuit test carried out from rated open-circuit voltage gives a current that is usually several times full load value, so that saturation is present and the reactance measured is the saturated value. This value is also known as the 'rated voltage' value since it is measured by a short circuit applied with the 5.13 TRANSFORMERS A transformer may be replaced in a power system by an equivalent circuit representing the self-impedance of, and the mutual coupling between, the windings. A two-winding transformer can be simply represented as a 'T' network in which the cross member is the short-circuit impedance, and the column the excitation impedance. It is rarely necessary in fault studies to consider excitation impedance as this is usually many times the magnitude of the short-circuit impedance. With these simplifying assumptions a three-winding transformer becomes a star of three impedances and a fourwinding transformer a mesh of six impedances. The impedances of a transformer, in common with other plant, can be given in ohms and qualified by a base voltage, or in per unit or percentage terms and qualified by a base MVA. Care should be taken with multi-winding transformers to refer all impedances to a common base MVA or to state the base on which each is given. The impedances of static apparatus are independent of the phase sequence of the applied voltage; in consequence, transformer negative sequence and positive sequence impedances are identical. In determining the impedance to zero phase sequence currents, account must be taken of the winding connections, earthing, and, in some cases, the construction type. The existence of a path for zero sequence currents implies a fault to earth and a flow of balancing currents in the windings of the transformer. Practical three-phase transformers may have a phase shift between primary and secondary windings depending on the connections of the windings – delta or star. The phase shift that occurs is generally of no significance in fault level calculations as all phases are shifted equally. It is therefore ignored. It is normal to find delta-star transformers at the transmitting end of a transmission system and in distribution systems for the following reasons: x At the transmitting end, a higher step-up voltage ratio is possible than with other winding arrangements, while the insulation to ground of the star secondary winding does not increase by the same ratio. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-9 Network Protection & Automation Guide x In distribution systems, the star winding allows a neutral connection to be made, which may be important in considering system earthing arrangements. x The delta winding allows circulation of zero sequence currents within the delta, thus preventing transmission of these from the secondary (star) winding into the This simplifies protection primary circuit. considerations. 5.14 TRANSFORMER POSITIVE SEQUENCE EQUIVALENT CIRCUITS The transformer is a relatively simple device. However, the equivalent circuits for fault calculations need not necessarily be quite so simple, especially where earth faults are concerned. The following two sections discuss the positive sequence equivalent circuits of various types of transformers. B A A C Z11 Load E B' C' A' B Z22 Z12 A' B' Zero bus (b) Equivalent circuit of model (a) Model of transformer Z1=Z11-Z12 Z2=Z22-Z12 A r1+jx1 B B Z3=Z12 R B' A' r2+jx2 A jXM A' B' Zero bus Zero bus (c) 'T' equivalent circuit (d) ‘’ equivalent circuit ZT=Z1+Z2 A B A' B' Zero bus (e) Equivalent circuit: secondary winding s/c 5.14.1 Two-Winding Transformers The two-winding transformer has four terminals, but in most system problems, two-terminal or three-terminal equivalent circuits as shown in Figure 5.10 can represent it. In Figure 5.10(a), terminals A' and B' are assumed to be at the same potential. Hence if the per unit self-impedances of the windings are Z11 and Z22 respectively and the mutual impedance between them Z12, the transformer may be represented by Figure 5.10(b). The circuit in Figure 5.10(b) is similar to that shown in Figure 3.14(a), and can therefore be replaced by an equivalent 'T' as shown in Figure 5.10(c) where: Z1 Z11  Z12 Z2 Z 22  Z12 Z3 Z12 Figure 5.10: Equivalent circuits for a two-winding transformer The relative magnitudes of ZT and XM are 10% and 2000% respectively. ZT and XM rarely have to be considered together, so that the transformer may be represented either as a series impedance or as an excitation impedance, according to the problem being studied. Figure 5.11 shows a typical high voltage power transformer. Equation 5.6 Z1 is described as the leakage impedance of winding AA' and Z2 the leakage impedance of winding BB'. Impedance Z3 is the mutual impedance between the windings, usually represented by XM, the magnetising reactance paralleled with the hysteresis and eddy current loops as shown in Figure 5.10(d). If the secondary of the transformers is short-circuited, and Z3 is assumed to be large with respect to Z1 and Z2, the shortcircuit impedance viewed from the terminals AA’ is ZT=Z1+Z2 and the transformer can be replaced by a twoterminal equivalent circuit as shown in Figure 5.10(e). 5-10 Figure 5.11: Testing a high voltage transformer 5.14.1 Three-Winding Transformers If excitation impedance is neglected the equivalent circuit of a three-winding transformer may be represented by a star of impedances, as shown in Figure 5.12, where P, T and S are the primary, tertiary and secondary windings respectively. The impedance of any of these branches can be determined by © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant considering the short-circuit impedance between pairs of windings with the third open. ZT/2 ZT/2 a a S b Ze b Zs Zero potential bus Secondary (a) Two windings Zp P Primary a Tertiary Zt Zs T Zp a Zero bus Figure 5.12: Equivalent circuit for a three-winding transformer 5.15 TRANSFORMER ZERO SEQUENCE EQUIVALENT CIRCUITS The flow of zero sequence currents in a transformer is only possible when the transformer forms part of a closed loop for uni-directional currents and ampere-turn balance is maintained between windings. Zt a b Ze b b Zero potential bus The positive sequence equivalent circuit is still maintained to represent the transformer but now there are certain conditions attached to its connection into the external circuit. The order of excitation impedance is much lower than for the positive sequence circuit and is roughly between 1 and 4 per unit but still high enough to be neglected in most fault studies. The mode of connection of a transformer to the external circuit is determined by taking account of each winding arrangement and its connection or otherwise to ground. If zero sequence currents can flow into and out of a winding, the winding terminal is connected to the external circuit (that is, link a is closed in Figure 5.13). If zero sequence currents can circulate in the winding without flowing in the external circuit, the winding terminal is connected directly to the zero bus (that is, link b is closed in Figure 5.13). Table 5.3 gives the zero sequence connections of some common two- and threewinding transformer arrangements applying the above rules. (b) Three windings Figure 5.13: Zero sequence equivalent circuits The exceptions to the general rule of neglecting magnetising impedance occur when the transformer is star/star and either or both neutrals are earthed. In these circumstances the transformer is connected to the zero bus through the magnetising impedance. Where a three-phase transformer bank is arranged without interlinking magnetic flux (that is a three-phase shell type, or three single-phase units) and provided there is a path for zero sequence currents, the zero sequence impedance is equal to the positive sequence impedance. In the case of three-phase core type units, the zero sequence fluxes produced by zero sequence currents can find a high reluctance path, the effect being to reduce the zero sequence impedance to about 90% of the positive sequence impedance. However, in hand calculations, it is usual to ignore this variation and consider the positive and zero sequence impedances to be equal. It is common when using software to perform fault calculations to enter a value of zero-sequence impedance in accordance with the above guidelines, if the manufacturer is unable to provide a value. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-11 Network Protection & Automation Guide Connections and zero phase sequence currents Zero phase sequence network a a Zt b b Zero bus a a Zt b b Zero bus a Zt a b b Zero bus a a Zt b b Zero bus a a Zt b b Zero bus a a ZT b b Zero bus Zt Zero bus Zs a a Zp Zt b a b b Zero bus Zs a Zp b a Zt a b b Zero bus Zs a a Zp Zt b a b b Zero bus Zs a a Zp Zt b a b b Zero bus Zs a Zp a Zt b a b Zero bus Table 5.3: Zero sequence equivalent circuit connections 5-12 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. b Chapter 5 ˜ Equivalent circuits and parameters of power system plant 5.16 AUTO-TRANSFORMERS The auto-transformer is characterised by a single continuous winding, part of which is shared by both the high and low voltage circuits, as shown in Figure 5.14(a). The 'common' winding is the winding between the low voltage terminals whereas the remainder of the winding, belonging exclusively to the high voltage circuit, is designated the 'series' winding, and, combined with the 'common' winding, forms the 'seriescommon' winding between the high voltage terminals. The advantage of using an auto-transformer as opposed to a twowinding transformer is that the auto-transformer is smaller and lighter for a given rating. The disadvantage is that galvanic isolation between the two windings does not exist, giving rise to the possibility of large overvoltages on the lower voltage system in the event of major insulation breakdown. Three-phase auto-transformer banks generally have star connected main windings, the neutral of which is normally connected solidly to earth. In addition, it is common practice to include a third winding connected in delta called the tertiary winding, as shown in Figure 5.14(b). H IH L IH H T IL IL IT L IL -IH N winding transformer. The star equivalent for a three-winding transformer, for example, is obtained in the same manner, with the difference that the impedances between windings are designated as follows: ZL ZH ZT 1 Z sc  c  Z c t  Z sc t 2 1 Z sc  c  Z sc  t  Z c  t 2 1 Z sc t  Z c  t  Z sc  c 2 Equation 5.7 where: Zsc-t = impedance between ‘series-common’ and tertiary windings. Zsc-c = impedance between ‘series-common’ and ‘common’ windings. Zc-t = impedance between ‘common’ and tertiary windings When no load is connected to the delta tertiary, the point T is open-circuited and the short-circuit impedance of the transformer becomes ZL+ZH=ZSC-C, similar to the equivalent circuit of a two-winding transformer, with magnetising impedance neglected; see Figure 5.14(c). VH VL ZN IL -IH IH N 5.16.2 Zero Sequence Equivalent Circuit IN IL (a) Circuit diagram ZL (b) Circuit diagram with tertiary winding ZH ZX L IH1 IL1 H L ZY IL0 IH0 H ZZ T ZT IT0 IT1 Zero potential bus T (d) Zero sequence equivalent circuit (c) Positive sequence impedance L The zero sequence equivalent circuit is derived in a similar manner to the positive sequence circuit, except that, as there is no identity for the neutral point, the current in the neutral and the neutral voltage cannot be given directly. Furthermore, in deriving the branch impedances, account must be taken of an impedance in the neutral Zn, as shown in Equation 5.8, where Zx, Zy and Zz are the impedances of the low, high and tertiary windings respectively and N is the ratio between the series and common windings. ZLH IL0 IH0 H ZHT ZLT Zx Zy T IT0 Zero potential bus (e) Equivalent circuit with isolated neutral Figure 5.14: Equivalent circuits of auto-transformers 5.16.1 Positive Sequence Equivalent Circuit The positive sequence equivalent circuit of a three-phase autotransformer bank is the same as that of a two- or three- Zz N N 1 N Z H  3Z n 2 N 1 1 Z T  3Z n N 1 Z L  3Z n Equation 5.8 Figure 5.14(d) shows the equivalent circuit of the transformer bank. Currents IL0 and IH0 are those circulating in the low and high voltage circuits respectively. The difference between these currents, expressed in amperes, is the current in the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-13 Network Protection & Automation Guide common winding. The current in the neutral impedance is three times the current in the common winding. 5.16.3 Special Conditions of Neutral Earthing With a solidly grounded neutral, Zn=0, the branch impedances Zx, Zy, Zz, become ZL, ZH, ZT, that is, identical to the corresponding positive sequence equivalent circuit, except that the equivalent impedance ZT of the delta tertiary is connected to the zero potential bus in the zero sequence network. When the neutral is ungrounded ZT=f and the impedances of the equivalent star also become infinite because there are apparently no paths for zero sequence currents between the windings, although a physical circuit exists and ampere-turn balance can be obtained. A solution is to use an equivalent delta circuit (see Figure 5.14(e)), and evaluate the elements of the delta directly from the actual circuit. The method requires three equations corresponding to three assumed operating conditions. Solving these equations relates the delta impedances to the impedance between the series and tertiary windings as follows: Z LT N2 Z s t N 1  Z s t N Z HT Z s t Z LH N N 1 Equation 5.9 With the equivalent delta replacing the star impedances in the autotransformer zero sequence equivalent circuit the transformer can be combined with the system impedances in the usual manner to obtain the system zero sequence diagram. 5.17 TRANSFORMER IMPEDANCES In most fault calculations the protection engineer is only concerned with the transformer leakage impedance; the magnetising impedance is neglected as it is very much higher. Impedances for transformers rated at 200MVA or less are given in IEC 60076 and repeated in Table 5.4, together with an indication of X/R values (not part of IEC 60076). These impedances are commonly used for transformers installed in industrial plants. Some variation is possible to assist in controlling fault levels or motor starting, and typically up to r10% variation of the impedance values given in the table is possible without incurring a significant cost penalty. For these transformers, the tapping range is small, and the variation of impedance with tap position is normally neglected in fault level calculations. 5-14 For transformers used in electricity distribution networks, the situation is more complex, due to an increasing trend to assign importance to the standing (or no-load) losses represented by the magnetising impedance. This can be adjusted at the design stage but there is often an impact on the leakage reactance in consequence. In addition, it may be more important to control fault levels on the LV side than to improve motor starting voltage drops. Therefore, departures from the IEC 60076 values are commonplace. IEC 60076 does not make recommendations of nominal impedance in respect of transformers rated over 200MVA, while generator transformers and a.c. traction supply transformers have impedances that are usually specified as a result of Power Systems Studies to ensure satisfactory performance. Typical values of transformer impedances covering a variety of transformer designs are given in Table 5.4 to Table 5.10. Where appropriate, they include an indication of the impedance variation at the extremes of the taps given. Transformers designed to work at 60Hz have much the same impedance as their 50Hz counterparts. Z% MVA Tolerance X/R HV/LV on Z% <0.630 4.00 1.5 ±10 0.631-1.25 5.00 3.5 ±10 1.251 - 3.15 6.25 6.0 ±10 3.151 - 6.3 7.15 8.5 ±10 6.301-12.5 8.35 13.0 ±10 12.501- 25.0 10.00 20.0 ±7.5 25.001 - 200 12.50 45.0 ±7.5 >200 by agreement Table 5.4: Transformer impedances IEC 60076 MVA Primary kV Primary Taps Secondary kV X/R ratio Z% HV/LV 7.5 33 +5.72% -17.16% 11 7.5 15 7.5 33 +5.72% -17.16% 11 7.5 17 8 33 +5.72% -17.16% 11 8 9 11.5 33 +5.72% -17.16% 6.6 11.5 24 11.5 33 +5.72% -17.16% 6.6 11.5 24 11.5 33 +5.72% -17.16% 11 11.5 24 11.5 33 +5.72% -17.16% 11 11.5 26 11.5 33 +4.5% -18% 6.6 11.5 24 12 33 +5% -15% 11.5 12 27 12 33 ±10% 11.5 12 27 12 33 ±10% 11.5 12 25 15 66 +9% -15% 11.5 15 14 15 66 +9% -15% 11.5 15 16 16 33 ±10% 11.5 16 16 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant MVA Primary kV Primary Taps Secondary kV Z% HV/LV X/R ratio 16 33 +5.72% -17.16% 11 16 30 16 33 +5.72% -17.16% 6.6 16 31 19 33 +5.72% -17.16% 11 19 37 30 33 +5.72% -17.16% 11 30 40 24 33 ±10% 6.9 24 25 30 33 +5.72% -17.16% 11 30 40 30 132 +10% -20% 11 21.3 43 30 132 +10% -20% 11 25 30 30 132 +10% -20% 11 23.5 46 40 132 +10% -20% 11 27.9 37 45 132 +10% -20% 33 11.8 18 60 132 +10% -20% 33 16.7 28 60 132 +10% -20% 33 17.7 26 60 132 +10% -20% 33 14.5 25 60 132 +10% -20% 66 11 25 60 132 +10% -20% 11/11 35.5 52 60 132 +9.3% -24% 11/11 36 75 60 132 +9.3% -24% 11/11 35.9 78 65 140 +7.5% -15% 11 12.3 28 90 132 +10% -20% 33 24.4 60 90 132 +10% -20% 66 15.1 41 Table 5.5: Impedances of two winding distribution transformers – Primary voltage <200kV Primary MVA kV 20 220 20 230 57 275 74 345 Primary Taps +12.5% -7.5% +12.5% -7.5% ±10% +14.4% -10% Secondary kV 6.9 Tertiary kV - Z% HV/LV 9.9 MVA 95 Primary kV Primary Taps Secondary kV 132 18 6.9 - 10-14 13 11.8 7.2 18.2 34 96 12 8.9 25 79.2 220 +10% -15% 11.6 11 18.9 35 120 275 +10% -15% 34.5 - 22.5 63 125 230 ±16.8% 66 - 13.1 52 125 230 not known 150 - 10-14 11 ±10% 13.5 X/R ratio 46 140 157.5 11.5 12.7 41 141 400 ±5% 15 14.7 57 151 236 ±5% 15 13.6 47 167 145 +7.5% -16.5% 15 25.7 71 180 289 ±5% 16 13.4 34 180 132 ±10% 15 13.8 40 247 432 +3.75% -16.25% 15.5 15.2 61 250 300 +11.2% -17.6% 15 28.6 70 290 420 ±10% 15 15.7 43 307 432 +3.75% -16.25% 15.5 15.3 67 346 435 +5% -15% 17.5 16.4 81 420 432 +5.55% -14.45% 22 16 87 437.8 144.1 +10.8% -21.6% 21 14.6 50 450 132 ±10% 19 14 49 600 420 ±11.25% 21 16.2 74 716 525 ±10% 19 15.7 61 721 362 +6.25% -13.75% 22 15.2 83 736 245 +7% -13% 22 15.5 73 900 525 +7% -13% 23 15.7 67 Table 5.7: Impedances of generator transformers (three-phase units) MVA/ Primary kV Primary Taps Secondary kV phase X/R ratio ±10% Z% HV/LV 266.7 Z% HV/LV X/R ratio 432/3 +6.67% -13.33% 23.5 15.8 92 266.7 432/3 +6.6% -13.4% 23.5 15.7 79 277 515/3 ±5% 22 16.9 105 375 525/3 +6.66% -13.32% 26 15 118 375 420/3 +6.66% -13.32% 26 15.1 112 Table 5.8: Impedances of generator transformers (single-phase units) MVA Primary kV Primary Taps Secondary kV Secondary Taps Tertiary kV Z% HV/LV X/R ratio 22 100 66 - 33 - - 10.7 28 55 180 275 ±15% 66 13 22.2 38 180 275 - 132 ±15% 13 15.5 255 230 +10% 16.5 - 14.8 43 240 400 - 132 +15% -5% 13 20.2 83 240 400 - 132 +15% -5% 13 20.0 51 240 400 - 132 +15% -5% 13 20.0 61 Table 5.6: Impedances of two winding distribution transformers – Primary voltage >200kV 250 400 - 132 +15% -5% 13 10-13 50 500 400 - 132 +0% -15% 22 14.3 51 750 400 - 275 - 13 12.1 90 1000 400 - 275 - 13 15.8 89 1000 400 - 275 - 33 17.0 91 333.3 500/3 230/3 - 22 18.2 101 ±10% Table 5.9: Autotransformer data © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-15 Network Protection & Automation Guide Secondary Taps R Primary kV Primary Taps Secondary kV 10 132 - 25 +10% -2.5% 7.7 14 12 132 ±5.5% 27.5 - 12.3 21 26.5 132 ±7.5% 25 - 19 63 MVA Z% HV/LV G Table 5.10: Traction supply transformer data B R X § si nh Z Y Z ¨¨ ZY © Y 2 With short lines it is usually possible to ignore the shunt admittance, which greatly simplifies calculations, but on longer lines it must be included. Another simplification that can be made is that of assuming the conductor configuration to be symmetrical. The self-impedance of each conductor becomes Zp, and the mutual impedance between conductors becomes Zm. However, for rigorous calculations a detailed treatment is necessary, with account being taken of the spacing of a conductor in relation to its neighbour and earth. 5.19 CALCULATION OF SERIES IMPEDANCE The self impedance of a conductor with an earth return and the mutual impedance between two parallel conductors with a common earth return are given by the Carson equations: Zn D 0.000988 f  j 0.0029 f log10 e D De dc · ¸¸ ¹ § t anh Z Y 2 · ¨¨ ¸ Z Y 2 ¸¹ © A transmission circuit may be represented by an equivalent S or T network using lumped constants as shown in Figure 5.15. Z is the total series impedance (R+jX)L and Y is the total shunt admittance (G+jB)L, where L is the circuit length. The terms inside the brackets in Figure 5.15 are correction factors that allow for the fact that in the actual circuit the parameters are distributed over the whole length of the circuit and not lumped, as in the equivalent circuits. R  0.000988 f  j 0.0029 f log10 B (a) Actual transmission circuit In this section a description of common overhead lines and cable systems is given, together with tables of their important characteristics. The formulae for calculating the characteristics are developed to give a basic idea of the factors involved, and to enable calculations to be made for systems other than those tabulated. Zp G Series impedance Z = R + jX per unit length Shunt admittance Y = G + jB per unit length 5.18 OVERHEAD LINES AND CABLES Equation 5.10 X X/R ratio Y 2 (b) Z § t anh Z Y 2 · ¨ ¸ 2 ¨© Z Y 2 ¸¹ § t anh Z Y 2 · ¨¨ ¸ Z Y 2 ¸¹ © equivalent Z § t anh Z Y 2 · ¨ ¸ 2 ¨© Z Y 2 ¸¹ § si nh Z Y · Y ¨¨ ¸¸ ZY © ¹ (c) T equivalent Note: Z and Y in (b) and (c) are the total series impedance and shunt admittance respectively. Z=(R+jX)L and Y=(G+jB)L where L is the circuit length si nh Z Y ZY 1 Z Y Z 2Y 2 Z 3Y 3    ... 6 120 5040 t anh Z Y ZY 1 Z Y Z 2Y 2 1 7Z 3Y 3    ... 12 120 20160 Figure 5.15: Transmission circuit equivalents where: R = conductor ac resistance (ohms/km) dc = geometric mean radius of a single conductor D = spacing between the parallel conductors f = system frequency De = equivalent spacing of the earth return path = 216 U f where U is earth resistivity (ohms/cm3) Equation 5.10 gives the impedances in ohms/km. The last terms in Equation 5.10 are very similar to the classical inductance formulae for long straight conductors. 5-16 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant The geometric means radius (GMR) of a conductor is an equivalent radius that allows the inductance formula to be reduced to a single term. It arises because the inductance of a solid conductor is a function of the internal flux linkages in addition to those external to it. If the original conductor can be replaced by an equivalent that is a hollow cylinder with infinitesimally thin walls, the current is confined to the surface of the conductor, and there can be no internal flux. The geometric mean radius is the radius of the equivalent conductor. If the original conductor is a solid cylinder having a radius r its equivalent has a radius of 0.779r. It can be shown that the sequence impedances for a symmetrical three-phase circuit are: Z p  Zm Z1 Z2 Z0 Z p  2Z m Equation 5.11 5.20 CALCULATION OF SHUNT IMPEDANCE It can be shown that the potential of a conductor a above ground due to its own charge qa and a charge -qa on its image is: Va 2qa log e Equation 5.14 where: h is the height above ground of the conductor r is the radius of the conductor, as shown in Figure 5.16 Similarly, it can be shown that the potential of a conductor a due to a charge qb on a neighbouring conductor b and the charge -qb on its image is: Va ' 2qb log e where: Zp and Zm are given by Equation 5.10. Substituting Equation 5.10 in Equation 5.11 gives: R  j 0.0029 f log10 D dc Z1 Z2 Z0 R  0.00296 f  j 0.00869 f log10 dcD where D is the spacing between conductors a and b and D’ is the spacing between conductor b and the image of conductor a as shown in Figure 5.16. D In the formula for Z0 the expression mean radius of the conductor group. 2 Conductor radius r dcD is the geometric 2 h Typically circuits are not symmetrical. In this case symmetry can be maintained by transposing the conductors so that each conductor is in each phase position for one third of the circuit length. If A, B and C are the spacings between conductors bc, ca and ab then D in the above equations becomes the geometric mean distance between conductors, equal to 3 b a Equation 5.12 3 D' D Equation 5.15 De 3 2h r D' Earth ABC . Dc Writing 3 dcD 2 , the sequence impedances in h ohms/km at 50Hz become: Z1 Z0 Equation 5.13 ABC dc D ( R  0.148)  j 0.434 log10 e Dc Z2 R  j 0.145 log10 3 a' Figure 5.16: Geometry of two parallel conductors a and b and the image of a (a') Since the capacitance C=q/V and the capacitive reactance Xc=1/ Z C, it follows that the self and mutual capacitive reactance of the conductor system in Figure 5.16 can be © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-17 Network Protection & Automation Guide obtained directly from Equation 5.14 and Equation 5.15. Further, as leakage can usually be neglected, the self and mutual shunt impedances Z’p and Z’m in megohm-km at a system frequency of 50Hz are: Z' p Z'm 2h r D'  j 0.132 log10 D  j 0.132 log10 Equation 5.16 Where the distances above ground are great in relation to the conductor spacing, which is the case with overhead lines. From Equation 5.11, the sequence impedances of a symmetrical three-phase circuit are:  j 0.132 log10 Z1 Z2 Z0  j 0.396 log10 D r D' 3 rD 2 Equation 5.17 The logarithmic terms in Equation 5.17 are similar to those in Equation 5.12 except that r is the actual radius of the conductors and D’ is the spacing between the conductors and their images. Where the conductors are transposed and not symmetrically spaced, Equation 5.17 can be rewritten using the geometric mean distance between conductors 3 ABC , giving the distance of each conductor above ground, ha hb hc as follows: ABC r 8ha hb hc  j 0.132 log10 Z1 Z2 Z0  j 0.132 log10 3 r 3 A2 B 2 C 2 Equation 5.18 5.21 OVERHEAD LINE CIRCUITS WITH OR WITHOUT EARTH WIRES Typical configurations of overhead line circuits are given in Figure 5.18. Tower heights are not given as they vary considerably according to the design span and nature of the ground. As indicated in some of the tower outlines, some tower designs are designed with a number of base extensions for this purpose. Figure 5.17 shows a typical tower. Figure 5.17: Double circuit 132kV overhead line tower 5-18 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant Figure 5.18: Typical overhead line tower outlines © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-19 Network Protection & Automation Guide Figure 5.19: Typical overhead line tower outlines 5-20 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant In some cases the phase conductors are not symmetrically disposed to each other and therefore, as previously indicated, electrostatic and electromagnetic unbalance result, which can be largely eliminated by transposition. Modern practice is to build overhead lines without transposition towers to reduce costs; this must be taken into account in rigorous calculations of the unbalances. In other cases, lines are formed of bundled conductors, that is conductors formed of two, three or four separate conductors. This arrangement minimises losses when voltages of 220kV and above are involved. From Equation 5.19 it can be seen that: The line configuration and conductor spacings are influenced, not only by voltage, but also by many other factors including type of insulators, type of support, span length, conductor sag and the nature of terrain and external climatic loadings. Therefore there can be large variations in spacings between different line designs for the same voltage level, so those depicted in Figure 5.17 are only typical examples. Equation 5.20 When calculating the phase self and mutual impedances, Equation 5.10 and Equation 5.16 may be used. However, in this case Zp is calculated for each conductor and Zm for each pair of conductors. This section is not intended to give a detailed analysis but rather to show the general method of formulating the equations, taking the calculation of series impedance as an example and assuming a single circuit line with a single earth wire. The phase voltage drops Va Vb Vc of a single circuit line with a single earth wire due to currents Ia Ib Ic flowing in the phases and Ie in the earth wire are:  Ie Z Z Z ea I a  eb I b  ec I c Z ee Z ee Z ee Making use of this relation, the self and mutual impedances of the phase conductors can be modified using the following formula: Z nm  Z ne Z me Z ee J aa Z aa  Z 2 ae Z ee J ab Z ab  Z ae Z be Z ee J nm For example: and so on. Equation 5.19 can be simplified while still accounting for the effect of the earth wire. This is done by deleting the fourth row and fourth column and substituting Jaa for Zaa, Jab for Zab, and so on, calculated using Equation 5.20. The single circuit line with a single earth wire can therefore be replaced by an equivalent single circuit line having phase self and mutual impedances Jaa, Jab and so on. It can be shown from the symmetrical component theory given in Chapter 4 that the sequence voltage drops of a general three-phase circuit are: Va Z aa I a  Z ab I b  Z ac I c  Z ae I e Vb Z ba I a  Z bb I b  Z bc I c  Z be I e V0 Z 00 I 0  Z 01 I1  Z 02 I 2 Vc Z ca I a  Z cb I b  Z cc I c  Z ce I e V1 Z10 I 0  Z11 I1  Z12 I 2 V2 Z 20 I 0  Z 21 I1  Z 22 I 2 0 Z ea I a  Z eb I b  Z ec I c  Z ee I e Equation 5.19 Equation 5.21 where: And, from Equation 5.19 modified as indicated above and Equation 5.21, the sequence impedances are: Z aa R  0.000988 f  j 0.0029 f log10 Z ab 0.000988 f  j 0.0029 f log10 De dc De D and so on. The equation required for the calculation of shunt voltage drops is identical to Equation 5.19 in form, except that primes must be included, the impedances being derived from Equation 5.16. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-21 Network Protection & Automation Guide Z 00 Z11 Z12 Z 21 Z 20 Z10 1 2 Sequence impedance ( J aa  J bb  J cc )  ( J ab  J bc  J ac ) 3 3 Z00 = (Z0'0') 1 1 Z 22 ( J aa  J bb  J cc )  ( J ab  J bc  J ac ) Z11 = Z22 = (Z1'1') 3 3 (Z0'0 = Z00') 1 2 ( J aa  a 2 J bb  aJ cc )  ( aJ ab  a 2 J ac  J bc ) Z01 = Z20 = (Z0'1' = Z2'0') 3 3 Z02 = Z10 = (Z0'2' = Z1'0') 1 2 ( J aa  aJ bb  a 2 J cc )  ( a 2 J ab  aJ ac  J bc ) Z12 = (Z1'2') 3 3 Z21 = (Z2'1') 1 1 Z 01 ( J aa  a 2 J bb  aJ cc )  ( aJ ab  a 2 J ac  J bc ) (Z11'=Z1'1 = Z22' = Z2'2) 3 3 1 1 (Z = Z = Z = Z ) Z 02 ( J aa  aJ bb  a 2 J cc )  ( a2 J ab  aJ ac  J bc ) 02' 0'2 1'0 10' 3 3 (Z02' = Z0'2 = Z1'0 = Z10' Equation 5.22 The development of these equations for double circuit lines with two earth wires is similar except that more terms are involved. The sequence mutual impedances are very small and can usually be neglected; this also applies for double circuit lines except for the mutual impedance between the zero sequence circuits, namely Z00’ = Z0’0 . Table 5.11 and Table 5.12 give typical values of all sequence self and mutual impedances some single and double circuit lines with earth wires. All conductors are 400mm2 ACSR, except for the 132kV double circuit example where they are 200mm2. Sequence impedance 132kV Single circuit line (400 mm2) 1.0782 ‘73°54’ 0.8227 ‘70°36’ Z11 = Z22 = (Z1'1') 0.3947 ‘78°54’ 0.3712 ‘75°57’ (Z0'0 = Z00') - - Z01 = Z20 = (Z0'1' = Z2'0') 0.0116 ‘-166°52’ 0.0094 ‘-39°28’ Z02 = Z10 = (Z0'2' = Z1'0') 0.0185 ‘ 5°8’ 0.0153 ‘28°53’ Z12 = (Z1'2') 0.0255 ‘-40°9’ 0.0275 ‘147°26’ Z21 = (Z2'1') 0.0256 ‘-139°1’ 0.0275 ‘27°29’ (Z11'=Z1'1 = Z22' = Z2'2) - - (Z02' = Z0'2 = Z1'0 = Z10') - - (Z02' = Z0'2 = Z1'0 = Z10' - - (Z1'2 = Z12') - - (Z21' = Z2'1) - - 275kV Double circuit line (400 mm2) 1.1838 ‘71°6’ 0.9520 ‘76°46’ 0.4433 ‘66°19’ 0.3354 ‘74°35’ 0.6334 ‘71°2’ 0.5219 ‘75°43’ 0.0257 ‘-63°25’ 0.0241 ‘-72°14’ 0.0197 ‘-94°58’ 0.0217 ‘-100°20’ 0.0276 ‘161°17’ 0.0281 ‘149°46’ 0.0277 ‘37°13’ 0.0282 ‘29°6’ 0.0114 ‘88°6’ 0.0129 ‘88°44’ 0.0140 ‘-93°44’ 0.0185 ‘-91°16’ 0.0150 ‘-44°11’ 0.0173 ‘-77°2’ (Z1'2 = Z12') 0.0103 ‘145°10’ 0.0101 ‘149°20’ (Z21' = Z2'1) 0.0106 ‘30°56’ 0.0102 ‘27°31’ Table 5.12: Sequence self and mutual impedances for various lines 5.22 OHL EQUIVALENT CIRCUITS Consider an earthed, infinite busbar source behind a length of transmission line as shown in Figure 5.20(a). An earth fault involving phase A is assumed to occur at F. If the driving voltage is E and the fault current is Ia then the earth fault impedance is Ze. From symmetrical component theory (see Chapter 4): 380kV Single circuit line (400 mm2) Z00 = (Z0'0') 132kV Double circuit line (200 mm2) Ia 3E Z1  Z 2  Z 0 Ze 2Z1  Z 0 3 thus Equation 5.23 since, as shown, Z1=Z2 for a transmission circuit. From Equation 5.11, Z1=Zp-Zm and Zo=Zp+2Zm. Thus, substituting these values in Equation 5.23 gives Ze=Zp. This relation is physically valid because Zp is the self-impedance of a single conductor with an earth return. Similarly, for a phase fault between phases B and C at F: Ib Ic 3E 2Z1 Table 5.11: Sequence self and mutual impedances for various lines where 3E is the voltage between phases and 2Z1 is the impedance of the fault loop. 5-22 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant F Source Line C B A E (a) Actual circuit S 3E Ic Z1 Ib Z1 Ia Z1 Z1 Z2 2 · § X ¨ Rc  Rs 2 cs 2 ¸  ¨ Rs  X s ¸¹ © 2 · § X cs ¸ ¨ j¨ X c  X s 2 2 ¸ R X  s s ¹ © Equation 5.24 F C B A (Z0 - Z1)/3 E errors. However, the formulae must be modified by the inclusion of empirical factors to take account of sheath and screen effects. A useful general reference on cable formulae is given in reference [5.4]; more detailed information on particular types of cables should be obtained direct from the manufacturers. The equivalent circuit for determining the positive and negative sequence series impedances of a cable is shown in Figure 5.21. From this circuit it can be shown that: E (b) Equivalent circuit Figure 5.20: Three-phase equivalent of a transmission circuit Making use of the above relations, a transmission circuit may be represented, generally without any loss, by the equivalent of Figure 5.20(b), where Z1 is the phase impedance to the fault and (Z0-Z1)/3 is the impedance of the earth path, there being no mutual impedance between the phases or between phase and earth. The equivalent is valid for single and double circuit lines except that for double circuit lines there is zero sequence mutual impedance, hence Z0=Z00-Z0’0. The equivalent circuit of Figure 5.20(b) is valuable in distance relay applications because the phase and earth fault relays are set to measure Z1 and are compensated for the earth return impedance (Z0-Z1)/3. It is customary to quote the impedances of a transmission circuit in terms of Z1 and the ratio Z0/Z1, since in this form they are most directly useful. By definition, the positive sequence impedance Z1 is a function of the conductor spacing and radius, whereas the Z0/Z1 ratio is dependent mainly on the level of earth resistivity U . Further details may be found in Chapter 12. where Rc and Rs are the core and sheath (screen) resistances per unit length, Xc and Xs core and sheath (screen) reactances per unit length and Xcs the mutual reactance between core and sheath (screen) per unit length. Xcs is generally equal to Xs . The zero sequence series impedances are obtained directly using Equation 5.10 and account can be taken of the sheath in the same way as an earth wire in the case of an overhead line. The shunt capacitances of a sheathed cable can be calculated from the simple formula: C § ¨ 1 0.0241H ¨ ¨ log d  2T ¨ d © · ¸ ¸ PF / km ¸ ¸ ¹ Equation 5.25 where d is the overall diameter for a round conductor, T core insulation thickness and H permittivity of dielectric. When the conductors are oval or shaped an equivalent diameter d’ may be used where d’=(1/) x periphery of conductor. No simple formula exists for belted or unscreened cables, but an empirical formula that gives reasonable results is: C 0.0555H PF / km G Equation 5.26 where G is a geometric factor which is a function of core and belt insulation thickness and overall conductor diameter. 5.23 CABLE CIRCUITS The basic formulae for calculating the series and shunt impedances of a transmission circuit, Equation 5.10 and Equation 5.16 may be applied for evaluating cable parameters; since the conductor configuration is normally symmetrical GMD and GMR values can be used without risk of appreciable © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-23 Network Protection & Automation Guide Sheath circuit (s) Number of Layers Core circuit (c) Ic Xcs per unit length Number of Al Strands GMR 4 76 0.793r 4 84 0.801r * - Indicative values only, since GMR for single layer conductors is affected by cyclic magnetic flux, which depends on various factors. Is Table 5.14: GMR for aluminium conductor steel reinforced (ACSR) (r = conductor radius) Rs, Xs per unit length V Sectional area Stranding (mm²) Rc , Xc per unit length V is voltage per unit length Figure 5.21: Equivalent circuit for determining positive or negative sequence impedance of cables 5.24 OVERHEAD LINE AND CABLE DATA The following tables show typical data on overhead lines and cables that can be used with the equations in this text. The data shown is only a guide and where the results of calculations are important, data should be sourced directly from a manufacturer or supplier. Number of Strands GMR Wire Diameter (mm) Overall Diameter (mm) RDC (20°C) (Ohm/km) 10.6 7 1.38 4.17 1.734 21.2 7 1.96 5.89 0.865 26.7 7 2.20 6.60 0.686 33.6 7 7.00 7.42 0.544 42.4 7 2.77 8.33 0.431 53.5 7 3.12 9.35 0.342 67.4 7 3.50 10.52 0.271 85.0 7 3.93 11.79 0.215 107.2 7 4.42 13.26 0.171 126.6 19 2.91 14.58 0.144 152.0 19 3.19 15.98 0.120 177.3 19 3.45 17.25 0.103 202.7 19 3.69 18.44 0.090 7 0.726r 228.0 37 2.80 19.61 0.080 19 0.758r 253.3 37 2.95 20.65 0.072 37 0.768r 278.7 37 3.10 21.67 0.066 61 0.772r 304.3 37 3.23 22.63 0.060 91 0.774r 329.3 61 2.62 23.60 0.056 127 0.776r 354.7 61 2.72 24.49 0.052 169 0.776r 380.0 61 2.82 25.35 0.048 Solid 0.779r 405.3 61 2.91 26.19 0.045 456.0 61 3.09 27.79 0.040 506.7 61 3.25 29.26 0.036 Table 5.13: GMR for stranded copper, aluminium and aluminium alloy conductors (r = conductor radius) Number of Layers 1 Number of Al Strands 6 GMR 0.5r* 1 12 0.75r* 2 18 0.776r 2 24 0.803r 2 26 0.812r 2 30 0.826r 2 32 0.833r 3 36 0.778r 3 45 0.794r 3 48 0.799r 3 54 0.81r 3 66 0.827r 4 72 0.789r 5-24 Table 5.15: Overhead line conductor - hard drawn copper ASTM Standards Sectional area Stranding (mm²) Wire Diameter (mm) Overall Diameter (mm) RDC (20°C) (Ohm/km) 11.0 1 3.73 3.25 1.617 13.0 1 4.06 4.06 1.365 14.0 1 4.22 4.22 1.269 14.5 7 1.63 4.88 1.231 16.1 1 4.52 4.52 1.103 18.9 1 4.90 4.90 0.938 23.4 1 5.46 5.46 0.756 32.2 1 6.40 6.40 0.549 38.4 7 2.64 7.92 0.466 47.7 7 2.95 8.84 0.375 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant Sectional area Stranding (mm²) Wire Diameter (mm) Overall Diameter (mm) RDC (20°C) (Ohm/km) Stranding and wire diameter (mm) Designation 65.6 7 3.45 10.36 0.273 70.1 1 9.45 9.45 0.252 Gopher 97.7 7 4.22 12.65 0.183 Weasel Aluminium 6 Steel Sectional area (mm2) Aluminium 2.4 26.2 Steel 4.4 Approximate overall diameter (mm) Total area (mm2) 30.6 7.08 RDC at 20 °C (ohm/km) 2.36 1 1.093 6 2.59 1 2.6 31.6 5.3 36.9 7.77 0.908 6 3 1 3 42.4 7.1 49.5 9 0.676 129.5 19 2.95 14.73 0.139 Ferret 132.1 7 4.90 14.71 0.135 Rabbit 6 3.35 1 3.4 52.9 8.8 61.7 10.05 0.542 Horse 12 2.79 7 2.8 73.4 42.8 116.2 13.95 0.393 164.0 7 5.46 16.38 0.109 165.2 19 3.33 16.64 0.109 Table 5.16: Overhead line conductor - hard drawn copper BS Standards Stranding and wire diameter (mm) Designation Sparrow Aluminium 6 2.67 Steel 1 Sectional area (mm2) Aluminium 2.7 33.6 Steel 5.6 Approximate overall diameter (mm) Total area (mm2) 39.2 8.01 RDC at 20 °C (ohm/km) 194.9 18.13 0.182 8.8 167.5 16.75 0.181 0.157 Lynx 30 2.79 7 2.8 183.4 42.8 226.2 19.53 Caracal 18 3.61 1 3.6 184.2 10.2 194.5 18.05 0.156 Jaguar 18 3.86 1 3.9 210.6 11.7 222.3 19.3 0.137 261.5 21 0.136 28.62 0.067 9 0.677 10.11 0.536 0.426 Quail 6 3.78 1 3.8 67.4 11.2 78.6 11.34 Pigeon 6 4.25 1 4.3 85.0 14.2 99.2 12.75 0.337 Penguin 6 4.77 1 4.8 107.2 17.9 125.1 14.31 0.268 Partridge 26 2.57 7 2 135.2 22.0 157.2 16.28 0.214 Ostrich 26 2.73 7 2.2 152.0 26.9 178.9 17.28 0.191 Merlin 18 3.47 1 3.5 170.5 9.5 179.9 17.35 0.169 Lark 30 2.92 7 2.9 201.4 46.9 248.3 20.44 0.144 Hawk 26 3.44 7 2.7 241.7 39.2 280.9 21.79 0.120 0.103 Teal 30 3.61 19 2.2 306.6 69.6 376.2 25.24 0.095 Swift 36 3.38 1 3.4 322.3 9.0 331.2 23.62 0.089 Tern 45 3.38 7 2.3 402.8 27.8 430.7 27.03 0.072 Canary 54 3.28 7 3.3 456.1 59.1 515.2 29.52 0.064 Curlew 54 3.52 7 3.5 523.7 68.1 591.8 31.68 0.055 Finch 54 3.65 19 2.3 565.0 78.3 643.3 33.35 0.051 Bittern 45 4.27 7 2.9 644.5 44.7 689.2 34.17 0.045 Falcon 54 4.36 19 2.6 805.7 102.4 908.1 39.26 0.036 44.07 36.9 3.4 158.7 484.5 62.4 1147.5 2.6 158.1 1 49.5 49.5 47.5 7 3.35 55.6 7.1 2.9 1100.0 2.59 18 212.1 8.9 7 30 Dingo 3 42.4 4.41 Wolf 3.2 428.9 3 72 0.220 7 3.4 53.5 Kiwi 0.273 16.52 7 1 23.55 14.15 161.9 3 1 327.9 118.5 30.6 3.18 3 45.9 13.6 2.4 131.2 30 3.37 2.9 282.0 1.6 105.0 7 54 6 7 7 2.36 Zebra 6 3.72 4.72 30 Panther Raven 26 6 Tiger 0.854 Robin Dove Dog 0.027 Table 5.17: Overhead line conductor data - aluminium conductors steel reinforced (ACSR), to ASTM B232 Table 5.18: Overhead line conductor data - aluminium conductors steel reinforced (ACSR), to BS215.2 Stranding and wire diameter (mm) Designation Aluminium Steel Sectional area (mm2) Aluminium Steel Total area (mm2) Approximate overall diameter (mm) RDC at 20 °C (ohm/km) 35/6 6 2.7 1 2.7 34.4 5.7 40.1 8.1 0.834 44/32 14 2 7 2.4 44.0 31.7 75.6 11.2 0.652 50/8 6 3.2 1 3.2 48.3 8.0 56.3 9.6 0.594 70/12 26 1.85 7 1.4 69.9 11.4 81.3 11.7 0.413 95/15 26 2.15 7 1.7 94.4 15.3 109.7 13.6 0.305 95/55 12 3.2 7 3.2 96.5 56.3 152.8 16 0.299 120/70 12 3.6 7 3.6 122.1 71.3 193.4 18 0.236 150/25 26 2.7 7 2.1 148.9 24.2 173.1 17.1 0.194 170/40 30 2.7 7 2.7 171.8 40.1 211.8 18.9 0.168 185/30 26 3 7 2.3 183.8 29.8 213.6 19 0.157 210/50 30 3 7 3 212.1 49.5 261.5 21 0.136 265/35 24 3.74 7 2.5 263.7 34.1 297.7 22.4 0.109 305/40 54 2.68 7 2.7 304.6 39.5 344.1 24.1 0.095 380/50 54 3 7 3 381.7 49.5 431.2 27 0.076 550/70 54 3.6 7 3.6 549.7 71.3 620.9 32.4 0.052 0.051 560/50 48 3.86 7 3 561.7 49.5 611.2 32.2 650/45 45 4.3 7 2.9 653.5 45.3 698.8 34.4 0.044 1045/45 72 4.3 7 2.9 1045.6 45.3 1090.9 43 0.028 Table 5.19: Overhead line conductor data - aluminium conductors steel reinforced (ACSR), to DIN48204 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-25 Network Protection & Automation Guide Designation CANNA 59.7 Stranding and wire diameter (mm) Aluminium 12 2 Steel 7 2 Sectional area (mm2) Aluminium 37.7 Steel 22.0 Total area (mm2) 59.7 Approximate overall diameter (mm) 10 RDC at 20 °C (ohm/km) 0.765 CANNA 75.5 12 2.25 7 2.3 47.7 27.8 75.5 11.25 0.604 CANNA 93.3 12 2.5 7 2.5 58.9 34.4 93.3 12.5 0.489 CANNA 116.2 30 2 7 2 22.0 116.2 14 0.306 CROCUS 116.2 CANNA 147.1 30 2 7 94.2 2 94.2 22.0 116.2 14 0.306 30 2.25 7 2.3 119.3 27.8 147.1 15.75 Sectional area (mm²) Overall diameter (mm) RDC at 20°C (Ohm/k m) ASTM B-399 - 19 4.12 253.3 20.6 0.132 ASTM B-399 - 37 3.096 278.5 21.7 0.120 ASTM B-399 - 37 3.233 303.7 22.6 0.110 ASTM B-399 - 37 3.366 329.2 23.6 0.102 ASTM B-399 - 37 3.493 354.6 24.5 0.094 ASTM B-399 - 37 3.617 380.2 25.3 0.088 ASTM B-399 - 37 3.734 405.2 26.1 0.083 ASTM B-399 - 37 3.962 456.2 27.7 0.073 ASTM B-399 - 37 4.176 506.8 29.2 0.066 0.243 30 2.5 7 2.5 147.3 34.4 181.6 17.5 0.197 CROCUS 228 30 2.8 7 2.8 184.7 43.1 227.8 19.6 0.157 36 2.8 19 2.3 221.7 75.5 297.2 22.45 30 3.15 7 3.2 233.8 54.6 288.3 22.05 0.124 CROCUS 288 30 3.15 7 3.2 233.8 54.6 288.3 22.05 0.124 CROCUS 412 32 3.6 19 2.4 325.7 86.0 411.7 26.4 0.089 CROCUS 612 66 3.13 19 2.7 507.8 104.8 612.6 32.03 0.057 66 3.72 19 3.2 717.3 148.1 865.4 Standard 0.131 CANNA 288 CROCUS 865 Designation Wire diameter (mm) Table 5.21: Overhead line conductor data - aluminium alloy (ASTM) CROCUS 181.6 CROCUS 297 Standard No. of Al Strands 38.01 0.040 Table 5.20: Overhead line conductor data - aluminium conductors steel reinforced (ACSR), to NF C34-120 Standard No. of Al Strands Designation ASTM B-397 Kench 7 Wire diameter (mm) 2.67 Sectional area (mm²) 39.2 Overall diameter (mm) 8.0 No. of Al Strands Designation Wire diameter (mm) Sectional area (mm²) Overall diameter (mm) RDC at 20°C (Ohm/k m) BS 3242 Box 7 1.85 18.8 5.6 1.750 BS 3242 Acacia 7 2.08 23.8 6.2 1.384 BS 3242 Almond 7 2.34 30.1 7.0 1.094 BS 3242 Cedar 7 2.54 35.5 7.6 0.928 BS 3242 Fir 7 2.95 47.8 8.9 0.688 BS 3242 Hazel 7 3.3 59.9 9.9 0.550 BS 3242 Pine 7 3.61 71.6 10.8 0.460 BS 3242 Willow 7 4.04 89.7 12.1 0.367 BS 3242 - 7 4.19 96.5 12.6 0.341 BS 3242 - 7 4.45 108.9 13.4 0.302 BS 3242 Oak 7 4.65 118.9 14.0 0.277 BS 3242 Mullberry 19 3.18 150.9 15.9 0.219 BS 3242 Ash 19 3.48 180.7 17.4 0.183 RDC at 20°C (Ohm/k m) BS 3242 Elm 19 3.76 211.0 18.8 0.157 BS 3242 Poplar 37 2.87 239.4 20.1 0.139 BS 3242 Sycamore 37 3.23 303.2 22.6 0.109 0.838 BS 3242 Upas 37 3.53 362.1 24.7 0.092 ASTM B-397 Kibe 7 3.37 62.4 10.1 0.526 BS 3242 Yew 37 4.06 479.0 28.4 0.069 ASTM B-397 Kayak 7 3.78 78.6 11.4 0.418 BS 3242 Totara 37 4.14 498.1 29.0 0.067 ASTM B-397 Kopeck 7 4.25 99.3 12.8 0.331 BS 3242 Rubus 61 3.5 586.9 31.5 0.057 ASTM B-397 Kittle 7 4.77 125.1 14.3 0.262 BS 3242 Araucaria 61 4.14 821.1 28.4 0.040 ASTM B-397 Radian 19 3.66 199.9 18.3 0.164 ASTM B-397 Rede 19 3.78 212.6 18.9 0.155 ASTM B-397 Ragout 19 3.98 236.4 19.9 0.140 ASTM B-397 Rex 19 4.14 255.8 19.9 0.129 0.116 ASTM B-397 Remex 19 4.36 283.7 21.8 ASTM B-397 Ruble 19 4.46 296.8 22.4 0.111 ASTM B-397 Rune 19 4.7 330.6 23.6 0.100 ASTM B-397 Spar 37 3.6 376.6 25.2 0.087 ASTM B-397 Solar 37 4.02 469.6 28.2 0.070 ASTM B-399 - 19 3.686 202.7 18.4 0.165 ASTM B-399 - 19 3.909 228.0 19.6 0.147 5-26 Table 5.22: Overhead line conductor data - aluminium alloy (BS) © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant Standard Designation CSA C49.1M87 10 CSA C49.1M87 16 CSA C49.1M87 CSA C49.1M87 No. of Al Strands 25 40 7 7 7 7 Wire diameter (mm) 1.45 1.83 2.29 2.89 Sectional area (mm²) 11.5 18.4 28.8 46.0 Overall diameter (mm) 4.3 5.5 6.9 8.7 RDC at 20°C (Ohm/k m) 2.863 1.788 1.142 0.716 CSA C49.1M87 63 7 3.63 72.5 10.9 0.454 CSA C49.1M87 100 19 2.78 115.1 13.9 0.287 CSA C49.1M87 125 19 3.1 143.9 15.5 0.230 CSA C49.1M87 160 19 3.51 184.2 17.6 0.180 CSA C49.1M87 200 19 3.93 230.2 19.6 0.144 CSA C49.1M87 250 19 4.39 287.7 22.0 0.115 CSA C49.1M87 315 37 3.53 362.1 24.7 0.092 CSA C49.1M87 400 37 3.98 460.4 27.9 0.072 Standard Designation 37 4.22 517.9 29.6 0.064 CSA C49.1M87 500 37 4.45 575.5 31.2 0.058 CSA C49.1M87 560 37 4.71 644.5 33.0 0.051 CSA C49.1M87 630 61 3.89 725.0 35.0 0.046 CSA C49.1M87 710 61 4.13 817.2 37.2 0.041 CSA C49.1M87 800 61 4.38 920.8 39.5 0.036 CSA C49.1M87 900 61 4.65 1035.8 41.9 0.032 CSA C49.1M87 1000 CSA C49.1M87 1120 91 4.25 1289.1 46.7 0.026 CSA C49.1M87 1250 91 4.49 1438.7 49.4 0.023 CSA C49.1M87 1400 91 4.75 1611.3 52.2 0.021 CSA C49.1M87 1500 91 4.91 1726.4 54.1 0.019 91 4.01 1150.9 44.1 0.029 Overall diameter (mm) RDC at 20°C (Ohm/k m) 16 7 1.7 15.9 5.1 2.091 DIN 48201 25 7 2.1 24.3 6.3 1.370 DIN 48201 35 7 2.5 34.4 7.5 0.967 DIN 48201 50 19 1.8 48.4 9.0 0.690 DIN 48201 50 7 3 49.5 9.0 0.672 DIN 48201 70 19 2.1 65.8 10.5 0.507 DIN 48201 95 19 2.5 93.3 12.5 0.358 DIN 48201 120 19 2.8 117.0 14.0 0.285 DIN 48201 150 37 2.25 147.1 15.7 0.228 DIN 48201 185 37 2.5 181.6 17.5 0.184 DIN 48201 240 61 2.25 242.5 20.2 0.138 DIN 48201 300 61 2.5 299.4 22.5 0.112 DIN 48201 400 61 2.89 400.1 26.0 0.084 DIN 48201 500 61 3.23 499.8 29.1 0.067 Table 5.24: Overhead line conductor data - aluminium alloy (DIN) Wire diameter (mm) No. of Al Strands Designation NF C34-125 ASTER 22 450 Sectional area (mm²) DIN 48201 Standard CSA C49.1M87 Wire diameter (mm) No. of Al Strands 7 2 Sectional area (mm²) 22.0 Overall diameter (mm) 6.0 RDC at 20°C (Ohm/k m) 1.497 NF C34-125 ASTER 34-4 7 2.5 34.4 7.5 0.958 NF C34-125 ASTER 54-6 7 3.15 54.6 9.5 0.604 NF C34-125 ASTER 75-5 19 2.25 75.5 11.3 0.438 NF C34-125 ASTER 93,3 19 2.5 93.3 12.5 0.355 NF C34-125 ASTER 117 19 2.8 117.0 14.0 0.283 NF C34-125 ASTER 148 19 3.15 148.1 15.8 0.223 NF C34-125 ASTER 181-6 37 2.5 181.6 17.5 0.183 NF C34-125 ASTER 228 37 2.8 227.8 19.6 0.146 NF C34-125 ASTER 288 37 3.15 288.3 22.1 0.115 NF C34-125 ASTER 366 37 3.55 366.2 24.9 0.091 NF C34-125 ASTER 570 61 3.45 570.2 31.1 0.058 NF C34-125 ASTER 851 91 3.45 850.7 38.0 0.039 NF C34-125 ASTER 1144 91 4 1143.5 44.0 0.029 NF C34-125 ASTER 1600 127 4 1595.9 52.0 0.021 Table 5.25: Overhead line conductor data - aluminium alloy (NF) Table 5.23: Overhead line conductor data - aluminium alloy (CSA) © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-27 Network Protection & Automation Guide Standard Designa tion Stranding and wire diameter (mm) Alloy Steel Sectional area (mm2) Alloy Steel Total area (mm2) Approxi mate overall dia (mm) RDC at 20 °C (ohm /km) ASTM B711 26 2.62 7 2 140.2 22.9 163.1 7.08 0.240 ASTM B711 26 2.97 7 2.3 180.1 29.3 209.5 11.08 0.187 ASTM B711 30 2.76 7 2.8 179.5 41.9 221.4 12.08 0.188 ASTM B711 26 3.13 7 2.4 200.1 32.5 232.5 13.08 0.168 ASTM B711 30 3.08 7 3.1 223.5 52.2 275.7 16.08 0.151 ASTM B711 26 3.5 7 2.7 250.1 40.7 290.8 17.08 0.135 ASTM B711 26 3.7 7 2.9 279.6 45.6 325.2 19.08 0.120 ASTM B711 30 3.66 19 2.2 315.6 72.2 387.9 22.08 0.107 ASTM B711 30 3.88 19 2.3 354.7 81.0 435.7 24.08 0.095 ASTM B711 30 4.12 19 2.5 399.9 91.0 491.0 26.08 0.084 ASTM B711 54 3.26 19 2 450.7 58.5 509.2 27.08 0.075 ASTM B711 54 3.63 19 2.2 558.9 70.9 629.8 29.08 0.060 ASTM B711 54 3.85 19 2.3 628.6 79.6 708.3 30.08 0.054 ASTM B711 54 4.34 19 2.6 798.8 100.9 899.7 32.08 0.042 ASTM B711 84 4.12 19 2.5 1119.9 91.0 1210.9 35.08 0.030 ASTM B711 84 4.35 19 2.6 1248.4 101.7 1350.0 36.08 0.027 Table 5.26: Overhead line conductor data – aluminium alloy conductors, steel re-inforced (AACSR) ASTM Standard Designa tion Stranding and wire diameter (mm) Alloy Steel Sectional area (mm2) Alloy Steel Total area (mm2) Approxi mate overall dia (mm) RDC at 20 °C (ohm /km) DIN 48206 70/12 26 1.85 7 1.4 69.9 11.4 81.3 11.7 0.479 DIN 48206 95/15 26 2.15 7 1.7 94.4 15.3 109.7 13.6 0.355 DIN 48206 125/30 30 2.33 7 2.3 127.9 29.8 157.8 16.3 0.262 DIN 48206 150/25 26 2.7 7 2.1 148.9 24.2 173.1 17.1 0.225 DIN 48206 170/40 30 2.7 7 2.7 171.8 40.1 211.8 18.9 0.195 DIN 48206 185/30 26 3 7 2.3 183.8 29.8 213.6 19 0.182 DIN 48206 210/50 30 3 7 3 261.5 21 0.158 DIN 48206 230/30 24 3.5 7 2.3 230.9 29.8 260.8 21 0.145 DIN 48206 265/35 24 3.74 7 2.5 263.7 34.1 297.7 22.4 0.127 DIN 48206 305/40 54 2.68 7 2.7 304.6 39.5 344.1 24.1 0.110 DIN 48206 380/50 54 3 7 3 431.2 27 0.088 DIN 48206 450/40 48 3.45 7 2.7 448.7 39.5 488.2 28.7 0.075 DIN 48206 560/50 48 3.86 7 3 561.7 49.5 611.2 32.2 0.060 DIN 48206 680/85 54 4 19 2.4 678.6 86.0 764.5 36 0.049 212.1 49.5 381.7 49.5 Standard Designa tion Stranding and wire diameter (mm) Alloy Steel Sectional area (mm2) Alloy Steel Total area (mm2) RDC at 20 °C (ohm /km) PHLOX NF C34-125 116.2 18 2 19 2 56.5 59.7 116.2 14 0.591 PHLOX NF C34-125 147.1 18 2.25 19 2.3 71.6 75.5 147.1 15.75 0.467 PASTEL NF C34-125 147.1 30 2.25 7 2.3 119.3 27.8 147.1 15.75 0.279 PHLOX NF C34-125 181.6 18 2.5 19 2.5 88.4 93.3 181.6 17.5 0.378 PASTEL NF C34-125 181.6 30 2.5 7 2.5 147.3 34.4 181.6 17.5 0.226 PHLOX NF C34-125 228 18 2.8 19 2.8 110.8 117.0 227.8 19.6 0.300 PASTEL NF C34-125 228 30 2.8 7 2.8 184.7 43.1 19.6 0.180 PHLOX NF C34-125 288 18 3.15 19 3.2 140.3 148.1 288.3 22.05 0.238 PASTEL NF C34-125 288 30 3.15 7 3.2 233.8 54.6 288.3 22.05 0.142 PASTEL NF C34-125 299 42 2.5 19 2.5 206.2 93.3 299.4 22.45 0.162 PHLOX NF C34-125 376 24 2.8 37 2.8 147.8 227.8 375.6 26.4 0.226 227.8 Table 5.28: Overhead line conductor data – aluminium alloy conductors, steel re-inforced (AACSR) NF Table 5.27: Overhead line conductor data – aluminium alloy conductors, steel re-inforced (AACSR) DIN 5-28 Approxi mate overall dia (mm) © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant Conductor Size (mm2) 10 3.3kV 6.6kV 11kV 22kV 33kV 16 25 35 50 70 Conductor Size (mm2) 95 120 150 Series Resistance R (/km) 206 1303 825.5 595 439.9 304.9 220.4 174.5 142.3 Series Reactance X (/km) 87.7 83.6 76.7 74.8 72.5 70.2 67.5 66.6 65.7 Susceptance C (mS/km) Series Resistance R (/km) 514.2 326 206.4 148.8 110 Series Reactance X (/km) 26.2 24.3 22 21.2 Susceptance C (mS/km) Series Resistance R (/km) - 111 0.87 0.63 0.46 0.32 0.23 0.184 0.15 Series Reactance X (/km) - 9.26 0.107 0.1 0.096 0.091 0.087 0.085 0.083 Susceptance C (mS/km) Series Resistance R (/km) - - 17.69 12.75 9.42 6.53 4.71 3.74 3.04 Series Reactance X (/km) - - 2.89 2.71 Susceptance C (mS/km) Series Resistance R (/km) - - - - 4.19 2.9 Series Reactance X (/km) - - - - 1.16 1.09 1.03 0.107 0.103 Susceptance C (mS/km) 3.3kV 76.2 55.1 43.6 35.6 20.4 19.6 18.7 18.3 17.9 2.6 185 2.46 2.36 2.25 2.19 6.6kV 11kV 22kV 2.09 0.181 0.147 0.104 0.116 33kV 300 400 *630 *800 87.6 70.8 56.7 45.5 37.1 31.2 27.2 64.7 63.8 62.9 62.4 73.5 72.1 71.2 69.8 R (/km) 28.5 21.9 17.6 14.1 11.3 9.3 7.8 6.7 Series Reactance X (/km) 17.6 17.1 16.9 16.5 18.8 18.4 18 17.8 Susceptance C (mS/km) Series Resistance R (/km) 0.12 0.092 0.074 0.059 0.048 0.039 0.033 0.028 Series Reactance X (/km) 0.081 0.079 0.077 0.076 0.085 0.083 0.081 0.08 Susceptance C (mS/km) Series Resistance R (/km) 2.44 1.87 1.51 1.21 0.96 0.79 0.66 0.57 Series Reactance X (/km) 2.11 2.04 1.97 1.92 1.9 1.84 1.8 1.76 Susceptance C (mS/km) Series Resistance R (/km) 0.118 0.09 0.073 0.058 0.046 0.038 0.031 0.027 Series Reactance X (/km) 0.101 0.097 0.094 0.09 0.098 0.097 0.092 0.089 Susceptance C 0.124 (mS/km) 0.194 0.151 0.281 0.179 0.198 0.22 Series Resistance R (/km) 113.9 Series Reactance X (/km) Susceptance C (mS/km) Series Resistance 240 *500 Cables are solid type 3 core except for those marked *. Impedances are at 50Hz Cables are solid type 3 core except for those marked *. Impedances are at 50Hz Table 5.29: Characteristics of paper insulated cables, conductor size 10 to 150 mm2 Table 5.30: Characteristics of paper insulated cables, conductor size 185 to 1000 mm2 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. *1000 0.245 5-29 Network Protection & Automation Guide 3.3kV Conductor size (mm2) R /km X /km 16 1.380 0.106 25 0.870 0.100 35 0.627 0.094 50 0.463 0.091 70 0.321 0.086 95 0.232 0.084 120 0.184 0.081 150 0.150 0.079 185 0.121 0.077 240 0.093 0.076 300 0.075 0.075 400 0.060 0.075 *500 0.049 0.089 *630 0.041 0.086 *800 0.035 0.086 *1000 0.030 Voltage Level Un kV Cross Sectional 2 Area mm 22 33 Voltage Drop Loading Indicative Thermal Loading MVA MWkm MVA Um kV 30 11 Conductors per phase Surge Impedance Loading 12 24 36 0.084 3 core copper conductors, 50Hz values. 1 A 0.3 11 2.9 151 50 1 0.3 17 3.9 204 90 1 0.4 23 5.1 268 120 1 0.5 27 6.2 328 150 1 0.5 30 7.3 383 30 1 1.2 44 5.8 151 50 1 1.2 66 7.8 204 90 1 1.2 92 10.2 268 120 1 1.4 106 12.5 328 150 1 1.5 119 14.6 383 50 1 2.7 149 11.7 204 90 1 2.7 207 15.3 268 120 1 3.1 239 18.7 328 150 1 3.5 267 21.9 383 90 1 11 827 41 268 150 1 11 1068 59 383 250 1 11 1240 77 502 250 2 15 1790 153 1004 150 1 44 4070 85 370 250 1 44 4960 115 502 250 2 58 7160 230 1004 x conductor material and hence maximum temperature 400 1 56 6274 160 698 x cost of losses 400 2 73 9057 320 1395 400 1 130 15600 247 648 400 2 184 22062 494 1296 400 4 260 31200 988 2592 400 2 410 58100 850 1296 400 4 582 82200 1700 2590 550 2 482 68200 1085 1650 550 3 540 81200 1630 2475 * - single core cables in trefoil Table 5.31: 3.3 kV PVC insulated cables 66 72.5 At the conceptual design stage, initial selection of overhead line conductor size is determined by four factors: x maximum load to be carried in MVA x length of line 132 gives indicative details of the capability of various sizes of overhead lines using the above factors, for AAAC and ACSR conductor materials. It is based on commonly used standards for voltage drop and ambient temperature. Since these factors may not be appropriate for any particular project, the Table should only be used as a guide for initial sizing, with appropriately detailed calculations carried out to arrive at a final proposal. 5-30 220 380 145 245 420 Table 5.32: OHL capabilities © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant XAC at 50 Hz XAC at 50 Hz and shunt capacitance 66kV Sectional area of Al 33kV RDC (20°C) 3.3kV 6.6kV 11kV X mm² 13.3 15.3 21.2 23.9 26.2 28.3 33.6 37.7 42.4 44.0 47.7 51.2 58.9 63.1 67.4 73.4 79.2 85.0 94.4 105.0 121.6 127.9 131.2 135.2 148.9 158.7 170.5 184.2 201.4 210.6 221.7 230.9 241.7 263.7 282.0 306.6 322.3 339.3 362.6 386.0 402.8 428.9 448.7 456.1 483.4 494.4 510.5 523.7 /km 2.1586 1.8771 1.3557 1.2013 1.0930 1.0246 0.8535 0.7647 0.6768 0.6516 0.6042 0.5634 0.4894 0.4545 0.4255 0.3930 0.3622 0.3374 0.3054 0.2733 0.2371 0.2254 0.2197 0.2133 0.1937 0.1814 0.1691 0.1565 0.1438 0.1366 0.1307 0.1249 0.1193 0.1093 0.1022 0.0945 0.0895 0.0850 0.0799 0.0747 0.0719 0.0671 0.0642 0.0635 0.0599 0.0583 0.0565 0.0553 /km 0.395 0.391 0.381 0.376 0.374 0.352 0.366 0.327 0.359 0.320 0.319 0.317 0.313 0.346 0.344 0.306 0.339 0.337 0.302 0.330 0.294 0.290 0.289 0.297 0.288 0.292 0.290 0.287 0.280 0.283 0.274 0.276 0.279 0.272 0.274 0.267 0.270 0.265 0.262 0.261 0.261 0.267 0.257 0.257 0.255 0.254 0.252 0.252 /km 0.409 0.405 0.395 0.390 0.388 0.366 0.380 0.341 0.373 0.334 0.333 0.331 0.327 0.360 0.358 0.320 0.353 0.351 0.316 0.344 0.308 0.304 0.303 0.311 0.302 0.306 0.304 0.302 0.294 0.297 0.288 0.290 0.293 0.286 0.288 0.281 0.284 0.279 0.276 0.275 0.275 0.281 0.271 0.271 0.269 0.268 0.266 0.266 /km 0.420 0.415 0.405 0.401 0.398 0.377 0.390 0.351 0.383 0.344 0.344 0.341 0.337 0.371 0.369 0.330 0.363 0.361 0.327 0.355 0.318 0.314 0.313 0.322 0.312 0.316 0.314 0.312 0.304 0.308 0.298 0.300 0.303 0.296 0.298 0.291 0.294 0.289 0.286 0.285 0.285 0.291 0.281 0.281 0.279 0.279 0.277 0.277 Flat circuit 22kV /km 0.434 0.429 0.419 0.415 0.412 0.391 0.404 0.365 0.397 0.358 0.358 0.355 0.351 0.385 0.383 0.344 0.377 0.375 0.341 0.369 0.332 0.328 0.327 0.336 0.326 0.330 0.328 0.326 0.318 0.322 0.312 0.314 0.317 0.310 0.312 0.305 0.308 0.303 0.300 0.299 0.299 0.305 0.295 0.295 0.293 0.293 0.291 0.291 C X C 132kV Double vertical X C Triangle X C /km nF/km /km nF/km /km nF/km /km nF/km 0.445 8.7 0.503 7.6 0.513 7.4 0.520 7.3 0.441 8.8 0.499 7.7 0.508 7.5 0.515 7.4 0.430 9.0 0.488 7.8 0.498 7.7 0.505 7.6 0.426 9.1 0.484 7.9 0.494 7.8 0.501 7.6 0.424 9.2 0.482 8.0 0.491 7.8 0.498 7.7 0.402 9.4 0.460 8.2 0.470 8.0 0.477 7.8 0.416 9.4 0.474 8.1 0.484 7.9 0.491 7.8 0.376 9.7 0.435 8.4 0.444 8.2 0.451 8.1 0.409 9.6 0.467 8.3 0.476 8.1 0.483 7.9 0.369 9.9 0.427 8.5 0.437 8.3 0.444 8.2 0.369 9.9 0.427 8.5 0.437 8.3 0.444 8.2 0.367 10.0 0.425 8.6 0.434 8.4 0.441 8.2 0.362 10.1 0.421 8.7 0.430 8.5 0.437 8.3 0.396 9.9 0.454 8.5 0.464 8.3 0.471 8.2 0.394 10.0 0.452 8.5 0.462 8.3 0.469 8.2 0.356 10.3 0.414 8.8 0.423 8.6 0.430 8.5 0.389 10.1 0.447 8.7 0.457 8.4 0.464 8.3 0.387 10.2 0.445 8.7 0.454 8.5 0.461 8.4 0.352 10.3 0.410 8.8 0.420 8.6 0.427 8.4 0.380 10.4 0.438 8.8 0.448 8.6 0.455 8.5 0.344 10.6 0.402 9.0 0.412 8.8 0.419 8.6 0.340 10.7 0.398 9.0 0.407 8.8 0.414 8.7 0.339 10.7 0.397 9.1 0.407 8.8 0.414 8.7 0.347 10.5 0.405 9.0 0.415 8.8 0.422 8.6 0.338 10.8 0.396 9.1 0.406 8.9 0.413 8.7 0.342 10.7 0.400 9.1 0.410 8.9 0.417 8.7 0.340 10.8 0.398 9.1 0.407 8.9 0.414 8.8 0.337 10.9 0.395 9.2 0.405 9.0 0.412 8.8 0.330 11.0 0.388 9.3 0.398 9.1 0.405 8.9 0.333 11.0 0.391 9.3 0.401 9.1 0.408 8.9 0.323 11.3 0.381 9.5 0.391 9.3 0.398 9.1 0.326 11.2 0.384 9.4 0.393 9.2 0.400 9.0 0.329 11.2 0.387 9.4 0.396 9.2 0.403 9.0 0.321 11.3 0.380 9.5 0.389 9.3 0.396 9.1 0.324 11.3 0.382 9.5 0.392 9.3 0.399 9.1 0.317 11.5 0.375 9.7 0.384 9.4 0.391 9.2 0.320 11.5 0.378 9.6 0.387 9.4 0.394 9.2 0.315 11.6 0.373 9.7 0.383 9.5 0.390 9.3 0.311 11.7 0.369 9.8 0.379 9.6 0.386 9.4 0.311 11.8 0.369 9.8 0.379 9.6 0.386 9.4 0.310 11.8 0.368 9.9 0.378 9.6 0.385 9.4 0.316 11.5 0.374 9.7 0.384 9.4 0.391 9.2 0.306 11.9 0.364 10.0 0.374 9.7 0.381 9.5 0.307 12.0 0.365 10.0 0.374 9.7 0.381 9.5 0.305 12.0 0.363 10.0 0.372 9.8 0.379 9.6 0.304 12.1 0.362 10.0 0.372 9.8 0.379 9.6 0.302 12.1 0.360 10.1 0.370 9.8 0.377 9.6 0.302 12.1 0.360 10.1 0.370 9.8 0.377 9.6 Double vertical X C Double triangle X C Flat circuit X C /km nF/km /km nF/km /km nF/km 0.541 7.0 0.528 7.2 0.556 6.8 0.537 7.1 0.523 7.3 0.552 6.9 0.527 7.2 0.513 7.4 0.542 7.0 0.522 7.3 0.509 7.5 0.537 7.1 0.520 7.3 0.506 7.5 0.535 7.1 0.498 7.5 0.485 7.7 0.513 7.3 0.512 7.5 0.499 7.7 0.527 7.2 0.473 7.7 0.459 7.9 0.488 7.4 0.505 7.6 0.491 7.8 0.520 7.3 0.465 7.8 0.452 8.0 0.481 7.5 0.465 7.8 0.452 8.1 0.480 7.6 0.463 7.9 0.449 8.1 0.478 7.6 0.459 7.9 0.445 8.2 0.474 7.7 0.492 7.8 0.479 8.0 0.507 7.5 0.490 7.8 0.477 8.1 0.505 7.6 0.452 8.1 0.438 8.3 0.467 7.8 0.485 7.9 0.472 8.2 0.500 7.6 0.483 7.9 0.469 8.2 0.498 7.7 0.448 8.0 0.435 8.3 0.463 7.8 0.476 8.1 0.463 8.3 0.491 7.8 0.440 8.2 0.427 8.4 0.455 7.9 0.436 8.2 0.422 8.5 0.451 8.0 0.435 8.3 0.421 8.5 0.450 8.0 0.443 8.2 0.430 8.4 0.458 7.9 0.434 8.3 0.420 8.6 0.449 8.0 0.438 8.3 0.425 8.5 0.453 8.0 0.436 8.3 0.422 8.6 0.451 8.0 0.433 8.4 0.420 8.6 0.449 8.1 0.426 8.5 0.412 8.8 0.441 8.2 0.429 8.4 0.416 8.7 0.444 8.1 0.419 8.6 0.406 8.9 0.435 8.3 0.422 8.6 0.408 8.9 0.437 8.3 0.425 8.5 0.411 8.8 0.440 8.2 0.418 8.6 0.404 8.9 0.433 8.3 0.420 8.6 0.406 8.9 0.435 8.3 0.413 8.7 0.399 9.1 0.428 8.4 0.416 8.7 0.402 9.0 0.431 8.4 0.411 8.8 0.398 9.1 0.426 8.5 0.408 8.9 0.394 9.2 0.423 8.5 0.407 8.9 0.393 9.2 0.422 8.6 0.407 8.9 0.393 9.2 0.422 8.6 0.413 8.7 0.399 9.0 0.428 8.4 0.402 9.0 0.389 9.3 0.418 8.7 0.403 9.0 0.389 9.3 0.418 8.7 0.401 9.0 0.387 9.4 0.416 8.7 0.400 9.0 0.387 9.4 0.415 8.7 0.398 9.1 0.385 9.4 0.413 8.7 0.398 9.1 0.385 9.4 0.413 8.7 Table 5.33: Overhead line feeder circuit data, ACSR Conductors, 50Hz © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-31 Network Protection & Automation Guide XAC at 60 Hz and shunt capacitance XAC at 60 Hz . Sectional area of Al mm² 13.3 15.3 21.2 23.9 26.2 28.3 33.6 37.7 42.4 44.0 47.7 51.2 58.9 63.1 67.4 73.4 79.2 85.0 94.4 105.0 121.6 127.9 131.2 135.2 148.9 158.7 170.5 184.2 201.4 210.6 221.7 230.9 241.7 263.7 282.0 306.6 322.3 339.3 362.6 386.0 402.8 428.9 448.7 456.1 483.4 494.4 510.5 523.7 RDC (20°C) /km 2.1586 1.8771 1.3557 1.2013 1.0930 1.0246 0.8535 0.7647 0.6768 0.6516 0.6042 0.5634 0.4894 0.4545 0.4255 0.3930 0.3622 0.3374 0.3054 0.2733 0.2371 0.2254 0.2197 0.2133 0.1937 0.1814 0.1691 0.1565 0.1438 0.1366 0.1307 0.1249 0.1193 0.1093 0.1022 0.0945 0.0895 0.0850 0.0799 0.0747 0.0719 0.0671 0.0642 0.0635 0.0599 0.0583 0.0565 0.0553 RAC at 60Hz 66kV 3.3kV 6.6kV 11kV & 20° C /km 2.159 1.877 1.356 1.201 1.093 1.025 0.854 0.765 0.677 0.652 0.604 0.564 0.490 0.455 0.426 0.393 0.362 0.338 0.306 0.274 0.238 0.226 0.220 0.214 0.194 0.182 0.170 0.157 0.145 0.137 0.132 0.126 0.120 0.110 0.103 0.096 0.091 0.086 0.081 0.076 0.074 0.069 0.066 0.065 0.062 0.060 0.059 0.057 Flat circuit X X X X /km 0.474 0.469 0.457 0.452 0.449 0.423 0.439 0.392 0.431 0.384 0.383 0.380 0.375 0.416 0.413 0.367 0.407 0.404 0.363 0.396 0.353 0.348 0.347 0.357 0.346 0.351 0.348 0.345 0.336 0.340 0.328 0.331 0.335 0.326 0.329 0.320 0.324 0.318 0.314 0.313 0.313 0.320 0.308 0.305 0.306 0.305 0.303 0.303 /km 0.491 0.486 0.474 0.469 0.466 0.440 0.456 0.409 0.447 0.400 0.400 0.397 0.392 0.432 0.430 0.384 0.424 0.421 0.380 0.413 0.370 0.365 0.364 0.374 0.362 0.367 0.365 0.362 0.353 0.357 0.345 0.348 0.351 0.343 0.346 0.337 0.341 0.335 0.331 0.330 0.330 0.337 0.325 0.322 0.323 0.322 0.320 0.320 /km 0.503 0.498 0.486 0.481 0.478 0.452 0.468 0.421 0.460 0.413 0.412 0.409 0.404 0.445 0.442 0.396 0.436 0.433 0.392 0.426 0.382 0.377 0.376 0.386 0.375 0.380 0.377 0.374 0.365 0.369 0.357 0.360 0.364 0.355 0.358 0.349 0.353 0.347 0.343 0.342 0.342 0.349 0.337 0.334 0.335 0.334 0.332 0.332 /km 0.520 0.515 0.503 0.498 0.495 0.469 0.485 0.438 0.477 0.429 0.429 0.426 0.421 0.462 0.459 0.413 0.453 0.450 0.409 0.442 0.399 0.394 0.393 0.403 0.392 0.397 0.394 0.391 0.382 0.386 0.374 0.377 0.381 0.372 0.375 0.366 0.370 0.364 0.360 0.359 0.359 0.366 0.354 0.351 0.352 0.351 0.349 0.349 132kV 33kV 22kV X C X C Double vertical X C Triangle X C Double vertical X Double triangle C C X C /km nF/km /km nF/km /km nF/km /km nF/km /km nF/km /km nF/km /km nF/km 0.534 8.7 0.604 7.6 0.615 7.4 0.624 7.3 0.649 7.0 0.633 7.2 0.668 6.8 0.529 8.8 0.598 7.7 0.610 7.5 0.619 7.4 0.644 7.1 0.628 7.3 0.662 6.9 0.516 9.0 0.586 7.8 0.598 7.7 0.606 7.6 0.632 7.2 0.616 7.4 0.650 7.0 0.511 9.1 0.581 7.9 0.593 7.8 0.601 7.6 0.627 7.3 0.611 7.5 0.645 7.1 0.508 9.2 0.578 8.0 0.590 7.8 0.598 7.7 0.624 7.3 0.608 7.5 0.642 7.1 0.483 9.4 0.552 8.2 0.564 8.0 0.572 7.8 0.598 7.5 0.582 7.7 0.616 7.3 0.499 9.4 0.569 8.1 0.580 7.9 0.589 7.8 0.614 7.5 0.598 7.7 0.633 7.2 0.452 9.7 0.521 8.4 0.533 8.2 0.541 8.1 0.567 7.7 0.551 7.9 0.585 7.4 0.490 9.6 0.560 8.3 0.572 8.1 0.580 7.9 0.606 7.6 0.589 7.8 0.624 7.3 0.443 9.9 0.513 8.5 0.525 8.3 0.533 8.2 0.559 7.8 0.542 8.0 0.577 7.5 0.443 9.9 0.513 8.5 0.524 8.3 0.533 8.2 0.558 7.8 0.542 8.1 0.576 7.6 0.440 10.0 0.510 8.6 0.521 8.4 0.530 8.2 0.555 7.9 0.539 8.1 0.573 7.6 0.435 10.1 0.505 8.7 0.516 8.5 0.525 8.3 0.550 7.9 0.534 8.2 0.568 7.7 0.475 9.9 0.545 8.5 0.557 8.3 0.565 8.2 0.591 7.8 0.574 8.0 0.609 7.5 0.473 10.0 0.543 8.5 0.554 8.3 0.563 8.2 0.588 7.8 0.572 8.1 0.606 7.6 0.427 10.3 0.496 8.8 0.508 8.6 0.516 8.5 0.542 8.1 0.526 8.3 0.560 7.8 0.467 10.1 0.536 8.7 0.548 8.4 0.556 8.3 0.582 7.9 0.566 8.2 0.600 7.6 0.464 10.2 0.534 8.7 0.545 8.5 0.554 8.4 0.579 7.9 0.563 8.2 0.598 7.7 0.423 10.3 0.492 8.8 0.504 8.6 0.512 8.4 0.538 8.0 0.522 8.3 0.556 7.8 0.456 10.4 0.526 8.8 0.537 8.6 0.546 8.5 0.572 8.1 0.555 8.3 0.590 7.8 0.413 10.6 0.482 9.0 0.494 8.8 0.502 8.6 0.528 8.2 0.512 8.4 0.546 7.9 0.408 10.7 0.477 9.0 0.489 8.8 0.497 8.7 0.523 8.2 0.507 8.5 0.541 8.0 0.407 10.7 0.476 9.1 0.488 8.8 0.496 8.7 0.522 8.3 0.506 8.5 0.540 8.0 0.416 10.5 0.486 9.0 0.498 8.8 0.506 8.6 0.532 8.2 0.516 8.4 0.550 7.9 0.405 10.8 0.475 9.1 0.487 8.9 0.495 8.7 0.521 8.3 0.504 8.6 0.539 8.0 0.410 10.7 0.480 9.1 0.492 8.9 0.500 8.7 0.526 8.3 0.509 8.5 0.544 8.0 0.408 10.8 0.477 9.1 0.489 8.9 0.497 8.8 0.523 8.3 0.507 8.6 0.541 8.0 0.405 10.9 0.474 9.2 0.486 9.0 0.494 8.8 0.520 8.4 0.504 8.6 0.538 8.1 0.396 11.0 0.466 9.3 0.477 9.1 0.486 8.9 0.511 8.5 0.495 8.8 0.529 8.2 0.400 11.0 0.469 9.3 0.481 9.1 0.489 8.9 0.515 8.4 0.499 8.7 0.533 8.1 0.388 11.3 0.458 9.5 0.469 9.3 0.478 9.1 0.503 8.6 0.487 8.9 0.522 8.3 0.391 11.2 0.460 9.4 0.472 9.2 0.480 9.0 0.506 8.6 0.490 8.9 0.524 8.3 0.394 11.2 0.464 9.4 0.476 9.2 0.484 9.0 0.510 8.5 0.493 8.8 0.528 8.2 0.386 11.3 0.455 9.5 0.467 9.3 0.476 9.1 0.501 8.6 0.485 8.9 0.519 8.3 0.389 11.3 0.458 9.5 0.470 9.3 0.478 9.1 0.504 8.6 0.488 8.9 0.522 8.3 0.380 11.5 0.450 9.7 0.461 9.4 0.470 9.2 0.495 8.7 0.479 9.1 0.514 8.4 0.384 11.5 0.453 9.6 0.465 9.4 0.473 9.2 0.499 8.7 0.483 9.0 0.517 8.4 0.378 11.6 0.448 9.7 0.459 9.5 0.468 9.3 0.493 8.8 0.477 9.1 0.511 8.5 0.374 11.7 0.443 9.8 0.455 9.6 0.463 9.4 0.489 8.9 0.473 9.2 0.507 8.5 0.373 11.8 0.443 9.8 0.454 9.6 0.463 9.4 0.488 8.9 0.472 9.2 0.506 8.6 0.372 11.8 0.442 9.9 0.454 9.6 0.462 9.4 0.488 8.9 0.472 9.2 0.506 8.6 0.380 11.5 0.449 9.7 0.461 9.4 0.469 9.2 0.495 8.7 0.479 9.0 0.513 8.4 0.367 11.9 0.437 10.0 0.449 9.7 0.457 9.5 0.483 9.0 0.467 9.3 0.501 8.7 0.364 12.0 0.434 10.0 0.446 9.7 0.454 9.6 0.480 9.0 0.463 9.4 0.498 8.7 0.366 12.0 0.435 10.0 0.447 9.8 0.455 9.6 0.481 9.0 0.465 9.4 0.499 8.7 0.365 12.1 0.435 10.0 0.446 9.8 0.455 9.6 0.480 9.0 0.464 9.4 0.498 8.7 0.362 12.1 0.432 10.1 0.444 9.8 0.452 9.6 0.478 9.1 0.462 9.4 0.496 8.7 0.363 12.1 0.432 10.1 0.444 9.8 0.452 9.6 0.478 9.1 0.462 9.4 0.496 8.7 Table 5.34: Overhead line feeder circuit data, ACSR Conductors, 60Hz 5-32 X Flat circuit © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 5 ˜ Equivalent circuits and parameters of power system plant Conductor size mm2 3.3kV 6.6kV 11kV 22kV 33kV 66kV* 145kV* 245kV* 420kV* Series Resistance Series Reactance Susceptance Series Resistance Series Reactance Susceptance Series Resistance Series Reactance Susceptance Series Resistance Series Reactance Susceptance Series Resistance Series Reactance Susceptance Series Resistance Series Reactance Susceptance Series Resistance Series Reactance Susceptance Series Resistance Series Reactance Susceptance Series Resistance Series Reactance Susceptance R (/km) X (/km) C (mS/km) R (/km) X (/km) C (mS/km) R (/km) X (/km) C (mS/km) R (/km) X (/km) C (mS/km) R (/km) X (/km) C (mS/km) R (/km) X (/km) C (mS/km) R (/km) X (/km) C (mS/km) R (/km) X (/km) C (mS/km) R (/km) X (/km) C (mS/km) 25 0.927 0.097 0.059 0.927 0.121 0.085 0.927 0.128 0.068 - - 35 0.669 0.092 0.067 0.669 0.113 0.095 0.669 0.119 0.074 0.669 0.136 0.053 0.669 0.15 0.042 - 50 0.494 0.089 0.079 0.494 0.108 0.104 0.494 0.114 0.082 0.494 0.129 0.057 0.494 0.143 0.045 - 70 0.342 0.083 0.09 0.342 0.102 0.12 0.342 0.107 0.094 0.348 0.121 0.065 0.348 0.134 0.05 - 95 0.247 0.08 0.104 0.247 0.096 0.136 0.247 0.101 0.105 0.247 0.114 0.072 0.247 0.127 0.055 - 120 0.196 0.078 0.111 0.196 0.093 0.149 0.196 0.098 0.115 0.196 0.11 0.078 0.196 0.122 0.059 - 150 0.158 0.076 0.122 0.158 0.091 0.16 0.158 0.095 0.123 0.158 0.107 0.084 0.158 0.118 0.063 - 185 0.127 0.075 0.133 0.127 0.088 0.177 0.127 0.092 0.135 0.127 0.103 0.091 0.127 0.114 0.068 - 240 0.098 0.073 0.146 0.098 0.086 0.189 0.098 0.089 0.15 0.098 0.1 0.1 0.098 0.109 0.075 - 300 0.08 0.072 0.16 0.08 0.085 0.195 0.08 0.087 0.165 0.08 0.094 0.109 0.08 0.105 0.081 - 400 0.064 0.071 0.179 0.064 0.083 0.204 0.064 0.084 0.182 0.064 0.091 0.12 0.064 0.102 0.089 - - - - - - - - - - - - - 0.0487 0.145 0.044 *500 0.051 0.088 0.19 0.057 0.088 0.205 0.051 0.089 0.194 0.051 0.096 0.128 0.051 0.103 0.094 0.0387 0.117 0.079 0.0387 0.13 0.053 0.0387 0.137 0.047 *630 0.042 0.086 0.202 0.042 0.086 0.228 0.042 0.086 0.216 0.042 0.093 0.141 0.042 0.1 0.103 0.031 0.113 0.082 0.031 0.125 0.06 0.0310 0.134 0.05 0.0310 0.172 0.04 *800 *1000 *1200 *1600 0.0254 0.109 0.088 0.0254 0.12 0.063 0.0254 0.128 0.057 0.0254 0.162 0.047 0.0215 0.102 0.11 0.0215 0.115 0.072 0.0215 0.123 0.057 0.0215 0.156 0.05 0.0161 0.0126 0.119 0.113 0.063 0.072 0.0161 0.0126 0.151 0.144 0.057 0.063 Table 5.35: Characteristics of polyethylene insulated cables (XLPE), copper conductors (50Hz) 5.25 REFERENCES [5.1] Physical significance of sub-subtransient quantities in dynamic behaviour of synchronous machines. I.M. Canay. Proc. IEE, Vol. 135, Pt. B, November 1988. [5.2] IEC 60034-4. Methods for determining synchronous machine quantities from tests. [5.3] IEEE Standards 115/115A. IEEE Test Procedures for Synchronous Machines. [5.4] Power System Analysis. J.R. Mortlock and M.W. Humphrey Davies. Chapman & Hall, London. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 5-33 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 Current and Voltage Transformers 6.1 6.2 6.3 6.4 6.5 Introduction Electromagnetic Voltage Transfomers Capacitor Voltage Transfomers Current Transfomers Non-Conventional Instrument Transformers 6.1 INTRODUCTION If the voltage or current in a power circuit are too high to connect measuring instruments or relays directly, coupling is made through transformers. Such 'measuring' transformers are required to produce a scaled down replica of the input quantity to the accuracy expected for the particular measurement; this is made possible by the high efficiency of the transformer. During and following large instantaneous changes in the input quantity, the waveform may no longer be sinusoidal, therefore the performance of measuring transformers is important. The deviation may be a step change in magnitude, or a transient component that persists for an significant period, or both. The resulting effect on instrument performance is usually negligible, although for precision metering a persistent change in the accuracy of the transformer may be significant. However, many protection systems are required to operate during the transient disturbance in the output of the measuring transformers following a system fault. The errors in transformer output may delay the operation of the protection or cause unnecessary operations. Therefore the functioning of such transformers must be examined analytically. The transformer can be represented by the equivalent circuit of Figure 6.1, where all quantities are referred to the secondary side. Figure 6.1: Equivalent circuit of transformer When the transformer is not 1/1 ratio, this condition can be represented by energising the equivalent circuit with an ideal transformer of the given ratio but having no losses. 6.1.1 Measuring Transformers Voltage and current transformers for low primary voltage or current ratings are not readily distinguishable; for higher ratings, dissimilarities of construction are usual. Nevertheless the main differences between these devices are the way they are connected into the power circuit. Voltage transformers are Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-1 Network Protection & Automation Guide much like small power transformers, differing only in details of design that control ratio accuracy over the specified range of output. Current transformers have their primary windings connected in series with the power circuit, and so also in series with the system impedance. The response of the transformer is radically different in these two modes of operation. 6.2 ELECTROMAGNETIC VOLTAGE TRANSFOMERS In the shunt mode, the system voltage is applied across the input terminals of the equivalent circuit of Figure 6.1. The vector diagram for this circuit is shown in Figure 6.2. Vp The secondary output voltage Vs is required to be an accurate scaled replica of the input voltage Vp over a specified range of output. Therefore the winding voltage drops are made small and the normal flux density in the core is designed to be well below the saturation density, so the exciting current can be low and the exciting impedance substantially constant with a variation of applied voltage over the desired operating range including some degree of overvoltage. These limitations in design result in a VT for a given burden being much larger than a typical power transformer of similar rating. Consequently the exciting current is not as small, relative to the rated burden, as it would be for a typical power transformer. IpXp 6.2.1 Errors The ratio and phase errors of the transformer can be calculated using the vector diagram of Figure 6.2. IpRp Ep The ratio error is defined as: K nVs  V p Vp T -Vs Ie where: Ip IpL u 100% Kn is the nominal ratio Ie Ic Im I ) Vp is the primary voltage Vs is the secondary voltage If the error is positive, the secondary voltage is greater than the nominal value. If the error is negative, the secondary voltage is less than the nominal value. The turns ratio of the transformer need not be equal to the nominal ratio and a small turns compensation is usually used so the error is positive for low burdens and negative for high burdens. Is Vs IsXs Es IsRs = Primary applied voltage = Primary induced e.m.f. = Secondary output voltage = Secondary induced e.m.f. = Flux = Exciting current = Magnetising component = Iron loss component = Phase angle error I = Secondary burden angle IpRp = Primary resistance voltage drop IpXp = Primary reactance voltage drop IsRs = Secondary resistance voltage drop Vp Ep Vs Es ) Ie Im Ic T The phase error is the phase difference between the reversed secondary and the primary voltage vectors. It is positive when the reversed secondary voltage leads the primary vector. Requirements in this respect are set out in IEC 60044-2. All voltage transformers are required to comply with one of the classes in Table 6.1. For protection purposes, accuracy of voltage measurement may be important during fault conditions, as the system voltage might be reduced by the fault to a low value. Voltage transformers for such types of service must comply with the extended range of requirements set out in Table 6.2. IsXs = Secondary reactance voltage drop Is = Secondary current IpL = Load component of primary current Ip = Primary current Figure 6.2: Vector diagram of voltage transformer 6-2 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers 0.8 - 1.2 x rated voltage 0.25 - 1.0 x rated burden at 0.8pf Accuracy Class phase displacement (minutes) voltage ratio error (%) 0.1 +/- 0.1 +/- 5 0.2 +/- 0.2 +/- 10 0.5 +/- 0.5 +/- 20 1.0 +/- 1.0 +/- 40 3.0 +/- 3.0 not specified Table 6.1: Measuring Voltage Transformer error limits 0.25 - 1.0 x rated burden at 0.8pf 0.05 - Vf x rated primary voltage Accuracy Class Voltage ratio error (%) Phase displacement (minutes) 3P +/- 3.0 +/- 120 6P +/- 6.0 +/- 240 Table 6.2: Additional limits for protection Voltage Transformers 6.2.2 Voltage Factors The quantity Vf in Table 6.2 is an upper limit of operating voltage, expressed in per unit of rated voltage. This is important for correct relay operation and operation under unbalanced fault conditions on unearthed or impedance earthed systems, resulting in a rise in the voltage on the healthy phases. Voltage Time rating factor Vf 1.2 continuous Primary winding connection/system earthing conditions Between lines in any network. Between transformer star point and earth in any network 1.2 continuous 1.5 30 sec 1.2 continuous 1.9 30 sec 1.2 continuous 1.9 8 hours Between line and earth in an effectively earthed network Between line and earth in a non-effectively earthed neutral system with automatic earth fault tripping Between line and earth in an isolated neutral system without automatic earth fault tripping, or in a resonant earthed system without automatic earth fault tripping Table 6.3: Voltage transformers permissible duration of maximum voltage 6.2.4 Protection of Voltage Transformers Voltage Transformers can be protected by High Rupturing Capacity (H.R.C.) fuses on the primary side for voltages up to 66kV. Fuses do not usually have a sufficient interrupting capacity for use with higher voltages. Practice varies, and in some cases protection on the primary is omitted. The secondary of a Voltage Transformer should always be protected by fuses or a miniature circuit breaker (MCB). The device should be located as near to the transformer as possible. A short circuit on the secondary circuit wiring produces a current of many times the rated output and causes excessive heating. Even where primary fuses can be fitted, these usually do not clear a secondary side short circuit because of the low value of primary current and the minimum practicable fuse rating. 6.2.5 Construction of Voltage Transformers The construction of a voltage transformer differs from that of a power transformer in that different emphasis is placed on cooling, insulation and mechanical design. The rated output seldom exceeds a few hundred VA and therefore the heat generated normally presents no problem. The size of a VT is largely determined by the system voltage and the insulation of the primary winding often exceeds the winding in volume. A VT should be insulated to withstand overvoltages, including impulse voltages, of a level equal to the withstand value of the switchgear and the high voltage system. To achieve this in a compact design the voltage must be distributed uniformly across the winding, which requires uniform distribution of the winding capacitance or the application of electrostatic shields. Voltage transformers are commonly used with switchgear so the physical design must be compact and adapted for mounting in or near to the switchgear. Three-phase units are common up to 36kV but for higher voltages single-phase units are usual. Voltage transformers for medium voltage circuits have dry type insulation, but high and extra high voltage systems still use oil immersed units. Figure 6.3 shows an Alstom OTEF 36.5kV to 765kV high voltage electromagnetic transformer. 6.2.3 Secondary Leads Voltage transformers are designed to maintain the specified accuracy in voltage output at their secondary terminals. To maintain this if long secondary leads are required, a distribution box can be fitted close to the VT to supply relay and metering burdens over separate leads. If necessary, allowance can be made for the resistance of the leads to individual burdens when the particular equipment is calibrated © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-3 Network Protection & Automation Guide 9 1 - Expansion bellow 2 - Primary terminal H1 3 - Capacitive grading layers 4 - Secondary terminal box 5 - Core / coil assembly 6 - Oil-level indicator 7 - Porcelain or composite insulator 8 - Secondary terminal box 9 - Expansion chamber 1 10 - Lifting eye 11 - Primary terminal 12 - Post type porcelain insulator 13 - Capacitive grading layers 14 - Two coil and core assembly 15 - Transformer tank 16 - Post type porcelain insulator 17 - Oil to air seal bock 18 - Secondary terminal box 6 10 11 12 13 2 7 3 14 15 8 4 16 5 17 18 Figure 6.3: Alstom OTEF electromagnetic 36.6kV to 765kV high voltage transformer 6.2.6 Residually connected Voltage Transformers The three voltages of a balanced system summate to zero, but this is not so when the system is subject to a single-phase earth fault. The residual voltage of a system is measured by connecting the secondary windings of a VT in 'broken delta' as shown in Figure 6.4. Figure 6.4: Residual voltage connection The output of the secondary windings connected in broken delta is zero when balanced sinusoidal voltages are applied, but under conditions of imbalance a residual voltage equal to 6-4 three times the zero sequence voltage of the system is developed. To measure this component it is necessary for a zero sequence flux to be set up in the VT, and for this to be possible there must be a return path for the resultant summated flux. The VT core must have one or more unwound limbs linking the yokes in addition to the limbs carrying windings. Usually the core is made symmetrically, with five limbs, the two outermost ones being unwound. Alternatively, three single-phase units can be used. It is equally necessary for the primary winding neutral to be earthed, for without an earth, zero sequence exciting current cannot flow. A VT should be rated to have an appropriate voltage factor as described in Section 6.2.2 and Table 6.3, to cater for the voltage rise on healthy phases during earth faults. Voltage transformers are often provided with a normal starconnected secondary winding and a broken-delta connected ‘tertiary’ winding. Alternatively the residual voltage can be extracted by using a star/broken-delta connected group of auxiliary voltage transformers energised from the secondary winding of the main unit, providing the main voltage transformer fulfils all the requirements for handling a zero sequence voltage as previously described. The auxiliary VT must also be suitable for the appropriate voltage factor. It should be noted that third harmonics in the primary voltage wave, which are of zero sequence, summate in the brokendelta winding. 6.2.7 Transient Performance Transient errors cause few difficulties in the use of conventional voltage transformers although some do occur. Errors are generally limited to short time periods following the sudden application or removal of voltage from the VT primary. If a voltage is suddenly applied, an inrush transient occurs, as with power transformers. However, the effect is less severe than for power transformers because of the lower flux density for which the VT is designed. If the VT is rated to have a fairly high voltage factor, there is little inrush effect. An error appears in the first few cycles of the output current in proportion to the inrush transient that occurs. When the supply to a voltage transformer is interrupted, the core flux does not immediately collapse. The secondary winding maintains the magnetising force to sustain this flux and circulates a current through the burden, which decays more or less exponentially. There may also be a superimposed audio-frequency oscillation due to the capacitance of the winding. If the exciting quantity in ampere-turns exceeds the burden, the transient current may be significant. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers 6.2.8 Cascade Voltage Transformer The capacitor VT (section 6.3) was developed because of the high cost of conventional electromagnetic voltage transformers but, as shown in Section 6.3.2, the frequency and transient responses are less satisfactory than those of the orthodox voltage transformers. Another solution to the problem is the cascade VT shown in Figure 6.5. accumulating to a value able to withstand the full system voltage across the complete height of the stack. The entire assembly is contained in a hollow cylindrical porcelain housing with external weather-sheds; the housing is filled with oil and sealed, an expansion bellows being included to maintain hermetic sealing and to permit expansion with temperature change. 6.3 A CAPACITOR VOLTAGE TRANSFOMERS The size of electromagnetic voltage transformers for the higher voltages is largely proportional to the rated voltage; the cost tends to increase at a disproportionate rate. The capacitor voltage transformer (CVT) is often more economic. C P C C C P - primary winding C - coupling windings S - secondary winding C n S a N Figure 6.5: Schematic diagram of typical cascade voltage transformer The conventional type of VT has a single primary winding, the insulation of which presents a problem for voltages above about 132kV. The cascade VT avoids these difficulties by breaking down the primary voltage in several distinct and separate stages. This device is basically a capacitance potential divider. As with resistance-type potential dividers, the output voltage is seriously affected by load at the tapping point. The capacitance divider differs in that its equivalent source impedance is capacitive and can therefore be compensated by a reactor connected in series with the tapping point. With an ideal reactor, such an arrangement would have no regulation and could supply any value of output. A reactor possesses some resistance, which limits the output that can be obtained. For a secondary output voltage of 110V, the capacitors would have to be very large to provide a useful output while keeping errors within the usual limits. The solution is to use a high secondary voltage and further transform the output to the normal value using a relatively inexpensive electromagnetic transformer. The successive stages of this reasoning are shown in Figure 6.6: Development of capacitor voltage transformer. C1 The complete VT is made up of several individual transformers, the primary windings of which are connected in series as shown in Figure 6.5. Each magnetic core has primary windings (P) on two opposite sides. The secondary winding (S) consists of a single winding on the last stage only. Coupling windings (C) connected in pairs between stages, provide low impedance circuits for the transfer of load ampereturns between stages and ensure that the power frequency voltage is equally distributed over the several primary windings. The potentials of the cores and coupling windings are fixed at definite values by connecting them to selected points on the primary windings. The insulation of each winding is sufficient for the voltage developed in that winding, which is a fraction of the total according to the number of stages. The individual transformers are mounted on a structure built of insulating material, which provides the interstage insulation, C1 L C2 Zb C2 (a) Basic capacitive voltage divider Zb (b) Capacitive divider with inductive compensation C1 T L C2 Zb (c) Divider with E/M VT output stage Figure 6.6: Development of capacitor voltage transformer © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-5 Network Protection & Automation Guide There are numerous variations of this basic circuit. The inductance L may be a separate unit or it may be incorporated in the form of leakage reactance in the transformer T. Capacitors C1 and C2 cannot conveniently be made to close tolerances, so tappings are provided for ratio adjustment, either on the transformer T, or on a separate auto-transformer in the secondary circuit. Adjustment of the tuning inductance L is also needed; this can be done with tappings, a separate tapped inductor in the secondary circuit, by adjustment of gaps in the iron cores, or by shunting with variable capacitance. A simplified equivalent circuit is shown in Figure 6.7. Standards generally require a CVT used for protection to conform to accuracy requirements of Table 6.2 within a frequency range of 97-103% of nominal. The corresponding frequency range of measurement CVTs is much less, 99%101%, as reductions in accuracy for frequency deviations outside this range are less important than for protection applications. 6.3.1 Voltage Protection of Auxiliary Capacitor If the burden impedance of a CVT is short-circuited, the rise in the reactor voltage is limited only by the reactor losses and possible saturation to Q  E2 where E2 is the no-load tapping point voltage and Q is the amplification factor of the resonant circuit. This value would be excessive and is therefore limited by a spark gap connected across the auxiliary capacitor. The voltage on the auxiliary capacitor is higher at full rated output than at no load, and the capacitor is rated for continuous service at this raised value. The spark gap is set to flash over at about twice the full load voltage. The spark gap limits the short-circuit current which the VT delivers and fuse protection of the secondary circuit is carefully designed with this in mind. Usually the tapping point can be earthed either manually or automatically before making any adjustments to tappings or connections. Figure 6.7: Simplified equivalent circuit of capacitor voltage transformer 6.3.2 Transient Behaviour of Capacitor Voltage Transformers A CVT is a series resonant circuit. The introduction of the electromagnetic transformer between the intermediate voltage and the output makes further resonance possible involving the exciting impedance of this unit and the capacitance of the divider stack. When a sudden voltage step is applied, oscillations in line with these different modes take place and persist for a period governed by the total resistive damping that is present. Any increase in resistive burden reduces the time constant of a transient oscillation, although the chance of a large initial amplitude is increased. Figure 6.8: Section view of an Alstom OTCF 72.5kV to 765kV coupling capacitor voltage transformer The main difference between Figure 6.7 and Figure 6.1 is the presence of C and L. At normal frequency when C and L resonate and therefore cancel, the circuit behaves in a similar way to a conventional VT. However, at other frequencies a reactive component exists which modifies the errors. 6-6 For very high-speed protection, transient oscillations should be minimised. Modern capacitor voltage transformers are much better in this respect than their earlier counterparts. However, high performance protection schemes may still be adversely affected unless their algorithms and filters have been specifically designed with care. 6.3.3 Ferro-Resonance The exciting impedance Ze of the auxiliary transformer T and the capacitance of the potential divider together form a resonant circuit that usually oscillates at a sub-normal frequency. If this circuit is subjected to a voltage impulse, the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers resulting oscillation may pass through a range of frequencies. If the basic frequency of this circuit is slightly less than onethird of the system frequency, it is possible for energy to be absorbed from the system and cause the oscillation to build up. The increasing flux density in the transformer core reduces the inductance, bringing the resonant frequency nearer to the onethird value of the system frequency. The result is a progressive build-up until the oscillation stabilises as a third sub-harmonic of the system, which can be maintained indefinitely. Depending on the values of components, oscillations at fundamental frequency or at other sub-harmonics or multiples of the supply frequency are possible but the third subharmonic is the one most likely to be encountered. The principal manifestation of such an oscillation is a rise in output voltage, the r.m.s. value being perhaps 25% to 50% above the normal value. The output waveform would generally be of the form shown in Figure 6.9. winding of the current transformer. This condition can be represented by inserting the load impedance, referred through the turns ratio, in the input connection of Figure 6.1. This approach is developed in Figure 6.10, taking the numerical example of a 300/5A CT applied to an 11kV power system. The system is considered to be carrying rated current (300A) and the CT is feeding a burden of 10VA. Z 21.2 : Burden 10VA 300/ 5A E 6350V (a) Physical arrangement 0.2 : Z 21.2 : E 6350V r 'Ideal' CT 300/ 5 j 50 : 150 : 0.4 : Amplitude (b) Equivalent circuit of (a) Zr = 21.2 x 602 = 76.2k Er 6 3 5 0V u 6 0 381kV Figure 6.9: Typical secondary voltage waveform with third subharmonic oscillation Such oscillations are less likely to occur when the circuit losses are high, as is the case with a resistive burden, and can be prevented by increasing the resistive burden. Special antiferro-resonance devices that use a parallel-tuned circuit are sometimes built into the VT. Although such arrangements help to suppress ferro-resonance, they tend to impair the transient response, so that the design is a matter of compromise. Correct design prevents a CVT that supplies a resistive burden from exhibiting this effect, but it is possible for non-linear inductive burdens, such as auxiliary voltage transformers, to induce ferro-resonance. Auxiliary voltage transformers for use with capacitor voltage transformers should be designed with a low value of flux density that prevents transient voltages from causing core saturation, which in turn would bring high exciting currents. 6.4 CURRENT TRANSFOMERS The primary winding of a current transformer is connected in series with the power circuit and the impedance is negligible compared with that of the power circuit. The power system impedance governs the current passing through the primary j 50 : 0.2 : 150 : 0.4 : (c) Equivalent circuit, all quantities referred to secondary side Figure 6.10: Derivation of equivalent circuit of a current transformer A study of the final equivalent circuit of Figure 6.10(c), taking note of the typical component values, reveals all the properties of a current transformer. It can be seen that: x The secondary current is not affected by change of the burden impedance over a considerable range. x The secondary circuit must not be interrupted while the primary winding is energised. The induced secondary e.m.f. under these circumstances is high enough to present a danger to life and insulation. x The ratio and phase angle errors can be calculated easily if the magnetising characteristics and the burden impedance are known. 6.4.1 Errors The general vector diagram shown in Figure 6.2 can be simplified by omitting details that are not of interest in current measurement; see Figure 6.11. Errors arise because of the shunting of the burden by the exciting impedance. This uses a small portion of the input current for exciting the core, reducing the amount passed to the burden. So Is = Ip - Ie, © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-7 Network Protection & Automation Guide where Ie is dependent on Ze, the exciting impedance and the secondary e.m.f. Es, given by the equation Es=Is(Zs+Zb), where: Zs = the self-impedance of the secondary winding, which can generally be taken as the resistive component Rs only Zb = the impedance of the burden IsRs IsXs Es Iq For lower value burden or a different burden power factor, the error would change in the positive direction to a maximum of +0.7% at zero burden; the leakage reactance of the secondary winding is assumed to be negligible. No corresponding correction can be made for phase error, but it should be noted that the phase error is small for moderately reactive burdens. 6.4.2 Composite Error Ir This is defined in IEC 60044-1 as the r.m.s. value of the difference between the ideal secondary current and the actual secondary current. It includes current and phase errors and the effects of harmonics in the exciting current. The accuracy class of measuring current transformers is shown in Table 6.4 and Table 6.5. Ip Vs an inductive burden of rated value would be about 1.2%. If the nominal turns ratio is 2:120, removal of one secondary turn would raise the output by 0.83% leaving the overall current error as -0.37%. T Is Ie ) Es = Secondary induced e.m.f. Vs = Secondary output voltage Ip = Primary current Is = Secondary current T = Phase angle error ) = Flux IsRs = Secondary resistance voltage drop IsXs = Secondary reactance voltage drop Ie = Exciting current Ir = Component of le in phase with ls Iq = Component of le in quadrature with ls Accuracy Class % current This is the difference in magnitude between Ip and Is and is equal to Ir, the component of Ie which is in phase with Is. 6.4.1.2 Phase Error This is represented by Iq, the component of Ie in quadrature with Is and results in the phase error I . The values of the current error and phase error depend on the phase displacement between Is and Ie, but neither current nor phase error can exceed the vectorial error Ie. With a moderately inductive burden, resulting in Is and Ie approximately in phase, there is little phase error and the exciting component results almost entirely in ratio error. A reduction of the secondary winding by one or two turns is often used to compensate for this. For example, in the CT corresponding to Figure 6.10, the worst error due to the use of 6-8 5 20 100 120 (minutes) 5 20 100 120 0.1 0.4 0.2 0.1 0.1 15 8 5 5 0.2 0.75 0.35 0.2 0.2 30 15 10 10 0.5 1.5 0.75 0.5 0.5 90 45 30 30 1 3 1.5 1.0 1.0 180 90 60 60 Table 6.4: Limits of CT error for accuracy classes 0.1 to 1.0 Accuracy Class Figure 6.11: Vector diagram for current transformer (referred to secondary) 6.4.1.1 Current or Ratio Error +/- Phase displacement +/- Percentage current (ratio) error +/- current (ratio) error, % % current 50 120 3 3 3 5 5 5 Table 6.5: Limits of CT error for accuracy classes 3 and 5 6.4.3 Accuracy Limit Current of Protection Current Transformers Protection equipment is intended to respond to fault conditions, and is for this reason required to function at current values above the normal rating. Protection class current transformers must retain a reasonable accuracy up to the largest relevant current. This value is known as the ‘accuracy limit current’ and may be expressed in primary or equivalent secondary terms. The ratio of the accuracy limit current to the rated current is known as the 'accuracy limit factor'. The accuracy class of protection current transformers is shown in Table 6.6. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers Class Current error at rated primary current (%) Phase displacement at rated current (minutes) Composite error at rated accuracy limit primary current (%) 5P +/-1 +/-60 5 10P +/-3 - 10 VK +10% Vk +50%IeK Standard accuracy limit factors are 5, 10, 15, 20, and 30 Even though the burden of a protection CT is only a few VA at rated current, the output required from the CT may be considerable if the accuracy limit factor is high. For example, with an accuracy limit factor of 30 and a burden of 10VA, the CT may have to supply 9000VA to the secondary circuit. Alternatively, the same CT may be subjected to a high burden. For overcurrent and earth fault protection, with elements of similar VA consumption at setting, the earth fault element of an electromechanical relay set at 10% would have 100 times the impedance of the overcurrent elements set at 100%. Although saturation of the relay elements somewhat modifies this aspect of the matter, the earth fault element is a severe burden, and the CT is likely to have a considerable ratio error in this case. Therefore it is not much use applying turns compensation to such current transformers; it is generally simpler to wind the CT with turns corresponding to the nominal ratio. Current transformers are often used for the dual duty of measurement and protection. They then need to be rated according to a class selected from Table 6.4, Table 6.5 and Table 6.6. The applied burden is the total of instrument and relay burdens. Turns compensation may well be needed to achieve the measurement performance. Measurement ratings are expressed in terms of rated burden and class, for example 15VA Class 0.5. Protection ratings are expressed in terms of rated burden, class, and accuracy limit factor, for example 10VA Class 10P10. 6.4.4 Class PX Current Transformers The classification of Table 6.6 is only used for overcurrent protection. Class PX is the definition in IEC 60044-1 for the quasi-transient current transformers formerly covered by Class X of BS 3938, commonly used with unit protection schemes. Guidance was given in the specifications to the application of current transformers to earth fault protection, but for this and for the majority of other protection applications it is better to refer directly to the maximum useful e.m.f. that can be obtained from the CT. In this context, the 'knee-point' of the excitation curve is defined as 'that point at which a further increase of 10% of secondary e.m.f. would require an increment of exciting current of 50%’; see Figure 6.12. Exciting voltage (Vs) Table 6.6: Protection CT error limits for classes 5P and 10P IeK Exciting current (Ie) Figure 6.12: Definition of knee-point of excitation curve Design requirements for current transformers for general protection purposes are frequently laid out in terms of kneepoint e.m.f., exciting current at the knee-point (or some other specified point) and secondary winding resistance. Such current transformers are designated Class PX 6.4.5 CT Winding Arrangements Several CT winding arrangements are used. These are described in the following sections. 6.4.5.1 Wound primary type This type of CT has conventional windings formed of copper wire wound round a core. It is used for auxiliary current transformers and for many low or moderate ratio current transformers used in switchgear of up to 11kV rating. 6.4.5.2 Bushing or bar primary type Many current transformers have a ring-shaped core, sometimes built up from annular stampings, but often consisting of a single length of strip tightly wound to form a close-turned spiral. The distributed secondary winding forms a toroid which should occupy the whole perimeter of the core, a small gap being left between start and finish leads for insulation. Such current transformers normally have a single concentrically placed primary conductor, sometimes permanently built into the CT and provided with the necessary primary insulation. In other cases, the bushing of a circuit © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-9 Network Protection & Automation Guide breaker or power transformer is used for this purpose. At low primary current ratings it may be difficult to obtain sufficient output at the desired accuracy. This is because a large core section is needed to provide enough flux to induce the secondary e.m.f. in the small number of turns, and because the exciting ampere-turns form a large proportion of the primary ampere-turns available. The effect is particularly pronounced when the core diameter has been made large to fit over large EHV bushings. 6.4.5.3 Core-Balance Current Transformers The core-balance CT (or CBCT) is normally of the ring type, through the centre of which is passed cable that forms the primary winding. An earth fault relay, connected to the secondary winding, is energised only when there is residual current in the primary system. The advantage in using this method of earth fault protection lies in the fact that only one CT core is used in place of three phase CTs whose secondary windings are residually connected. In this way the CT magnetising current at relay operation is reduced by approximately three-to-one, an important consideration in sensitive earth fault relays where a low effective setting is required. The number of secondary turns does not need to be related to the cable rated current because no secondary current would flow under normal balanced conditions. This allows the number of secondary turns to be chosen such as to optimise the effective primary pick-up current. Core-balance transformers are normally mounted over a cable at a point close up to the cable gland of switchgear or other apparatus. Physically split cores ('slip-over' types) are normally available for applications in which the cables are already made up, as on existing switchgear. 6.4.5.4 Summation Current Transformers The summation arrangement is a winding arrangement used in a measuring relay or on an auxiliary current transformer to give a single-phase output signal having a specific relationship to the three-phase current input. 6.4.5.5 Air-gapped current transformers the widest practical range of input currents. 6.4.6 CT Winding Arrangements CTs for measuring line currents fall into one of three types. 6.4.6.1 Over-Dimensioned CTs Over-dimensioned CTs are capable of transforming fully offset fault currents without distortion. In consequence, they are very large, as can be deduced from Section 6.4.10. They are prone to errors due to remanent flux arising, for instance, from the interruption of heavy fault currents. 6.4.6.2 Anti-Remanence CTs This is a variation of the overdimensioned current transformer and has small gap(s) in the core magnetic circuit, thus reducing the possible remanent flux from approximately 90% of saturation value to approximately 10%. These gap(s) are quite small, for example 0.12mm total, and so the excitation characteristic is not significantly changed by their presence. However, the resulting decrease in possible remanent core flux confines any subsequent d.c. flux excursion, resulting from primary current asymmetry, to within the core saturation limits. Errors in current transformation are therefore significantly reduced when compared with those with the gapless type of core. Transient protection Current Transformers are included in IEC 60044-6 as types TPX, TPY and TPZ and this specification gives good guidance to their application and use. 6.4.6.3 Linear Current Transformers The 'linear' current transformer constitutes an even more radical departure from the normal solid core CT in that it incorporates an appreciable air gap, for example 7.5-10mm. As its name implies the magnetic behaviour tends to linearisation by the inclusion of this gap in the magnetic circuit. However, the purpose of introducing more reluctance into the magnetic circuit is to reduce the value of magnetising reactance. This in turn reduces the secondary time-constant of the CT, thereby reducing the overdimensioning factor necessary for faithful transformation. Figure 6.13 shows a CT for use on HV systems. These are auxiliary current transformers in which a small air gap is included in the core to produce a secondary voltage output proportional in magnitude to current in the primary winding. Sometimes termed 'transactors' and 'quadrature current transformers', this form of current transformer has been used as an auxiliary component of traditional pilot-wire unit protection schemes in which the outputs into multiple secondary circuits must remain linear for and proportional to 6-10 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers x The primary conductor(s) passes through the approximate centre of the core aperture or, if wound, is approximately evenly distributed along the whole length of the magnetic circuit. x Flux equalising windings, where fitted to the requirements of the design, consist of at least four parallel-connected coils, evenly distributed along the whole length of the magnetic circuit, each coil occupying one quadrant. 1 2 3 4 5 1. Diaphragm bellows 2. CT cores and secondary windings 3. Primary terminal 4. Primary conductor assembly 5. Head housing 6. Core housing 7. Porcelain or composite insulator 8. Bushing tube 9. Capacitive grading layers 10 . Secondary terminal blocks 11 . Fault current carrying connector to ground 12 . Ground pad 13 . Secondary terminal box 14 . Mounting base 15 . Oil/Air block Alternatively, when a current transformer does not comply with all of the above requirements, it may be proved to be of low-reactance. In this case the composite error, as measured in the accepted way, does not exceed by a factor of 1.3 that error obtained directly from the V-I excitation characteristic of the secondary winding. 6 6.4.8 Secondary Current Rating 7 8 9 10 11 12 14 13 15 Figure 6.13: Alstom OSKF 72.5kV to 765kV high voltage current transformer 6.4.7 Secondary Winding Impedance As a protection CT may be required to deliver high values of secondary current, the secondary winding resistance must be made as low as practicable. Secondary leakage reactance also occurs, particularly in wound primary current transformers, although its precise measurement is difficult. The non-linear nature of the CT magnetic circuit makes it difficult to assess the definite ohmic value representing secondary leakage reactance. It is however, normally accepted that a current transformer is of the low reactance type provided that the following conditions prevail: x The core is of the jointless ring type (including spirally wound cores). x The secondary turns are substantially evenly distributed along the whole length of the magnetic circuit. The choice of secondary current rating is determined largely by the secondary winding burden and the standard practice of the user. Standard CT secondary current ratings are 5A and 1A. The burden at rated current imposed by digital or numerical relays or instruments is largely independent of the rated value of current. This is because the winding of the device has to develop a given number of ampere-turns at rated current, so that the actual number of turns is inversely proportional to the current, and the impedance of the winding varies inversely with the square of the current rating. However, electromechanical or static earth-fault relays may have a burden that varies with the current tapping used. Interconnection leads do not share this property, however, being commonly of standard cross-section regardless of rating. Where the leads are long, their resistance may be appreciable, and the resultant burden varies with the square of the current rating. For example a CT lead run of the order of 200 metres, a typical distance for outdoor EHV switchgear, could have a loop resistance of approximately 3 ohms. The CT lead VA burden if a 5A CT is used would be 75VA, to which must be added the relay burden (up to of perhaps 10VA for an electromechanical relay, but less than 1VA for a numerical relay), making a total of 85VA. Such a burden would require the CT to be very large and expensive, particularly if a high accuracy limit factor were also applicable. With a 1A CT secondary rating, the lead burden is reduced to 3VA, so that with the same relay burden the total becomes a maximum of 13VA. This can be provided by a CT of normal dimensions, resulting in a saving in size, weight and cost. Hence modern CTs tend to have secondary windings of 1A rating. However, where the primary rating is high, say above 2000A, a CT of higher secondary rating may be used, to limit © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-11 Network Protection & Automation Guide the number of secondary turns. In such a situation secondary ratings of 2A, 5A or, in extreme cases, 20A, might be used. The maximum transient occurs when sin other condition need be examined. 6.4.9 Rated Short-Time Current So: A current transformer is overloaded while system short-circuit currents are flowing and is short-time rated. Standard times for which the CT must be able to carry rated short-time current (STC) are 0.25, 0.5, 1.0, 2.0 or 3.0 seconds. D E 1 and no ª § º S· I p «sin ¨ Zt  ¸  e  R L t » 2¹ ¬ © ¼ ip Equation 6.2 When the current is passed through the primary winding of a current transformer, the response can be examined by replacing the CT with an equivalent circuit as shown in Figure 6.10(b). A CT with a particular short-time current/ time rating carries a lower current for a longer time in inverse proportion to the square of the ratio of current values. The converse, however, cannot be assumed, and larger current values than the STC rating are not permissible for any duration unless justified by a new rating test to prove the dynamic capability. As the 'ideal' CT has no losses, it transfers the entire function, and all further analysis can be carried out in terms of equivalent secondary quantities (is and Is). A simplified solution is obtainable by neglecting the exciting current of the CT. 6.4.10 Transient Response of a Current Transformer When accuracy of response during very short intervals is being studied, it is necessary to examine what happens when the primary current is suddenly changed. The effects are most important, and were first observed in connection with balanced forms of protection, which were liable to operate unnecessarily when short-circuit currents were suddenly established. The flux developed in an inductance is obtained by integrating the applied e.m.f. through a time interval: t2 K ³ vdt I t1 Equation 6.3 6.4.10.1 Primary Current Transient For the CT equivalent circuit, the voltage is the drop on the burden resistance Rb. The power system, neglecting load circuits, is mostly inductive, so that when a short circuit occurs, the fault current that flows is given by: Ep ip R Z L 2 2 2 >sin Zt  E  D  sin D  E e  R / L ) t Integrating for each component in turn, the steady state peak flux is given by: @ 3S 2Z IA KRb I s Equation 6.1 where: ³ S Z S· § sin ¨ Zt  ¸dt 2¹ © KRb I s Z Ep = peak system e.m.f. R = system resistance Equation 6.4 L = system inductance The transient flux is given by: E = initial phase angle governed by instant of fault occurrence D = system power factor angle = tan 1 ZL R The first term of Equation 6.1 represents the steady state alternating current, while the second is a transient quantity responsible for displacing the waveform asymmetrically. Ep R 2  Z 2 L2 6-12 f KRb I s ³ e  R L t dt IB 0 KRb I s L R Equation 6.5 Hence, the ratio of the transient flux to the steady state value is: is the steady state peak current Ip © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers IB IA ZL X R R where X and R are the primary system reactance and resistance values. The CT core has to carry both fluxes, so that: IC § © I A  I B I A ¨1  X· ¸ R¹ Equation 6.6 The term (1+X/R) has been called the 'transient factor' (TF), the core flux being increased by this factor during the transient asymmetric current period. From this it can be seen that the ratio of reactance to resistance of the power system is an important feature in the study of the behaviour of protection relays. Alternatively, L/R is the primary system time constant T, so that the transient factor TF can be written: TF 1  ZL R 1  ZT Again, fT is the time constant expressed in cycles of the a.c. quantity T’ so that: TF 1  2SfT Figure 6.14: Response of a CT of infinite shunt impedance to transient asymmetric primary current Since a CT requires a finite exciting current to maintain a flux, it does not remain magnetised (neglecting hysteresis), and for this reason a complete representation of the effects can only be obtained by including the finite inductance of the CT in the calculation. The response of a current transformer to a transient asymmetric current is shown in Figure 6.15. 1.0 1  2ST ' 0.9 This latter expression is particularly useful when assessing a recording of a fault current, because the time constant in cycles can be easily estimated and leads directly to the transient factor. For example, a system time constant of three cycles results in a transient factor of (1+6 S ), or 19.85; that is, the CT would be required to handle almost twenty times the maximum flux produced under steady state conditions. The above theory is sufficient to give a general view of the problem. In this simplified treatment, no reverse voltage is applied to demagnetise the CT, so that the flux would build up as shown in Figure 6.14. e 0.8  t T1 e 0.7  t T ie 0.6 0.5 0.4 0.3 0.2 0.1 i's 0 -0.1 Time (secs) ie = Transient exciting current i cs = Secondary output current to burden T = 0.06s T1= 0.12s Figure 6.15: Response of a current transformer to a transient asymmetric current Let is = the nominal secondary current © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-13 Network Protection & Automation Guide i’s = the actual secondary output current chord. The above theory is sufficient to give a good insight into the problem and to allow most practical issues to be decided. ie = the exciting current then: d. is = ie + i’s Equation 6.7 also, die dt Le Rbi 's IB developed in Equation 6.5 has to be regarded as Equation 6.8 where: die dt Rbie Le Rbis Le Equation 6.9 which gives for the transient term ie I1 T e t T1  e t T T1  T where: T = primary system time constant L/R T1 = CT secondary circuit time constant Le/Rb I1 = prospective peak secondary current 6.4.10.2 Practical Conditions Practical conditions differ from theory for the following reasons: a. 6-14 The effect of hysteresis, apart from loss as discussed under (b) above, is not included. Hysteresis makes the inductance different for flux build up and decay, so that the secondary time constant is variable. Moreover, the ability of the core to retain a 'remanent' flux means that the value of No account has been taken of secondary leakage or burden inductance. This is usually small compared with Le so has little effect on the maximum transient flux. b. Iron loss has not been considered. This has the effect of reducing the secondary time constant, but the value of the equivalent resistance is variable, depending upon both the sine and exponential terms. Consequently, it cannot be included in any linear theory and is too complicated for a satisfactory treatment to be evolved. c. The theory is based upon a linear excitation characteristic. This is only approximately true up to the knee-point of the excitation curve. A precise solution allowing for non-linearity is not practicable. Solutions have been sought by replacing the excitation curve with several chords; a linear analysis can then be made for the extent of each an increment of flux from any possible remanent value positive or negative. The formula would then be reasonable provided the applied current transient did not produce saturation. A precise calculation of the flux and excitation current is not feasible; the value of the study is to explain the observed phenomena. The asymmetric (or d.c.) component can be regarded as building up the mean flux over a period corresponding to several cycles of the sinusoidal component, during which period the latter component produces a flux swing about the varying 'mean level' established by the former. The asymmetric flux ceases to increase when the exciting current is equal to the total asymmetric input current, since beyond this point the output current, and hence the voltage drop across the burden resistance, is negative. Saturation makes the point of equality between the excitation current and the input occur at a flux level lower than would be expected from linear theory. When the exponential component drives the CT into saturation, the magnetising inductance decreases, causing a large increase in the alternating component ie. The total exciting current during the transient period is of the form shown in Figure 6.16 and the corresponding resultant distortion in the secondary current output, due to saturation, is shown in Figure 6.17. Time Figure 6.16: Typical exciting current of CT during transient asymmetric input current © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers Current 6.4.12 Test Windings Figure 6.17: Distortion in secondary current due to saturation The presence of residual flux varies the starting point of the transient flux excursion on the excitation characteristic. Remanence of like polarity to the transient reduces the value of symmetric current of given time constant which the CT can transform without severe saturation. Conversely, reverse remanence greatly increases the ability of a CT to transform transient current. If the CT were the linear non-saturable device considered in the analysis, the sine current would be transformed without loss of accuracy. In practice the variation in excitation inductance caused by transferring the centre of the flux swing to other points on the excitation curve causes an error that may be very large. The effect on measurement is of little consequence, but for protection equipment that is required to function during fault conditions, the effect is more serious. The output current is reduced during transient saturation, which may prevent the relays from operating if the conditions are near to the relay setting. This must not be confused with the increased r.m.s. value of the primary current due to the asymmetric transient, a feature which sometimes offsets the increase ratio error. In the case of balanced protection, during through faults the errors of the several current transformers may differ and produce an out-of-balance quantity, causing unwanted operation. 6.4.11 Harmonics During the Transient Period When a CT is required to develop a high secondary e.m.f. under steady state conditions, the non-linearity of the excitation impedance causes some distortion of the output waveform. In addition to the fundamental current, such a waveform contains odd harmonics only. However, when the CT is saturated unidirectionally while being simultaneously subjected to a small a.c. quantity, as in the transient condition discussed above, the output contains both odd and even harmonics. Usually the lower numbered harmonics are of greatest amplitude and the second and third harmonic components may be of considerable value. This may affect relays that are sensitive to harmonics. On-site conjunctive testing of current transformers and the apparatus that they energise is often required. It may be difficult, however, to pass a suitable value of current through the primary windings, because of the scale of such current and in many cases because access to the primary conductors is difficult. Additional windings can be provided to make such tests easier and these windings are usually rated at 10A. The test winding inevitably occupies appreciable space and the CT costs more. This should be weighed against the convenience achieved and often the tests can be replaced by alternative procedures. 6.4.13 Use of IEEE Standard Current Transformers Most of this chapter has been based around IEC standards for current transformers. Parts of the world preferring IEEE specifications for CTs may require an easy method of converting requirements between the two. In reality, the fundamental technology and construction of the CTs remains the same, however the knee-point voltage is specified in a different way. IEC CT excitation curves are typically drawn on linear scales, whereas IEEE CT standards prefer to use log-log scales, defining the knee point as the excitation voltage at which the gradient of the curve is 45o. The voltage found by this definition is typically 5 to 10% different to the point on the excitation curve found by the IEC definition, as in Figure 6.12. An additional complication is that the IEC voltage is an e.m.f., which means that it is not an actual measurable voltage at the CT terminals. The e.m.f. is the internal voltage, compounded by any voltage drop across the CT winding resistance. The IEEE specifications relate to a terminal voltage, which is often referred to as a “C class” voltage rating. This means that a C200 rating CT has a knee voltage of 200V according to the IEEE definition of the knee point. Assume that the IEC knee point voltage required in a protection application is VkIEC. The IEEE C class standard voltage rating required is lower and the method of conversion is as follows: Vc Vk IEC  In u RCT u ALF 1.05 where: Vc = IEEE C Class standard voltage rating VkIEC = IEC Knee point voltage In = CT rated current, usually always 5A for IEEE RCT = CT secondary winding resistance ALF = CT accuracy limit factor, always 20 for an IEEE CT. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-15 Network Protection & Automation Guide The factor of 1.05 accounts for the differing points on the excitation curve at which the two philosophy standards are defined. 6.5 NON-CONVENTIONAL INSTRUMENT TRANSFORMERS 6.5.1.1 Optical Sensor Concepts Certain optical sensing media (glass, crystals, plastics) show a sensitivity to electric and magnetic fields and that some properties of a probing light beam can be altered when passing through them. A simple optical transducer description is shown in Figure 6.19. The preceding types of instrument transformers have all been based on electromagnetic principles using a magnetic core. There are now available several new methods of transforming the measured quantity using optical and mass state methods. Input polariser Optical fibre Figure 6.18 shows the key features of a freestanding optical instrument transducer. Light source 45° 90° Optical sensing medium 1.0 0 + 0 Reference light input intensity Insulating function Sensor E/O converter + Communication Sensing function Instrument Transformer Optical link (fibre optics) Communication + O/E converter Secondary output Figure 6.18: Typical architecture using optical communication between sensing unit and electronic interface Non-conventional optical transducers lend themselves to smaller, lighter devices where the overall size and power rating of the unit does not have any significant bearing on the size and the complexity of the sensor. Small, lightweight insulator structures may be tailor-made to fit optical sensing devices as an integral part of the insulator. Additionally, the non-linear effects and electromagnetic interference problems in the secondary wiring of conventional VTs and CTs are minimised. Optical transducers can be separated in two families: firstly the hybrid transducers, making use of conventional electrical circuit techniques to which are coupled various optical converter systems, and secondly the ‘all-optical’ transducers that are based on fundamental, optical sensing principles. 6-16 t Zero field level 1.0 0.5 0.5 HV Bus Sensing light detector Out In 6.5.1 Optical Instrument Transducers Electronic interface 'Odd' polariser Output polariser Optical fibre t Modulated light input intensity Figure 6.19: Schematic representation of the concepts behind the optical sensing of varying electric and magnetic fields If a beam of light passes through a pair of polarising filters, and if the input and output polarising filters have their axes rotated 45q from each other, only half the light comes through. The reference light input intensity is maintained constant over time. If these two polarising filters remain fixed and a third polarising filter is placed in between them, a random rotation of this middle polariser either clockwise or anticlockwise is monitored as a varying or modulated light output intensity at the light detector. When a block of optical sensing material (glass or crystal) is immersed in a varying magnetic or electric field, it plays the role of the ‘odd’ polariser. Changes in the magnetic or electric field in which the optical sensor is immersed are monitored as a varying intensity of the probing light beam at the light detector. The light output intensity fluctuates around the zerofield level equal to 50% of the reference light input. This modulation of the light intensity due to the presence of varying fields is converted back to time-varying currents or voltages. A transducer uses a magneto-optic effect sensor for optical current measuring applications. This reflects the fact that the sensor is not basically sensitive to a current but to the magnetic field generated by this current. Solutions exist using both wrapped fibre optics and bulk glass sensors as the optical sensing medium. However, most optical voltage transducers rely on an electro-optic effect sensor. This reflects the fact that the sensor used is sensitive to the imposed electric field. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers 6.5.1.2 Hybrid Transducers The hybrid family of non-conventional instrument transducers can be divided in two types: those with active sensors and those with passive sensors. The idea behind a transducer with an active sensor is to change the existing output of the conventional instrument transformer into an optically isolated output by adding an optical conversion system (Figure 6.19). This conversion system may require a power supply of its own: this is the active sensor type. The use of an optical isolating system serves to de-couple the instrument transformer output secondary voltages and currents from earthed or galvanic links. Therefore the only link that remains between the control-room and the switchyard is a fibre optic cable. A.C. line current Optical fibre Magneto-optic sensor Magnetic field Optical fibre (a) 'Free-field' type A.C. line current 6.5.1.3 ‘All-optical’ Transducers These instrument transformers are based entirely on optical materials and are fully passive. The sensing function is achieved directly by the sensing material and a simple fibre optic cable running between the base of the unit and the sensor location provides the communication link. The sensing element consists of an optical material that is positioned in the electric or magnetic field to be sensed. The sensitive element of a current measuring device is either located freely in the magnetic field (Figure 6.20(a)) or it can be immersed in a field-shaping magnetic ‘gap’ (Figure 6.20(b)). In the case of a voltage-sensing device (Figure 6.21) the same alternatives exist, this time for elements that are sensitive to electric fields. Both sensors can be combined in a single compact housing, providing both a CT and VT to save space in a substation. Magnetic field Optical fibres Gapped Magneto-optic sensor magnetic core (b) 'Field-shaping' type Figure 6.20: Optical current sensor based on the magnetic properties of optical materials 'Floating' electrode Electro-optic sensor A.C. line voltage In all cases there is an optical fibre that channels the probing reference light from a source into the medium and another fibre that channels the light back to the analysing circuitry. In sharp contrast with a conventional free-standing instrument transformer, the optical instrument transformer needs an electronic interface module to function. Therefore its sensing principle (the optical material) is passive but its operational integrity relies on a powered interface. Optical fibres Reference electrode (a) 'Free-field' type Reference electrode A.C. line voltage Light path Electro-optic sensor Reference electrode Optical fibres (b) 'Field shaping' type Figure 6.21: Optical voltage sensor based on the electrical properties of optical materials © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-17 Network Protection & Automation Guide Typically, current transducers take the shape of a closed loop of light-transparent material, fitted around a straight conductor carrying the line current (Figure 6.22). In this case a bulk-glass sensor unit is depicted (Figure 6.22(a)), along with a wrapped fibre sensor example, as shown in Figure 6.22(b) and Figure 6.23. Light detectors are very sensitive devices and the sensing material can be selected to scale-up readily for larger currents. However, ‘all-optical’ voltage transducers are not ideally suited to extremely high line voltages. Two concepts using a ‘full voltage’ sensor are shown in Figure 6.24. AC line current Figure 6.23: Alstom COSI-NXCT F3 flexible optical current transformer in a portable substation application AC line current Bulk glass sensing element Light in Light in Optical fibres Light out Fibre sensing element Light out Conductor (b) 'All-fibre' sensor concept (a) Glass sensor approach Dome Electro-optic sensor (Bulk-glass transducer) Electro-optic sensor ('All-fibre' transducer) AC H1 line current Fibre optic cable conduit H2 (a) 'Live tank' Liquid /solid/ gaseous internal insulation (b) 'Dead tank' Figure 6.24: Optical voltage transducer concepts, using a ‘full-voltage’ sensor Insulator column Fibre junction box Sensor #1 Fibre optic Sensor #2 cables Figure 6.22: Conceptual design of a double-sensor optical CT 6-18 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers Figure 6.26 Cross section of an Alstom CTO 72.5kV to 765kV current transformer with an optical sensor Figure 6.25: Installation of a CT with an optical sensor 6.5.2 Other Sensing Systems There are several other sensing systems that can be used, as described in the following sections. 6.5.2.1 Zero-flux (Hall Effect) Current Transformer In this case the sensing element is a semi-conducting wafer that is placed in the gap of a magnetic concentrating ring. This type of transformer is also sensitive to d.c. currents. The transformer requires a power supply that is fed from the line or from a separate power supply. The sensing current is typically 0.1% of the current to be measured. In its simplest shape, the Hall effect voltage is directly proportional to the magnetising current to be measured. For more accurate and more sensitive applications, the sensing current is fed through a secondary, multiple-turn winding, placed around the magnetic ring to balance out the gap magnetic field. This zero-flux or null-flux version allows very accurate current measurements in both d.c. and high-frequency applications. A schematic representation of the sensing part is shown in Figure 6.27. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-19 Network Protection & Automation Guide Magnetic concentrator (gapped magnetic core) Air core toroidal coil Electrical to optical converter Optical fibres i V i Current carrying conductor Sensing current Figure 6.29: Schematic representation of a Rogowski coil, used for current sensing Sensing element Figure 6.27: Conceptual design of a Hall-effect current sensing element fitted in a field-shaping gap 6.5.2.2 Hybrid Magnetic-Optical Sensor This type of transformer is mostly used in applications such as series capacitive compensation of long transmission lines, where a non-grounded measurement of current is required. In this case, several current sensors are required on each phase to achieve capacitor surge protection and balance. The preferred solution is to use small toroidally wound magnetic core transformers connected to fibre optic isolating systems. These sensors are usually active sensors because the isolated systems require a power supply. This is shown in Figure 6.28. Electrical to optical converter/transmitter Burden Optical fibres Current transformer Figure 6.28: Design principle of a hybrid magnetic current transformer fitted with an optical transmitter 6.5.2.3 Rogowski Coils The Rogowski coil is based on the principle of an air-cored current transformer with a very high load impedance. The secondary winding is wound on a toroid of insulation material. In most cases the Rogowski coil is connected to an amplifier, to deliver sufficient power to the connected measuring or protection equipment and to match the input impedance of this equipment. The Rogowski coil requires integration of the magnetic field and therefore has a time and phase delay while the integration is completed. This can be corrected for in a digital protection relay. The schematic representation of the Rogowski coil sensor is shown in Figure 6.29. 6-20 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 6 ˜ Current and Voltage Transformers © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 6-21 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 7 Relay Technology 7.1 7.2 7.3 7.4 7.5 7.6 7.7 Introduction Electromechanical Relays Static Relays Digital Relays Numerical Relays Additional Features of Numerical Relays Numerical Relay Considerations 7.1 INTRODUCTION This chapter describes how relay technology has changed. The electromechanical relay in all of its different forms has been replaced successively by static, digital and numerical relays, each change bringing with it reductions in size and improvements in functionality. Reliability levels have also been maintained or even improved and availability significantly increased due to techniques not available with older relay types. This represents a tremendous achievement for all those involved in relay design and manufacture. This book concentrates on modern digital and numerical protection relay technology, although the vast number of electromechanical and static relays are still giving dependable service. 7.2 ELECTROMECHANICAL RELAYS These relays were the earliest forms of relay used for the protection of power systems, and they date back around 100 years. They work on the principle of a mechanical force operating a relay contact in response to a stimulus. The mechanical force is generated through current flow in one or more windings on a magnetic core or cores, hence the term electromechanical relay. The main advantage of such relays is that they provide galvanic isolation between the inputs and outputs in a simple, cheap and reliable form. Therefore these relays are still used for simple on/off switching functions where the output contacts carry substantial currents. Electromechanical relays can be classified into several different types as follows: x attracted armature x moving coil x induction x thermal x motor operated x mechanical However, only attracted armature types presently have significant applications while all other types have been superseded by more modern equivalents. Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 7-1 Network Protection & Automation Guide 7.2.1 Attracted Armature Relays These generally consist of an iron-cored electromagnet that attracts a hinged armature when energised. A restoring force is provided by a spring or gravity so that the armature returns to its original position when the electromagnet is de-energised. Typical forms of an attracted armature relay are shown in Figure 7.1. Movement of the armature opens or closes a contact. The armature either carries a moving contact that engages with a fixed one or causes a rod to move that brings two contacts together. It is easy to mount multiple contacts in rows or stacks, causing a single input to actuate several outputs. The contacts can be robust and therefore able to make, carry and break large currents under difficult conditions such as highly inductive circuits. This is still a significant advantage of this type of relay that ensures its continued use. operating time of as little as 1ms. Operating power is typically 0.05-0.2 watts, but could be as large as 80 watts for a relay with several heavy-duty contacts and a high degree of resistance to mechanical shock. Some applications need a polarised relay. This is a permanent magnet added to the basic electromagnet. Both self-reset and bistable forms can be made using the basic construction shown in Figure 7.2. An example of its use is to provide very fast operating times for a single contact, with speeds of less than 1msec. Figure 7.3 shows a typical attracted armature relay. (c) Solenoid relay (a) D.C. relay Figure 7.2: Typical polarised relay (b) Shading loop modification to pole of relay (a) for a.c. operation (d) Reed relay Figure 7.1: Typical attracted armature relays The energising quantity can be either an a.c. or a d.c. current. If an a.c. current is used, there is chatter due to the flux passing through zero every half cycle. A common solution is to split the magnetic pole and provide a copper loop around one half. The flux is then phase-shifted in that pole so the total flux is never equal to zero. Conversely, for relays energised using a d.c. current, remanent flux may prevent the relay from releasing when the actuating current is removed. This can be avoided by preventing the armature from contacting the electromagnet by a non-magnetic stop, or constructing the electromagnet using a material with very low remanent flux properties. Operating speed, power consumption and the number and type of contacts required are a function of the design. The typical attracted armature relay has an operating speed of between 100ms and 400ms, but reed relays (whose use spanned a relatively short period in the history of protection relays) with light current contacts can be designed to have an 7-2 Figure 7.3: Attracted armature relay in manufacture © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 7  Relay Technology 7.3 STATIC RELAYS The term ‘static’ implies that the relay has no moving parts. This is not strictly the case for a static relay, as the output contacts are still generally attracted armature relays. In a protection relay, the term ‘static’ refers to the absence of moving parts to create the relay characteristic. Introduction of static relays began in the early 1960s. Their design is based on the use of analogue electronic devices instead of coils and magnets to create the relay characteristic. Early versions used discrete devices such as transistors and diodes with resistors, capacitors and inductors. However, advances in electronics enabled the use of linear and digital integrated circuits in later versions for signal processing and implementation of logic functions. Although basic circuits were common to several relays, each protection function had its own case, so complex functions required several cases of interconnected hardware. User programming was restricted to the basic functions of adjustment of relay characteristic curves. Therefore they can be considered as an analogue electronic replacement for electromechanical relays, with some additional flexibility in settings and some saving in space requirements. In some cases, relay burden is reduced, reducing CT/VT output requirements. Several design problems had to be solved with static relays, such as a reliable d.c. power source and measures to prevent damage to vulnerable electronic circuits. Substation environments are particularly hostile to electronic circuits due to electrical interference of various forms that are commonly found, such as switching operations and the effect of faults. Although the d.c. supply can be generated from the measured quantities of the relay, this has the disadvantage of increasing the burden on the CTs or VTs, and there is a minimum primary current or voltage below which the relay will not operate. This directly affects the possible sensitivity of the relay. So provision of an independent, highly reliable and secure source of relay power supply was an important consideration. To prevent maloperation or destruction of electronic devices during faults or switching operations, sensitive circuitry is housed in a shielded case to exclude common mode and radiated interference. The devices are also sensitive to electrostatic discharge (ESD), requiring special precautions during handling. ESD damage may not be immediately apparent but may cause premature failure of the relay. Therefore, radically different relay manufacturing facilities are required compared to electromechanical relays. Calibration and repair is no longer a task performed in the field without specialised equipment. Figure 7.4 shows a typical static relay. Figure 7.4: Busbar supervision static relay 7.4 DIGITAL RELAYS Digital protection relays introduced a step change in technology. Microprocessors and microcontrollers replaced analogue circuits used in static relays to implement relay functions. Early examples were introduced around 1980 and with improvements in processing capacity are still current technology for many relay applications. However, such technology could be completely superseded by numerical relays. Compared to static relays, digital relays use analogue to digital conversion of all measured quantities and use a microprocessor to implement the protection algorithm. The microprocessor may use a counting technique or use Discrete Fourier Transforms (DFT) to implement the algorithm. However, these microprocessors have limited processing capacity and associated memory compared to numerical relays. Therefore the functionality is limited mainly to the protection function itself. Compared to an electromechanical or static relay, digital relays have a wider range of settings, greater accuracy and a communications link to a remote computer. Figure 7.5 shows a typical digital relay. Digital relays typically use 8 or 16-bit microprocessors that were later used in modems, hard disk controllers or early car engine management systems. The limited power of the microprocessors used in digital relays restricts the number of samples of the waveform that can be measured per cycle. This limits the speed of operation of the relay in certain applications. Therefore a digital relay for a particular protection function may have a longer operation time than the static relay equivalent. However, the extra time is insignificant compared to overall tripping time and possible effects on power system stability. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 7-3 Network Protection & Automation Guide Figure 7.5: Second generation distribution digital relay (1982) 7.5 NUMERICAL RELAYS The distinction between digital and numerical relays is particular to Protection. Numerical relays are natural developments of digital relays due to advances in technology. They use one or more digital signal processors (DSP) optimised for real time signal processing, running the mathematical algorithms for the protection functions. Figure 7.7: First generation distribution numerical relay The continuing reduction in the cost and size of microprocessors, memory and I/O circuitry leads to a single item of hardware for a range of functions. For faster real time processing and more detailed analysis of waveforms, several DSPs can be run in parallel. Many functions previously implemented in separate items of hardware can then be included in a single item. Table 7.1 provides a list of typical functions available, while Table 7.2 summarises the advantages of a modern numerical relay over static relay equivalents. Figure 7.6, Figure 7.7 and Figure 7.8 show typical numerical relays, while Figure 7.9 and Figure 7.10 show typical numerical relay boards. Figure 7.6: First generation transmission numerical relay (1986) Figure 7.8: Typical modern numerical relay 7-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 7 ˜ Relay Technology Distance Protection- several schemes including user definable Overcurrent Protection (directional/non-directional) Several Setting Groups for protection values Switch-on-to-Fault Protection Power Swing Blocking Voltage Transformer Supervision Negative Sequence Current Protection Undervoltage Protection Overvoltage Protection Figure 7.9: Numerical relay processor board CB Fail Protection Fault Location CT Supervision VT Supervision Check Synchronisation Autoreclose CB Condition Monitoring CB State Monitoring User-Definable Logic Broken Conductor Detection Measurement of Power System Quantities (Current, Voltage, etc.) Fault/Event/Disturbance recorder Table 7.1: Numerical distance relay features Figure 7.10: Numerical relay redundant Ethernet board Several setting groups A numerical relay has the functionality that previously required several discrete relays, therefore the relay functions such as overcurrent or earth fault are referred to as ‘relay elements’. Each relay element is in software so with modular hardware the main signal processor can run a vast variety of relay elements. Wider range of parameter adjustment The argument against putting many features into one piece of hardware centres on the issues of reliability and availability. A failure of a numerical relay may cause many more functions to be lost, compared to applications where different functions are implemented by separate hardware items. Comparison of reliability and availability between the two methods is complex as inter-dependency of elements of an application provided by separate relay elements needs to be taken into account. Auxiliary protection functions (broken conductor, negative sequence, etc.) With the experience gained with static and digital relays, most hardware failure mechanisms are now well understood and suitable precautions taken at the design stage. Software problems are minimised by rigorous use of software design techniques, extensive prototype testing (see Chapter 21) and the ability to download updated software. Practical experience indicates that numerical relays are as reliable as relays of earlier technologies. Modern numerical relays will have comprehensive self monitoring to alert the user to any problems. Communications built in (serial, Ethernet, teleprotection, etc.) Internal Fault diagnosis Power system measurements available Distance to fault locator Disturbance recorder CB monitoring (state, condition) User-definable logic Backup protection functions in-built Consistency of operation times - reduced grading margin Table 7.2: Advantages of numerical relays over static relays 7.5.1 Hardware Architecture The typical architecture of a numerical relay is shown in Figure 7.11. It consists of one or more DSPs, some memory, digital and analogue input/output (I/O), and a power supply. Where multiple processors are used, one of them is a general controller of the I/O, Human Machine Interface (HMI) and any associated logic while the others are dedicated to the protection relay algorithms. By organising the I/O on a set of plug-in printed circuit boards (PCBs), additional I/O up to the limits of the hardware/software can be easily added. The internal communications bus links the hardware and therefore © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 7-5 Network Protection & Automation Guide is a critical component in the design. It must work at high speed, use low voltages, yet be immune to conducted and radiated interference from the electrically noisy substation environment. Excellent shielding of the relevant areas is therefore required. Digital inputs are optically isolated to prevent transients being transmitted to the internal circuitry. Analogue inputs are isolated using precision transformers to maintain measurement accuracy while removing harmful transients. Additionally, the input signals must be amplitude limited to avoid them exceeding the measurement range, otherwise the waveform is clipped, introducing harmonics. See Figure 7.12. SRAM Executable code & data, setting database data Ethernet Output relay contacts Ethernet and IRIG-B board Output relays CPU Serial data link Parallel Data Bus Ethernet comms CPU SRAM GPS interface 1pps GPS input Coprocessor board Optoinputs Relay board ADC Power supply Rear comms data Power Supply Board Power supply Watchdog contacts Rear RS485 comms where: f s = sampling rate f h = highest frequency of interest +Vref Vref Vin Vout Vref Figure 7.12: Clipping due to excessive amplitude FPGA Comms between main and coprocessor board IRIG-B fs t 2 fh -Vref Main processor board Front LCD display IRIG-B Signal Flash memory Default settings & paramaters, language text, code, present settings Digital inputs SRAM Alarm, event, fault disturbance & maintenance records The frequency of sampling must be carefully considered, as the Nyquist criterion applies: Input board Analogue Input signals Transformer Board If the sampling frequency is too low, aliasing of the input signal can occur (see Figure 7.13) so that high frequencies can appear as part of the signal in the frequency range of interest. Incorrect results are then obtained. The solution is to use an anti-aliasing filter and the correct sampling frequency on the analogue signal, filtering out the frequency components that could cause aliasing. Digital sine and cosine filters (Figure 7.12) extract the real and imaginary components of the signal; the frequency response of the filters is shown in Figure 7.13. Frequency tracking of the input signals is applied to adjust the sampling frequency so that the desired number of samples/cycle is always obtained. A modern numerical relay can sample each analogue input quantity at typically between 24 and 80 samples per cycle. Current and voltage inputs Actual signal Figure 7.11: Typical numerical relay hardware architecture Analogue signals are converted to digital form using an A/D converter. The cheapest method is to use a single A/D converter, preceded by a multiplexer to connect each of the input signals in turn to the converter. The signals may be initially input to several simultaneous sample-and–hold circuits before multiplexing, or the time relationship between successive samples must be known if the phase relationship between signals is important. The alternative is to provide each input with a dedicated A/D converter and logic to ensure that all converters perform the measurement simultaneously. 7-6 Apparent signal Sample points Figure 7.13: Signal aliasing problem © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 7 ˜ Relay Technology 7.5.2 Relay Operating System Software The software provided is commonly organised into a series of tasks operating in real time. An essential component is the Real Time Operating System (RTOS) which ensures that the other tasks are executed when required, in the correct priority. Other software depends on the function of the relay, but can be generalised as follows: xs 2­ x1 x x x ½  x 2  3  0  5  x6  7 ¾ ®0  8¯ 2 2 2 2¿ x system services software – this is comparable with the BIOS of an ordinary PC and controls the low-level I/O for the relay such as drivers for the relay hardware and boot-up sequence. x HMI interface software – this is the high level software for communicating with a user on the front panel controls or through a data link to another computer to store data such as settings or event records. x application software – this is the software that defines the protection function of the relay x auxiliary functions – software to implement other features in the relay, often structured as a series of modules to reflect the options offered by the manufacturer. 7.5.3 Relay Application Software xc 2­ x1 x x x ½  0  3  x4  5  0  7 ¾ ®x0  8¯ 2 2 2 2¿ Figure 7.14: Sine and cosine filters (simple 8 sample per cycle example) The relevant software algorithm is then applied. Firstly the quantities of interest are determined from the information in the data samples. This is often done using a Discrete Fourier Transform (DFT) and the result is magnitude and phase information for the selected quantity. This calculation is repeated for all of the quantities of interest. The quantities can then be compared with the relay characteristic, and a decision made in terms of the following: x value above setting – start timers, etc. x timer expired – action alarm/trip x value returned below setting – reset timers, etc. x value below setting – do nothing x value still above setting – increment timer, etc. Since the overall cycle time for the software is known, timers are generally implemented as counters. Figure 7.15: Filter frequency response All subsequent signal processing is carried out in software. The final digital outputs use relays to provide isolation or are sent through an external communications bus to other devices. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 7-7 Network Protection & Automation Guide 7.6 ADDITIONAL FEATURES OF NUMERICAL RELAYS The DSP in a numerical relay normally can handle both the relay protection function calculations and general management of the relay such as HMI and I/O. However, if the DSP is overloaded it cannot complete the protection algorithm calculations in the required time and the protection function is slowed. Typical functions that may be found in a numerical relay other than protection functions are described in this section. Note that not all functions are found in a particular relay. As with earlier generations of relays and according to market segmentation, manufacturers offer different versions, each with a different set of functions. Function parameters are usually displayed on the front panel of the relay and through an external communications port. 7.6.1 Measured Values Display This is perhaps the most obvious and simple function to implement, as it involves the least additional processor time. The values that the relay must measure to perform its protection function have already been acquired and processed. It is therefore a simple task to display them on the front panel, or transmit them to a remote computer or HMI station. Several extra quantities may be derived from the measured quantities, depending on the input signals available. These might include: x sequence quantities (positive, negative, zero) x power, reactive power and power factor x energy (kWh, kVArh) x max. demand in a period ( kW, kVAr; average and peak values) x harmonic quantities x frequency x temperatures/RTD status x motor start information (start time, total no. of starts/reaccelerations, total running time x distance to fault The accuracy of the measured values can only be as good as the accuracy of the transducers used such as VTs CTs, and the A/D converter. As CTs and VTs for protection functions may have a different accuracy specification to those for metering functions, such data may not be sufficiently accurate for tariff purposes. However, it is sufficiently accurate for an operator to assess system conditions and make appropriate decisions. 7-8 7.6.2 VT/CT Supervision If suitable VTs are used, supervision of the VT/CT supplies can be made available. VT supervision is made more complicated by the different conditions under which there may be no VT signal, some of which indicate VT failure and some occur because a power system fault has occurred. If only one or two phases are lost, the VT failure algorithm can be accomplished by detecting residual voltage without the presence of zero or negative phase sequence current. For loss of all three phases, a fault in the system would be accompanied by a change in the phase currents, so absence of such a change can be taken as loss of the VT signal. However, this technique fails when closing onto a dead but healthy line, so a level detector is also required to distinguish between current inrush due to line charging and that due to a fault. CT supervision is carried out more easily. The general principle is the calculation of a level of negative sequence current that is inconsistent with the calculated value of negative sequence voltage. 7.6.3 CB Control/State Indication /Condition Monitoring System operators normally require knowledge of the state of all circuit breakers under their control. The CB position-switch outputs can be connected to the relay digital inputs and therefore provide the indication of state through the communications bus to a remote control centre. Circuit breakers also require periodic maintenance of their operating mechanisms and contacts to ensure they operate when required and that the fault capacity is not affected adversely. The requirement for maintenance is a function of the number of trip operations, the cumulative current broken and the type of breaker. A numerical relay can record all of these parameters and hence be configured to send an alarm when maintenance is due. If maintenance is not carried out within a predefined time or number of trips after maintenance is required, the CB can be arranged to trip and lockout or inhibit certain functions such as auto-reclose. Finally, as well as tripping the CB as required under fault conditions, it can also be arranged for a digital output to be used for CB closure, so that separate CB close control circuits can be eliminated. 7.6.4 Disturbance Recorder (Oscillograph) The relay memory requires a certain minimum number of cycles of measured data to be stored for correct signal processing and detection of events. The memory can easily be expanded to allow storage of a greater time period of input © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 7 ˜ Relay Technology data, both analogue and digital, plus the state of the relay outputs. It then has the capability to act as a disturbance recorder for the circuit being monitored, so that by freezing the memory at the instant of fault detection or trip, a record of the disturbance is available for later download and analysis. It may be inconvenient to download the record immediately, so facilities may be provided to capture and store a number of disturbances. In industrial and small distribution networks, this may be all that is required. In transmission networks, it may be necessary to provide a single recorder to monitor several circuits simultaneously, and in this case, a separate disturbance recorder is still required. For more information on the different types of disturbance recording, see Chapter 22. 7.6.5 Time Synchronisation Disturbance records and data relating to energy consumption requires time tagging to serve any useful purpose. Although there is an internal clock, this is of limited accuracy and use of this clock to provide time information may cause problems if the disturbance record has to be correlated with similar records from other sources to obtain a complete picture of an event. Many numerical relays have the facility for time synchronisation from an external clock. The standard normally used is an IRIG-B or IEEE 1588 signal, which may be derived from several sources including a GPS satellite receiver. 7.6.6 Programmable Logic Logic functions are well suited to implementation using microprocessors. The implementation of logic in a relay is not new, as functions such as intertripping and auto-reclose require a certain amount of logic. However, by providing a substantial number of digital I/O and making the logic capable of being programmed using suitable off-line software, the functionality of such schemes can be enhanced or additional features provided. For instance, an overcurrent relay at the receiving end of a transformer feeder could use the temperature inputs provided to monitor transformer winding temperature and provide alarm or trip facilities to the operator or upstream relay, eliminating the need for a separate winding temperature relay. There may be other advantages such as different logic schemes required by different utilities that no longer need separate relay versions, or some hard-wired logic to implement, and all of these reduce the cost of manufacture. It is also easier to customise a relay for a specific application, and eliminate other devices that would otherwise be required. operational reasons on a regular basis, such as supply from normal or emergency generation. Different configurations may require different relay settings to maintain the desired level of network protection. Fault levels are significantly different on parts of the network that are energised under normal and emergency generation. This problem can be overcome by the provision within the relay of several setting groups, only one of which is in use at any one time. Changeover between groups can be achieved from a remote command from the operator, or possibly through the programmable logic system. This may obviate the need for duplicate relays to be fitted with some form of switching arrangement of the inputs and outputs depending on network configuration. Also the operator can program the relay remotely with a group of settings if required. 7.6.8 Conclusions The extra facilities in numerical relays may avoid the need for other measurement and control devices to be fitted in a substation. Also numerical relays have functionality that previously required separate equipment. The protection relay no longer performs a basic protection function but is an integral and major part of a substation automation scheme. The choice of a protection relay rather than some other device is logical as the protection relay is probably the only device that is virtually mandatory on circuits of any significant rating. Therefore the functions previously carried out by separate devices such as bay controllers, discrete metering transducers and similar devices are now found in a protection relay. It is now possible to implement a substation automation scheme using numerical relays as the main hardware provided at bay level. As the power of microprocessors continues to grow and pressure on operators to reduce costs continues, this trend will continue; one obvious development is the provision of RTU facilities in designated relays that act as local concentrators of information within the overall network automation scheme. 7.7 NUMERICAL RELAY CONSIDERATIONS The introduction of numerical relays replaces some of the issues of previous generations of relays with new ones. Some of the new issues that must be addressed are as follows: x software version control x relay data management x testing and commissioning 7.6.7 Provision of Setting Groups Historically, electromechanical and static relays have been provided with fixed plug settings applied to the relay. Unfortunately, power systems change their topology due to © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 7-9 Network Protection & Automation Guide 7.7.1 Software Version Control Numerical relays perform their functions in software. The process used for software generation is no different in principle to that for any other device using real-time software, and includes the difficulties of developing code that is error-free. Manufacturers must therefore pay particular attention to the methodology used for software generation and testing to ensure that as far as possible, the code contains no errors. 7.7.3 Relay Testing and Commissioning Numerical relays perform many more functions than earlier generations of relays so testing them is more complex. Site commissioning is usually restricted to running the in-built software self-check, verifying that currents and voltages measured by the relay are correct, and exercising a subset of the protection functions. Any problems revealed by such tests require specialist equipment to resolve so it is simpler to replace a faulty relay and send it for repair. If a manufacturer advances the functionality available in a new software version of a relay, or where problems are discovered in software after the release of a numerical relay, a field upgrade may be desirable. This process then requires a rigorous system of software version control to keep track of: x the different software versions in existence x the differences between each version x the reasons for the change x relays fitted with each of the versions With an effective version control system, manufacturers are able to advise users in the event of reported problems if the problem is a known software related problem and what remedial action is required. With the aid of suitable software held by a user, it may be possible to download the new software version instead of requiring a visit from a service engineer. Figure 7.16: Quality inspection of a numerical relay printed circuit board 7.7.2 Relay Data Management A numerical relay usually provides many more features than a relay using static or electromechanical technology. To use these features, the appropriate data must be entered into the relay’s memory and it is good practice to keep a backup copy. The amount of data per numerical relay may be 10-100 times that of an equivalent electromechanical relay, to which must be added the possibility of user-defined logic functions. The task of entering the data correctly into a numerical relay becomes a much more complex task than previously, which adds to the possibility of a mistake being made. Similarly, the amount of data that must be recorded is much larger, requiring larger storage. The problems have been addressed with software to automate the preparation and download of relay setting data from a laptop PC connected to a communications port of the relay. As part of the process, the setting data can be read back from the relay and compared with the desired settings to ensure that the download has been error-free. A copy of the setting data (including user-defined logic schemes where used) can also be stored on the computer. These can then be printed or uploaded to the user’s database facilities. 7-10 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 7 ˜ Relay Technology © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 7-11 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 8 Protection Signalling and Intertripping 8.1 8.2 8.3 8.4 8.5 8.6 Introduction Unit Protection Schemes Teleprotection Commands Performance Requirements Transmission Media, Interference and Noise Signalling Methods 8.1 INTRODUCTION Unit protection schemes can be formed by several relays located remotely from each other and some distance protectionn schemes. Such unit protection schemes need communication between each location to achieve a unit protection function. This communication is known as protection signalling. Communications facilities are also needed when remote circuit breakers need to be operated due to a local event. This communication is known as intertripping. The communication messages involved may be quite simple, involving instructions for the receiving device to take some defined action (trip, block, etc.), or it may be the passing of measured data in some form from one device to another (as in a unit protection scheme). Various types of communication links are available for protection signalling, for example: x private pilot wires installed by the utility x pilot wires or channels rented from a communications company x carrier channels at high frequencies over the power lines x radio channels at very high or ultra high frequencies x optical fibres Whether or not a particular link is used depends on factors such as the availability of an appropriate communication network, the distance between protection relaying points, the terrain over which the power network is constructed, as well as cost. Protection signalling is used to implement unit protection schemes, provide teleprotection commands, or implement intertripping between circuit breakers. 8.2 UNIT PROTECTION SCHEMES Phase comparison and current differential schemes use signalling to convey information concerning the relaying quantity - phase angle of current and phase and magnitude of current respectively - between local and remote relaying points. Comparison of local and remote signals provides the basis for both fault detection and discrimination of the schemes. Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 8-1 Network Protection & Automation Guide Figure 8.1: Application of protection signalling and its relationship to other systems using communication. (Shown as a unidirectional system for simplicity) Details of Unit Protection schemes are given in Chapter 10. Communications methods are covered later in this Chapter. 8.3 TELEPROTECTION COMMANDS Some Distance Protection schemes described in Chapter 12 use signalling to convey a command between local and remote relaying points. Receipt of the information is used to aid or speed up clearance of faults within a protected zone or to prevent tripping from faults outside a protected zone. Teleprotection systems are often referred to by their mode of operation, or the role of the teleprotection command in the system. 8.3.1 Intertripping Intertripping is the controlled tripping of a circuit breaker to complete the isolation of a circuit or piece of apparatus in sympathy with the tripping of other circuit breakers. The main use of such schemes is to ensure that protection at both ends of a faulted circuit isolates the equipment concerned. Possible circumstances when it may be used are: x feeder protection applied to transformer–feeder circuits. Faults on the transformer windings may operate the transformer protection but not the feeder protection. Similarly, some earth faults may not be detected due to transformer connections x faults between the CB and feeder protection CTs, when these are located on the feeder side of the CB. Buszone protection does not result in fault clearance – the fault is still fed from the remote end of the feeder, while feeder unit protection may not operate as the fault is outside the protected zone x Some distance protection schemes use intertripping to improve fault clearance times for particular kinds of fault – see Chapters 12/13 Intertripping schemes use signalling to convey a trip command to remote circuit breakers to isolate circuits. For high reliability EHV protection schemes, intertripping can be used to provide back-up to main protection, or back-tripping in the case of breaker failure. Three types of intertripping are commonly encountered, as described in the following sections. x a feeder with a weak infeed at one end, insufficient to operate the protection for all faults 8-2 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 8 ˜ Protection Signalling and Intertripping 8.3.2 Direct Tripping In direct tripping applications, intertrip signals are sent directly to the master trip relay. Receipt of the command causes circuit breaker operation. The method of communication must be reliable and secure because any signal detected at the receiving end causes a trip of the circuit at that end. The communications system must be designed so that interference on the communication circuit does not cause spurious trips. If a spurious trip occurs, the primary system might be unnecessarily isolated. High security means that an intertrip command does not spuriously pick up due to a noisy channel. High dependability is the means by which a blocking or permissive command may easily pass through noise and still be received at the remote line end. Figure 8.1 shows the typical applications of protection signalling and their relationship to other signalling systems commonly required for control and management of a power system. Of course, not all of the protection signals shown are required in any particular scheme. 8.3.3 Permissive Tripping 8.4 Permissive trip commands are always monitored by a protection relay. The circuit breaker is tripped when receipt of the command coincides with a ‘start’ condition being detected by the protection relay at the receiving end responding to a system fault. Requirements for the communications channel are less onerous than for direct tripping schemes, since receipt of an incorrect signal must coincide with a ‘start’ of the receiving end protection for a trip operation to take place. The intention of these schemes is to speed up tripping for faults occurring within the protected zone. Overall fault clearance time is the sum of: 8.3.4 Blocking Scheme Blocking commands are initiated by a protection element that detects faults external to the protected zone. Detection of an external fault at the local end of a protected circuit results in a blocking signal being transmitted to the remote end. At the remote end, receipt of the blocking signal prevents the remote end protection operating if it had detected the external fault. Loss of the communications channel is less serious for this scheme than in others as loss of the channel does not result in a failure to trip when required. However, the risk of a spurious trip is higher. Figure 8.2 shows the typical trade-off triangle that applies when determining the required performance for teleprotection. PERFORMANCE REQUIREMENTS x signalling time x protection relay operating time x trip relay operating time x circuit breaker operating time The overall time must be less than the maximum time for which a fault can remain on the system for minimum plant damage, loss of stability, etc. Fast operation is therefore a prerequisite of most signalling systems. Typically the time allowed for the transfer of a command is of the same order as the operating time of the associated protection relays. Nominal operating times range from 4 to 40ms dependent on the mode of operation of the teleprotection system. Protection signals are subjected to the noise and interference associated with each communication medium. If noise reproduces the signal used to convey the command, unwanted commands may be produced, whilst if noise occurs when a command signal is being transmitted, the command may be retarded or missed completely. Performance is expressed in terms of security, dependability and speed. Security is assessed by the probability of an unwanted command occurring, and dependability is assessed by the probability of missing a command. Poor security is indicated by a high probability of an unwanted command being received (Puc), therefore a lower Puc figure is generally preferable. Poor dependability is indicated by a high probability of a missing command (Pmc). Generally a lower Pmc figure is also preferable. The required degree of security and dependability is related to the mode of operation, the characteristics of the communication medium and the operating standards of the particular utility. Typical design objectives for teleprotection systems are not Figure 8.2: Teleprotection performance trade-off triangle © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 8-3 Network Protection & Automation Guide more than one incorrect trip per 500 equipment years and less than one failure to trip in every 1000 attempts, or a delay of more than 50msec should not occur more than once per 10 equipment years. To achieve these objectives, special emphasis may be attached to the security and dependability of the teleprotection command for each mode of operation in the system, as follows. 8.4.1 Performance Requirements – Intertripping Since any unwanted command causes incorrect tripping, very high security is required at all noise levels up to the maximum that might ever be encountered. 8.4.2 Performance Requirements – Permissive Tripping Security somewhat lower than that required for intertripping is usually satisfactory, since incorrect tripping can occur only if an unwanted command happens to coincide with operation of the protection relay for an out-of-zone fault. For permissive over-reach schemes, resetting after a command should be highly dependable to avoid any chance of maloperations during current reversals. 8.4.3 Performance Requirements – Blocking Schemes Low security is usually adequate since an unwanted command can never cause an incorrect trip. High dependability is required since absence of the command could cause incorrect tripping if the protection relay operates for an out-of-zone fault. greatly increases the number of communication channels available for each physical fibre connection and thus enables more comprehensive monitoring of the power system to be achieved by the provision of a large number of communication channels. 8.5.1 Private Pilot Wires and Channels Pilot wires are continuous copper connections between signalling stations, while pilot channels are discontinuous pilot wires with isolation transformers or repeaters along the route between signalling stations. They may be laid in a trench with high voltage cables, laid by a separate route or strung as an open wire on a separate wood pole route. Distances over which signalling is required vary considerably. At one end of the scale, the distance may be only a few tens of metres, where the devices concerned are located in the same substation. For applications on EHV lines, the distance between devices may be between 10-100km or more. For short distances, no special measures are required against interference, but over longer distances, special send and receive relays may be required to boost signal levels and provide immunity against induced voltages from power circuits, lightning strikes to ground adjacent to the route, etc. Isolation transformers may also have to be provided to guard against rises in substation ground potential due to earth faults. The capacity of a link can be increased if multiplexing techniques are used to run parallel signalling systems but some utilities prefer the link to be used only for protection signalling. 8.5 TRANSMISSION MEDIA, INTERFERENCE AND NOISE Private pilot wires or channels can be attractive to a utility running a very dense power system with short distances between stations. The transmission media that provide the communication links involved in protection signalling are: 8.5.2 Rented Pilot Wires and Channels x private pilots x rented pilots or channels x power line carrier x radio x optical fibres Historically, pilot wires and channels (discontinuous pilot wires with isolation transformers or repeaters along the route between signalling points) have been the most widely used due to their availability, followed by Power Line Carrier Communications (PLCC) techniques and radio. In recent years, fibre-optic systems have become the usual choice for new installations, primarily due to their complete immunity from electrical interference. The use of fibre-optic cables also 8-4 These are rented from national communication authorities and, apart from the connection from the relaying point to the nearest telephone exchange, the routing is through cables forming part of the national communication network. An economic decision has to be made between the use of private or rented pilots. If private pilots are used, the owner has complete control, but bears the cost of installation and maintenance. If rented pilots are used, most of these costs are eliminated, but fees must be paid to the owner of the pilots and the signal path may be changed without warning. This may be a problem in protection applications where signal transmission times are critical. The chance of voltages being induced in rented pilots is smaller than for private pilots, as the pilot route is normally not related © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 8 ˜ Protection Signalling and Intertripping to the route of the power line with which it is associated. However, some degree of security and protection against induced voltages must be built into signalling systems. Station earth potential rise is a significant factor to be taken into account and isolation must be provided to protect both the personnel and equipment of the communication authority. The most significant hazard to be withstood by a protection signalling system using this medium arises when a linesman inadvertently connects a low impedance test oscillator across the pilot link that can generate signalling tones. Transmissions by such an oscillator may simulate the operating code or tone sequence that, in the case of direct intertripping schemes, would result in incorrect operation of the circuit breaker. Communication between relaying points may be over a twowire or four-wire link. Consequently the effect of a particular human action, for example an incorrect disconnection, may disrupt communication in one direction or both. The signals transmitted must be limited in both level and bandwidth to avoid interference with other signalling systems. The owner of the pilots impose standards in this respect that may limit transmission capacity or transmission distance, or both. With a power system operating at, say, 132kV, where relatively long protection signalling times are acceptable, signalling has been achieved above speech together with metering and control signalling on an established control network. Consequently the protection signalling was achieved at very low cost. High voltage systems; (220kV and above), have demanded shorter operating times and improved security, which has led to the renting of pilot links exclusively for protection signalling purposes. 8.5.3 Power Line Carrier Communications Techniques Where long line sections are involved, or if the route involves installation difficulties, the expense of providing physical pilot connections or operational restrictions associated with the route length require that other means of providing signalling facilities are required. Power Line Carrier Communications (PLCC) is a technique that involves high frequency signal transmission along the overhead power line, typically in the 300Hz to 3400Hz band. It is robust and therefore reliable, constituting a low loss transmission path that is fully controlled by the Utility. High voltage capacitors are used, along with drainage coils, for the purpose of injecting the signal to and extracting it from the line. Injection can be carried out by impressing the carrier signal voltage between one conductor and earth or between any two phase conductors. The basic units can be built up into a high pass or band pass filter as shown in Figure 8.3. Figure 8.3: Typical phase-to-phase coupling equipment © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 8-5 Network Protection & Automation Guide The high voltage capacitor is tuned by a tuning coil to present a low impedance at the signal frequency; the parallel circuit presents a high impedance at the signal frequency while providing a path for the power frequency currents passed by the capacitor. Receiving equipment commonly incorporates automatic gain control (AGC) to compensate for variations in attenuation of signals. High noise levels arise from lightning strikes and system fault inception or clearance. Although these are of short duration, lasting only a few milliseconds at the most, they may cause overloading of power line carrier receiving equipment. 8.5.3.1 Application Considerations Figure 8.4: Carrier coupling equipment It is necessary to minimise the loss of signal into other parts of the power system, to allow the same frequency to be used on another line. This is done with a 'line trap' or 'wave trap', which in its simplest form is a parallel circuit tuned to present a very high impedance to the signal frequency. It is connected in the phase conductor on the station side of the injection equipment. The single frequency line trap can be treated as an integral part of the complete injection equipment to accommodate two or more carrier systems. However, difficulties may arise in an overall design because at certain frequencies the actual station reactance, which is normally capacitive, tunes with the trap which is inductive below its resonant frequency. The result is a low impedance across the transmission path, preventing operation at these frequencies. This situation can be avoided by using an independent 'double frequency' or 'broad-band' trap. The attenuation of a channel is of prime importance in the application of carrier signalling because it determines the amount of transmitted energy available at the receiving end to overcome noise and interfering voltages. The loss of each line terminal is 1 to 2dB through the coupling filter, a maximum of 3dB through its broad-band trap and not more than 0.5dB per 100 metres through the high frequency cable. The high frequency transmission characteristics of power circuits are good the loss amounting to 0.02 to 0.2dB per kilometre depending upon line voltage and frequency. Line attenuation is not affected appreciably by rain, but serious increase in loss may occur when the phase conductors are thickly coated with hoar-frost or ice. Attenuations of up to three times the fair weather value have been experienced. 8-6 Signalling systems used for intertripping in particular must incorporate appropriate security features to avoid maloperation. The most severe noise levels are encountered with operation of the line isolators, and these may last for some seconds. Although maloperation of the associated teleprotection scheme may have little operational significance, since the circuit breaker at one end at least is normally already open, high security is generally required to cater for noise coupled between parallel lines or passed through line traps from adjacent lines. Signalling for permissive intertrip applications needs special consideration, as this involves signalling through a power system fault. The increase in channel attenuation due to the fault varies according to the type of fault, but most utilities select a nominal value, usually between 20 and 30dB, as an application guide. A protection signal boost facility can be employed to cater for an increase in attenuation of this order of magnitude, to maintain an acceptable signal-to-noise ratio at the receiving end, so that the performance of the service is not impaired. Most direct intertrip applications require signalling over a healthy power system, so boosting is not normally needed. In fact, if a voice frequency intertrip system is operating over a carrier bearer channel, the dynamic operating range of the receiver must be increased to accommodate a boosted signal. This makes it less inherently secure in the presence of noise during a quiescent signalling condition. 8.5.3.2 Digital Power Line Carrier The latest power line carrier equipment allows analogue, digital and mixed-mode communication. Digital communication up to 128kbits/s can be achieved using a 16kHz bandwidth. Low-latency Ethernet bridging facilities are a cost-effective communications solution for substations that have no access to any fibre network. 8.5.4 Radio Channels At first consideration, the wide bandwidth associated with radio frequency transmissions could allow the use of modems operating at very high data rates. Protection signalling © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 8 ˜ Protection Signalling and Intertripping commands could be sent by serial coded messages of sufficient length and complexity to give high security, but still achieve fast operating times. In practice, it is seldom economic to provide radio equipment exclusively for protection signalling, so standard general-purpose telecommunications channel equipment is normally adopted. Typical radio bearer equipment operates at the microwave frequencies of 0.2 to 10GHz. Because of the relatively short range and directional nature of the transmitter and receiver aerial systems at these frequencies, large bandwidths can be allocated without much chance of mutual interference with other systems. Multiplexing techniques allow several channels to share the common bearer medium and exploit the large bandwidth. In addition to voice frequency channels, wider bandwidth channels or data channels may be available, dependent on the particular system. For instance, in analogue systems using frequency division multiplexing, normally up to 12 voice frequency channels are grouped together in basebands at 1260kHz or 60-108kHz, but alternatively the baseband may be used as a 48kHz signal channel. Modern digital systems employing pulse code modulation and time division multiplexing usually provide the voice frequency channels by sampling at 8kHz and quantising to 8 bits; alternatively, access may be available for data at 64kbits/s (equivalent to one voice frequency channel) or higher data rates. Radio systems are well suited to the bulk transmission of information between control centres and are widely used for this. When the route of the trunk data network coincides with that of transmission lines, channels can often be allocated for protection signalling. More generally, radio communication is between major stations rather than the ends of individual lines, because of the need for line-of-sight operation between aerials and other requirements of the network. Roundabout routes involving repeater stations and the addition of pilot channels to interconnect the radio installation and the relay station may be possible, but overall dependability is normally much lower than for PLCC systems in which the communication is direct from one end of the line to the other. Radio channels are not affected by increased attenuation due to power system faults, but fading has to be taken into account when the signal-to-noise ratio of a particular installation is being considered. Most of the noise in such a protection signalling system is generated in the radio equipment. A polluted atmosphere can cause radio beam refraction that interferes with efficient signalling. The height of aerial tower should be limited, so that winds and temperature changes have the minimum effect on their position. 8.5.5 Optical Fibre Channels Optical fibres are fine strands of glass, which behave as wave guides for light. This ability to transmit light over considerable distances can be used to provide optical communication links with enormous information carrying capacity and an inherent immunity to electromagnetic interference. A practical optical cable consists of a central optical fibre which comprises core, cladding and protective buffer coating surrounded by a protective plastic oversheath containing strength members which, in some cases, are enclosed by a layer of armouring. To communicate information a beam of light is modulated in accordance with the signal to be transmitted. This modulated beam travels along the optical fibre and is subsequently decoded at the remote terminal into the received signal. On/off modulation of the light source is normally preferred to linear modulation since the distortion caused by non-linearities in the light source and detectors, as well as variations in received light power, are largely avoided. The light transmitter and receiver are usually laser or LED devices capable of emitting and detecting narrow beams of light at selected frequencies in the low attenuation 850, 1300 and 1550 nanometre spectral windows. The distance over which effective communications can be established depends on the attenuation and dispersion of the communication link and this depends on the type and quality of the fibre and the wavelength of the optical source. Within the fibre there are many modes of propagation with different optical paths that cause dispersion of the light signal and result in pulse broadening. The degrading of the signal in this way can be reduced by the use of 'graded index' fibres that cause the various modes to follow nearly equal paths. The distance over which signals can be transmitted is significantly increased by the use of 'monomode' fibres that support only one mode of propagation. Optical fibre channels allow communication at data rates of hundreds of megahertz over a few tens of kilometres, however, repeaters are needed for greater distances. An optical fibre can be used as a dedicated link between two items of terminal equipment or as a multiplexed link that carries all communication traffic such as voice, telecontrol and protection signalling. For protection signalling, the available bandwidth of a link is divided by time division multiplexing (T.D.M.) techniques into several channels, each of 64kbits/s. Each 64kbits/s channel is equivalent to one voice frequency channel, which typically uses 8-bit analogue-to-digital conversion at a sampling rate of 8kHz. Several utilities sell surplus capacity on © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 8-7 Network Protection & Automation Guide their links to telecommunications operators, or they may take the opportunity to increase the data rate in end-to-end applications up to 2Mbits/s. The trend of using rented pilot circuits is being reversed as the utilities revert to ownership of the communication circuits that carry protection signalling. optical cable helically around a phase or earth conductor. This latter technique can be used without restringing of the line. The equipment that carries out this multiplexing at each end of a line is known as 'Pulse Code Modulation' (P.C.M.) terminal equipment. This approach is the one adopted by telecommunications authorities and some utilities favour its adoption on their private systems, for economic considerations. Optical fibre communications are well established in the electrical supply industry. They are the preferred means for the communications link between a substation and a telephone exchange when rented circuits are used, as trials have shown that this link is particularly susceptible to interference from power system faults if copper conductors are used. Whilst such fibres can be laid in cable trenches, there is a strong trend to associate them with the conductors themselves by producing composite cables comprising optical fibres embedded in the conductors, either earth or phase. For overhead lines use of OPGW (Optical Ground Wire) earth conductors is very common, while an alternative is to wrap the Figure 8.6: Example digital teleprotection, e-terragridcom DIP 8.6 SIGNALLING METHODS Various methods are used in protection signalling; not all need be suited to every transmission medium. The methods to be considered briefly are:  d.c. voltage step or d.c. voltage reversals  plain tone keyed signals at high and voice frequencies  frequency shift keyed signals involving two or more tones at high and voice frequencies General purpose telecommunications equipment operating Figure 8.5: Communication arrangements commonly encountered in protection signalling 8-8 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 8 ˜ Protection Signalling and Intertripping over power line carrier, radio or optical fibre media incorporate frequency translating or multiplexing techniques to provide the user with standardised communication channels. They have a nominal bandwidth/channel of 2kHz to 4kHz and are often referred to as voice frequency (vf) channels. Protection signalling equipment operating at voice frequencies exploits the standardisation of the communication interface. Where voice frequency channels are not available or suitable, protection signalling may make use of media or specialised equipment dedicated entirely to the signalling requirements. Figure 8.5 shows the communication arrangements commonly encountered in protection signalling. 8.6.1 D.C. Voltage Signalling A d.c. voltage step or d.c. voltage reversals may be used to convey a signalling instruction between protection relaying points in a power system, but these are suited only to private pilot wires, where low speed signalling is acceptable, with its inherent security. In all applications there is the need to ensure that no maloperation can occur due to power frequency interference. 8.6.2 Plain Tone Signals Plain high frequency signals can be used successfully for the signalling of blocking information over a power line. A normally quiescent power line carrier equipment can be dedicated entirely to the transfer to teleprotection blocking commands. Phase comparison power line carrier unit protection schemes often use such equipment and take advantage of the very high speed and dependability of the signalling system. The special characteristics of dedicated 'on/off' keyed carrier systems are discussed later. A relatively insensitive receiver is used to discriminate against noise on an amplitude basis, and for some applications the security may be satisfactory for permissive tripping, particularly if the normal high-speed operation of about 7ms or less is sacrificed by the addition of delays. The need for regular reflex testing of a normally quiescent channel usually precludes any use for intertripping. Plain tone power line carrier signalling systems are particularly suited to providing the blocking commands often associated with the protection of multi-ended feeders, as described in Chapter 13. A blocking command sent from one end can be received simultaneously at all the other ends using a single power line carrier channel. Other signalling systems usually require discrete communication channels between each of the ends or involve repeaters, leading to decreased dependability of the blocking command. 8.6.3 Frequency Shift Keyed Signals Frequency shift keyed high frequency signals can be used over a power line carrier link to give short operating times (15 milliseconds for blocking and permissive intertripping, 20 milliseconds for direct intertripping) for all applications of protection signalling. The required amount of security can be achieved by using a broadband noise detector to monitor the actual operational signalling equipment. Frequency shift keyed voice frequency signals can be used for all protection signalling applications over all transmission media. Frequency modulation techniques make possible an improvement in performance, because amplitude limiting rejects the amplitude modulation component of noise, leaving only the phase modulation components to be detected. The operational protection signal may consist of tone sequence codes with, say, three tones, or a multi-bit code using two discrete tones for successive bits, or of a single frequency shift. Modern high-speed systems use multi-bit code or single frequency shift techniques. Complex codes are used to give the required degree of security in direct intertrip schemes: the short operating times needed may result in uneconomical use of the available voice frequency spectrum, particularly if the channel is not exclusively employed for protection signalling. As noise power is directly proportional to bandwidth, a large bandwidth causes an increase in the noise level admitted to the detector, making operation in the presence of noise more difficult. So, again, it is difficult to obtain both high dependability and high security. The signal frequency shift technique has advantages where fast signalling is needed for blocked distance and permissive intertrip applications. It has little inherent security, but additional algorithms responsive to every type of interference can give acceptable security. This system does not require a high transmission rate channel as the frequency changes once only. The bandwidth can therefore be narrower than in coded systems, giving better noise rejection as well as being advantageous if the channel is shared with telemetry and control signalling, which is inevitably the case if a power line carrier bearer is used. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 8-9 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 Overcurrent Protection for Phase and Earth Faults 9.1 9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 9.10 9.11 9.12 9.13 9.14 9.15 9.16 9.17 9.18 9.19 9.20 9.21 9.22 Introduction Co-ordination Procedure Principles of Time/Current Grading Standard IDMT Overcurrent Relays Combined IDMT and High Set Instantaneous Overcurrent Relays Very Inverse (VI) Overcurrent Relays Extremely Inverse (EI) Overcurrent Relays Other Relay Characteristics Independent (definite) Time Overcurrent Relays Relay Current Setting Relay Time Grading Margin Recommended Grading Margins Calculation of Phase Fault Overcurrent Relay Settings Directional Phase Fault Overcurrent Relays Ring Mains Earth Fault Protection Directional Earth Fault Overcurrent Protection Earth Fault Protection on Insulated Networks Earth Fault Protection on Petersen Coil Earthed Networks Examples of Time and Current Grading Hi-Z - High Impedance Downed Conductor Protection References INTRODUCTION Protection against excess current was naturally the earliest protection system to evolve. From this basic principle, the graded overcurrent system, a discriminative fault protection, has been developed. This should not be confused with ‘overload’ protection, which normally makes use of relays that operate in a time related in some degree to the thermal capability of the plant to be protected. Overcurrent protection, on the other hand, is directed entirely to the clearance of faults, although with the settings usually adopted some measure of overload protection may be obtained. 9.2 CO-ORDINATION PROCEDURE Correct overcurrent relay application requires knowledge of the fault current that can flow in each part of the network. Since large-scale tests are normally impracticable, system analysis must be used – see Chapter 4 for details. The data required for a relay setting study are: x a one-line diagram of the power system involved, showing the type and rating of the protection devices and their associated current transformers x the impedances in ohms, per cent or per unit, of all power transformers, rotating machine and feeder circuits x the maximum and minimum values of short circuit currents that are expected to flow through each protection device x the maximum load current through protection devices x the starting current requirements of motors and the starting and locked rotor/stalling times of induction motors x the transformer inrush, thermal withstand and damage characteristics x decrement curves showing the rate of decay of the fault current supplied by the generators x performance curves of the current transformers The relay settings are first determined to give the shortest operating times at maximum fault levels and then checked to see if operation will also be satisfactory at the minimum fault current expected. It is always advisable to plot the curves of relays and other protection devices, such as fuses, that are to Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-1 Network Protection & Automation Guide operate in series, on a common scale. It is usually more convenient to use a scale corresponding to the current expected at the lowest voltage base, or to use the predominant voltage base. The alternatives are a common MVA base or a separate current scale for each system voltage. The basic rules for correct relay co-ordination can generally be stated as follows: x whenever possible, use relays with the same operating characteristic in series with each other x make sure that the relay farthest from the source has current settings equal to or less than the relays behind it, that is, that the primary current required to operate the relay in front is always equal to or less than the primary current required to operate the relay behind it 9.3 PRINCIPLES OF TIME/CURRENT GRADING Among the various possible methods used to achieve correct relay co-ordination are those using either time or overcurrent, or a combination of both. The common aim of all three methods is to give correct discrimination. That is to say, each one must isolate only the faulty section of the power system network, leaving the rest of the system undisturbed. 9.3.1 Discrimination by Time In this method, an appropriate time setting is given to each of the relays controlling the circuit breakers in a power system to ensure that the breaker nearest to the fault opens first. A simple radial distribution system is shown in Figure 9.1, to illustrate the principle. It is the time delay element, therefore, which provides the means of discrimination. The relay at B is set at the shortest time delay possible to allow the fuse to blow for a fault at A on the secondary side of the transformer. After the time delay has expired, the relay output contact closes to trip the circuit breaker. The relay at C has a time delay setting equal to t1 seconds, and similarly for the relays at D and E. If a fault occurs at F, the relay at B will operate in t seconds and the subsequent operation of the circuit breaker at B will clear the fault before the relays at C, D and E have time to operate. The time interval t1 between each relay time setting must be long enough to ensure that the upstream relays do not operate before the circuit breaker at the fault location has tripped and cleared the fault. The main disadvantage of this method of discrimination is that the longest fault clearance time occurs for faults in the section closest to the power source, where the fault level (MVA) is highest. 9.3.2 Discrimination by Current Discrimination by current relies on the fact that the fault current varies with the position of the fault because of the difference in impedance values between the source and the fault. Hence, typically, the relays controlling the various circuit breakers are set to operate at suitably tapered values of current such that only the relay nearest to the fault trips its breaker. Figure 9.2 illustrates the method. For a fault at F1, the system short-circuit current is given by: 6350 A Z S  Z L1 I where: Z S = source impedance = Figure 9.1: Radial system with time discrimination Overcurrent protection is provided at B, C, D and E, that is, at the infeed end of each section of the power system. Each protection unit comprises a definite-time delay overcurrent relay in which the operation of the current sensitive element simply initiates the time delay element. Provided the setting of the current element is below the fault current value, this element plays no part in the achievement of discrimination. For this reason, the relay is sometimes described as an ‘independent definite-time delay relay’, since its operating time is for practical purposes independent of the level of overcurrent. 9-2 112 = 0.485 250 Z L1 = cable impedance between C and B = 0.24 Hence I 6350 = 8800A 0.725 So, a relay controlling the circuit breaker at C and set to operate at a fault current of 8800A would in theory protect the whole of the cable section between C and B. However, there are two important practical points that affect this method of co-ordination: x it is not practical to distinguish between a fault at F1 and a fault at F2, since the distance between these points may be only a few metres, corresponding to a change in fault current of approximately 0.1% © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults x in practice, there would be variations in the source fault level, typically from 250MVA to 130MVA. At this lower fault level the fault current would not exceed 6800A, even for a cable fault close to C. A relay set at 8800A would not protect any part of the cable section concerned Discrimination by current is therefore not a practical proposition for correct grading between the circuit breakers at C and B. However, the problem changes appreciably when there is significant impedance between the two circuit breakers concerned. Consider the grading required between the circuit breakers at C and A in Figure 9.2. Assuming a fault at F4, the short-circuit current is given by: 6350 Z S  Z L1  Z L 2  Z T I where Z S = source impedance = 112 = 0.485 250 Z L1 = cable impedance between C and B = 0.24 Z L 2 = cable impedance between B and 4MVA transformer = 0.04 § 112 · ¸¸ =2.12 Z T = transformer impedance = 0.07¨¨ © 4 ¹ Hence I 6350 = 2200A 2.885 I 6350 Z S  Z L1  Z L 2 Thus, assuming a 250MVA source fault level: I 6350 = 8300A 0.485  0.24  0.04 Alternatively, assuming a source fault level of 130MVA: I 6350 = 5250A 0.93  0.214  0.04 For either value of source level, the relay at B would operate correctly for faults anywhere on the 11kV cable feeding the transformer. 9.3.3 Discrimination by both Time and Current Each of the two methods described so far has a fundamental disadvantage. In the case of discrimination by time alone, the disadvantage is due to the fact that the more severe faults are cleared in the longest operating time. On the other hand, discrimination by current can be applied only where there is appreciable impedance between the two circuit breakers concerned. It is because of the limitations imposed by the independent use of either time or current co-ordination that the inverse time overcurrent relay characteristic has evolved. With this characteristic, the time of operation is inversely proportional to the fault current level and the actual characteristic is a function of both ‘time’ and 'current' settings. Figure 9.3 shows the characteristics of two relays given different current/time settings. For a large variation in fault current between the two ends of the feeder, faster operating times can be achieved by the relays nearest to the source, where the fault level is the highest. The disadvantages of grading by time or current alone are overcome. Figure 9.2: Radial system with current discrimination For this reason, a relay controlling the circuit breaker at B and set to operate at a current of 2200A plus a safety margin would not operate for a fault at F4 and would thus discriminate with the relay at A. Assuming a safety margin of 20% to allow for relay errors and a further 10% for variations in the system impedance values, it is reasonable to choose a relay setting of 1.3 x 2200A, that is, 2860A, for the relay at B. Now, assuming a fault at F3, at the end of the 11kV cable feeding the 4MVA transformer, the short-circuit current is given by: © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-3 Network Protection & Automation Guide The tripping characteristics for different TMS settings using the SI curve are shown in Figure 9.6. Relay Characteristic Equation (IEC 60255) Standard Inverse (SI) t TMS u 0.14 I r0.02  1 Very Inverse (VI) t TMS u 13.5 Ir 1 Extremely Inverse (EI) t TMS u 80 I r2  1 Long time standby earth fault t TMS u 120 Ir 1 Table 9.1: Definitions of standard relay characteristics Characteristic Equation IEEE Moderately Inverse t º TD ª§ 0.0515 · ¸  0.114» «¨ 7 ¬¨© I r0.02  1 ¸¹ ¼ IEEE Very Inverse t º TD ª§ 19.61 · ¸  0.491» «¨ 7 ¬¨© I r2  1 ¸¹ ¼ IEEE Extremely Inverse t º TD ª§ 28.2 · ¸  0.1217 » «¨ 7 ¬¨© I r2  1 ¸¹ ¼ US CO8 Inverse t º TD ª§ 5.95 · ¸  0.18» «¨ 7 ¬¨© I r2  1 ¸¹ ¼ US CO2 Short Time Inverse t º TD ª§ 0.02394 · ¸  0.01694» «¨ 7 ¬¨© I r0.02  1 ¸¹ ¼ Table 9.2: North American IDMT definitions of standard relay characteristics For Table 9.1 and Table 9.2: Ir = I / Is Where: I = Measured current Figure 9.3: Relay characteristics for different settings Is = Relay setting current TMS = Time Multiplier Setting 9.4 STANDARD IDMT OVERCURRENT RELAYS TD = Time Dial setting The current/time tripping characteristics of IDMT relays may need to be varied according to the tripping time required and the characteristics of other protection devices used in the network. For these purposes, IEC 60255 defines a number of standard characteristics as follows: x Standard Inverse (SI) x Very Inverse (VI) x Extremely Inverse (EI) x Definite Time (DT) The mathematical descriptions of the curves are given in Table 9.1, and the curves based on a common setting current and time multiplier setting of 1 second are shown in Figure 9.4. 9-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults 1000.00 1000.00 100.00 100.00 10.00 10.00 Standard Inverse (SI) 1.00 1.00 Moderately Inverse Very Inverse Very Inverse (VI) CO 2 Short Time Inverse Extremely Inverse (EI) CO 8 Inverse Extremely Inverse 0.10 0.10 1 10 Current (multiples of Is) Figure 9.4: IEC 60255 IDMT relay characteristics; TMS=1.0 100 1 10 100 Current (multiples of Is ) Figure 9.5: North American IDMT relay characteristics; TD=7 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-5 Network Protection & Automation Guide source impedance is small in comparison with the protected circuit impedance. This makes a reduction in the tripping time at high fault levels possible. It also improves the overall system grading by allowing the 'discriminating curves' behind the high set instantaneous elements to be lowered. 10 8 6 4 3 TMS 1.0 0.9 0.8 0.7 2 0.6 0.5 1 0.4 0.8 0.3 0.6 0.2 0.4 0.3 0.1 0.2 0.1 1 2 3 4 6 8 10 20 30 As shown in Figure 9.7, one of the advantages of the high set instantaneous elements is to reduce the operating time of the circuit protection by the shaded area below the 'discriminating curves'. If the source impedance remains constant, it is then possible to achieve high-speed protection over a large section of the protected circuit. The rapid fault clearance time achieved helps to minimise damage at the fault location. Figure 9.7 also shows a further important advantage gained by the use of high set instantaneous elements. Grading with the relay immediately behind the relay that has the instantaneous elements enabled is carried out at the current setting of the instantaneous elements and not at the maximum fault level. For example, in Figure 9.7 relay R2 is graded with relay R3 at 500A and not 1100A, allowing relay R2 to be set with a TMS of 0.15 instead of 0.2 while maintaining a grading margin between relays of 0.4s. Similarly, relay R1 is graded with R2 at 1400A and not at 2300A. Current (multiples of plug settings) Figure 9.6: Typical time/current characteristics of standard IDMT relay Although the curves are only shown for discrete values of TMS, continuous adjustment may be possible in an electromechanical relay. For other relay types, the setting steps may be so small as to effectively provide continuous adjustment. In addition, almost all overcurrent relays are also fitted with a high-set instantaneous element. In most cases, use of the standard SI curve proves satisfactory, but if satisfactory grading cannot be achieved, use of the VI or EI curves may help to resolve the problem. When digital or numeric relays are used, other characteristics may be provided, including the possibility of user-definable curves. More details are provided in the following sections. Relays for power systems designed to North American practice utilise ANSI/IEEE curves. Table 9.2 gives the mathematical description of these characteristics and Figure 9.5 shows the curves standardised to a time dial setting of 7. Take great care that different vendors may standardise their curves at different settings other than TD=7. The protection engineer must ensure whether the factor of 7, or some other nominal, is applied. 9.5 COMBINED IDMT AND HIGH SET INSTANTANEOUS OVERCURRENT RELAYS A high-set instantaneous element can be used where the 9-6 Figure 9.7: Characteristics of combined IDMT and high-set instantaneous overcurrent relays 9.5.1 Transient Overreach The reach of a relay is that part of the system protected by the relay if a fault occurs. A relay that operates for a fault that lies beyond the intended zone of protection is said to overreach. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults When using instantaneous overcurrent elements, care must be exercised in choosing the settings to prevent them operating for faults beyond the protected section. The initial current due to a d.c. offset in the current wave may be greater than the relay pick-up value and cause it to operate. This may occur even though the steady state r.m.s. value of the fault current for a fault at a point beyond the required reach point may be less than the relay setting. This phenomenon is called transient over-reach, and is defined as: % Transient over-reach = I1  I 2 x 100% I2 Equation 9.1 where: I1 = r.m.s steady state pickup current I 2 = steady state r.m.s current which when fully offset just causes relay pickup When applied to power transformers, the high set instantaneous overcurrent elements must be set above the maximum through fault current than the power transformer can supply for a fault across its LV terminals, to maintain discrimination with the relays on the LV side of the transformer. Figure 9.8: Comparison of SI and VI relay characteristics 9.6 VERY INVERSE (VI) OVERCURRENT RELAYS 9.7 EXTREMELY INVERSE (EI) OVERCURRENT RELAYS Very inverse overcurrent relays are particularly suitable if there is a substantial reduction of fault current as the distance from the power source increases, i.e. there is a substantial increase in fault impedance. The VI operating characteristic is such that the operating time is approximately doubled for reduction in current from 7 to 4 times the relay current setting. This permits the use of the same time multiplier setting for several relays in series. With this characteristic, the operation time is approximately inversely proportional to the square of the applied current. This makes it suitable for the protection of distribution feeder circuits in which the feeder is subjected to peak currents on switching in, as would be the case on a power circuit supplying refrigerators, pumps, water heaters and so on, which remain connected even after a prolonged interruption of supply. The long time operating characteristic of the extremely inverse relay at normal peak load values of current also makes this relay particularly suitable for grading with fuses. Figure 9.9 shows typical curves. The EI characteristic gives a satisfactory grading margin, but the VI or SI characteristics at the same settings does not. Another application of this relay is in conjunction with auto-reclosers in low voltage distribution circuits. The majority of faults are transient in nature and unnecessary blowing and replacing of the fuses present in final circuits of such a system can be avoided if the auto-reclosers are set to operate before the fuse blows. If the fault persists, the auto-recloser locks itself in the closed position after one opening and the fuse blows to isolate the fault. Figure 9.8 comparies the SI and VI curves for a relay. The VI curve is much steeper and therefore the operation increases much faster for the same reduction in current compared to the SI curve. This enables the requisite grading margin to be obtained with a lower TMS for the same setting current, and hence the tripping time at source can be minimised. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-7 Network Protection & Automation Guide 200.0 9.9 INDEPENDENT (DEFINITE) TIME OVERCURRENT RELAYS 100.0 Overcurrent relays are normally also provided with elements having independent or definite time characteristics. These characteristics provide a ready means of co-ordinating several relays in series in situations in which the system fault current varies very widely due to changes in source impedance, as there is no change in time with the variation of fault current. The time/current characteristics of this curve are shown in Figure 9.10, together with those of the standard IDMT characteristic, to indicate that lower operating times are achieved by the inverse relay at the higher values of fault current, whereas the definite time relay has lower operating times at the lower current values. 10.0 Standard Inverse (SI) Very Inverse (VI) 1.0 Extremely Inverse (EI) 200A Fuse 0.1 100 1000 Current (Amps) 10000 Figure 9.9: Comparison of relay and fuse characteristics 9.8 OTHER RELAY CHARACTERISTICS User definable curves may be provided on some types of digital or numerical relays. The general principle is that the user enters a series of current/time co-ordinates that are stored in the memory of the relay. Interpolation between points is used to provide a smooth trip characteristic. Such a feature, if available, may be used in special cases if none of the standard tripping characteristics is suitable. However, grading of upstream protection may become more difficult, and it is necessary to ensure that the curve is properly documented, along with the reasons for use. Since the standard curves provided cover most cases with adequate tripping times, and most equipment is designed with standard protection curves in mind, the need to utilise this form of protection is relatively rare. Digital and numerical relays may also include pre-defined logic schemes utilising digital (relay) I/O provided in the relay to implement standard schemes such as CB failure and trip circuit supervision. This saves the provision of separate relay hardware to perform these functions. 9-8 Figure 9.10: Comparison of definite time and standard IDMT relay Vertical lines T1, T2, T3, and T4 indicate the reduction in operating times achieved by the inverse relay at high fault levels. 9.10 RELAY CURRENT SETTING An overcurrent relay has a minimum operating current, known as the current setting of the relay. The current setting must be chosen so that the relay does not operate for the maximum load current in the circuit being protected, but does operate for a current equal or greater to the minimum expected fault current. Although by using a current setting that is only just above the maximum load current in the circuit a certain degree of protection against overloads as well as faults may be provided, the main function of overcurrent protection is to © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults isolate primary system faults and not to provide overload protection. In general, the current setting will be selected to be above the maximum short time rated current of the circuit involved. Since all relays have hysteresis in their current settings, the setting must be sufficiently high to allow the relay to reset when the rated current of the circuit is being carried. The amount of hysteresis in the current setting is denoted by the pick-up/drop-off ratio of a relay – the value for a modern relay is typically 0.95. Thus, a relay minimum current setting of at least 1.05 times the short-time rated current of the circuit is likely to be required. 9.11 RELAY TIME GRADING MARGIN The time interval that must be allowed between the operation of two adjacent relays to achieve correct discrimination between them is called the grading margin. If a grading margin is not provided, or is insufficient, more than one relay will operate for a fault, leading to difficulties in determining the location of the fault and unnecessary loss of supply to some consumers. The grading margin depends on a number of factors: 1. the fault current interrupting time of the circuit breaker 2. relay timing errors 3. the overshoot time of the relay IEC 60255, a relay error index is quoted that determines the maximum timing error of the relay. The timing error must be taken into account when determining the grading margin. 9.11.3 Overshoot When the relay is de-energised, operation may continue for a little longer until any stored energy has been dissipated. For example, an induction disc relay will have stored kinetic energy in the motion of the disc; static relay circuits may have energy stored in capacitors. Relay design is directed to minimising and absorbing these energies, but some allowance is usually necessary. The overshoot time is defined as the difference between the operating time of a relay at a specified value of input current and the maximum duration of input current, which when suddenly reduced below the relay operating level, is insufficient to cause relay operation. 9.11.4 CT Errors Current transformers have phase and ratio errors due to the exciting current required to magnetise their cores. The result is that the CT secondary current is not an identical scaled replica of the primary current. This leads to errors in the operation of relays, especially in the operation time. CT errors are not relevant for independent definite-time delay overcurrent relays. 4. CT errors 9.11.5 Final Margin 5. final margin on completion of operation After allowances have been made for circuit breaker interrupting time, relay timing error, overshoot and CT errors, the discriminating relay must just fail to complete its operation. Some extra safety margin is required to ensure that relay operation does not occur. Factors (2) and (3) depend on the relay technology used. For example, an electromechanical relay has a larger overshoot time than a numerical relay. Grading is initially carried out for the maximum fault level at the relaying point under consideration, but a check is also made that the required grading margin exists for all current levels between relay pick-up current and maximum fault level. 9.11.1 Circuit Breaker Interrupting Time 9.11.6 Overall Accuracy The overall limits of accuracy according to IEC 60255-4 for an IDMT relay with standard inverse characteristic are shown in Figure 9.11. The circuit breaker interrupting the fault must have completely interrupted the current before the discriminating relay ceases to be energised. The time taken is dependent on the type of circuit breaker used and the fault current to be interrupted. Manufacturers normally provide the fault interrupting time at rated interrupting capacity and this value is invariably used in the calculation of grading margin. 9.11.2 Relay Timing Error All relays have errors in their timing compared to the ideal characteristic as defined in IEC 60255. For a relay specified to © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-9 Network Protection & Automation Guide operating times, the permitted error specified in IEC 60255 (7.5% of operating time) may exceed the fixed grading margin, resulting in the possibility that the relay fails to grade correctly while remaining within specification. This requires consideration when considering the grading margin at low fault current levels. Pick-up 1.05 - 1.3 times setting 50 40 30 Time (seconds) 20 A practical solution for determining the optimum grading margin is to assume that the relay nearer to the fault has a maximum possible timing error of +2E, where E is the basic timing error. To this total effective error for the relay, a further 10% should be added for the overall current transformer error. 10 8 6 5 Relay Technology 4 3 Typical basic timing error (%) 2 1 1 2 3 4 5 6 8 10 20 30 Current (multiples of plug settings) Time/Current characteristic allowable limit At 2 times setting At 5 times setting At 10 times setting At 20 times setting 2.5 x declared error 1.5 x declared error 1.0 x declared error 1.0 x declared error 5 5 5 0.03 0.02 0.02 0.05 0.03 0.03 Typical overall grading margin 0.4 - relay to relay(s) 0.35 0.3 0.3 Table 9.3: Typical relay timing errors – standard IDMT relays A suitable minimum grading time interval, t c , may be calculated as follows: ª 2 ER  ECT º «¬ 100 »¼t  tCB  to  t S seconds The following sections give the recommended overall grading margins for between different protection devices. where: 9-10 7.5 0.05 Equation 9.2 It should be noted that use of a fixed grading margin is only appropriate at high fault levels that lead to short relay operating times. At lower fault current levels, with longer Numerical 0.1 9.12 RECOMMENDED GRADING MARGINS The use of a fixed grading margin is popular, but it may be better to calculate the required value for each relay location. This more precise margin comprises a fixed time, covering circuit breaker fault interrupting time, relay overshoot time and a safety margin, plus a variable time that allows for relay and CT errors. Table 9.3 gives typical relay errors according to the technology used. Digital Safety margin (s) t' The total interval required to cover circuit breaker interrupting time, relay timing error, overshoot and CT errors, depends on the operating speed of the circuit breakers and the relay performance. At one time 0.5s was a normal grading margin. With faster modern circuit breakers and a lower relay overshoot time, 0.4s is reasonable, while under the best conditions even lower intervals may be practical. Static Overshoot time (s) Figure 9.11: Typical limits of accuracy from IEC 60255-4 for an inverse definite minimum time overcurrent relay 9.12.1 Grading: Relay to Relay Electromechanical ER = relay timing error (IEC60255-4) ECT = allowance for CT ratio error (%) t = nominal operating time of relay nearer to fault (sec) tCB = CB interrupting time (sec) tO = relay overshoot time (sec) tS = safety margin (sec) if, for example t=0.5s, the time interval for an electromechanical relay tripping a conventional circuit breaker would be 0.375s, whereas, at the lower extreme, for a static relay tripping a vacuum circuit breaker, the interval could be as low as 0.25s. When the overcurrent relays have independent definite time delay characteristics, it is not necessary to include the allowance for CT error. Hence: t' ª 2 ER º «¬ 100 »¼t  tCB  to  t S seconds Equation 9.3 Calculation of specific grading times for each relay can often be tedious when performing a protection grading calculation on a © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults power system. Table 9.3 also gives practical grading times at high fault current levels between overcurrent relays for different technologies. Where relays of different technologies are used, the time appropriate to the technology of the downstream relay should be used. 9.12.2 Grading: Fuse to Fuse The operating time of a fuse is a function of both the prearcing and arcing time of the fusing element, which follows an 2 I t law. So, to achieve proper co-ordination between two 2 fuses in series, it is necessary to ensure that the total I t taken by the smaller fuse is not greater than the pre-arcing 2 I t value of the larger fuse. It has been established by tests that satisfactory grading between the two fuses will generally be achieved if the current rating ratio between them is greater than two. 9.12.3 Grading: Fuse to Relay For grading inverse time relays with fuses, the basic approach is to ensure whenever possible that the relay backs up the fuse and not vice versa. If the fuse is upstream of the relay, it is very difficult to maintain correct discrimination at high values of fault current because of the fast operation of the fuse. The relay characteristic best suited for this co-ordination with fuses is normally the extremely inverse (EI) characteristic as it 2 follows a similar I t characteristic. To ensure satisfactory coordination between relay and fuse, the primary current setting of the relay should be approximately three times the current rating of the fuse. The grading margin for proper coordination, when expressed as a fixed quantity, should not be less than 0.4s or, when expressed as a variable quantity, should have a minimum value of: t' 0.4t  0.15 seconds Equation 9.4 where t is the nominal operating time of the fuse. Section 9.20.1 gives an example of fuse to relay grading. 9.13 CALCULATION OF PHASE FAULT OVERCURRENT RELAY SETTINGS The correct co-ordination of overcurrent relays in a power system requires the calculation of the estimated relay settings in terms of both current and time. The resultant settings are then traditionally plotted in suitable log/log format to show pictorially that a suitable grading margin exists between the relays at adjacent substations. Plotting is usually done using suitable software although it can be done by hand. The information required at each relaying point to allow a relay setting calculation to proceed is given in Section 9.2. The main relay data can be recorded in a table such as that shown in Table 9.4, populating the first five columns. Fault Current (A) Maximum CT Load Location Current Ratio Maximum Minimum (A) Relay Current Setting Per Cent Primary Current (A) Relay Time Multiplier Setting Table 9.4: Typical relay data table It is usual to plot all time/current characteristics to a common voltage/MVA base on log/log scales. The plot includes all relays in a single path, starting with the relay nearest the load and finishing with the relay nearest the source of supply. A separate plot is required for each independent path The settings of any relays that lie on multiple paths must be carefully considered to ensure that the final setting is appropriate for all conditions. Earth faults are considered separately from phase faults and require separate plots. After relay settings have been finalised they are entered into a table such as that shown in Table 9.4, populating the last three columns. This also assists in record keeping during commissioning of the relays at site. 9.13.1 Independent (Definite) Time Relays The selection of settings for independent (definite) time relays presents little difficulty. The overcurrent elements must be given settings that are lower, by a reasonable margin, than the fault current that is likely to flow to a fault at the remote end of the system up to which back-up protection is required, with the minimum plant in service. The settings must be high enough to avoid relay operation with the maximum probable load, a suitable margin being allowed for large motor starting currents or transformer inrush transients. Time settings will be chosen to allow suitable grading margins, as discussed in Section 9.12. 9.13.2 Inverse Time Relays When the power system consists of a series of short sections of cable, so that the total line impedance is low, the value of fault current will be controlled principally by the impedance of transformers or other fixed plant and will not vary greatly with the location of the fault. In such cases, it may be possible to grade the inverse time relays in very much the same way as definite time relays. However, when the prospective fault current varies substantially with the location of the fault, it is possible to make use of this fact by employing both current © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-11 Network Protection & Automation Guide and time grading to improve the overall performance of the relay. The procedure begins by selection of the appropriate relay characteristics. Current settings are then chosen, with finally the time multiplier settings to give appropriate grading margins between relays. Otherwise, the procedure is similar to that for definite time delay relays. An example of a relay setting study is given in Section 9.20.1. the protection of plain feeders with the zero sequence source behind the relaying point. Ia Zero torque line Va A MT ' Vbc 9.14 DIRECTIONAL PHASE FAULT OVERCURRENT RELAYS 30° 150° 30° When fault current can flow in both directions through the relay location, it may be necessary to make the response of the relay directional by the introduction of a directional control facility. The facility is provided by use of additional voltage inputs to the relay. Vbc Vc Vb 9.14.1 Relay Connections There are many possibilities for a suitable connection of voltage and current inputs. The various connections are dependent on the phase angle, at unity system power factor, by which the current and voltage applied to the relay are displaced. Reference [9.1] details all of the connections that have been used. However, only very few are used in current practice and these are described below. In a digital or numerical relay, the phase displacements are obtained by software, while electromechanical and static relays generally obtain the required phase displacements by connecting the input quantities to the relay. The history of the topic results in the relay connections being defined as if they were obtained by suitable connection of the input quantities, irrespective of the actual method used. 9.14.2 90° Relay Quadrature Connection This is the standard connection for static, digital or numerical relays. Depending on the angle by which the applied voltage is shifted to produce maximum relay sensitivity (the Relay Characteristic Angle, or RCA), two types are available. 9.14.2.1 90°-30° Characteristic (30° RCA) The A phase relay element is supplied with Ia current and Vbc voltage displaced by 30o in an anti-clockwise direction. In this case, the relay maximum sensitivity is produced when the current lags the system phase to neutral voltage by 60o. This connection gives a correct directional tripping zone over the current range of 30o leading to 150o lagging; see Figure 9.12. The relay sensitivity at unity power factor is 50% of the relay maximum sensitivity and 86.6% at zero power factor lagging. This characteristic is recommended when the relay is used for 9-12 A phase element connected Ia Vbc B phase element connected Ib Vca C phase element connected Ic Vab Figure 9.12: Vector diagram for the 90o-30o connection (phase A element) 9.14.2.2 90°-45° characteristic (45° RCA) The A phase relay element is supplied with current Ia and voltage Vbc displaced by 45o in an anti-clockwise direction. The relay maximum sensitivity is produced when the current lags the system phase to neutral voltage by 45o. This connection gives a correct directional tripping zone over the current range of 45o leading to 135o lagging. The relay sensitivity at unity power factor is 70.7% of the maximum torque and the same at zero power factor lagging; see Figure 9.13. This connection is recommended for the protection of transformer feeders or feeders that have a zero sequence source in front of the relay. It is essential in the case of parallel transformers or transformer feeders, to ensure correct relay operation for faults beyond the star/delta transformer. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults line faults. This is done by setting the directional relays R’1 and R’2 in Figure 9.14 with their directional elements looking into the protected line, and giving them lower time and current settings than relays R1 and R2. The usual practice is to set relays R’1 and R’2 to 50% of the normal full load of the protected circuit and 0.1TMS, but care must be taken to ensure that the continuous thermal rating of the relays of twice rated current is not exceeded. An example calculation is given in Section 9.20.3 Source R1 R'1 I> I> Load Fault Figure 9.13: Vector diagram for the element) 90o-45o connection (phase A For a digital or numerical relay, it is common to allow userselection of the RCA within a wide range. Theoretically, three fault conditions can cause maloperation of the directional element: x a phase-phase-ground fault on a plain feeder x a phase-ground fault on a transformer feeder with the zero sequence source in front of the relay x a phase-phase fault on a power transformer with the relay looking into the delta winding of the transformer These conditions are assumed to establish the maximum angular displacement between the current and voltage quantities at the relay. The magnitude of the current input to the relay is insufficient to cause the overcurrent element to operate. The possibility of maloperation with the 90o-45o connection is non-existent. 9.14.3 Application of Directional Relays If non-unit, non-directional relays are applied to parallel feeders having a single generating source, any faults that might occur on any one line will, regardless of the relay settings used, isolate both lines and completely disconnect the power supply. With this type of system configuration, it is necessary to apply directional relays at the receiving end and to grade them with the non-directional relays at the sending end, to ensure correct discriminative operation of the relays during R2 R'2 I> I> Figure 9.14: Directional relays applied to parallel feeders 9.15 RING MAINS A particularly common arrangement within distribution networks is the Ring Main. The primary reason for its use is to maintain supplies to consumers in case of fault conditions occurring on the interconnecting feeders. A typical ring main with associated overcurrent protection is shown in Figure 9.15. Current may flow in either direction through the various relay locations, and therefore directional overcurrent relays are applied. In the case of a ring main fed at one point only, the settings of the relays at the supply end and at the mid-point substation are identical. They can therefore be made non-directional, if, in the latter case, the relays are located on the same feeder, that is, one at each end of the feeder. It is interesting to note that when the number of feeders round the ring is an even number, the two relays with the same operating time are at the same substation. They will therefore have to be directional. When the number of feeders is an odd number, the two relays with the same operating time are at different substations and therefore do not need to be directional. It may also be noted that, at intermediate substations, whenever the operating time of the relays at each substation are different, the difference between their operating times is never less than the grading margin, so the relay with the longer operating time can be non-directional. With modern numerical relays, a directional facility is often available © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-13 Network Protection & Automation Guide for little or no extra cost, so that it may be simpler in practice to apply directional relays at all locations. Also, in the event of an additional feeder being added subsequently, the relays that can be non-directional need to be re-determined and will not necessarily be the same – giving rise to problems of changing a non-directional relay for a directional one. If a VT was not provided originally, this may be very difficult to install at a later date. 9.15.1 Grading of Ring Mains The usual grading procedure for relays in a ring main circuit is to open the ring at the supply point and to grade the relays first clockwise and then anti-clockwise. That is, the relays looking in a clockwise direction around the ring are arranged to operate in the sequence 1-2-3-4-5-6 and the relays looking in the anti-clockwise direction are arranged to operate in the sequence 1’-2’-3’-4’-5’-6’, as shown in Figure 9.15. direction. The directional relays are set in accordance with the invariable rule, applicable to all forms of directional protection, that the current in the system must flow from the substation busbars into the protected line so the relays may operate. Disconnection of the faulted line is carried out according to time and fault current direction. As in any parallel system, the fault current has two parallel paths and divides itself in the inverse ratio of their impedances. Thus, at each substation in the ring, one set of relays will be made inoperative because of the direction of current flow, and the other set operative. It will also be found that the operating times of the relays that are inoperative are faster than those of the operative relays, with the exception of the mid-point substation, where the operating times of relays 3 and 3’ happen to be the same. The relays that are operative are graded downwards towards the fault and the last to be affected by the fault operates first. This applies to both paths to the fault. Consequently, the faulted line is the only one to be disconnected from the ring and the power supply is maintained to all the substations. When two or more power sources feed into a ring main, time graded overcurrent protection is difficult to apply and full discrimination may not be possible. With two sources of supply, two solutions are possible. The first is to open the ring at one of the supply points, whichever is more convenient, by means of a suitable high set instantaneous overcurrent relay. The ring is then graded as in the case of a single infeed. The second method is to treat the section of the ring between the two supply points as a continuous bus separate from the ring and to protect it with a unit protection system, and then proceed to grade the ring as in the case of a single infeed. Section 9.20.4 provides a worked example of ring main grading. 9.16 EARTH FAULT PROTECTION Figure 9.15: Grading of ring mains The arrows associated with the relaying points indicate the direction of current flow that will cause the relay to operate. A double-headed arrow is used to indicate a non-directional relay, such as those at the supply point where the power can flow only in one direction. A single-headed arrow is used to indicate a directional relay, such as those at intermediate substations around the ring where the power can flow in either 9-14 In the foregoing description, attention has been principally directed towards phase fault overcurrent protection. More sensitive protection against earth faults can be obtained by using a relay that responds only to the residual current of the system, since a residual component exists only when fault current flows to earth. The earth fault relay is therefore completely unaffected by load currents, whether balanced or not, and can be given a setting which is limited only by the design of the equipment and the presence of unbalanced leakage or capacitance currents to earth. This is an important consideration if settings of only a few percent of system rating are considered, since leakage currents may produce a residual quantity of this order. On the whole, the low settings permissible for earth fault relays are very useful, as earth faults are not only by far the most © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults frequent of all faults, but may be limited in magnitude by the neutral earthing impedance, or by earth contact resistance. The residual component is extracted by connecting the line current transformers in parallel as shown in Figure 9.16. The simple connection shown in Figure 9.16(a) can be extended by connecting overcurrent elements in the individual phase leads, as shown in Figure 9.16(b), and inserting the earth fault relay between the star points of the relay group and the current transformers. Phase fault overcurrent relays are often provided on only two phases since these will detect any interphase fault; the connections to the earth fault relay are unaffected by this consideration. The arrangement is shown in Figure 9.16(c). sensitive earth fault protection must be used. 9.16.1 Effective Setting of Earth Fault Relays The primary setting of an overcurrent relay can usually be taken as the relay setting multiplied by the CT ratio. The CT can be assumed to maintain a sufficiently accurate ratio so that, expressed as a percentage of rated current, the primary setting is directly proportional to the relay setting. However, this may not be true for an earth fault relay. The performance varies according to the relay technology used. 9.16.1.1 Static, digital and numerical relays When static, digital or numerical relays are used the relatively low value and limited variation of the relay burden over the relay setting range results in the above statement holding true. The variation of input burden with current should be checked to ensure that the variation is sufficiently small. If not, substantial errors may occur, and the setting procedure will have to follow that for electromechanical relays. 9.16.1.2 Electromechanical Relays When using an electromechanical relay, the earth fault element generally will be similar to the phase elements. It will have a similar VA consumption at setting, but will impose a far higher burden at nominal or rated current, because of its lower setting. For example, a relay with a setting of 20% will have an impedance of 25 times that of a similar element with a setting of 100%. Very frequently, this burden will exceed the rated burden of the current transformers. It might be thought that correspondingly larger current transformers should be used, but this is considered to be unnecessary. The current transformers that handle the phase burdens can operate the earth fault relay and the increased errors can easily be allowed for. Figure 9.16: Residual connection of current transformers to earth fault relays The typical settings for earth fault relays are 30%-40% of the full-load current or minimum earth fault current on the part of the system being protected. However, account may have to be taken of the variation of setting with relay burden as described in Section 9.16.1. If greater sensitivity than this is required, one of the methods described in Section 9.16.3 for obtaining Not only is the exciting current of the energising current transformer proportionately high due to the large burden of the earth fault relay, but the voltage drop on this relay is impressed on the other current transformers of the paralleled group, whether they are carrying primary current or not. The total exciting current is therefore the product of the magnetising loss in one CT and the number of current transformers in parallel. The summated magnetising loss can be appreciable in comparison with the operating current of the relay, and in extreme cases where the setting current is low or the current transformers are of low performance, may even exceed the output to the relay. The ‘effective setting current’ in secondary terms is the sum of the relay setting current and the total excitation loss. Strictly speaking, the effective setting is the vector sum of the relay setting current and the total exciting current, but the arithmetic sum is near enough, because of the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-15 Network Protection & Automation Guide At still higher input currents, the CT performance falls off until finally the output current ceases to increase substantially. Beyond this value of input current, operation is further complicated by distortion of the output current waveform. Relay Plug Setting % Coil voltage Current (A) at Setting (V) Exciting Current Ie Effective Setting Current (A) % 5 0.25 12 0.583 2 40 10 0.5 6 0.405 1.715 34.3 15 0.75 4 0.3 1.65 33 20 1 3 0.27 1.81 36 40 2 1.5 0.17 2.51 50 60 3 1 0.12 3.36 67 80 4 0.75 0.1 4.3 86 100 5 0.6 0.08 5.24 105 Table 9.5: Calculation of effective settings Secondary voltage The effect of the relatively high relay impedance and the summation of CT excitation losses in the residual circuit is augmented still further by the fact that, at setting, the flux density in the current transformers corresponds to the bottom bend of the excitation characteristic. The exciting impedance under this condition is relatively low, causing the ratio error to be high. The current transformer actually improves in performance with increased primary current, while the relay impedance decreases until, with an input current several times greater than the primary setting, the multiple of setting current in the relay is appreciably higher than the multiple of primary setting current which is applied to the primary circuit. This causes the relay operating time to be shorter than might be expected. 30 20 10 Current transformer excitation characteristic 0 0.5 1.5 1.0 Exciting current (amperes) 100 Effective setting (per cent) similarity of power factors. It is instructive to calculate the effective setting for a range of setting values of a relay, a process that is set out in Table 9.5, with the results shown in Figure 9.17. 80 60 40 20 0 20 40 60 80 100 Relay setting (per cent) Figure 9.17: Effective setting of earth fault relay 9.16.1.3 Time Grading of Electromechanical Earth Fault Relays The time grading of earth fault relays can be arranged in the same manner as for phase fault relays. The time/primary current characteristic for electromechanical relays cannot be kept proportionate to the relay characteristic with anything like the accuracy that is possible for phase fault relays. As shown above, the ratio error of the current transformers at relay setting current may be very high. It is clear that time grading of electromechanical earth fault relays is not such a simple matter as the procedure adopted for phase relays in Table 9.4. Either the above factors must be taken into account with the errors calculated for each current level, making the process much more tedious, or longer grading margins must be allowed. However, for other types of relay, the procedure adopted for phase fault relays can be used. 9.16.2 Sensitive Earth Fault Protection LV systems are not normally earthed through an impedance, due to the resulting overvoltages that may occur and consequential safety implications. HV systems may be designed to accommodate such overvoltages, but not the majority of LV systems. However, it is quite common to earth HV systems through an impedance that limits the earth fault current. Further, in some 9-16 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults countries, the resistivity of the earth path may be very high due to the nature of the ground itself (e.g. desert or rock). A fault to earth not involving earth conductors may result in the flow of only a small current, insufficient to operate a normal protection system. A similar difficulty also arises in the case of broken line conductors, which, after falling on to hedges or dry metalled roads, remain energised because of the low leakage current, and therefore present a danger to life. Cable gland Cable box Cable gland /sheath ground connection I > (a) Physical connections To overcome the problem, it is necessary to provide an earth fault protection system with a setting that is considerably lower than the normal line protection. This presents no difficulty to a modern digital or numerical relay. However, older electromechanical or static relays may present difficulties due to the high effective burden they may present to the CT. The required sensitivity cannot normally be provided by means of conventional CTs. A core balance current transformer (CBCT) will normally be used. The CBCT is a current transformer mounted around all three phase (and neutral if present) conductors so that the CT secondary current is proportional to the residual (i.e. earth) current. Such a CT can be made to have any convenient ratio suitable for operating a sensitive earth fault relay element. By use of such techniques, earth fault settings down to 10% of the current rating of the circuit to be protected can be obtained. Care must be taken to position a CBCT correctly in a cable circuit. If the cable sheath is earthed, the earth connection from the cable gland/sheath junction must be taken through the CBCT primary to ensure that phase-sheath faults are detected. Figure 9.18 shows the correct and incorrect methods. With the incorrect method, the fault current in the sheath is not seen as an unbalance current and hence relay operation does not occur. The normal residual current that may flow during healthy conditions limits the application of non-directional sensitive earth fault protection. Such residual effects can occur due to unbalanced leakage or capacitance in the system. No operation I > (b) Incorrect positioning Operation I > (c) Correct positioning Figure 9.18: Positioning of core balance current transformers 9.17 DIRECTIONAL EARTH FAULT OVERCURRENT PROTECTION Directional earth fault overcurrent may need to be applied in the following situations: x for earth fault protection where the overcurrent protection is by directional relays x in insulated-earth networks x in Petersen coil earthed networks x where the sensitivity of sensitive earth fault protection is insufficient – use of a directional earth fault relay may provide greater sensitivity The relay elements previously described as phase fault elements respond to the flow of earth fault current, and it is important that their directional response be correct for this condition. If a special earth fault element is provided as described in Section 9.16 (which will normally be the case), a related directional element is needed. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-17 Network Protection & Automation Guide 9.17.1 Relay Connections The residual current is extracted as shown in Figure 9.16. Since this current may be derived from any phase, to obtain a directional response it is necessary to obtain an appropriate quantity to polarise the relay. In digital or numerical relays there are usually two choices provided. 9.17.2 Residual Voltage A suitable quantity is the residual voltage of the system. This is the vector sum of the individual phase voltages. If the secondary windings of a three-phase, five limb voltage transformer or three single-phase units are connected in broken delta, the voltage developed across its terminals will be the vector sum of the phase to ground voltages and hence the residual voltage of the system, as shown in Figure 9.19. A star point of the primary windings of the interposing voltage transformers must be connected to the star point of the secondary windings of the main voltage transformers. The residual voltage will be zero for balanced phase voltages. For simple earth fault conditions, it will be equal to the depression of the faulted phase voltage. In all cases the residual voltage is equal to three times the zero sequence voltage drop on the source impedance and is therefore displaced from the residual current by the characteristic angle of the source impedance. The residual quantities are applied to the directional element of the earth fault relay. The residual current is phase offset from the residual voltage and hence angle adjustment is required. Typically, the current will lag the polarising voltage. The method of system earthing also affects the Relay Characteristic Angle (RCA), and the following settings are usual: B x Resistance-earthed system: 0 RCA C x Distribution system, solidly-earthed: -45 RCA o o x Transmission system, solidly-earthed: -60 RCA o The different settings for distribution and transmission systems arise from the different X/R ratios found in these systems. I > 9.17.3 Negative Sequence Current (a) Relay connections Va Va 3Io Va2 3Vo Vc Vb (b) Balanced system (zero residual volts) Vc Vb (c) Unbalanced system phase A to ground fault (3Vo residual volts) Figure 9.19: Voltage polarised directional earth fault relay The primary star point of the VT must be earthed. However, a three-phase, three limb VT is not suitable, as there is no path for the residual magnetic flux. When the main voltage transformer associated with the high voltage system is not provided with a broken delta secondary winding to polarise the directional earth fault relay, it is permissible to use three single-phase interposing voltage transformers. Their primary windings are connected in star and their secondary windings are connected in broken delta. For satisfactory operation, however, it is necessary to ensure that the main voltage transformers are of a suitable construction to reproduce the residual voltage and that the star point of the primary winding is solidly earthed. In addition, the 9-18 The residual voltage at any point in the system may be insufficient to polarise a directional relay, or the voltage transformers available may not satisfy the conditions for providing residual voltage. In these circumstances, negative sequence current can be used as the polarising quantity. The fault direction is determined by comparison of the negative sequence voltage with the negative sequence current. The RCA must be set based on the angle of the negative phase sequence source voltage. 9.18 EARTH FAULT PROTECTION ON INSULATED NETWORKS Occasionally, a power system is run completely insulated from earth. The advantage of this is that a single phase-earth fault on the system does not cause any earth fault current to flow, and so the whole system remains operational. The system must be designed to withstand high transient and steady-state overvoltages however, so its use is generally restricted to low and medium voltage systems. It is vital that detection of a single phase-earth fault is achieved, so that the fault can be traced and rectified. While system operation is unaffected for this condition, the occurrence of a second earth fault allows substantial currents to flow. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults The absence of earth fault current for a single phase-earth fault clearly presents some difficulties in fault detection. Two methods are available using modern relays. 9.18.1 Residual Voltage phase-earth fault is present. The relays on the healthy feeders see the unbalance in charging currents for their own feeders. The relay in the faulted feeder sees the charging currents in the rest of the system, with the current of its’ own feeders cancelled out. Figure 9.21 shows the phasor diagram. When a single phase-earth fault occurs, the healthy phase voltages rise by a factor of 3 and the three phase voltages no longer have a phasor sum of zero. Hence, a residual voltage element can be used to detect the fault. However, the method does not provide any discrimination, as the unbalanced voltage occurs on the whole of the affected section of the system. One advantage of this method is that no CTs are required, as voltage is being measured. However, the requirements for the VTs as given in Section 9.17.1.1 apply. Grading is a problem with this method, since all relays in the affected section will see the fault. It may be possible to use definite-time grading, but in general, it is not possible to provide fully discriminative protection using this technique. Figure 9.21: Phasor diagram for insulated system with C phase-earth fault Use of Core Balance CTs is essential. With reference to Figure 9.21, the unbalance current on the healthy feeders lags the residual voltage by 90º . The charging currents on these feeders will be 3 times the normal value, as the phase-earth voltages have risen by this amount. The magnitude of the residual current is therefore three times the steady-state charging current per phase. As the residual currents on the healthy and faulted feeders are in antiphase, use of a directional earth fault relay can provide the discrimination required. The polarising quantity used is the residual voltage. By shifting this by 90o, the residual current seen by the relay on the faulted feeder lies within the ‘operate’ region of the directional characteristic, while the residual currents on the healthy feeders lie within the ‘restrain’ region. Thus, the RCA required is 90o. The relay setting has to lie between one and three times the per-phase charging current. Figure 9.20: Current distribution in an insulated system with a C phase–earth fault 9.18.2 Sensitive Earth Fault This method is principally applied to MV systems, as it relies on detection of the imbalance in the per-phase charging currents that occurs. Figure 9.20 shows the situation that occurs when a single This may be calculated at the design stage, but confirmation by means of tests on-site is usual. A single phase-earth fault is deliberately applied and the resulting currents noted, a process made easier in a modern digital or numeric relay by the measurement facilities provided. As noted earlier, application of such a fault for a short period does not involve any disruption to the network, or fault currents, but the duration should be as short as possible to guard against a second such fault occurring. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-19 Network Protection & Automation Guide It is also possible to dispense with the directional element if the relay can be set at a current value that lies between the charging current on the feeder to be protected and the charging current of the rest of the system. 9.19 EARTH FAULT PROTECTION ON PETERSEN COIL EARTHED NETWORKS Petersen Coil earthing is a special case of high impedance earthing. The network is earthed via a reactor, whose reactance is made nominally equal to the total system capacitance to earth. Under this condition, a single phaseearth fault does not result in any earth fault current in steadystate conditions. The effect is therefore similar to having an insulated system. The effectiveness of the method is dependent on the accuracy of tuning of the reactance value – changes in system capacitance (due to system configuration changes for instance) require changes to the coil reactance. In practice, perfect matching of the coil reactance to the system capacitance is difficult to achieve, so that a small earth fault current will flow. Petersen Coil earthed systems are commonly found in areas where the system consists mainly of rural overhead lines, and are particularly beneficial in locations subject to a high incidence of transient faults. V an jXL I f I B  I C  0 if V an jXL V an jXL  I B  IC V ab j XC  V ac j XC Figure 9.22: Earth fault in Petersen Coil earthed system To understand how to correctly apply earth fault protection to such systems, system behaviour under earth fault conditions must first be understood. Figure 9.22 shows a simple network earthed through a Petersen Coil. The equations clearly show that, if the reactor is correctly tuned, no earth fault current will flow. Figure 9.23 shows a radial distribution system earthed using a Petersen Coil. One feeder has a phase-earth fault on phase C. Figure 9.24 shows the resulting phasor diagrams, assuming that no resistance is present. In Figure 9.24(a), it can be seen that the fault causes the healthy phase voltages to rise by a factor of 3 and the charging currents lead the voltages by 90o. Figure 9.23: Distribution of currents during a C phase-earth fault – radial distribution system 9-20 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults IOF IROF Faulted feeder IROH Healthy feeders IROH IL 3XL -Vo IH3 IH2 IH1 Xco Key : IROF = Residual current on faulted feeder IROH = Residual current on healthy feeder It can therefore be seen that :- IOF = IL - IH1 - IH2 - IH3 IROF = IH3 + IOF So :- IROF = IL - IH1 - IH2 Figure 9.25: Zero sequence network showing residual currents Figure 9.24: C phase-earth fault in Petersen Coil earthed network: theoretical case –no resistance present in XL or XC Using a CBCT, the unbalance currents seen on the healthy feeders can be seen to be a simple vector addition of Ia1 and Ib1 and this lies at exactly 90o lagging to the residual voltage (Figure 9.24(b)). The magnitude of the residual current IR1 is equal to three times the steady-state charging current per phase. On the faulted feeder, the residual current is equal to IL - IH1 - IH2, as shown in Figure 9.24(c) and more clearly by the zero sequence network of Figure 9.25. However, in practical cases, resistance is present and Figure 9.26 shows the resulting phasor diagrams. If the residual voltage Vres is used as the polarising voltage, the residual current is phase shifted by an angle less than 90o on the faulted feeder and greater than 90o on the healthy feeders. Hence a directional relay can be used, and with an RCA of 0o, the healthy feeder residual current will fall in the ‘restrain’ area of the relay characteristic while the faulted feeder residual current falls in the ‘operate’ area. Figure 9.26: C phase-earth fault in Petersen Coil earthed network: practical case with resistance present in XL or XC Often, a resistance is deliberately inserted in parallel with the Petersen Coil to ensure a measurable earth fault current and increase the angular difference between the residual signals to aid relay application. Having established that a directional relay can be used, two possibilities exist for the type of protection element that can be applied – sensitive earth fault and zero sequence wattmetric. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-21 Network Protection & Automation Guide 9.19.1 Sensitive Earth Fault Protection To apply this form of protection, the relay must meet two requirements: x current measurement setting capable of being set to very low values quantities instead of zero sequence ones. The resulting values are therefore nine times the zero sequence quantities as the residual values of current and voltage are each three times the corresponding zero sequence values. The equation used is: Vres u I res u cos M  M c x an RCA of 0o, and capable of fine adjustment around this value The sensitive current element is required because of the very low current that may flow – so settings of less than 0.5% of rated current may be required. However, as compensation by the Petersen Coil may not be perfect, low levels of steady-state earth fault current will flow and increase the residual current seen by the relay. An often used setting value is the per phase charging current of the circuit being protected. Fine tuning of the RCA is also required about the 0o setting, to compensate for coil and feeder resistances and the performance of the CT used. In practice, these adjustments are best carried out on site through deliberate application of faults and recording of the resulting currents. 9 u VO u I O u cos M  M c Equation 9.5 where: Vres = residual voltage Ires = residual current VO = zero sequence voltage IO = zero sequence current  = angle between Vres and Ires C = relay characteristic angle setting The current and RCA settings are as for a sensitive earth fault relay. 9.19.2 Sensitive Wattmetric Protection It can be seen in Figure 9.26 that a small angular difference exists between the spill current on the healthy and faulted feeders. Figure 9.27 shows how this angular difference gives rise to active components of current which are in antiphase to each other. 9.20 EXAMPLES OF TIME AND CURRENT GRADING This section provides details of the time/current grading of some example networks, to illustrate the process of relay setting calculations and relay grading. They are based on the use of a modern numerical overcurrent relay shown in Figure 9.28 with setting data taken from this relay. Figure 9.27: Resistive components of spill current Consequently, the active components of zero sequence power will also lie in similar planes and a relay capable of detecting active power can make a discriminatory decision. If the wattmetric component of zero sequence power is detected in the forward direction, it indicates a fault on that feeder, while a power in the reverse direction indicates a fault elsewhere on the system. This method of protection is more popular than the sensitive earth fault method, and can provide greater security against false operation due to spurious CBCT output under non-earth fault conditions. Figure 9.28: MiCOM numerical overcurrent relay Wattmetric power is calculated in practice using residual 9-22 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults 9.20.1 Relay Phase Fault Setting Example – IDMT Relays/Fuses as 500MVA, as follows: x Reactor R1 Z R1 x 4 u 500 20 100% Cable C1 Z C1 0.096 u2 5 0.038: On 500MVA base, Z C1 x 0.038 u 100 u 500 112 15.7% Cables C2,C3 0.158: ZC 2 , ZC3 On 500MVA base, ZC 2 , ZC3 x 0.158 u 100 u 500 112 65.3% Source Impedance (500MVA base) 500 u 100% 100% 500 ZS 9.20.1.2 Fault Levels The fault levels are calculated as follows: x (i) At bus C, For 2 feeders, Fault Level = Figure 9.29: IDMT relay grading example In the system shown in Figure 9.29., the problem is to calculate appropriate relay settings for relays 1-5 inclusive. Because the example is concerned with grading, considerations such as bus-zone protection and CT knee-point voltage requirements are not dealt with. All curves are plotted to an 11kV base. The contactors in series with fuses FS1/FS2 have a maximum breaking capacity of 3kA, and relay F2 has been set to ensure that the fuse operates before the contactor for currents in excess of this value. CTs for relays F1, F2 and 5 are existing CTs with 5A secondaries, while the remaining CTs are new with 1A secondaries. Relay 5 is the property of the supply utility, and is required to be set using an SI characteristic to ensure grading with upstream relays. 9.20.1.1 Impedance Calculations 500 u 100 MVA Z R1  Z S  Z C1  Z C 2 2 = 201MVA = 10.6kA on 11kV base. For a single feeder, fault level = 178MVA = 9.33kA x (ii) At bus B Fault Level = 500 u 100 MVA Z S  Z C1  Z R1 = 232MVA = 12.2kA x (iii) At bus A Fault Level = 500 u 100 MVA Z S  Z C1 = 432MVA = 22.7kA x (iv) Source Fault Level = 500MVA = 26.3kA All impedances must first be referred to a common base, taken © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-23 Network Protection & Automation Guide 9.20.1.3 CT Ratio Selection This requires consideration not only of the maximum load current, but also of the maximum secondary current under fault conditions. CT secondaries are generally rated to carry a short-term current equal to 100 x rated secondary current. Therefore, a check is required that none of the new CT secondaries has a current of more than 100A when maximum fault current is flowing in the primary. Using the calculated fault currents, this condition is satisfied, so modifications to the CT ratios are not required. 9.20.1.4 Relay Overcurrent Settings – Relays 1/2 These relays perform overcurrent protection of the cable feeders, Busbar C and backup-protection to relays F1, F2 and their associated fuses FS1 and FS2. The settings for Relays 1 and 2 will be identical, so calculations will only be performed for Relay 1. Consider first the current setting of the relay. Relay 1 must be able to reset at a current of 400A – the rating of the feeder. The relay has a drop-off/pick-up ratio of 0.95, so the relay current setting must not be less than 400/0.95A, or 421A. A suitable setting that is greater than this value is 450A. However, Section 9.12.3 also recommends that the current setting should be three times the largest fuse rating (i.e. 3 x 160A, the rating of the largest fuse on the outgoing circuits from Busbar C), leading to a current setting of 480A, or 96% of relay rated primary current. Note that in this application of relays to a distribution system, the question of maximum and minimum fault levels are probably not relevant as the difference between maximum and minimum fault levels will be very small. However in other applications where significant differences between maximum and minimum fault levels exist, it is essential to ensure that the selection of a current setting that is greater than full load current does not result in the relay failing to operate under minimum fault current conditions. Such a situation may arise for example in a self-contained power system with its own generation. Minimum generation may be represented by the presence of a single generator and the difference between minimum fault level and maximum load level may make the choice of relay current settings difficult. The grading margin now has to be considered. For simplicity, a fixed grading margin of 0.3s between relays is used in the calculations, in accordance with Table 9.3. Between fuse and relay, Equation 9.4 is applied, and with fuse FS2 pre-arcing time of 0.01s (from Figure 9.30), the grading margin is 0.154s. Consider first the IDMT overcurrent protection. Select the EI characteristic, as fuses exist downstream, to ensure grading. 9-24 The relay must discriminate with the longest operating time between relays F1, F2 and fuse FS2 (being the largest fuse) at the maximum fault level seen by relays 1 and 2. The maximum fault current seen by relay 1 for a fault at Busbar C occurs when only one of cables C2, C3 is in service. This is because the whole of the fault current then flows through the feeder that is in service. With two feeders in service, although the fault level at Busbar C is higher, each relay only sees half of the total fault current, which is less than the fault current with a single feeder in service. With EI characteristics used for relays F1 and F2, the operating time for relay F1 is 0.02s at TMS=0.1 because the fault current is greater than 20 times relay setting, at which point the EI characteristic becomes definite time (Figure 9.4) and 0.05s for relay F2 (TMS=0.25). Hence select relay 1 operating time = 0.3+0.05=0.35s, to ensure grading with relay F2 at a fault current of 9.33kA. With a primary setting of 480A, a fault current of 9.33kA represents 9330/480 = 19.44 times setting Thus relay 1 operating time at TMS=1.0 is 0.21s. The required TMS setting is given by the formula: Operation Time Required / Actual Operation Time @ TMS=1 ?TMS 0.35 1.66 0.21 If this value of TMS is outside the settable range of the relay (maximum setting was 1.2 in historical variants), changes must be made to the relay current setting. This is necessary to bring the value of TMS required into the range available, provided this does not result in the inability of the relay to operate at the minimum fault level. By re-arrangement of the formula for the EI characteristic: I srIf § 80 · ¨  1¸ © t ¹ Where t= the required operation time (sec) IsrIf = setting of relay at fault current Hence, with t= 0.35, IsrIf = 15.16 Or, I srI 9330 15.16 So, I srI 616 500 615.4 A 1.232 Use 1.24 = 620A nearest available value © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults At a TMS of 1.0, operation time at 9330A 80 2 § 9330 · ¸ 1 ¨ © 620 ¹ 0.355s Hence, required TMS = 0.35/0.355 = 0.99, for convenience, use a TMS of 1.0, slightly greater than the required value. From the grading curves of Figure 9.30, it can be seen that there are no grading problems with fuse FS1 or relays F1 and F2. 9.20.1.5 Relay Overcurrent Settings - Relay 3 This relay provides overcurrent protection for reactor R1, and backup overcurrent protection for cables C2 and C3. The overcurrent protection also provides busbar protection for Busbar B. Again, the EI characteristic is used to ensure grading with relays 1 and 2. The maximum load current is 1000A. Relay 3 current setting is therefore: I sr 3 ! feederFLC CTprimary u 0.95 Substituting values, Isr3>1052A Use a setting of 106% or 1060A, nearest available setting above 1052A. Relay 3 has to grade with relays 1/2 under two conditions: x Condition 1: for a fault just beyond relays 1 and 2 where the fault current is the busbar fault current of 12.2kA x Condition 2: for a fault at Bus C where the fault current seen by either relay 1 or 2 is half the total Bus C fault current of 10.6kA, i.e. 5.3kA Examining first condition 1. With a current setting of 620A, a TMS of 1.0 and a fault current of 12.2kA, relay 1 operates in 0.21s. Using a grading interval of 0.3s, relay 3 must therefore operate in 0.3+0.21=0.51s at a fault current of 12.2kA 12.2kA represents 12200/1060 = 11.51 times setting for relay 3 and thus the time multiplier setting of relay 3 should be 0.84 to give an operating time of 0.51s at 11.51 times setting. Consider now condition 2. With settings of 620A and TMS of 1.0 and a fault current of 5.3kA, relay 1 operates in 1.11s. Using a grading interval of 0.3s, relay 3 must therefore operate in 0.3+1.11=1.41s at a fault current of 5.3kA 5.3kA represents 5300/1060 = 5 times setting for relay 3, and thus the time multiplier setting of relay 3 should be 0.33 to give an operating time of 1.11s at 5 times setting. Thus condition 1 represents the worst case and the time multiplier setting of relay 3 should be set at 0.84. In practice, a value of 0.85 is used as the nearest available setting on the relay. Relay 3 also has an instantaneous element. This is set so that it does not operate for the maximum through-fault current seen by the relay and a setting of 130% of this value is satisfactory. The setting is therefore: 1.3 x 12.2kA = 15.86kA This is equal to a current setting of 14.96 times the setting of relay 3. 9.20.1.6 Relay 4 This must grade with relay 3 and relay 5. The supply authority requires that relay 5 use an SI characteristic to ensure grading with relays further upstream, so the SI characteristic will be used for relay 4 also. Relay 4 must grade with relay 3 at Bus A maximum fault level of 22.7kA. However with the use of an instantaneous high set element for relay 3, the actual grading point becomes the point at which the high set setting of relay 3 operates, i.e. 15.86kA. At this current, the operation time of relay 3 is 80 u 0.85s 2 14.96  1 0.305s Thus, relay 4 required operating time is 0.305 + 0.3 = 0.605s at a fault level of 15.86kA. Relay 4 current setting must be at least 2800 3000 u 0.95 98% For convenience, use a value of 100% (=3000A). Thus relay 4 must operate in 0.605s at 15860/3000 = 5.29 times setting. Thus select a time multiplier setting of 0.15, giving a relay operating time of 0.62s for a normal inverse type characteristic. At this stage, it is instructive to review the grading curves, which are shown in Figure 9.30(a). While it can be seen that there are no grading problems between the fuses and relays 1/2, and between relays F1/2 and relays 1/2, it is clear that relay 3 and relay 4 do not grade over the whole range of fault current. This is a consequence of the change in characteristic for relay 4 to SI from the EI characteristic of relay 3 to ensure grading of relay 4 with relay 5. The solution is to increase the TMS setting of relay 4 until correct grading is achieved. The alternative is to increase the current setting, but this is © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-25 Network Protection & Automation Guide undesirable unless the limit of the TMS setting is reached, because the current setting should always be as low as possible to help ensure positive operation of the relay and provide overload protection. Trial and error is often used, but suitable software can speed the task – for instance it is not difficult to construct a spreadsheet with the fuse/relay operation times and grading margins calculated. Satisfactory grading can be found for relay 4 setting values of: must operate in 0.3 + 0.93 = 1.23s at 22.7kA A current setting of 110% of relay 4 current setting (i.e. 110% or 3300A) is chosen to ensure relay 4 picks up prior to relay 5. Thus 22.7kA represents 6.88 times the setting of relay 5. Relay 5 must grade with relay 4 at a fault current of 22.7kA, where the required operation time is 1.23s. At a TMS of 1.0, relay 5 operation time is IsrI4 = 1.0 or 3000A; TMS = 0.275 0.14 03.56s 0.02 1 6.88 At 22.7kA, the operation time of relay 4 is 0.93s. The revised grading curves are shown in Figure 9.30(b). 100.00 Therefore, the required TMS is 1.23/3.56 = 0.345, use 0.35 nearest available value. 10.00 The protection grading curves that result are shown in Figure 9.31 and the setting values in Table 9.6. Grading is now satisfactory. 1.00 0.10 0.01 100 1000 10000 100000 Current (A) (a) Initial grading curves. In situations where one of the relays to be graded is provided by a third party, it is common for the settings of the relay to be specified and this may lead to a lack of co-ordination between this relay and others (usually those downstream). Negotiation is then required to try and achieve acceptable settings, but it is often the case that no change to the settings of the relay provided by the third party is allowed. A lack of co-ordination between relays then has to be accepted over at least part of the range of fault currents. Relay Settings 100.00 Max Relay Load Fault or current Current CT Fuse Ratio 10.00 (A) Fuse Rating Current Setting Characteristic TMS Primary Per Amps Cent kA F1 190 10.6 200/5 EI 100 100 0.1 F2 130 10.6 150/5 EI 150 120 0.25 FS1 90 10.6 - 125A FS2 130 10.6 - 160A - - - 1 400 12.2 500/1 EI 620 124 1 2 400 12.2 500/1 EI 620 124 1 EI 1060 106 0.85 1.00 0.10 0.01 100 1000 10000 100000 3 1000 22.7 1000/1 Instantaneous 15860 14.96 - 4 3000 22.7 3000/1 SI 3000 100 0.275 5 3000 26.25 3000/5 SI 3300 110 0.35 Current (A) (b) Revised grading curves Relay F1 Relays 1/2 Relay F2 Relay 3 Fuse FS1 Relay 4 Table 9.6: Relay settings for overcurrent relay example Fuse FS2 Figure 9.30: Overcurrent grading exercise - initial relay grading curves 9.20.1.7 Relay 5 Relay 5 must grade with relay 4 at a fault current of 22.7kA. At this fault current, relay 4 operates in 0.93s and thus relay 5 9-26 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults detect and isolate low level earth faults not seen by the phase fault elements. Following the guidelines of Section 9.16, relays 1/2 can use a current setting of 30% (150A) and a TMS of 0.2, using the EI characteristic. Grading of relays 3/4/5 follows the same procedure as described for the phase-fault elements of these relays. 100.00 Time (sec) 10.00 1.00 9.20.3 Protection of Parallel Feeders 0.10 0.01 100 10000 1000 100000 Current (A) Relay F1 Relays 1/2 Relay F2 Relay 3 Fuse FS1 Relay 4 Fuse FS2 Relay 5 Figure 9.31: Final relay grading curves for overcurrent relay example Figure 9.32(a) shows two parallel transformer feeders forming part of a supply circuit. Impedances are as shown in the diagram. The example shows that unless relays 2 and 3 are made directional, they maloperate for a fault at F3. Also shown is how to calculate appropriate relay settings for all six relays to ensure satisfactory protection for faults at locations F1-F4. Figure 9.32(b) shows the impedance diagram, to 100MVA, 110kV base. The fault currents for faults with various system configurations are shown in Table 9.7. T1 220/110kV 50MVA Z=12.5% 4 9.20.2 Relay Earth Fault Settings The procedure for setting the earth fault elements is identical to that for the overcurrent elements, except that zero sequence impedances must be used if available and different from positive sequence impedances to calculate fault levels. However, such impedances are frequently not available, or known only approximately and the phase fault current levels have to be used. Note that earth fault levels can be higher than phase fault levels if the system contains multiple earth points or if earth fault levels are considered on the star side of a delta-star transformer when the star winding is solidly earthed. On the circuit with fuse F2, low-level earth faults may not be of sufficient magnitude to blow the fuse. Attempting to grade the earth fault element of the upstream relay with fuse F2 will not be possible. Similarly, relays F1 and F2 have phase fault settings that do not provide effective protection against earth faults. The remedy would be to modify the downstream protection, but such considerations lie outside the scope of this example. In general therefore, the earth fault elements of relays upstream of circuits with only phase fault protection (i.e. relays with only phase fault elements or fuses) will have to be set with a compromise that they will detect downstream earth faults but will not provide a discriminative trip. This illustrates the practical point that it is rare in anything other than a very simple network to achieve satisfactory grading for all faults throughout the network. In the example of Figure 9.29, the difference in fault levels between phase to phase and phase to earth faults is probably very small so the only function of earth fault elements is to I> Id 6 Source 10000MVA I> 2 I> Ic Ia IF3 IF4 Bus P 220kV F3 F4 If Ie IF1 1 T2 220/110kV 50MVA Z=12.5% Bus Q 110kV I> F1 Ib 5 3 IF2 I> I> F2 (a) Circuit diagram 4 2 I> I> Z=0.25pu Id 6 Source 0.01pu I> Bus P Ic Ia IF3 IF4 F3 F4 If IF1 1 Bus Q Z=0.25pu Ie F1 Ib 5 I> I> 3 IF2 I> All impedances to 100MVA, 110kV base F2 (b) Impedance diagram Figure 9.32: System diagram: Parallel feeder example Currents (A) Fault System Position Configuration Fault Ia Ib Ic Id Ie If F1 2 fdrs 3888 1944 1944 0 972 972 1944 F1/F2 1 fdr 2019 2019 0 0 1009 0 1009 F2 2 fdrs 3888 1944 1944 0 972 972 1944 F3 2 fdrs 3888 1944 1944 1944 972 972 1944 F4 1 fdr 26243 0 0 26243 0 26243 0 Table 9.7: Fault currents for parallel feeder example © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-27 Network Protection & Automation Guide If relays 2 and 3 are non-directional, then, using SI relay characteristics for all relays, grading of the relays is dictated by the following: x relay 4 is graded with relay 1 for faults at location F1 with one transformer feeder in service x fault at location F1, with 2 feeders in service x relay 4 is graded with relay 3 for faults at location F3 with two transformer feeders in service x fault at location F4, with one feeder in service x relay 6 grades with relay 4 for faults at F4 The settings shown in Figure 9.33(a) can be arrived at, with the relay operation times shown in Figure 9.33 (b). It is clear that for a fault at F3 with both transformer feeders in service, relay 3 operates at the same time as relay 2 and results in total disconnection of Bus Q and all consumers supplied solely from it. This is undesirable – the advantages of duplicated 100% rated transformers have been lost. x relay 6 also has to grade with relay 4 for faults at F1 with both transformer feeders in service – relay 6 sees the total fault current but relay 4 only 50% of this current Normal rules about calculating current setting values of relays in series apply. The settings and resulting operation times are given in Figure 9.34(b) and(c) respectively. T1 220/110kV 50MVA Z=12.5% Ia 4 I> Id IF4 6 Bus P 220kV I> 2 I> Ic IF3 F3 F4 If T2 220/110kV 50MVA Z=12.5% Source 10000MVA Ie 1 IF1 Bus Q 110kV I> F1 Ib 5 3 I> IF2 I> F2 Relay 1 2 3 4 5 6 (a) Circuit diagram Current CT Primary Setting 1 0.42 0.42 0.6 0.6 0.7 300 300 300 300 300 300 TMS Characteristic 0.2 0.1 0.1 0.275 0.275 0.475 SI SI SI SI SI SI (b) Relay settings 100.00 10.00 1.00 Figure 9.33: Relay grading for parallel feeder example – nondirectional relays By making relays 2 and 3 directional as shown in Figure 9.34 (a), lower settings for these relays can be adopted – they can be set as low as reasonably practical but normally a current setting of about 50% of feeder full load current is used, with a TMS of 0.1. Grading rules can be established as follows: 0.10 100 1000 (ii) (i) 10000 (iii) 100000 Current (A) - referred to 110kV (i) Fault current 3888A - faults F1, F2, F3 - 2 feeders (ii) Fault current 2019A - faults F1, F2 - 1 feeder (iii) Fault current 26243A - fault F4 - 1 feeder Relay 1 Relays 2/3 Relays 4/5 Relay 6 (c) Relay characteristics Figure 9.34: Relay grading for parallel feeder example – directional relays In practice, a complete protection study would include instantaneous elements on the primary side of the transformers and analysis of the situation with only one 9-28 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults transformer in service. These have been omitted from this example, as the purpose is to illustrate the principles of parallel feeder protection in a simple fashion. 9.20.4 Grading of a Ring Main Figure 9.35 shows a simple ring main, with a single infeed at Bus A and three load busbars. Settings for the directional relays R2-R7 and non-directional relays R1/R8 are required. Maximum load current in the ring is 785A (maximum continuous current with one transformer out of service), so 1000/1A CTs are chosen. The relay considered is a MiCOM P140 series. Figure 9.36 shows the impedance diagram for these two cases. Three-phase fault currents I1 and I1c can be calculated as 2.13kA and 3.67kA respectively, so that the worst case is with the ring open (this can also be seen from consideration of the impedance relationships, without the necessity of performing the calculation). Table 9.8 shows the fault currents at each bus for open points at CB1 and CB8. For grading of the relays, consider relays looking in a clockwise direction round the ring, i.e. relays R1/R3/R5/R7. I1 V °­ Z  Z CD  Z A D °½ Z S ®1  BC ¾  Z BC  Z CD  Z A D Z AB °¯ °¿ I 1' V Z S  Z BC  Z CD  Z A D Figure 9.36: Impedance diagrams with ring open Bus Figure 9.35: Ring main grading example – circuit diagram The first step is to establish the maximum fault current at each relay location. Assuming a fault at Bus B (the actual location is not important), two possible configurations of the ring have to be considered, firstly a closed ring and secondly an open ring. For convenience, the ring will be considered to be open at CB1 (CB8 is the other possibility to be considered, but the conclusion will be the same). D Clockwise Anticlockwise Open Point CB8 Open Point CB1 Fault Current kA 7.124 Bus Fault Current kA B 3.665 C 4.259 C 5.615 B 3.376 D 8.568 Table 9.8: Fault current tabulation with ring open 9.20.4.1 Relay R7 Load current cannot flow from Bus D to Bus A since Bus A is the only source. Hence low relay current and TMS settings © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-29 Network Protection & Automation Guide can be chosen to ensure a rapid fault clearance time. These can be chosen arbitrarily, so long as they are above the cable charging current and within the relay setting characteristics. Select a relay current setting of 0.8 (i.e. 800A CT primary current) and TMS of 0.05. This ensures that the other relays will not pick up under conditions of normal load current. At a fault current of 3376A, relay operating time on the SI characteristic is: ª º 0.14 0.05 u « »s 0.02  4 . 22 1 ¬ ¼ 100.00 10.00 0.24 s 9.20.4.2 Relay R5 This relay must grade with Relay R7 at 3376A and have a minimum operation time of 0.54s. The current setting for Relay R5 must be at least 110% that of relay R7 to prevent unwanted pickup. Therefore select relay R5 current setting of 0.88 (880A CT primary current). 1.00 Relay R1 Relay R3 Relay R5 Relay R5 operating time at TMS = 1.0 ª º 0.14 « »s 0.02  1¼ ¬ 3.84 Relay R7 0.10 1000 5.14 s Let’s assume that we have, for example, an earlier version of the relay whose available TMS settings were less granular in steps of 0.025. In this case use the nearest settable value of TMS of 0.125. Table 9.9 summarises the relay settings while Figure 9.37 and Figure 9.38 show the relay grading curves. Relay Relay Characteristic CT Ratio 100,000 Figure 9.37: Ring main example – relay grading curves. Clockwise grading of relays (ring open at CB8) Hence, relay R5 TMS = 0.54/5.14 = 0.105 Bus 10000 Current (A) Max Max Fault Current Load Current (A) Setting Current (3.3kV base) p.u. (A) TMS D R7 SI 1000/1 874 3376 0.8 0.05 C R5 SI 1000/1 874 4259 0.88 0.125 B R3 SI 1000/1 874 7124 0.97 0.2 A R1 SI 1000/1 874 14387 1.07 0.275 A R8 SI 1000/1 874 14387 1.07 0.3 D R6 SI 1000/1 874 8568 0.97 0.2 C R4 SI 1000/1 874 5615 0.88 0.125 B R2 SI 1000/1 874 3665 0.8 0.05 100.00 10.00 1.00 Relay R8 Relay R6 Relay R4 Table 9.9: Ring main example relay settings Relay R2 0.10 1000 10000 100,000 Current (A) Figure 9.38: Ring main example – relay grading curves. Anticlockwise grading of relays (ring open at CB1) 9-30 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 9 ˜ Overcurrent Protection for Phase and Earth Faults 9.21 HI-Z - HIGH IMPEDANCE DOWNED CONDUCTOR PROTECTION too can pose fault detection problems due to the natural good insulating properties, especially if the road is dry. High impedance (“Hi-Z”) faults are generally defined as the unwanted contact of an electrical conductor with a nonconductive surface like asphalt road, concrete, tree limbs, sand, wooden fences or some other surface or object which restricts the fault current to a level below that which can be reliably detected by conventional overcurrent and earth fault relays. In some cases even sensitive earth fault protection cannot reliably detect such low levels of fault current flow. Undetected high impedance faults such as downed conductors are dangerous for nearby staff, the public, and livestock. The primary objective of clearing such faults is therefore towards protection of human and animal life, and property, and not towards the integrity and selectivity of the power system. Therefore, high-impedance fault detection is becoming increasingly important for utilities and protection engineers, as moral and legal challenges press them to take a greater duty of care and social responsibility for all that may be in the proximity of their power assets. It has been explained that such a downed conductor will tend to strike a fault arc. This offers a real advantage in terms of detection of such faults, because arcs have particular characteristics: The typical fault scenario is where a distribution overhead line conductor has fallen, for example where corrosion or wind and/or ice loading over time have caused the conductor to break free from its retaining clamp at the tower or pole. Repeat failures of jumpers or previously-repaired spliced sections may also give rise to a downed conductor, which then will fall under a combination of gravity and any remaining tension to rest on whatever surface lies below it. As previously described, non-conductive surfaces will tend to limit the fault current which flows. This is due to their high resistivity, and the need for the earth fault current to flow back to the source of supply, and a legitimate zero sequence current source. Typically, this will necessitate the current returning to the nearest adjacent earthed tower, for the return current then to flow in any aerial earth wire. If the circuit has no earth wire, the fault current will need to return typically to the earthed star-point of the upstream distribution transformer. In the case of a conductor falling onto rock or sand, the challenge is made all the harder in that the initial contact surface, and many metres of fault current flow in the same material composition which can drastically limit the prospective fault current. In the case of a conductor falling onto a fence, if the wood is dry this may have a high resistivity, but that high resistance may only apply for a few metres, until the current can flow in moist soil underground. x Arcs are rich in harmonics, with a persistence and randomness of the harmonic profile which is not typically seen in normal load current. x The heat and energy in the arc, plus any wind and remaining tension in the wire, tend to cause movement of the conductor – this leads to randomness in the flow of fundamental current too. x On certain surfaces, the heat from the arc will affect the insulating properties, and any moisture in the contact area – this will further induce randomness in harmonics, fundamental current, and the persistence of any fault current flow. Modern feeder management relays offer numerical algorithms which react to (1) prolonged intermittency in current flow, and (2) unusual levels or prevalence of harmonics, to be used independently, or in combination, as a reliable method to detect high impedance faults such as downed conductors. These techniques can be directionalised using power-based techniques. 9.22 REFERENCES [9.1]. Directional Element Connections for Phase Relays. W.K Sonnemann, Transactions A.I.E.E. 1950. Sand poses a particular problem, because once a conductor falls onto it and arc current strikes, the heat in the arc can cause clumps of the surrounding sand to turn to glass, which partially insulates the conductor from the earth. Asphalt roads © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 9-31 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 10 Unit Protection of Feeders 10.1 10.2 10.3 10.4 10.5 10.6 10.7 Introduction Convention of Direction Conditions for Direction Comparison Circulating Current System Balanced Voltage System Summation Arrangements Examples of Electromechanical and Static Unit Protection Systems 10.8 Digital/Numerical Current Differential Protection Systems 10.9 Carrier Unit Protection Schemes 10.10 Current Differential Scheme – Analogue Techniques 10.11 Phase Comparison Protection Scheme Considerations 10.12 Examples 10.13 Reference 10.1 INTRODUCTION The graded overcurrent systems described in Chapter 9, though attractively simple in principle, do not meet all the protection requirements of a power system. Application difficulties are encountered for two reasons: firstly, satisfactory grading cannot always be arranged for a complex network, and secondly, the settings may lead to maximum tripping times at points in the system that are too long to prevent excessive disturbances occurring. These problems led to the concept of 'Unit Protection', whereby sections of the power system are protected individually as a complete unit without reference to other sections. One form of ‘Unit Protection’ is also known as ‘Differential Protection’, as the principle is to sense the difference in currents between the incoming and outgoing terminals of the unit being protected. Other forms can be based on directional comparison, or distance teleprotection schemes, which are covered in Chapter 12, or phase comparison protection, which is discussed later in this chapter. The configuration of the power system may lend itself to unit protection; for instance, a simple earth fault relay applied at the source end of a transformer-feeder can be regarded as unit protection provided that the transformer winding associated with the feeder is not earthed. In this case the protection coverage is restricted to the feeder and transformer winding because the transformer cannot transmit zero sequence current to an out-of-zone fault. In most cases, however, a unit protection system involves the measurement of fault currents (and possibly voltages) at each end of the zone, and the transmission of information between the equipment at zone boundaries. It should be noted that a stand-alone distance relay, although nominally responding only to faults within their setting zone, does not satisfy the conditions for a unit system because the zone is not clearly defined; it is defined only within the accuracy limits of the measurement. Also, to cater for some conditions, the setting of a stand-alone distance relay may also extend outside of the protected zone to cater for some conditions. Merz and Price [10.1] first established the principle of current differential unit systems; their fundamental differential systems have formed the basis of many highly developed protection arrangements for feeders and numerous other items of plant. In one arrangement, an auxiliary ‘pilot’ circuit interconnects Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 10-1 Network Protection & Automation Guide similar current transformers at each end of the protected zone, as shown in Figure 10.1. Current transmitted through the zone causes secondary current to circulate round the pilot circuit without producing any current in the relay. For a fault within the protected zone the CT secondary currents will not balance, compared with the through-fault condition, and the difference between the currents will flow in the relay. An alternative arrangement is shown in Figure 10.2, in which the CT secondary windings are opposed for through-fault conditions so that no current flows in the series connected relays. The former system is known as a ‘Circulating Current’ system, while the latter is known as a ‘Balanced Voltage’ system. negative at H, while the infeeds to the faulted section HJ are both positive. Figure 10.3: Convention of current direction Neglect of this rule has often led to anomalous arrangements of equipment or difficulty in describing the action of a complex system. When applied, the rule will normally lead to the use of identical equipments at the zone boundaries, and is equally suitable for extension to multi-ended systems. It also conforms to the standard methods of network analysis 10.3 CONDITIONS FOR DIRECTION COMPARISON Figure 10.1: Circulating current system The circulating current and balanced voltage systems of Figure 10.1 and Figure 10.2 perform full vectorial comparison of the zone boundary currents. Such systems can be treated as analogues of the protected zone of the power system, in which CT secondary quantities represent primary currents and the relay operating current corresponds to an in-zone fault current. These systems are simple in concept; they are nevertheless applicable to zones having any number of boundary connections and for any pattern of terminal currents. Figure 10.2: Balanced voltage system Most systems of unit protection function through the determination of the relative direction of the fault current. This direction can only be expressed on a comparative basis, and such a comparative measurement is the common factor of many systems, including directional comparison protection and distance teleprotection schemes with directional impedance measurement. A major factor in consideration of unit protection is the method of communication between the relays. This is covered in detail in Chapter 8 in respect of the latest fibre-optic based digital techniques. 10.2 CONVENTION OF DIRECTION It is useful to establish a convention of direction of current flow; for this purpose, the direction measured from a busbar outwards along a feeder is taken as positive. Hence the notation of current flow shown in Figure 10.3; the section GH carries a through current which is counted positive at G but 10-2 To define a current requires that both magnitude and phase be stated. Comparison in terms of both of these quantities is performed in the Merz-Price systems, but it is not always easy to transmit all this information over some pilot channels. Chapter 8 provides a detailed description of modern methods that may be used. 10.4 CIRCULATING CURRENT SYSTEM The principle of this system is shown in outline in Figure 10.1. If the current transformers are ideal, the functioning of the system is straightforward. The transformers will, however, have errors arising from both Wattmetric and magnetising current losses that cause deviation from the ideal, and the interconnections between them may have unequal impedances. This can give rise to a ‘spill’ current through the relay even without a fault being present, thus limiting the sensitivity that can be obtained. Figure 10.4 shows the equivalent circuit of the circulating current scheme. If a high impedance relay is used, then unless the relay is located at point J in the circuit a current will flow through the relay even © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 10 ˜ Unit Protection of Feeders with currents IPg and IPh being identical. If a low impedance relay is used, voltage FF’ will be very small, but the CT exciting currents will be unequal due to the unequal burdens and relay current IR will still be non-zero. 10.4.2 Bias The 'spill' current in the relay arising from these various sources of error is dependent on the magnitude of the through current, being negligible at low values of through-fault current but sometimes reaching a disproportionately large value for more severe faults. Setting the operating threshold of the protection above the maximum level of spill current produces poor sensitivity. By making the differential setting approximately proportional to the fault current, the low-level fault sensitivity is greatly improved. Figure 10.5 shows a typical bias characteristic for a modern relay that overcomes the problem. At low currents, the bias is small, thus enabling the relay to be made sensitive. At higher currents, such as would be obtained from inrush or through fault conditions, the bias used is higher, and thus the spill current required to cause operation is higher. The relay is therefore more tolerant of spill current at higher fault currents and therefore less likely to maloperate, while still being sensitive at lower current levels. I1 I2 I3 Figure 10.4: Equivalent circuit and potential diagram for circulating current scheme 10.4.1 Transient Instability It is shown in Section 6.4.10 that an asymmetrical current applied to a current transformer will induce a flux that is greater than the peak flux corresponding to the steady state alternating component of the current. It may take the CT into saturation, with the result that the dynamic exciting impedance is reduced and the exciting current greatly increased. When the balancing current transformers of a unit protection system differ in excitation characteristics, or have unequal burdens, the transient flux build-ups will differ and an increased 'spill' current will result. There is a consequent risk of relay operation on a healthy circuit under transient conditions, which is clearly unacceptable. One solution is to include a stabilising resistance in series with the relay. Details of how to calculate the value of the stabilising resistor are usually included in the instruction manuals of all relays that require one. When a stabilising resistor is used, the relay current setting can be reduced to any practical value, the relay now being a voltage-measuring device. There is obviously a lower limit, below which the relay element does not have the sensitivity to pick up. Idiff = I1+ I2 + I3 Operate Percentage bias k2 Percentage bias k1 Restrain Is1 Is2 Ibias = I1 + I2 + I3 2 Figure 10.5: Typical bias characteristic of relay 10.5 BALANCED VOLTAGE SYSTEM This section is included for historical reasons, mainly because of the number of such schemes still to be found in service – for new installations it has been almost completely superseded by circulating current schemes. It is the dual of the circulating current protection, and is summarised in Figure 10.2 as used in the ‘MHOR’ scheme. With primary through current, the secondary e.m.f.s of the current transformers are opposed, and provide no current in the interconnecting pilot leads or the series connected relays. An in-zone fault leads to a circulating current condition in the CT secondaries and hence to relay operation. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 10-3 Network Protection & Automation Guide An immediate consequence of the arrangement is that the current transformers are in effect open-circuited, as no secondary current flows for any primary through-current conditions. To avoid excessive saturation of the core and secondary waveform distortion, the core is provided with nonmagnetic gaps sufficient to absorb the whole primary m.m.f. at the maximum current level, the flux density remaining within the linear range. The secondary winding therefore develops an e.m.f. and can be regarded as a voltage source. The shunt reactance of the transformer is relatively low, so the device acts as a transformer loaded with a reactive shunt; hence the name of transactor. The equivalent circuit of the system is as shown in Figure 10.6. The series connected relays are of relatively high impedance; because of this the CT secondary winding resistances are not of great significance and the pilot resistance can be moderately large without significantly affecting the operation of the system. This is why the scheme was developed for feeder protection. 10.6 SUMMATION ARRANGEMENTS Schemes have so far been discussed as though they were applied to single-phase systems. A polyphase system could be provided with independent protection for each phase. Modern digital or numerical relays communicating via fibre-optic links operate on this basis, since the amount of data to be communicated is not a major constraint. For older relays, use of this technique over pilot wires may be possible for relatively short distances, such as would be found with industrial and urban power distribution systems. Clearly, each phase would require a separate set of pilot wires if the protection was applied on a per phase basis. The cost of providing separate pilot-pairs and also separate relay elements per phase is generally prohibitive. Summation techniques can be used to combine the separate phase currents into a single relaying quantity for comparison over a single pair of pilot wires. 10.6.1 Summation Transformer Principle A winding, either within a measuring relay, or an auxiliary current transformer, is arranged as in Figure 10.7. The interphase sections of this winding, A-B, and B-C, often have a relatively similar number of turns, with the neutral end of the winding (C-N) generally having a greater number of turns. Figure 10.6: Equivalent circuit for balanced voltage system 10.5.1 Stability Limit of the Voltage Balance System Unlike normal current transformers, transactors are not subject to errors caused by the progressive build-up of exciting current, because the whole of the primary current is expended as exciting current. In consequence, the secondary e.m.f. is an accurate measure of the primary current within the linear range of the transformer. Provided the transformers are designed to be linear up to the maximum value of fault current, balance is limited only by the inherent limit of accuracy of the transformers, and as a result of capacitance between the pilot cores. A broken line in the equivalent circuit shown in Figure 10.6 indicates such capacitance. Under through-fault conditions the pilots are energised to a proportionate voltage, the charging current flowing through the relays. The stability ratio that can be achieved with this system is only moderate and a bias technique is used to overcome the problem. 10-4 Figure 10.7: Typical summation winding This winding has a number of special properties, which are discussed in the next section. 10.6.2 Sensitivity Using Summation Transformers This section shows the performance of the summation transformer in a typical MBCI ‘Translay’ scheme. In the MBCI relay, the number of turns on the input side of the summation CT is in the ratio: x A-B 1.25 x B-C 1 x C-N 3 (or 6) © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 10 ˜ Unit Protection of Feeders Boosting the turns ratio to 6 for the neutral end of the winding serves to increase the earth fault sensitivity of the scheme, as is shown in the bracketed performance below. Unbalanced fault currents will energise different numbers of turns, according to which phase(s) is/are faulted. This leads to relay settings which are in inverse ratio to the number of turns involved. If the relay has a setting of 100% for a B-C fault, the following proportionate trip thresholds will apply: x A-B 80% x B-C 100% x C-A 44% x A-B-C 50% x A-N 19% (or 12% for N=6) x B-N 25% (or 14% for N=6) x C-N 33% (or 17% for N=6) 10.7 EXAMPLES OF ELECTROMECHANICAL AND STATIC UNIT PROTECTION SYSTEMS As mentioned above, the basic balanced voltage principle of protection evolved to biased protection systems. Several of these have been designed, some of which appear to be quite different from others. These dissimilarities are, however, superficial. A number of these systems that are still in common use are described below. which delivers the reference e.m.f. The secondary windings of the conjugate relays are interconnected as a balanced voltage system over the pilot channel, the lower electromagnets of both relays being included in this circuit. Through current in the power circuit produces a state of balance in the pilot circuit and zero current in the lower electromagnet coils. In this condition, no operating torque is produced. An in-zone fault causing an inflow of current from each end of the line produces circulating current in the pilot circuit and the energisation of the lower electromagnets. These co-operate with the flux of the upper electromagnets to produce an operating torque in the discs of both relays. An infeed from one end only will result in relay operation at the feeding end, but no operation at the other, because of the absence of upper magnet flux. Bias is produced by a copper shading loop fitted to the pole of the upper magnet, thereby establishing a Ferraris motor action that gives a reverse or restraining torque proportional to the square of the upper magnet flux value. Typical settings achievable with such a relay are: x Least sensitive earth fault - 40% of rating x Least sensitive phase-phase fault - 90% of rating x Three-phase fault - 52% of rating 10.7.1 ‘Translay’ Balanced Voltage Electromechanical System 10.7.2 Static Circulating Current Unit Protection System - ‘MBCI Translay’ A typical biased, electromechanical balanced voltage system, trade name ‘Translay’, still giving useful service on distribution systems is shown in Figure 10.8. The electromechanical design derives its balancing voltages from the transactor incorporated in the measuring relay at each line end. The latter are based on the induction-type meter electromagnet as shown in Figure 10.8. A typical static modular pilot wire unit protection system, operating on the circulating current principle is shown in Figure 10.9. This uses summation transformers with a neutral section that is tapped, to provide alternative earth fault sensitivities. Phase comparators tuned to the power frequency are used for measurement and a restraint circuit gives a high level of stability for through faults and transient charging currents. High-speed operation is obtained with moderately sized current transformers and where space for current transformers is limited and where the lowest possible operating time is not essential, smaller current transformers may be used. This is made possible by a special adjustment (Kt) by which the operating time of the differential protection can be selectively increased if necessary, thereby enabling the use of current transformers having a correspondingly decreased knee-point voltage, whilst ensuring that throughfault stability is maintained to greater than 50 times the rated current. The upper magnet carries a summation winding to receive the output of the current transformers, and a secondary winding Internal faults give simultaneous tripping of relays at both ends of the line, providing rapid fault clearance irrespective of Figure 10.8: ‘Translay’ biased electromechanical differential protection system © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 10-5 Network Protection & Automation Guide whether the fault current is fed from both line ends or from only one line end. Ic Ic Ic Figure 10.9: Typical static circulating current feeder unit protection circuit diagram 10.8 DIGITAL/NUMERICAL CURRENT DIFFERENTIAL PROTECTION SYSTEMS A digital or numerical unit protection relay may typically provide phase-segregated current differential protection. This means that the comparison of the currents at each relay is done on a per phase basis. For digital data communication between relays, it is usual that a direct optical connection is used (for short distances) or a multiplexed link. Link speeds of 64kbit/s (56kbit/s in N. America) are normal, and up to 2 Mbit/s in some cases. Through current bias is typically applied to provide through fault stability in the event of CT saturation. A dual slope bias technique (Figure 10.5) is used to enhance stability for through faults. A typical trip criterion is as follows: I bias  I S 2 For I diff ! k1 I bias  I S 1 I bias ! I S 2 Tuned measurement of power frequency currents provides a high level of stability with capacitance inrush currents during line energisation. The normal steady-state capacitive charging current can be allowed for if a voltage signal can be made available and the susceptance of the protected zone is known. Where an earthed transformer winding or earthing transformer is included within the zone of protection, some form of zero sequence current filtering is required. This is because there will be an in-zone source of zero sequence current for an external earth fault. The differential protection will see zero sequence differential current for an external fault and it could incorrectly operate as a result. In older protection schemes, the problem was eliminated by delta connection of the CT secondary windings. For a digital or numerical relay, a selectable software zero sequence filter is typically employed. The minimum setting that can be achieved with such techniques while ensuring good stability is 20% of CT primary current. The problem remains of compensating for the time difference between the current measurements made at the ends of the feeder, since small differences can upset the stability of the scheme, even when using fast direct fibre-optic links. The problem is overcome by either time synchronisation of the measurements taken by the relays, or calculation of the propagation delay of the link continuously. 10.8.1 Time Synchronisation of Relays For I diff ! k 2 I bias  k 2  k1 I s 2  I S 1 Once the relay at one end of the protected section has determined that a trip condition exists, an intertrip signal is transmitted to the relay at the other end. Relays that are supplied with information on line currents at all ends of the line may not need to implement intertripping facilities. However, it is usual to provide intertripping in any case to ensure the protection operates in the event of any of the relays detecting a fault. 10-6 A facility for vector/ratio compensation of the measured currents, so that transformer feeders can be included in the unit protection scheme without the use of interposing CTs or defining the transformer as a separate zone increases versatility. Any interposing CTs required are implemented in software. Maloperation on transformer inrush is prevented by second harmonic detection. Care must be taken if the transformer has a wide-ratio on-load tap changer, as this results in the current ratio departing from nominal and may cause maloperation, depending on the sensitivity of the relays. The initial bias slope should be set taking this into consideration. Fibre-optic media allow direct transmission of the signals between relays for distances of up to several km without the need for repeaters. For longer distances repeaters will be required. Where a dedicated fibre pair is not available, multiplexing techniques can be used. As phase comparison techniques are used on a per phase basis, time synchronisation of the measurements is vitally important. This requires knowledge of the transmission delay between the relays. Four techniques are possible for this: © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 10 ˜ Unit Protection of Feeders a. assume a value b. measurement during commissioning only c. continuous online measurement d. GPS time signal Method (a) is not used, as the error between the assumed and actual value will be too great. Method (b) provides reliable data if direct communication between relays is used. As signal propagation delays may change over a period of years, repeat measurements may be required at intervals and relays re-programmed accordingly. There is some risk of maloperation due to changes in signal propagation time causing incorrect time synchronisation between measurement intervals. The technique is less suitable if rented fibre-optic pilots are used, since the owner may perform circuit re-routing for operational reasons without warning, resulting in the propagation delay being outside of limits and leading to scheme maloperation. Where re-routing is limited to a few routes, it may be possible to measure the delay on all routes and pre-program the relays accordingly, with the relay digital inputs and ladder logic being used to detect changes in route and select the appropriate delay accordingly. Method (c), continuous sensing of the signal propagation delay, also known as ‘ping-pong’, is a robust technique. One method of achieving this is shown in Figure 10.10. if they start coincidentally, due to slight differences in sampling frequencies. At time TA1 relay A transmits its data to relay B, containing a time tag and other data. Relay B receives it at time TA1+Tp1 where Tp1 is the propagation time from relay A to relay B. Relay B records this time as time TB*. Relay B also sends messages of identical format to relay A. It transmits such a message at time TB3, received by relay A at time TB3+Tp2 (say time TA*), where Tp2 is the propagation time from relay B to relay A. The message from relay B to relay A includes the time TB3, the last received time tag from relay A (TA1) and the delay time between the arrival time of the message from A (TB*) and TB3 – call this the delay time Td. The total elapsed time is therefore: (T A T A 1) (T d T p1T p 2) If it is assumed that Tp1 = Tp2, then the value of Tp1 and Tp2 can be calculated, and hence also TB3. The relay B measured data as received at relay A can then be adjusted to enable data comparison to be performed. Relay B performs similar computations in respect of the data received from relay A (which also contains similar time information). Therefore, continuous measurement of the propagation delay is made, thus reducing the possibility of maloperation due to this cause to a minimum. Comparison is carried out on a per-phase basis, so signal transmission and the calculations are required for each phase. A variation of this technique is available that can cope with unequal propagation delays in the two communication channels under well-defined conditions. The technique can also be used with all types of pilots, subject to provision of appropriate interfacing devices. Method (d) is also a robust technique. It involves both relays being capable of receiving a time signal from a GPS clock source. The propagation delay on each communication channel is no longer required to be known or calculated as both relays are synchronised to a common time signal. For the protection scheme to meet the required performance in respect of availability and maloperation, the GPS signal must be capable of reliable receipt under all atmospheric conditions. There is extra satellite signal receiving equipment required at both ends of the line, which implies extra cost. Figure 10.10: Signal propagation delay measurement Relays at ends A and B sample signals at time TA1, TA2 … and TB1, TB2 … respectively. The times will not be coincident, even In applications where SONET (synchronous digital hierarchy) communication links are used, it cannot be assumed that TP1 is equal to TP2, as split path routings which differ from A to B, and B to A are possible. In this scenario, method (d) is highly recommended, as it is able to calculate the independent propagation delays in each direction. The minimum setting that can be achieved with such techniques while ensuring good stability is 20% of CT primary current. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 10-7 Network Protection & Automation Guide 10.8.2 Application to Mesh Corner and 1 1/2 Breaker Switched Substations These substation arrangements are quite common, and the arrangement for the latter is shown in Figure 10.11. Problems exist in protecting the feeders due to the location of the line CTs, as either Bus 1 or Bus 2 or both can supply the feeder. Two alternatives are used to overcome the problem, and they are shown in the Figure. The first is to common the line CT inputs (as shown for Feeder A) and the alternative is to use a second set of CT inputs to the relay (as shown for Feeder B). Bus 2 Bus 1 B2 IF B1 IF F Id > Id > Stub bus inputs A B Figure 10.11: Breaker and a half switched substation In the case of a through fault as shown, the relay connected to Feeder A theoretically sees no unbalance current, and hence will be stable. However, with the line disconnect switch open, no bias is produced in the relay, so CTs need to be well matched and equally loaded if maloperation is to be avoided. For Feeder B, the relay also theoretically sees no differential current, but it will see a large bias current even with the line disconnect switch open. This provides a high degree of stability, in the event of transient asymmetric CT saturation. Therefore, this technique is preferred. Sensing of the state of the line isolator through auxiliary contacts enables the current values transmitted to and received from remote relays to be set to zero when the isolator is open. Hence, stub-bus protection for the energised part of the bus is then possible, with any fault resulting in tripping of the relevant CB. directly on the communication medium. Instead a relaying quantity may be used to vary the higher frequency associated with each medium (or the light intensity for fibre-optic systems), and this process is normally referred to as modulation of a carrier wave. Demodulation or detection of the variation at a remote receiver permits the relaying quantity to be reconstituted for use in conjunction with the relaying quantities derived locally, and forms the basis for all carrier systems of unit protection. Carrier systems are generally insensitive to induced power system currents since the systems are designed to operate at much higher frequencies, but each medium may be subjected to noise at the carrier frequencies that may interfere with its correct operation. Variations of signal level, restrictions of the bandwidth available for relaying and other characteristics unique to each medium influence the choice of the most appropriate type of scheme. Methods and media for communication are discussed in Chapter 8. 10.10 CURRENT DIFFERENTIAL SCHEME – ANALOGUE TECHNIQUES The carrier channel is used in this type of scheme to convey both the phase and magnitude of the current at one relaying point to another for comparison with the phase and magnitude of the current at that point. Transmission techniques may use either voice frequency channels using FM modulation or A/D converters and digital transmission. Signal propagation delays still need to be taken into consideration by introducing a deliberate delay in the locally derived signal before a comparison with the remote signal is made. A further problem that may occur concerns the dynamic range of the scheme. As the fault current may be up to 30 times the rated current, a scheme with linear characteristics requires a wide dynamic range, which implies a wide signal transmission bandwidth. In practice, bandwidth is limited, so either a nonlinear modulation characteristic must be used or detection of fault currents close to the setpoint will be difficult. 10.10.1 Phase Comparison Scheme 10.9 CARRIER UNIT PROTECTION SCHEMES In earlier sections, the pilot links between relays have been treated as an auxiliary wire circuit that interconnects relays at the boundaries of the protected zone. In many circumstances, such as the protection of longer line sections or where the route involves installation difficulties, it is too expensive to provide an auxiliary cable circuit for this purpose, and other means are sought. In all cases (apart from private pilots and some short rented pilots) power system frequencies cannot be transmitted 10-8 The carrier channel is used to convey the phase angle of the current at one relaying point to another for comparison with the phase angle of the current at that point. The principles of phase comparison are shown in Figure 10.12. The carrier channel transfers a logic or 'on/off' signal that switches at the zero crossing points of the power frequency waveform. Comparison of a local logic signal with the corresponding signal from the remote end provides the basis for the measurement of phase shift between power system currents at the two ends and hence discrimination between © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 10 ˜ Unit Protection of Feeders internal and through faults. T Load or through fault currents at the two ends of a protected feeder are in antiphase (using the normal relay convention for direction), whilst during an internal fault the (conventional) currents tend towards the in-phase condition. Hence, if the phase relationship of through fault currents is taken as a reference condition, internal faults cause a phase shift of approximately 180° with respect to the reference condition. Phase comparison schemes respond to any phase shift from the reference conditions, but tripping is usually permitted only when the phase shift exceeds an angle of typically 30 to 90 degrees, determined by the time delay setting of the measurement circuit, and this angle is usually referred to as the Stability Angle. Figure 10.13 is a polar diagram that shows the discrimination characteristics that result from the measurement techniques used in phase comparison schemes. End G End H Signalling equipment and communication channel A Summation Squarer B Transmitter network D' Receiver D Transmitter C Squarer Summation network IS 180 o _ Tripping O T T IS R Stability T 0o 270 o System differential phase shift referred to through fault reference condition Through fault reference condition G G I IG= -IH H ( IG, IH: conventional relay currents at ends of protected feeder) IS Discriminator stability angle setting Figure 10.13: Polar diagram for phase comparison scheme Signal transmission is usually performed by voice frequency channels using frequency shift keying (FSK) or PLC techniques. Receiver Phase E comparator Phase comparator Pulse length Discriminator F Pulse length Discriminator Load or through fault GIG IH H Internal fault GIG IH H A. Summation voltage at end G 1 0 1 0 D. Squarer output at end H (Received at end G via ideal carrier system as D' 1 0 1 0 E. Comparator output at end G E=B+D' F. Discriminator output at end G 1 0 1 0 1 0 1 0 B. Squarer output at end G T 90 o C. Summation voltage at end H Stability setting Figure 10.12: Principles of phase comparison protection Since the carrier channel is required to transfer only binary information, the techniques associated with sending teleprotection commands. Blocking or permissive trip modes of operation are possible, however Figure 10.12 shows the more usual blocking mode, since the comparator provides an output when neither squarer is at logic '1'. A permissive trip scheme can be realised if the comparator is arranged to give an output when both squarers are at logic '1'. Performance of the scheme during failure or disturbance of the carrier channel and its ability to clear single-end-fed faults depends on the mode of operation, the type and function of fault detectors or starting units, and the use of any additional signals or codes for channel monitoring and transfer tripping. Voice frequency channels involving FSK use two discrete frequencies either side of the middle of the voice band. This arrangement is less sensitive to variations in delay or frequency response than if the full bandwidth was used. Blocking or permissive trip modes of operation may be implemented. In addition to the two frequencies used for conveying the squarer information, a third tone is often used, either for channel monitoring or transfer tripping dependent on the scheme. For a sensitive phase comparison scheme, accurate compensation for channel delay is required. However, since both the local and remote signals are logic pulses, simple time delay circuits can be used, in contrast to the analogue delay circuitry usually required for current differential schemes. The principles of the Power Line Carrier channel technique are shown in Figure 10.14. The scheme operates in the blocking mode. The 'squarer' logic is used directly to turn a transmitter 'on' or 'off' at one end, and the resultant burst (or block) of carrier is coupled to and propagates along the power line which is being protected to a receiver at the other end. Carrier signals above a threshold are detected by the receiver, and hence produce a logic signal corresponding to the block of carrier. In contrast to Figure 10.12, the signalling system is a 2-wire rather than 4-wire arrangement, in which the local transmission is fed directly to the local receiver along with any received signal. The transmitter frequencies at both ends are nominally equal, so the receiver responds equally to blocks of carrier from either end. Through-fault current results in transmission of blocks of carrier from both ends, each lasting © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 10-9 Network Protection & Automation Guide for half a cycle, but with a phase displacement of half a cycle, so that the composite signal is continuously above the threshold level and the detector output logic is continuously '1'. Any phase shift relative to the through fault condition produces a gap in the composite carrier signal and hence a corresponding '0' logic level from the detector. The duration of the logic '0' provides the basis for discrimination between internal and external faults, tripping being permitted only when a time delay setting is exceeded. This delay is usually expressed in terms of the corresponding phase shift in degrees at system frequency s in Figure 10.13. 10.11 PHASE COMPARISON PROTECTION SCHEME CONSIDERATIONS The advantages generally associated with the use of the power line as the communication medium apply namely, that a power line provides a robust, reliable, and low-loss interconnection between the relaying points. In addition dedicated 'on/off' signalling is particularly suited for use in phase comparison blocking mode schemes, as signal attenuation is not a problem. This is in contrast to permissive or direct tripping schemes, where high power output or boosting is required to overcome the extra attenuation due to the fault. A problem can occur with the shunt capacitance current that flows from an energising source. Since this current is in addition to the load current that flows out of the line, and typically leads it by more than 90°, significant differential phase shifts between the currents at the ends of the line can occur, particularly when load current is low. The noise immunity is also very good, making the scheme very reliable. Signal propagation delay is easily allowed for in the stability angle setting, making the scheme very sensitive as well. End G One type of unit protection that uses carrier techniques for communication between relays is phase comparison protection. Communication between relays commonly uses PLCC or frequency modulated carrier modem techniques. There are a number of considerations that apply only to phase comparison protection systems, which are discussed in this section. 10.11.1 Lines with Shunt Capacitance The system differential phase shift may encroach into the tripping region of the simple discriminator characteristic, regardless of how large the stability angle setting may be. Figure 10.15 shows the effect and indicates techniques that are commonly used to ensure stability. End H Line trap Line trap Line trap Line trap Summation network Coupling filter Tc O Coupling filter A Squarer Transmitter B Pulse length discriminator D Trip IL Through fault reference Squarer threshold Trip 1 Load or through fault 0 A. Squarer output at end 1 0 Internal fault Squarer output at end H Starter threshold Limits of differential phase shift due to capacitive current IC Blocks of carrier transmitted from end G 1 0 1 0 Blocks of carrier transmitted from end H Encroachment into tripping region for discriminator with stability angle setting M s `Keyhole' characteristic Minimum starter threshold where M s B. Composite carrier signal at end G D. Discriminator output IC Identical relay to end G C Receiver C. Carrier detector output Ms 1 0 1 0 1 0 1 0 Stability setting Figure 10.14: Principles of power line carrier phase comparison capacitive current sin M s tan 1 IC IL Characteristic of system with amplitude dependent CompensationM s angular compensation for current of magnitude OA · § 1 IC ¨ 2 sin for squarer threshold IC ¸¸ ¨ OA ¹ © IL = load current Figure 10.15: Capacitive current in phase comparison schemes and techniques used to avoid instability 10-10 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 10 ˜ Unit Protection of Feeders Operation of the discriminator can be permitted only when current is above some threshold, so that measurement of the large differential phase shifts which occur near the origin of the polar diagram is avoided. By choice of a suitable threshold and stability angle, a 'keyhole' characteristic can be provided so the capacitive current characteristic falls within the resultant stability region. Fast resetting of the fault detector is required to ensure stability following the clearance of a through fault when the currents tend to fall towards the origin of the polar diagram. The mark-space ratio of the squarer (or modulating) waveform can be made dependent on the current amplitude. Any decrease in the mark-space ratio will permit a corresponding differential phase shift to occur between the currents before any output is given from the comparator for measurement in the discriminator. A squarer circuit with an offset or bias can provide a decreasing mark-space ratio at low currents, and with a suitable threshold level the extra phase shift c which is permitted can be arranged to equal or exceed the phase shift due to capacitive current. At high current levels the capacitive current compensation falls towards zero and the resultant stability region on the polar diagram is usually smaller than on the keyhole characteristic, giving improvements in sensitivity and/or dependability of the scheme. Since the stability region encompasses all through-fault currents, the resetting speed of any fault detectors or starter (which may still be required for other purposes, such as the control of a normally quiescent scheme) is much less critical than with the keyhole characteristic. 10.11.2 System Tripping Angles For the protection scheme to trip correctly on internal faults the change in differential phase shift, o, from the throughfault condition taken as reference, must exceed the effective stability angle of the scheme. Hence: T 0 t Is  T c IG I G ‘T G IH I H ‘T H Using the relay convention described in Section 10.2, the reference through-fault condition is IG I H ?I G‘T G  I H ‘T H ? TG  T H 180 D I H ‘T H r 180D During internal faults, the system tripping angle o is the differential phase shift relative to the reference condition. ?T o 180 T G  T H Substituting o in Equation 10.1, the conditions for tripping are: T o 180  TG  T H t Is  T c ? T G  T H d 180  I s  T c Equation 10.2 The term (Øs + c) is the effective stability angle setting of the scheme. Substituting a typical value of 60° in Equation 10.2, gives the tripping condition as T G  T H d 120 D Equation 10.3 In the absence of pre-fault load current, the voltages at the two ends of a line are in phase. Internal faults are fed from both ends with fault contributions whose magnitudes and angles are determined by the position of the fault and the system source impedances. Although the magnitudes may be markedly different, the angles (line plus source) are similar and seldom differ by more than about 20° T G  T H d 20 D and the requirements of Equation Equation 10.1 Hence Where: I s = stability angle setting 10.3 are very easily satisfied. The addition of arc or fault resistance makes no difference to the reasoning above, so the scheme is inherently capable of clearing such faults. T c = capacitive current compensation 10.11.3 Effect of Load Current (when applicable) The currents at the ends of a transmission line IG and IH may be expressed in terms of magnitude and phase shift  with respect a common system voltage. When a line is heavily loaded prior to a fault the e.m.f.s of the sources which cause the fault current to flow may be displaced by up to about 50°, that is, the power system stability limit. To this the differential line and source angles of up to 20° mentioned above need to be added. So T G  T H d 70 D and the requirements of Equation 10.3 are still easily satisfied. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 10-11 Network Protection & Automation Guide For three phase faults, or solid earth faults on phase-by-phase comparison schemes, through load current falls to zero during the fault and so need not be considered. For all other faults, load current continues to flow in the healthy phases and may therefore tend to increase T G  T H towards the through fault reference value. For low resistance faults the fault current usually far exceeds the load current and so has little effect. High resistance faults or the presence of a weak source at one end can prove more difficult, but high performance is still possible if the modulating quantity is chosen with care and/or fault detectors are added. 10.11.4 Modulating Quantity Phase-by-phase comparison schemes usually use phase current for modulation of the carrier. Load and fault currents are almost in antiphase at an end with a weak source. Correct performance is possible only when fault current exceeds load current, or for I F  I L , T G  T H | 180 for I F ! I L , T G  T H | 0 approximately in phase at the ends of the line and therefore could form an ideal modulating quantity. To provide a modulating signal during three phase faults, which give rise to positive phase sequence (PPS) currents, I1, only, a practical modulating quantity must include some response to I1 in addition to I2. Typical values of the ratio M : N exceed 5:1, so that the modulating quantity is weighted heavily in favour of NPS, and any PPS associated with load current tends to be swamped out on all but the highest resistance faults. For a high resistance phase-earth fault, the system remains well balanced so that load current IL is entirely positive sequence. The fault contribution IF provides equal parts of positive, negative and zero sequence components Assuming the fault is on 'A' phase and the load is resistive, all sequence components are in phase at the infeed end G. D ? I mG NI L  D MI FG NI FG  ?T G | 0 3 3 At the outfeed end load current is negative, Equation 10.4 ? I mH where I F = fault current contribution from weak source Most phase comparison schemes use summation techniques to produce a single modulating quantity, responsive to faults on any of the three phases. Phase sequence components are often used and a typical modulating quantity is Im MI 2  NI1  NI L  MI FH NI FH  3 3 for I L = load current flowing towards weak source To avoid any risk of failure to operate, fault detectors with a setting greater than the maximum load current may be applied, but they may limit the sensitivity of scheme. When the fault detector is not operated at one end, fault clearance invariably involves sequential tripping of the circuit breakers. I mH ! 0 , T H | 0 ? T G  T H 0D for I mH  0, T H | 180D ? T G  T H 180D Hence for correct operation I mH t 0 let ImH = 0 then I FH Equation 10.5 3I L · §M ¨  1¸ ¹ ©N IE Equation 10.6 Where: I1 = Positive Phase Sequence Component The fault current in Equation 10.6 is the effective earth fault sensitivity IE of the scheme. For the typical values of I 2 = Negative Phase Sequence Component M , N = constants (N typically negative) With the exception of three phase faults all internal faults give rise to negative phase sequence (NPS) currents, I2, which are 10-12 IF . 3 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 10 ˜ Unit Protection of Feeders M 6 and N ? IE 3  IL 5 1, M N 6 1 .1 0 .9 3 Comparing this with Equation 10.4, a scheme using summation is potentially 1.667 times more sensitive than one using phase current for modulation. Even though the use of a negative value of M gives a lower value of IE than if it were positive, it is usually preferred since Im = 0 then applies at the load the limiting condition of infeed end. Load and fault components are additive at the outfeed end so that a correct modulating quantity occurs there, even with the lowest fault levels. For operation of the scheme it is sufficient therefore that the fault current contribution from the load infeed end exceeds the effective setting. TH NIE ImH NILH ImH NILH 0 .9 MIE 3 MIE 0 o 1 .1 TH NIE 3 I mG ImG 0 .9 TG 180 MIE o 1 .1 MIE TG NILG 3 0 .9 NILG NIE 1 .1 3 TG  TH Very sensitive schemes may be implemented by using high values of M but the scheme then becomes more sensitive to N 0 3 NIE 3 0o TG  T H 180 o NIE 3 NIE NILH NILH MIE 3 For faults on B or C phases, the NPS components are displaced by 120° or 240° with respect to the PPS components. No simple cancellation can occur, but instead a phase displacement is introduced. For tripping to occur, Equation 10.2 must be satisfied, and to achieve high dependability under these marginal conditions, a small effective stability angle is essential. Figure 10.16 shows operation near to the limits of earth fault sensitivity. 0 3 TH TG ImH TG TH NIE NIE 3 3 ImG MIE MIE 3 3 TG  T H | 70 o ImH NILG NILG ImG 3 TG  T H | 70 o differential errors in NPS currents such as the unbalanced components of capacitive current or spill from partially saturated CTs. Techniques such as capacitive current compensation and reduction of M at high fault levels may be required to ensure N stability of the scheme. Figure 10.16: Effect of load current on differential phase shift ȱșg-șHȱ for resistive earth faults at the effective earth fault sensitivity IE 10.11.5 Fault Detection and Starting For a scheme using a carrier system that continuously transmits the modulating quantity, protecting an ideal line (capacitive current = 0) in an interconnected transmission system, measurement of current magnitude might be unnecessary. In practice, fault detector or starting elements are invariably provided and the scheme then becomes a permissive tripping scheme in which both the fault detector and the discriminator must operate to provide a trip output, and the fault detector may limit the sensitivity of the scheme. Requirements for the fault detectors vary according to the type of carrier channel used, mode of operation used in the phase angle measurement, that is, blocking or permissive, and the features used to provide tolerance to capacitive current. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 10-13 Network Protection & Automation Guide 10.11.6 Normally Quiescent Power Line Carrier (Blocking Mode) To ensure stability of through faults, it is essential that carrier transmission starts before any measurement of the width of the gap is permitted. To allow for equipment tolerances and the difference in magnitude of the two currents due to capacitive current, two starting elements are used, usually referred to as 'Low Set' and 'High Set' respectively. Low Set controls the start-up of transmission whilst High Set, having a setting typically 1.5 to 2 times that of the Low Set element, permits the phase angle measurement to proceed. The use of impulse starters that respond to the change in current level enables sensitivities of less than rated current to be achieved. Resetting of the starters occurs naturally after a swell time or at the clearance of the fault. Dwell times and resetting characteristics must ensure that during through faults, a High Set is never operated when a Low Set has reset and potential race conditions are often avoided by the transmitting of an demodulated (and therefore blocking) carrier for a short time following the reset of low set; this feature is often referred to as 'Marginal Guard.' 10.11.7 Scheme without Capacitive Current Compensation The 'keyhole' discrimination characteristic of depends on the inclusion of a fault detector to ensure that no measurements of phase angle can occur at low current levels, when the capacitive current might cause large phase shifts. Resetting must be very fast to ensure stability following the shedding of through load. 10.11.8 Scheme with Capacitive Current Compensation (Blocking Mode) When the magnitude of the modulating quantity is less than the threshold of the squarer, transmission if it occurred, would be a continuous blocking signal. This might occur at an end with a weak source, remote from a fault close to a strong source. A fault detector is required to permit transmission only when the current exceeds the modulator threshold by some multiple (typically about 2 times) so that the effective stability angle is not excessive. For PLCC schemes, the low set element referred to in Section 10.11.6 is usually used for this purpose. If the fault current is insufficient to operate the fault detector, circuit breaker tripping will normally occur sequentially. loaded and has a low fault level at the outfeed end, some faults can be accompanied by a fall in current, which would lead to failure of such fault detection, resulting in sequential tripping (for blocking mode schemes) or no tripping (for permissive schemes). Although fault detectors can be designed to respond to any disturbance (increase or decrease of current), it is more usual to use phase sequence components. All unbalanced faults produce a rise in the NPS components from the zero level associated with balanced load current, whilst balanced faults produce an increase in the PPS components from the load level (except at ends with very low fault level) so that the use of NPS and PPS fault detectors make the scheme sensitive to all faults. For schemes using summation of NPS and PPS components for the modulating quantity, the use of NPS and PPS fault detectors is particularly appropriate since, in addition to any reductions in hardware, the scheme may be characterised entirely in terms of sequence components. Fault sensitivities IF for PPS and NPS impulse starter settings I1s and I2s respectively are as follows: Three phase fault I F Phase-phase fault I F Phase-earth fault I F I 1S 3 I2S 3 I2S 10.12 EXAMPLES This section gives examples of setting calculations for simple unit protection schemes. It cannot and is not intended to replace a proper setting calculation for a particular application. It is intended to show the principles of the calculations required. The examples use the Alstom MiCOM P54x Current Differential relay, which has the setting ranges given in Table 10.1 for differential protection. The relay also has backup distance, high-set instantaneous, and earth-fault protection included in the basic model to provide a complete ‘one-box’ solution of main and backup protection. Parameter Setting Range Differential Current Setting Is1 0.2 – 2.0 In Bias Current Threshold Setting Is2 1.0 – 30.0 In Lower Percentage Bias Setting k1 0.3 – 1.5 Higher Percentage Bias Setting k2 0.3 – 1.5 In = CT Rated Secondary Current Table 10.1: Relay Setting Ranges 10.11.9 Fault Detector Operating Quantities 10.12.1 Unit Protection of a Plain Feeder Most faults cause an increase in the corresponding phase current(s) so measurement of current increase could form the basis for fault detection. However, when a line is heavily The circuit to be protected is shown in Figure 10.17. It consists of a plain feeder circuit formed of an overhead line 25km long. The relevant properties of the line are: 10-14 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 10 ˜ Unit Protection of Feeders Line voltage: 33kV Z 8 0.156  j 0.337: / km Shunt charging current 7 0.065 A / km To arrive at the correct settings, the characteristics of the relays to be applied must be considered. 6 Idiff 5 4 Idiff Figure 10.17: Protection of a plain feeder 3 The recommended settings for three of the adjustable values (taken from the relay manual) are: 2 I s2 2.0 pu k1 30% k2 150% The minimum operating current Id min is related to the value of Is1 by the formula I d min k1 I L  I S 1 1  0.5k1 for I bias  I s2 I d min k2 I L  k2  k1 I S 2  I S 1 1  0 .5 k 2 and for 1 0 To provide immunity from the effects of line charging current, the setting of Is1 must be at least 2.5 times the steady-state charging current, i.e. 4.1A or 0.01p.u., after taking into consideration the CT ratio of 400/1. The nearest available setting above this is 0.20p.u. This gives the points on the relay characteristic as shown in Figure 10.18. K2 slope K1 slope 0 1 2 3 Ibias 4 5 6 Figure 10.18: Relay characteristic; plain feeder example In cases where the capacitive charging current is very large and hence the minimum tripping current needs to be set to an unacceptably high value, some relays offer the facility of subtracting the charging current from the measured value. Use of this facility depends on having a suitable VT input and knowledge of the shunt capacitance of the circuit. 10.12.2 Unit Protection of a Transformer Feeder Figure 10.19 shows unit protection applied to a transformer feeder. The feeder is assumed to be a 100m length of cable, such as might be found in some industrial plants or where a short distance separates the 33kV and 11kV substations. While 11kV cable capacitance will exist, it can be regarded as negligible for the purposes of this example. I bias ! I s 2 where IL = load current and hence the minimum operating current at no load is 0.235p.u. or 94A. Figure 10.19: Unit Protection of a transformer feeder The delta/star transformer connection requires phase shift correction of CT secondary currents across the transformer, © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 10-15 Network Protection & Automation Guide and in this case software equivalents of interposing CTs are used. Since the LV side quantities lag the HV side quantities by 30°, it is necessary to correct this phase shift by using software CT settings that produce a 30° phase shift. There are two obvious possibilities: I S1 20% I S1 20% k1 30% k2 150% (Minimum possible) x HV side: Yd1, LV side: Yy0 10.12.3 Unit Protection of Transmission Circuits x HV side: Yy0, LV side: Yd11 Application of current differential to transmission circuits is similar to that described in Section 10.12.1, except that: Only the second combination is satisfactory, since only this one provides the necessary zero-sequence current trap to avoid maloperation of the protection scheme for earth faults on the LV side of the transformer outside of the protected zone. Ratio correction must also be applied, to ensure that the relays see currents from the primary and secondary sides of the transformer feeder that are well balanced under full load conditions. This is not always inherently the case, due to selection of the main CT ratios. For the example of Figure 10.19, transformer turns ratio at nominal tap 11 33 0.3333 Required turns ratio according to the CT ratios used 400 1 1250 1 x Lines will often be longer, and hence have higher charging current. x Signal attenuation in fibre optic channels will become larger. x The relay may be expected to single-pole trip and reclose. x High-speed backup distance protection elements may be brought into service automatically, in instances where signalling channel failure has been detected. 10.13 REFERENCE [10.1] Merz-Price Protective Gear. K. Faye-Hansen and G. Harlow. IEE Proceedings, 1911. 0.32 Spill current that will arise due to the incompatibility of the CT ratios used with the power transformer turns ratio may cause relay maloperation. This has to be eliminated by using the facility in the relay for CT ratio correction factors. For this particular relay, the correction factors are chosen so the full load current seen by the relay software is equal to 1A. The appropriate correction factors are: HV: 400 350 1.14 LV: 1250 1050 1.19 where: transformer rated primary current = 350A transformer rated secondary current = 1050A With the line charging current being negligible, the following relay settings are then suitable, and allow for transformer efficiency and mismatch due to tap-changing: 10-16 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 10 ˜ Unit Protection of Feeders © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 10-17 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 Distance Protection 11.1 11.2 11.3 11.4 Introduction Principles of Distance Relays Relay Performance Relationship Between Relay Voltage and Zs/Zl Ratio 11.5 Voltage Limit for Accurate Reach Point Measurement 11.6 Zones of Protection 11.7 Distance Relay Characteristics 11.8 Distance Relay Implementation 11.9 Effect of Source Impedance and Earthing Methods 11.10 Distance Relay Application Problems 11.11 Other Distance Relay Features 11.12 Distance Relay Application Example 11.13 References 11.1 INTRODUCTION The problem of combining fast fault clearance with selective tripping of plant is a key aim for the protection of power systems. To meet these requirements, high-speed protection systems for transmission and primary distribution circuits that are suitable for use with the automatic reclosure of circuit breakers are under continuous development and are very widely applied. Distance protection, in its basic form, is a non-unit system of protection offering considerable economic and technical advantages. Unlike phase and neutral overcurrent protection, the key advantage of distance protection is that its fault coverage of the protected circuit is virtually independent of source impedance variations. This is illustrated in Figure 11.1, where it can be seen that overcurrent protection cannot be applied satisfactorily. 3 I F1 IF2 115 u10 3 u 5 4 115 u10 3 3 u10 7380 A 6640 A Figure 11.1: Advantages of distance over overcurrent protection Distance protection is comparatively simple to apply and it can be fast in operation for faults located along most of a protected circuit. It can also provide both primary and remote back-up functions in a single scheme. It can easily be adapted to create a unit protection scheme when applied with a signalling channel. In this form it is eminently suitable for application Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-1 Network Protection & Automation Guide with high-speed auto-reclosing, for the protection of critical transmission lines. 11.2 PRINCIPLES OF DISTANCE RELAYS Since the impedance of a transmission line is proportional to its length, for distance measurement it is appropriate to use a relay capable of measuring the impedance of a line up to a predetermined point (the reach point). Such a relay is described as a distance relay and is designed to operate only for faults occurring between the relay location and the selected reach point, thus giving discrimination for faults that may occur in different line sections. The basic principle of distance protection involves the division of the voltage at the relaying point by the measured current. The apparent impedance so calculated is compared with the reach point impedance. If the measured impedance is less than the reach point impedance, it is assumed that a fault exists on the line between the relay and the reach point. The reach point of a relay is the point along the line impedance locus that is intersected by the boundary characteristic of the relay. Since this is dependent on the ratio of voltage and current and the phase angle between them, it may be plotted on an R/X diagram. The loci of power system impedances as seen by the relay during faults, power swings and load variations may be plotted on the same diagram and in this manner the performance of the relay in the presence of system faults and disturbances may be studied. 11.3 RELAY PERFORMANCE Distance relay performance is defined in terms of reach accuracy and operating time. Reach accuracy is a comparison of the actual ohmic reach of the relay under practical conditions with the relay setting value in ohms. Reach accuracy particularly depends on the level of voltage presented to the relay under fault conditions. The impedance measuring techniques employed in particular relay designs also have an impact. Operating times can vary with fault current, with fault position relative to the relay setting, and with the point on the voltage wave at which the fault occurs. Depending on the measuring techniques employed in a particular relay design, measuring signal transient errors, such as those produced by Capacitor Voltage Transformers or saturating CTs, can also adversely delay relay operation for faults close to the reach point. It is usual for electromechanical and static distance relays to claim both maximum and minimum operating times. However, for modern digital or numerical distance relays, the variation between these is small over a wide range of system operating conditions and fault positions. 11-2 11.3.1 Electromechanical/Static Distance Relays With electromechanical and earlier static relay designs, the magnitude of input quantities particularly influenced both reach accuracy and operating time. It was customary to present information on relay performance by voltage/reach curves, as shown in Figure 11.2, and operating time/fault position curves for various values of system impedance ratios (S.I.R.s) as shown in Figure 11.3, where: ZS ZL S .I . R and Z S = system source impedance behind the relay location Z L = line impedance equivalent to relay reach setting 105 100 95 0 10 20 30 40 50 % relay rated voltage (a) Phase-earth faults 0 20 60 65 105 100 95 40 60 80 100 % relay rated voltage (b) Phase-phase faults 105 100 95 0 20 40 60 80 100 % relay rated voltage (c) Three-phase and three-phase-earth faults Figure 11.2: Typical impedance reach accuracy characteristics for Zone 1 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection Operation time (ms) available ensure optimum performance under adverse waveform conditions or for boundary fault conditions. 11.4 RELATIONSHIP BETWEEN RELAY VOLTAGE AND ZS/ZL RATIO Operation time (ms) A single, generic, equivalent circuit, as shown in Figure 11.5, may represent any fault condition in a three-phase power system. The voltage V applied to the impedance loop is the open circuit voltage of the power system. Point R represents the relay location; IR and VR are the current and voltage measured by the relay, respectively. Figure 11.3: Typical operation time characteristics for Zone 1 phasephase faults Alternatively the above information was combined in a family of contour curves, where the fault position expressed as a percentage of the relay setting is plotted against the source to line impedance ratio, as illustrated in Figure 11.4. The impedances Zs and ZL are described as source and line impedances because of their position with respect to the relay location. Source impedance Zs is a measure of the fault level at the relaying point. For faults involving earth it is dependent on the method of system earthing behind the relaying point. Line impedance ZL is a measure of the impedance of the protected section. The voltage VR applied to the relay is, therefore, IRZL. For a fault at the reach point, this may be alternatively expressed in terms of source to line impedance ratio ZS /ZL using the following expressions: VR IRZL IR V ZS  ZL Fault position (p.u. relay setting ZL) where: Therefore: VR ZL V ZS  ZL Fault position (p.u. relay setting ZL) Or VR 1 V § ZS · ¨¨ ¸¸  1 © ZL ¹ Equation 11.1 Figure 11.4: Typical operation-time contours 11.3.2 Digital/Numerical Distance Relays Digital/Numerical distance relays tend to have more consistent operating times. The best transmission-class relays can achieve subcycle tripping, and the digital filtering techniques © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-3 Network Protection & Automation Guide x for earth faults, Vl-n is the phase-neutral source voltage and ZS/ZL, is a composite ratio involving the positive and zero sequence impedances. VR is the phase-neutral relay voltage and IR is the relay current for the faulted phase VR 1 Vl  n § Z S ·§ 2  p · ¨¨ ¸¸¨¨ ¸¸  1 © Z L ¹© 2  q ¹ Equation 11.3 where: ZS 2Z S1  Z S 0 Z S1 2  p ZL 2Z L1  Z L 0 Z L1 2  q and p ZS0 Z S1 q Z L0 Z L1 11.5 VOLTAGE LIMIT FOR ACCURATE REACH POINT MEASUREMENT The ability of a distance relay to measure accurately for a reach point fault depends on the minimum voltage at the relay location under this condition being above a declared value. This voltage, which depends on the relay design, can also be quoted in terms of an equivalent maximum ZS /ZL or S.I.R. Figure 11.5: Relationship between source to line ratio and relay voltage The above generic relationship between VR and ZS/ZL, illustrated in Figure 11.5, is valid for all types of short circuits provided a few simple rules are observed. These are: x for phase faults, V is the phase-phase source voltage and ZS/ZL is the positive sequence source to line impedance ratio. VR is the phase-phase relay voltage and IR is the phase-phase relay current, for the faulted phases VR Equation 11.2 11-4 1 V' § ZS · ¨¨ ¸¸  1 © ZL ¹ Distance relays are designed so that, provided the reach point voltage criterion is met, any increased measuring errors for faults closer to the relay will not prevent relay operation. Most modern relays are provided with healthy phase voltage polarisation and/or memory voltage polarisation. The prime purpose of the relay polarising voltage is to ensure correct relay directional response for close-up faults, in the forward or reverse direction, where the fault-loop voltage measured by the relay may be very small. 11.6 ZONES OF PROTECTION Careful selection of the reach settings and tripping times for the various zones of measurement enables correct coordination between distance relays on a power system. Basic distance protection will comprise instantaneous directional Zone 1 protection and one or more time-delayed zones. Typical reach and time settings for a 3-zone distance protection are shown in Figure 11.6. Digital and numerical distance relays may have up to five or six zones, some set to © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection measure in the reverse direction. Typical settings for three forward-looking zones of basic distance protection are given in the following sub-sections. To determine the settings for a particular relay design or for a particular distance teleprotection scheme, involving end-to-end signalling, the relay manufacturer’s instructions should be referred to. 11.6.1 Zone 1 Setting Electromechanical/static relays usually have a reach setting of up to 80% of the protected line impedance for instantaneous Zone 1 protection. For digital/numerical distance relays, settings of up to 85% may be safe. The resulting 15-20% safety margin ensures that there is no risk of the Zone 1 protection over-reaching the protected line due to errors in the current and voltage transformers, inaccuracies in line impedance data provided for setting purposes and errors of relay setting and measurement. Otherwise, there would be a loss of discrimination with fast operating protection on the following line section. Zone 2 of the distance protection must cover the remaining 15-20% of the line. 11.6.2 Zone 2 Setting To ensure full coverage of the line with allowance for the sources of error already listed in the previous section, the reach setting of the Zone 2 protection should be at least 120% of the protected line impedance. In many applications it is common practice to set the Zone 2 reach to be equal to the protected line section +50% of the shortest adjacent line. Where possible, this ensures that the resulting maximum effective Zone 2 reach does not extend beyond the minimum effective Zone 1 reach of the adjacent line protection. This avoids the need to grade the Zone 2 time settings between upstream and downstream relays. In electromechanical and static relays, Zone 2 protection is provided either by separate elements or by extending the reach of the Zone 1 elements after a time delay that is initiated by a fault detector. In most digital and numerical relays, the Zone 2 elements are implemented in software. Zone 2 tripping must be time-delayed to ensure grading with the primary relaying applied to adjacent circuits that fall within the Zone 2 reach. Thus complete coverage of a line section is obtained, with fast clearance of faults in the first 80-85% of the line and somewhat slower clearance of faults in the remaining section of the line. Z3JR Z3JF Time Z2J Y X Z1J Source H 0 J Source L Z1K Z1H X Y Time K Z1L Z2K Z3KF Z3KR Zone 1 = 80-85% of protected line impedance Zone 2 (minimum) = 120% of protected line Zone 2 (maximum) < Protected line + 50% of shortest second line Zone 3F = 1.2 (protected line + longest second line) Zone 3R = 20% of protected line X = Circuit breaker tripping time Y = Discriminating time Figure 11.6: Typical time/distance characteristics for three zone distance protection 11.6.3 Zone 3 Setting Remote back-up protection for all faults on adjacent lines can be provided by a third zone of protection that is time delayed to discriminate with Zone 2 protection plus circuit breaker trip time for the adjacent line. Zone 3 reach should be set to at least 1.2 times the impedance presented to the relay for a fault at the remote end of the second line section. On interconnected power systems, the effect of fault current infeed at the remote busbars will cause the impedance presented to the relay to be much greater than the actual impedance to the fault and this needs to be taken into account when setting Zone 3. In some systems, variations in the remote busbar infeed can prevent the application of remote back-up Zone 3 protection but on radial distribution systems with single end infeed, no difficulties should arise. 11.6.4 Settings for Reverse Reach and Other Zones Modern digital or numerical relays may have additional impedance zones that can be utilised to provide additional protection functions. For example, where the first three zones are set as above, Zone 4 might be used to provide back-up protection for the local busbar, by applying a reverse reach setting of the order of 25% of the Zone 1 reach. Alternatively, one of the forward-looking zones (typically Zone 3) could be set with a small reverse offset reach from the origin of the R/X diagram, in addition to its forward reach setting. An offset impedance measurement characteristic is non-directional. One advantage of a non-directional zone of impedance measurement is that it is able to operate for a close-up, zeroimpedance fault, in situations where there may be no healthy phase voltage signal or memory voltage signal available to allow operation of a directional impedance zone. With the offset-zone time delay bypassed, there can be provision of © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-5 Network Protection & Automation Guide ‘Switch-on-to-Fault’ (SOTF) protection. This is required where there are line voltage transformers, to provide fast tripping in the event of accidental line energisation with maintenance earthing clamps left in position. Additional impedance zones may be deployed as part of a distance protection scheme used in conjunction with a teleprotection signalling channel. 11.7 DISTANCE RELAY CHARACTERISTICS Some numerical relays measure the absolute fault impedance and then determine whether operation is required according to impedance boundaries defined on the R/X diagram. Traditional distance relays and numerical relays that emulate the impedance elements of traditional relays do not measure absolute impedance. They compare the measured fault voltage with a replica voltage derived from the fault current and the zone impedance setting to determine whether the fault is within zone or out-of-zone. Distance relay impedance comparators or algorithms which emulate traditional comparators are classified according to their polar characteristics, the number of signal inputs they have, and the method by which signal comparisons are made. The common types compare either the relative amplitude or phase of two input quantities to obtain operating characteristics that are either straight lines or circles when plotted on an R/X diagram. At each stage of distance relay design evolution, the development of impedance operating characteristic shapes and sophistication has been governed by the technology available and the acceptable cost. Since many traditional relays are still in service and since some numerical relays emulate the techniques of the traditional relays, a brief review of impedance comparators is justified. other type. For example, comparing V and I in an amplitude comparator results in a circular impedance characteristic centred at the origin of the R/X diagram. If the sum and difference of V and I are applied to the phase comparator the result is a similar characteristic. 11.7.2 Plain Impedance Characteristic This characteristic takes no account of the phase angle between the current and the voltage applied to it; for this reason its impedance characteristic when plotted on an R/X diagram is a circle with its centre at the origin of the coordinates and of radius equal to its setting in ohms. Operation occurs for all impedance values less than the setting, that is, for all points within the circle. The relay characteristic, shown in Figure 11.7, is therefore non-directional, and in this form would operate for all faults along the vector AL and also for all faults behind the busbars up to an impedance AM. A is the relaying point and RAB is the angle by which the fault current lags the relay voltage for a fault on the line AB and RAC is the equivalent leading angle for a fault on line AC. Vector AB represents the impedance in front of the relay between the relaying point A and the end of line AB. Vector AC represents the impedance of line AC behind the relaying point. AL represents the reach of instantaneous Zone 1 protection, set to cover 80% to 85% of the protected line. Line AC Line AB C A B Z X B 11.7.1 Amplitude and Phase Comparison Relay measuring elements whose functionality is based on the comparison of two independent quantities are essentially either amplitude or phase comparators. For the impedance elements of a distance relay, the quantities being compared are the voltage and current measured by the relay. There are numerous techniques available for performing the comparison, depending on the technology used. They vary from balancedbeam (amplitude comparison) and induction cup (phase comparison) electromagnetic relays, through diode and operational amplifier comparators in static-type distance relays, to digital sequence comparators in digital relays and to algorithms used in numerical relays. Any type of impedance characteristic obtainable with one comparator is also obtainable with the other. The addition and subtraction of the signals for one type of comparator produces the required signals to obtain a similar characteristic using the 11-6 L Restrains Line AB Operates A R Line AC M C Impedance relay Figure 11.7: Plain impedance relay characteristic A relay using this characteristic has three important disadvantages: © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection x it is non-directional; it will see faults both in front of and behind the relaying point, and therefore requires a directional element to give it correct discrimination x it has non-uniform fault resistance coverage x it is susceptible to power swings and heavy loading of a long line because of the large area covered by the impedance circle Directional control is an essential discrimination quality for a distance relay, to make the relay non-responsive to faults outside the protected line. This can be obtained by the addition of a separate directional control element. The impedance characteristic of a directional control element is a straight line on the R/X diagram, so the combined characteristic of the directional and impedance relays is the semi-circle APLQ shown in Figure 11.8. X Impedance element RZ< B L P Operates A R Restrains Q Directional element RD (a) Characteristic of combined directional/ impedance relay A IF1 B IF1 to IF2 when C opens could then result in incorrect tripping of the healthy line if the directional unit RD operates before the impedance unit resets. This is an example of the need to consider the proper co-ordination of multiple relay elements to attain reliable relay performance during evolving fault conditions. In older relay designs, the type of problem to be addressed was commonly referred to as one of ‘contact race’. 11.7.3 Self-Polarised Mho Relay The mho impedance element is generally known as such because its characteristic is a straight line on an admittance diagram. It cleverly combines the discriminating qualities of both reach control and directional control, thereby eliminating the ‘contact race’ problems that may be encountered with separate reach and directional control elements. This is achieved by the addition of a polarising signal. Mho impedance elements were particularly attractive for economic reasons where electromechanical relay elements were employed. As a result, they have been widely deployed worldwide for many years and their advantages and limitations are now well understood. For this reason they are still emulated in the algorithms of some modern numerical relays. The characteristic of a mho impedance element, when plotted on an R/X diagram, is a circle whose circumference passes through the origin, as illustrated in Figure 11.9. This demonstrates that the impedance element is inherently directional and such that it will operate only for faults in the forward direction along line AB. IF2 Source Source Z< C D F (b) Illustration of use of directional/impedance relay: circuit diagram RAZ< RAD & & Trip relay RAD Combined directional/impedance relay RAZ<: distance element at A RAD : directional element at A (c) Logic for directional and impedance elements at A Figure 11.8: Combined directional and impedance relays If a fault occurs at F close to C on the parallel line CD, the directional unit RD at A will restrain due to current IF1. At the same time, the impedance unit is prevented from operating by the inhibiting output of unit RD. If this control is not provided, the under impedance element could operate prior to circuit breaker C opening. Reversal of current through the relay from The impedance characteristic is adjusted by setting Zn, the impedance reach, along the diameter and , the angle of displacement of the diameter from the R axis. Angle  is known as the Relay Characteristic Angle (RCA). The relay operates for values of fault impedance ZF within its characteristic. The self-polarised mho characteristic can be obtained using a phase comparator circuit which compares input signals S2 and S1 and operates whenever S2 lags S1 by between 90 and 270, as shown in the voltage diagram of Figure 11.9(a). The two input signals are: S2 = V-IZn S1 = V where: V = fault voltage from VT secondary I = fault current from CT secondary Zn = impedance setting of the zone © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-7 Network Protection & Automation Guide The characteristic of Figure 11.9(a) can be converted to the impedance plane of Figure 11.9(b) by dividing each voltage by I. The impedance reach varies with fault angle. As the line to be protected is made up of resistance and inductance, its fault angle will be dependent upon the relative values of R and X at the system operating frequency. Under an arcing fault condition, or an earth fault involving additional resistance, such as tower footing resistance or fault through vegetation, the value of the resistive component of fault impedance will increase to change the impedance angle. Thus a relay having a characteristic angle equivalent to the line angle will underreach under resistive fault conditions. M Some users set the RCA less than the line angle, so that it is possible to accept a small amount of fault resistance without causing under-reach. However, when setting the relay, the difference between the line angle  and the relay characteristic angle Ø must be known. The resulting characteristic is shown in Figure 11.9 where GL corresponds to the length of the line to be protected. With Ø set less than , the actual amount of line protected, AB, would be equal to the relay setting value AQ multiplied by cosine (-Ø). Therefore the required relay setting AQ is given by: M AQ AB cos T  I Due to the physical nature of an arc, there is a non-linear relationship between arc voltage and arc current, which results in a non-linear resistance. Using the empirical formula derived by A.R. van C. Warrington, [11.1] the approximate value of arc resistance can be assessed as: Ra 28,710 L I 1.4 Equation 11.4 T M where: Ra = arc resistence (ohms) L = length of arc (metres) I = arc current (A) M T Figure 11.9: Mho relay characteristic 11-8 On long overhead lines carried on steel towers with overhead earth wires the effect of arc resistance can usually be neglected. The effect is most significant on short overhead lines and with fault currents below 2000A (i.e. minimum plant condition), or if the protected line is of wood-pole construction without earth wires. In the latter case, the earth fault resistance reduces the effective earth-fault reach of a ‘mho’ Zone 1 element to such an extent that the majority of faults © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection are detected in Zone 2 time. This problem can usually be overcome by using a relay with a cross-polarised mho or a polygonal characteristic. Where a power system is resistance-earthed, it should be appreciated that this does not need to be considered with regard to the relay settings other than the effect that reduced fault current may have on the value of arc resistance seen. The earthing resistance is in the source behind the relay and only modifies the source angle and source to line impedance ratio for earth faults. It would therefore be taken into account only when assessing relay performance in terms of system impedance ratio. 11.7.4.1 Third Zone and Busbar Back-Up Zone In this application it is used in conjunction with mho measuring units as a fault detector and/or Zone 3 measuring unit. So, with the reverse reach arranged to extend into the busbar zone, as shown in Figure 11.10, it will provide back-up protection for busbar faults. This facility can also be provided with quadrilateral characteristics. A further benefit of the Zone 3 application is for Switch-on-to-Fault (SOTF) protection, where the Zone 3 time delay would be bypassed for a short period immediately following line energisation to allow rapid clearance of a fault anywhere along the protected line. 11.7.4 Offset Mho/Lenticular Characteristics 11.7.4.2 Carrier Starting Unit in Distance Schemes With Carrier Blocking Under close up fault conditions, when the relay voltage falls to zero or near-zero, a relay using a self-polarised mho characteristic or any other form of self-polarised directional impedance characteristic may fail to operate when it is required to do so. Methods of covering this condition include the use of non-directional impedance characteristics, such as offset mho, offset lenticular, or cross-polarised and memory polarised directional impedance characteristics. If the offset mho unit is used for starting carrier signalling, it is arranged as shown in Figure 11.10. The carrier is transmitted if the fault is external to the protected line but inside the reach of the offset mho relay, to prevent accelerated tripping of the second or third zone relay at the remote station. Transmission is prevented for internal faults by operation of the local mho measuring units, which allows high-speed fault clearance by the local and remote end circuit breakers. If current bias is employed, the mho characteristic is shifted to embrace the origin, so that the measuring element can operate for close-up faults in both the forward and the reverse directions. The offset mho relay has two main applications: 11.7.4.3 Application of Lenticular Characteristic X Zone 3 §a· ¸ is adjustable, enabling it to be set to provide the ©b¹ the lens ¨ Zone 2 Zone 1 R Busbar zone X J Zone 3 Zone 2 maximum fault resistance coverage consistent with nonoperation under maximum load transfer conditions. Figure 11.11 shows how the lenticular characteristic can tolerate much higher degrees of line loading than offset mho and plain impedance characteristics. Reduction of load impedance from ZD3 to ZD1 will correspond to an equivalent increase in load current. (a) Busbar zone back-up using an offset mho relay H There is a danger that the offset mho relay shown in Figure 11.10 may operate under maximum load transfer conditions if Zone 3 of the relay has a large reach setting. A large Zone 3 reach may be required to provide remote back-up protection for faults on the adjacent feeder. To avoid this, a shaped type of characteristic may be used, where the resistive coverage is restricted. With a ‘lenticular’ characteristic, the aspect ratio of Carrier stop Zone 1 R G Carrier start K (b) Carrier starting in distance blocking schemes Figure 11.10: Typical applications for the offset mho relay © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-9 Network Protection & Automation Guide X Offset Lenticular Characteristic b Offset Mho Characterisitc a Z D2 Z D3 ZA Z D1 Load Area 0 R ZC ZB Impedance Characteristic Figure 11.11: Minimum load impedance permitted with lenticular, offset mho and impedance relays It can be observed in Figure 11.11 how the load area is defined according to a minimum impedance arc, constrained by straight lines which emanate from the origin, 0. Modem numerical relays typically do not use lenticular characteristic shaping, but instead use load encroachment (load blinder) detection. This allows a full mho characteristic to be used, but with tripping prevented in the region of the impedance plane known to be frequented by load (ZA-ZB-ZC-ZD). polarised, plain mho impedance characteristic, when applied to overhead line circuits with high impedance angles, is that it has limited coverage of arc or fault resistance. The problem is aggravated in the case of short lines, since the required Zone 1 ohmic setting is low. The amount of the resistive coverage offered by the mho circle is directly related to the forward reach setting. Hence, the resulting resistive coverage may be too small in relation to the expected values of fault resistance. One additional benefit of applying cross-polarisation to a mho impedance element is that its resistive coverage will be enhanced. This effect is illustrated in Figure 11.12, for the case where a mho element has 100% cross-polarisation. With cross-polarisation from the healthy phase(s) or from a memory system, the mho resistive expansion will occur during a balanced three-phase fault as well as for unbalanced faults. The expansion will not occur under load conditions, when there is no phase shift between the measured voltage and the polarising voltage. The degree of resistive reach enhancement depends on the ratio of source impedance to relay reach (impedance) setting as can be deduced by reference to Figure 11.13. X Zs ZL 2.5 11.7.5 Fully Cross-Polarised Mho Characteristic The previous section showed how the non-directional offset mho characteristic is inherently able to operate for close-up zero voltage faults, where there would be no polarising voltage to allow operation of a plain mho directional element. One way of ensuring correct mho element response for zero-voltage faults is to add a percentage of voltage from the healthy phase(s) to the main polarising voltage as a substitute phase reference. This technique is called cross-polarising, and it has the advantage of preserving and indeed enhancing the directional properties of the mho characteristic. By the use of a phase voltage memory system, that provides several cycles of pre-fault voltage reference during a fault, the crosspolarisation technique is also effective for close-up three-phase faults. For this type of fault, no healthy phase voltage reference is available. Zs ZL 0 R Figure 11.12: Fully cross-polarised mho relay characteristic with variations of ZS/ZL ratio Early memory systems were based on tuned, resonant, analogue circuits, but problems occurred when applied to networks where the power system operating frequency could vary. More modern digital or numerical systems can offer a synchronous phase reference for variations in power system frequency before or even during a fault. As described in Section 11.7.3, a disadvantage of the self- 11-10 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection Positive current direction for relay Source ~ ZS ZL Relay location IF Va1 E1 ZS1 ZL1 N1 F1 Ia1 Ia2 ZS2 ZL2 N2 F2 Va2 Mho unit characteristic (not cross-polarised) selection is not provided, a modern non-switched distance relay may only employ a relatively small percentage of cross polarisation. The level selected must be sufficient to provide reliable directional control in the presence of CVT transients for close-up faults, and also attain reliable faulted phase selection. By employing only partial cross-polarisation, the disadvantages of the fully cross-polarised characteristic are avoided, while still retaining the advantages. Figure 11.14 shows a typical characteristic that can be obtained using this technique (reference Micromho, Quadramho and Optimho family). X S'2 = ZL1 - Zn1 Zn1 ZL1 R Zn2 30° ZS1 S'1 = ZL1 + Zn2 Mho unit characteristic (fully cross-polarised) _X Figure 11.13: Illustration of improvement in relay resistive coverage for fully cross-polarised characteristic It must be emphasised that the apparent extension of a fully cross-polarised impedance characteristic into the negative reactance quadrants of Figure 11.13 does not imply that there would be operation for reverse faults. With cross-polarisation, the relay characteristic expands to encompass the origin of the impedance diagram for forward faults only. For reverse faults, the effect is to exclude the origin of the impedance diagram, thereby ensuring proper directional responses for close-up forward or reverse faults. Figure 11.14: Partially cross-polarised characteristic with 'shield' shape 11.7.7 Quadrilateral Characteristic Fully cross-polarised characteristics have now largely been superseded, due to the tendency of comparators connected to healthy phases to operate under heavy fault conditions on another phase. This is of no consequence in a switched distance relay, where a single comparator is connected to the correct fault loop impedance by starting units before measurement begins. However, modern relays offer independent impedance measurement for each of the three earth-fault and three phase-fault loops. For these types of relay, mal-operation of healthy phases is undesirable, especially when single-pole tripping is required for singlephase faults. This form of polygonal impedance characteristic is shown in Figure 11.15. The characteristic is provided with forward reach and resistive reach settings that are independently adjustable. It therefore provides better resistive coverage than any mho-type characteristic for short lines. This is especially true for earth fault impedance measurement, where the arc resistances and fault resistance to earth contribute to the highest values of fault resistance. To avoid excessive errors in the zone reach accuracy, it is common to impose a maximum resistive reach in terms of the zone impedance reach. Recommendations in this respect can usually be found in the appropriate relay manuals. 11.7.6 Partially Cross-Polarised Mho Characteristic Quadrilateral elements with plain reactance reach lines can introduce reach error problems for resistive earth faults where the angle of total fault current differs from the angle of the Where a reliable, independent method of faulted phase © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-11 Network Protection & Automation Guide current measured by the relay. This will be the case where the local and remote source voltage vectors are phase shifted with respect to each other due to pre-fault power flow. This can be overcome by selecting an alternative to use of a phase current for polarisation of the reactance reach line. Polygonal impedance characteristics are highly flexible in terms of fault impedance coverage for both phase and earth faults. For this reason, most digital and numerical distance relays now offer this form of characteristic. A further factor is that the additional cost implications of implementing this characteristic using discrete component electromechanical or early static relay technology do not arise. impedance vector, as shown in Figure 11.16. The ohm impedance elements divide the R/X impedance diagram into three zones, A, B and C. As the impedance changes during a power swing, the point representing the impedance moves along the swing locus, entering the three zones in turn and causing the ohm units to operate in sequence. When the impedance enters the third zone the trip sequence is completed and the circuit breaker trip coil can be energised at a favourable angle between system sources for arc interruption with little risk of restriking. X Zone 3 C Zone 2 B Zone s 1& Zone 1 2 R A Zone 3 RZ1 RZ2 RZ3 Figure 11.15: Quadrilateral characteristic 11.7.8 Protection against Power Swings – Use of the Ohm Characteristic During severe power swing conditions from which a system is unlikely to recover, stability might only be regained if the swinging sources are separated. Where such scenarios are identified, power swing, or out-of-step, tripping protection can be deployed, to strategically split a power system at a preferred location. Ideally, the split should be made so that the plant capacity and connected loads on either side of the split are matched. This type of disturbance cannot normally be correctly identified by an ordinary distance protection. As previously mentioned, it is often necessary to prevent distance protection schemes from operating during stable or unstable power swings, to avoid cascade tripping. To initiate system separation for a prospective unstable power swing, an out-of-step tripping scheme employing ohm impedance measuring elements can be deployed. Ohm impedance characteristics are applied along the forward and reverse resistance axes of the R/X diagram and their operating boundaries are set to be parallel to the protected line 11-12 Figure 11.16: Application of out-of-step tripping relay characteristic Only an unstable power swing condition can cause the impedance vector to move successively through the three zones. Therefore, other types of system disturbance, such as power system fault conditions, will not result in relay element operation. 11.7.9 Other Characteristics The execution time for the algorithm for traditional distance protection using quadrilateral or similar characteristics may result in a relatively long operation time, possibly up to 40ms in some relay designs. To overcome this, some numerical distance relays also use alternative algorithms that can be executed significantly faster. These algorithms are based generally on detecting changes in current and voltage that are in excess of what is expected, often known as the ‘Delta’ algorithm. This algorithm detects a fault by comparing the measured values of current and voltage with the values sampled previously. If the change between these samples exceeds a predefined amount (the ‘delta’), it is assumed a fault has occurred. In parallel, the distance to fault is also computed. Provided the computed distance to fault lies within the Zone reach of the relay, a trip command is issued. This algorithm © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection can be executed significantly faster than the conventional distance algorithm, resulting in faster overall tripping times. Faulted phase selection can be carried out by comparing the signs of the changes in voltage and current. Relays that use the ‘Delta’ algorithm generally run both this and conventional distance protection algorithms in parallel, as some types of fault (e.g. high-resistance faults) may not fall within the fault detection criteria of the ‘Delta’ algorithm. 11.8 DISTANCE RELAY IMPLEMENTATION Discriminating zones of protection can be achieved using distance relays, provided that fault distance is a simple function of impedance. While this is true in principle for transmission circuits, the impedances actually measured by a distance relay also depend on the following factors: x the magnitudes of current and voltage (the relay may not see all the current that produces the fault voltage) x the fault impedance loop being measured type of relay is commonly referred to as a reachstepped distance relay x each zone may be provided with independent sets of impedance measuring elements for each impedance loop. This is known as a full distance scheme, capable of offering the highest performance in terms of speed and application flexibility Furthermore, protection against earth faults may require different characteristics and/or settings to those required for phase faults, resulting in additional units being required. A total of 18 impedance-measuring elements or algorithms would be required in a full scheme distance relay for threezone protection for all types of fault. With electromechanical or static technology, each of the measuring elements would have been a separate relay housed in its own case, so that the distance relay comprised a panel-mounted assembly of the required relays with suitable inter-unit wiring. Figure 11.17(a) shows an example of such a relay scheme. x the type of fault x the fault resistance x the symmetry of line impedance x the circuit configuration (single, double or multiterminal circuit) It is impossible to eliminate all of the above factors for all possible operating conditions. However, considerable success can be achieved with a suitable distance relay. This may comprise relay elements or algorithms for starting, distance measuring and for scheme logic. The distance measurement elements may produce impedance characteristics selected from those described in Section 11.7. Various distance relay formats exist, depending on the operating speed required and cost considerations related to the relaying hardware, software or numerical relay processing capacity required. The most common formats are: x a single measuring element for each phase is provided, that covers all phase faults x a more economical arrangement is for ‘starter’ elements to detect which phase or phases have suffered a fault. The starter elements switch a single measuring element or algorithm to measure the most appropriate fault impedance loop. This is commonly referred to as a switched distance relay Figure 11.17a: Static distance relay x a single set of impedance measuring elements for each impedance loop may have their reach settings progressively increased from one zone reach setting to another. The increase occurs after zone time delays that are initiated by operation of starter elements. This © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-13 Network Protection & Automation Guide current (the ‘delta’ algorithm). This enables very fast detection of the faulted phases, within only a few samples of the analogue current inputs x change in voltage magnitude x change in current magnitude Figure 11.17b: MiCOM P440 series numerical distance relay Digital/numerical distance relays (Figure 11.17(b) are likely to have all of the above functions implemented in software. Starter units may not be necessary. The complete distance relay is housed in a single unit, making for significant economies in space, wiring and increased dependability, through the increased availability that stems from the provision of continuous self-supervision. When the additional features detailed in Section 11.11 are taken into consideration, such equipment offers substantial user benefits. 11.8.1 Starters for Switched Distance Protection Electromechanical and static distance relays do not normally use an individual impedance-measuring element per phase. The cost and the resulting physical scheme size made this arrangement impractical, except for the most demanding EHV transmission applications. To achieve economy for other applications, only one measuring element was provided, together with ‘starter’ units that detected which phases were faulted, to switch the appropriate signals to the single measuring function. A distance relay using this technique is known as a switched distance relay. A number of different types of starters have been used, the most common being based on overcurrent, undervoltage or under-impedance measurement. Numerical distance relays permit direct detection of the phases involved in a fault. This is called faulted phase selection, often abbreviated to phase selection. Several techniques are available for faulted phase selection, which then permits the appropriate distance-measuring zone to trip. Without phase selection, the relay risks having over or underreach problems, or tripping three-phase when single-pole fault clearance is required. Several techniques are available for faulted phase selection, such as: x superimposed current comparisons, comparing the step change of level between pre-fault load, and fault 11-14 Numerical phase selection is much faster than traditional starter techniques used in electromechanical or static distance relays. It does not impose a time penalty as the phase selection and measuring zone algorithms run in parallel. It is possible to build a full-scheme relay with these numerical techniques. The phase selection algorithm provides faulted phase selection, together with a segregated measuring algorithm for each phase-ground and phase to phase fault loop (AN, BN, CN, AB, BC, CA), thus ensuring full-scheme operation. However, there may be occasions where a numerical relay that mimics earlier switched distance protection techniques is desired. The reasons may be economic (less software required – thus cheaper than a relay that contains a full-scheme implementation) and/or technical. Some applications may require the numerical relay characteristics to match those of earlier generations already installed on a network, to aid selectivity. Such relays are available, often with refinements such as multi-sided polygonal impedance characteristics that assist in avoiding tripping due to heavy load conditions. With electromechanical or static switched distance relays, a selection of available starters often had to be made. The choice of starter was dependent on power system parameters such as maximum load transfer in relation to maximum reach required and power system earthing arrangements. Where overcurrent starters are used, care must be taken to ensure that, with minimum generating plant in service, the setting of the overcurrent starters is sensitive enough to detect faults beyond the third zone. Furthermore, these starters require a high drop-off to pick-up ratio, to ensure that they will drop off under maximum load conditions after a second or third zone fault has been cleared by the first zone relay in the faulty section. Without this feature, indiscriminate tripping may result for subsequent faults in the second or third zone. For satisfactory operation of the overcurrent starters in a switched distance scheme, the following conditions must be fulfilled: x the current setting of the overcurrent starters must be not less than 1.2 times the maximum full load current of the protected line x the power system minimum fault current for a fault at the Zone 3 reach of the distance relay must not be less than 1.5 times the setting of the overcurrent starters © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection On multiple-earthed systems where the neutrals of all the power transformers are solidly earthed, or in power systems where the fault current is less than the full load current of the protected line, it is not possible to use overcurrent starters. In these circumstances under-impedance starters are typically used. The type of under-impedance starter used is mainly dependent on the maximum expected load current and equivalent minimum load impedance in relation to the required relay setting to cover faults in Zone 3. This is illustrated in Figure 11.11 where ZD1, ZD2, and ZD3 are respectively the minimum load impedances permitted when lenticular, offset mho and impedance relays are used. 11.9 EFFECT OF SOURCE IMPEDANCE AND EARTHING METHODS For correct operation, distance relays must be capable of measuring the distance to the fault accurately. To ensure this, it is necessary to provide the correct measured quantities to the measurement elements. It is not always the case that use of the voltage and current for a particular phase will give the correct result, or that additional compensation is required. 11.9.1 Phase Fault Impedance Measurement Figure 11.18 shows the current and voltage relations for the different types of fault. If ZS1 and ZL1 are the source and line positive sequence impedances, viewed from the relaying point, the currents and voltages at this point for double phase faults are dependent on the source impedance as well as the line impedance. The relationships are given in Figure 11.19. I ca I 1c I bc a 2 I 1c a 2  a I 1c I cc aI 1c a  a 2 I 1c V ac Z L1 I 1c 2 Z S1  Z L1 I 1c V bc a Z L1 I 1c 2a 2 Z L1  Z S1 I 1c V cc aZ L1 I 1c 2aZ L1  Z S1 I 1c 2 1 I ac  aI bc  a 2 I cc 3 I c and V c I 1c Figure 11.19: Phase currents and voltages at relaying point for 3-phase and double-phase faults Applying the difference of the phase voltages to the relay eliminates the dependence on ZS1. For example: Vbc' a 2  a Z L1 I1' for 3 phase faults Vbc' 2 a 2  a Z L1 I1' for double phase faults Distance measuring elements are usually calibrated in terms of the positive sequence impedance. Correct measurement for both phase-phase and three-phase faults is achieved by supplying each phase-phase measuring element with its corresponding phase-phase voltage and difference of phase currents. Thus, for the B-C element, the current measured will be: I b'  I c' a 2  a I1' for 3 phase faults I b'  I c' 2 a 2  a I1' for double phase faults and the relay will measure ZL1 in each case. 11.9.2 Earth Fault Impedance Measurement When a phase-earth fault occurs, the phase-earth voltage at the fault location is zero. It would appear that the voltage drop to the fault is simply the product of the phase current and line impedance. However, the current in the fault loop depends on the number of earthing points, the method of earthing and sequence impedances of the fault loop. Unless these factors are taken into account, the impedance measurement will be incorrect. Figure 11.18: Current and voltage relationships for some shunt faults The voltage drop to the fault is the sum of the sequence voltage drops between the relaying point and the fault. The voltage drop to the fault and current in the fault loop are: © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-15 Network Protection & Automation Guide Va' I1' Z L1  I 2' Z L1  I o' Z Lo I a' I1'  I 2'  I o' and the residual current I'N at the relaying point is given by: I a'  I b'  I c' I N' 3I o' Where I a , I b , I c are the phase currents at the relaying point. ' ' ' From the above expressions, the voltage at the relaying point can be expressed in terms of: x the phase currents at the relaying point, K 1 ½ ­ Z ®1  ¾ Z L1 3 ¿ ¯ where K ZLO ZL1 x the ratio of the transmission line zero sequence to positive sequence impedance, K, x Z L O Z L1 the transmission line positive sequence impedance ZL1: Va' K  1½ ­ Z L1 ® I a'  I a'  I b'  I c' ¾ 3 ¿ ¯ Equation 11.5 The voltage appearing at the relaying point, as previously mentioned, varies with the number of infeeds, the method of system earthing and the position of the relay relative to the infeed and earthing points in the system. Figure 11.20 illustrates the three possible arrangements that can occur in practice with a single infeed. In Figure 11.20(a), the healthy phase currents are zero, so that the phase currents Ia, Ib and Ic have a 1-0-0 pattern. The impedance seen by a relay comparing Ia and Va is: Z K 1 ½ ­ ®1  ¾Z L1 3 ¿ ¯ Equation 11.6 In Figure 11.20(b), the currents entering the fault from the relay branch have a 2-1-1 distribution, so: Z Z L1 Figure 11.20: Effect of infeed and earthing arrangements on earth fault distance measurement In Figure 11.20(c), the phase currents have a 1-1-1 distribution, and hence: Z KZ L1 If there were infeeds at both ends of the line, the impedance measured would be a superposition of any two of the above examples, with the relative magnitudes of the infeeds taken into account. This analysis shows that the relay can only measure an impedance which is independent of infeed and earthing 11-16 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection K 1 of the residual 3 arrangements if a proportion K N current IN = Ia + Ib + Ic is added to the phase current Ia. This technique is known as ‘residual compensation’. Static distance relays compensate for the earth fault conditions by using an additional replica impedance ZN within the measuring circuits. This compensation is implemented in software in numerical relays. Whereas the phase replica impedance Z1 is fed with the phase current at the relaying point, ZN is fed with the full residual current. The value of ZN is adjusted so that for a fault at the reach point, the sum of the voltages developed across Z1 and ZN equals the measured phase to neutral voltage in the faulted phase. The required setting for ZN can be determined by considering an earth fault at the reach point of the relay. This is illustrated with reference to the A-N fault with single earthing point behind the relay as in Figure 11.20(a) Voltage supplied from the VT’s: I1 Z1  Z 2  Z O I1 2Z1  Z O I A Z1  I N Z N I A Z1  Z N 3I 1 Z 1  Z N Hence, the required setting of ZN for balance at the reach point is given by equating the above two expressions: 3I 1 Z 1  Z N ?ZN I 1 2Z1  Z 0 Z O  Z1 3 Z O  Z1 Z1 3Z 1 11.10.1 Minimum Voltage at Relay Terminals To attain their claimed accuracy, distance relays that do not employ voltage memory techniques require a minimum voltage at the relay terminals under fault conditions. This voltage should be declared in the data sheet for the relay. With knowledge of the sequence impedances involved in the fault, or alternatively the fault MVA, the system voltage and the earthing arrangements, it is possible to calculate the minimum voltage at the relay terminals for a fault at the reach point of the relay. It is then only necessary to check that the minimum voltage for accurate reach measurement can be attained for a given application. Care should be taken that both phase and earth faults are considered. 11.10.2 Minimum Length of Line Voltage across replica impedances: I A Z1  Z N application. Many of them have been overcome in the latest numerical relays. Nevertheless, an awareness of the problems is useful where a protection engineer has to deal with older relays that are already installed and not due for replacement. K N Z1 Equation 11.7 With the replica impedance set to Z O  Z1 , earth fault 3 measuring elements will measure the fault impedance correctly, irrespective of the number of infeeds and earthing points on the system. 11.10 DISTANCE RELAY APPLICATION PROBLEMS To determine the minimum length of line that can be protected by a distance relay, it is necessary to check first that any minimum voltage requirement of the relay for a fault at the Zone 1 reach is within the declared sensitivity for the relay. Secondly, the ohmic impedance of the line (referred if necessary to VT/CT secondary side quantities) must fall within the ohmic setting range for Zone 1 reach of the relay. For very short lines and especially for cable circuits, it may be found that the circuit impedance is less than the minimum setting range of the relay. In such cases, an alternative method of protection will be required. A suitable alternative might be current differential protection, as the line length will probably be short enough for the cost-effective provision of a high bandwidth communication link between the relays fitted at the ends of the protected circuit. However, the latest numerical distance relays have a very wide range of impedance setting ranges and good sensitivity with low levels of relaying voltage, so such problems are now rarely encountered. Application checks are still essential, though. When considering earth faults, particular care must be taken to ensure that the appropriate earth fault loop impedance is used in the calculation. 11.10.3 Under-Reach - Effect of Remote Infeed A distance relay is said to under-reach when the impedance presented to it is apparently greater than the impedance to the fault. Percentage under-reach is defined as: Distance relays may suffer from a number of difficulties in their © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-17 Network Protection & Automation Guide ZR  ZF x 100% ZR where: ZR = intended relay reach (relay reach setting) ZF = effective reach The main cause of under-reaching is the effect of fault current infeed at remote busbars. This is best illustrated by an example. In Figure 11.21, the relay at A will not measure the correct impedance for a fault on line section ZC due to current infeed IB. For a fault at point F, the relay is presented with an impedance: ZA  I A  IB ZC IA ZA  Care should also be taken that large forward reach settings will not result in operation of healthy phase relays for reverse earth faults, see Section 11.10.5. 11.10.4 Over-Reach So, for relay balance: Z A  ZC Figure 11.21: Effect on distance relays of infeed at the remote busbar IA  IB ZC IA A distance relay is said to over-reach when the apparent impedance presented to it is less than the impedance to the fault. Percentage over-reach is defined by the equation: ZF  ZR x 100% ZR Therefore the apparent impedance is §I I · Z A  ¨¨ A B ¸¸ Z C © IA ¹ Equation 11.8 It is clear from Equation 11.8 that the relay will underreach. It is relatively easy to compensate for this by increasing the reach setting of the relay, but care has to be taken. Should there be a possibility of the remote infeed being reduced or zero, the relay will then reach further than intended. For example, setting Zone 2 to reach a specific distance into an adjacent line section under parallel circuit conditions may mean that Zone 2 reaches beyond the Zone 1 reach of the adjacent line protection under single circuit operation. If IB = 91A and the relay reach is set to see faults at F, then in the absence of the remote infeed, the relay effective setting becomes ZA + 10ZC. 11-18 Equation 11.9 where: ZR = relay reach setting ZF = effective reach An example of the over-reaching effect is when distance relays are applied on parallel lines and one line is taken out of service and earthed at each end. This is covered in Section 13.2.3. 11.10.5 Forward Reach Limitations There are limitations on the maximum forward reach setting that can be applied to a distance relay. For example, with reference to Figure 11.6, Zone 2 of one line section should not reach beyond the Zone 1 coverage of the next line section relay. Where there is a link between the forward reach setting and the relay resistive coverage (e.g. a Mho Zone 3 element), a relay must not operate under maximum load conditions. Also, if the relay reach is excessive, the healthy phase-earth fault units of some relay designs may be prone to operation for heavy reverse faults. This problem only affected older relays applied to three-terminal lines that have significant line section length asymmetry. A number of the features offered with modern relays can eliminate this problem. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection 11.10.6 Power Swing Blocking Power swings are variations in power flow that occur when the internal voltages of generators at different points of the power system slip relative to each other. The changes in load flows that occur as a result of faults and their subsequent clearance are one cause of power swings. A power swing may cause the impedance presented to a distance relay to move away from the normal load area and into the relay characteristic. In the case of a stable power swing it is especially important that the distance relay should not trip to allow the power system to return to a stable conditions. For this reason, most distance protection schemes applied to transmission systems have a power swing blocking facility available. Different relays may use different principles for detection of a power swing, but all involve recognising that the movement of the measured impedance in relation to the relay measurement characteristics is at a rate that is significantly less than the rate of change that occurs during fault conditions. When the relay detects such a condition, operation of the relay elements can be blocked. Power swing blocking may be applied individually to each of the relay zones, or on an all zones applied/inhibited basis, depending on the particular relay used. Various techniques are used in different relay designs to inhibit power swing blocking in the event of a fault occurring while a power swing is in progress. This is particularly important, for example, to allow the relay to respond to a fault that develops on a line during the dead time of a single pole autoreclose cycle. Some Utilities may designate certain points on the network as split points, where the network should be split in the event of an unstable power swing or pole-slipping occurring. A dedicated power swing tripping relay may be employed for this purpose (see Section 11.7.8). Alternatively, it may be possible to achieve splitting by strategically limiting the duration for which the operation a specific distance relay is blocked during power swing conditions. 11.10.7 Voltage Transformer Supervision Fuses or sensitive miniature circuit breakers normally protect the secondary wiring between the voltage transformer secondary windings and the relay terminals. may maloperate if one or more voltage inputs are removed due to operation of these devices. For these types of distance relay, supervision of the voltage inputs is recommended. The supervision may be provided by external means, e.g. separate voltage supervision circuits, or it may be incorporated into the distance relay itself. On detection of VT failure, tripping of the distance relay can be inhibited and/or an alarm is given. Modern distance protection relays employ voltage supervision that operates from sequence voltages and currents. Zero or negative sequence voltages and corresponding zero or negative sequence currents are derived. Discrimination between primary power system faults and wiring faults or loss of supply due to individual fuses blowing or MCB’s being opened is obtained by blocking the distance protection only when zero or negative sequence voltage is detected without the presence of zero or negative sequence current. This arrangement will not detect the simultaneous loss of all three voltages and additional detection is required that operates for loss of voltage with no change in current, or a current less than that corresponding to the three phase fault current under minimum fault infeed conditions. If fast-acting miniature circuit breakers are used to protect the VT secondary circuits, contacts from these may be used to inhibit operation of the distance protection elements and prevent tripping. 11.11 OTHER DISTANCE RELAY FEATURES A modern digital or numerical distance relay will often incorporate additional features that assist the protection engineer in providing a comprehensive solution to the protection requirements of a particular part of a network. Table 11.1 provides an indication of the additional features that may be provided in such a relay. The combination of features that are actually provided is manufacturer and relay model dependent, but it can be seen from the Table that steady progression is being made towards a ‘one-box’ solution that incorporates all the protection and control requirements for a line or cable. However, at the highest transmission voltages, the level of dependability required for rapid clearance of any protected circuit fault will still demand the use of two independent protection systems. Distance relays having: x self-polarised offset characteristics encompassing the zero impedance point of the R/X diagram x sound phase polarisation x voltage memory polarisation © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-19 Network Protection & Automation Guide Fault location (distance to fault) Relay Parameter Instantaneous overcurrent protection Parameter Description Parameter Value Units Tee’d feeder protection R1ph Phase fault resistive reach value - Zone 1 78 : Alternative setting groups R2ph Phase fault resistive reach value - Zone 2 78 : CT supervision R3ph Phase fault resistive reach value - Zone 3 78 : Check synchroniser TZ1 Time delay - Zone 1 0 sec Auto-reclose TZ2 Time delay - Zone 2 0.35 sec CB state monitoring TZ3 Time delay - Zone 3 0.8 sec CB condition monitoring R1G Ground fault resistive reach value - Zone 1 104 : CB control R2G Ground fault resistive reach value - Zone 2 104 : Measurement of voltages, currents, etc. R3G Ground fault resistive reach value - Zone 3 104 : Table 11.2: Distance relay parameters for example Event recorder Calculations are carried out in terms of primary system impedances in ohms, rather than the traditional practice of using secondary impedances. With numerical relays, where the CT and VT ratios may be entered as parameters, the scaling between primary and secondary ohms can be performed by the relay. This simplifies the example by allowing calculations to be carried out in primary quantities and eliminates considerations of VT/CT ratios. Disturbance recorder CB failure detection/logic Directional/Non-directional phase fault overcurrent protection (backup to distance protection) Directional/Non-directional earth fault overcurrent protection (backup to distance protection) Negative sequence protection Under/overvoltage protection Stub-bus protection Broken conductor detection User-programmable scheme logic Table 11.1: Listing of possible additional features in a numerical distance relay 11.12 DISTANCE RELAY APPLICATION EXAMPLE The system diagram shown in Figure 11.22 shows a simple 230kV network. The following example shows the calculations necessary to apply three-zone distance protection to the line interconnecting substations ABC and XYZ. All relevant data for this exercise are given in the diagram. The MiCOM P441 relay with quadrilateral characteristics is considered in this example. Relay parameters used in the example are listed in Table 11.2. Relay Parameter Parameter Description Parameter Value Units Z 0.089  j0.476ȍ/ km 1 Z o 0. 4 2 6  j 1 . 5 7 6 ȍ / km Figure 11.22: Example network for distance relay setting calculation For simplicity it is assumed that only a conventional 3-zone distance protection is to be set and that there is no teleprotection scheme to be considered. In practice, a teleprotection scheme would normally be applied to a line at this voltage level. ZL1 (mag) Line positive sequence impedance (magnitude) 48.42 : ZL1 (ang) Line positive sequence impedance (phase angle) 79.41 deg ZLO (mag) Line zero sequence impedance (magnitude) 163.26 : ZLO (ang) Line zero sequence impedance (phase angle) 74.87 deg 11.12.1 Line Impedance KZO (mag) Default residual compensation factor (magnitude) 0.79 - The line impedance is: KZO (ang) Default residual compensation factor (phase angle) -6.5 deg Z1 (mag) Zone 1 reach impedance setting (magnitude) 38.74 : Z1 (ang) Zone 1 reach impedance setting (phase angle) 80 deg Z2 (mag) Zone 2 reach impedance setting (magnitude) 62.95 : Z2 (ang) Zone 2 reach impedance setting (phase angle) 80 deg Z3 (mag) Zone 3 reach impedance setting (magnitude) 83.27 : Z3 (ang) Zone 3 reach impedance setting (phase angle) 80 deg 11-20 ZL 0.089  j 0.476 x 100: 8.9  j 47.6: 48.42‘79.41D : Use values of 48.42: (magnitude) and 80o (angle) as nearest settable values. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection 11.12.2 Residual Compensation 48.42‘79.41D  (0.5 x 60 x (0.484 ‘79.41D )) : The relays used are calibrated in terms of the positive sequence impedance of the protected line. Since the zero sequence impedance of the line between substations ABC and XYZ is different from the positive sequence impedance, the impedance seen by the relay in the case of an earth fault, involving the passage of zero sequence current, will be different to that seen for a phase fault. Hence, the earth fault reach of the relay requires zero sequence compensation (see Section 11.9.2). 62.95‘79.41D : For the relay used, this adjustment is provided by the residual (or neutral) compensation factor KZO, set equal to: D 11.12.5 Zone 3 Phase Reach Zone 3 is set to cover 120% of the sum of the lines between substations ABC and PQR, provided this does not result in any transformers at substation XYZ being included. It is assumed that this constraint is met. Hence, Zone 3 reach: 48.42‘79.41D  (1.2 x 60 x (0.484 ‘79.41D )) : 83.275‘79.41D : Z 0  Z1 3Z 1 K ZO Use 62.95‘80 : nearest available setting. Use a setting of 83.27‘80 : , nearest available setting. D 11.12.6 Zone Time Delay Settings ‘K Z 0 ‘ Z 0  Z1 3Z1 Proper co-ordination of the distance relay settings with those of other relays is required. Independent timers are available for the three zones to ensure this. For each of the transmission lines: Z L1 0.089  j 0.476: 0.484‘79.41D : Z L0 0.426  j1.576: 1.632‘74.87D : Hence, KZ0 0.792 ‘K Z 0 6.5 D 11.12.3 Zone 1 Phase Reach The required Zone 1 reach is 80% of the line impedance. Therefore, 0.8x 48.42‘79.41D 38.74‘79.41D Use 38.74‘80 : nearest settable value. D 11.12.4 Zone 2 Phase Reach Ideally, the requirements for setting Zone 2 reach are: x at least 120% of the protected line x less than the protected line + 50% of the next line Sometimes, the two requirements are in conflict. both requirements can be met. A setting of the line between substations ABC and XYZ, plus adjacent line section to substation PQR is used. 2 reach: In this case, whole of the 50% of the Hence, Zone For Zone 1, instantaneous tripping is normal. A time delay is used only in cases where large d.c. offsets occur and old circuit breakers, incapable of breaking the instantaneous d.c. component, are involved. The Zone 2 element has to grade with the relays protecting the line between substations XYZ and PQR since the Zone 2 element covers part of these lines. Assuming that this line has distance, unit or instantaneous high-set overcurrent protection applied, the time delay required is that to cover the total clearance time of the downstream relays. To this must be added the reset time for the Zone 2 element following clearance of a fault on the adjacent line, and a suitable safety margin. A typical time delay is 350ms, and the normal range is 200-500ms. The considerations for the Zone 3 element are the same as for the Zone 2 element, except that the downstream fault clearance time is that for the Zone 2 element of a distance relay or IDMT overcurrent protection. Assuming distance relays are used, a typical time is 800ms. In summary: TZ 1 0ms TZ 2 250ms TZ 3 800ms 11.12.7 Phase Fault Resistive Reach Settings With the use of a quadrilateral characteristic, the resistive reach settings for each zone can be set independently of the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-21 Network Protection & Automation Guide impedance reach settings. The resistive reach setting represents the maximum amount of additional fault resistance (in excess of the line impedance) for which a zone will trip, regardless of the fault within the zone. Two constraints are imposed upon the settings, as follows: x it must be greater than the maximum expected phasephase fault resistance (principally that of the fault arc) x it must be less than the apparent resistance measured due to the heaviest load on the line, unless load blinding (load encroachment) is applied R1G 104: R2G 104: R3G 104: This completes the setting of the relay. Table 11.2 also shows the settings calculated. 11.13 REFERENCE [11.1] Protective Relays – their Theory and Practice. A.R. van C. Warrington. Chapman and Hall, 1962 The minimum fault current at Substation ABC is of the order of 1.8kA, leading to a typical arc resistance Rarc using the van Warrington formula (Equation 11.4) of 8:. Using the current transformer ratio as a guide to the maximum expected load current, the minimum load impedance Zlmin will be 130:. Typically, the resistive reaches will be set to avoid the minimum load impedance by a 40% margin for the phase elements, leading to a maximum resistive reach setting of 78:. Therefore, the resistive reach setting lies between 8: and 78:. Allowance should be made for the effects of any remote fault infeed, by using the maximum resistive reach possible. While each zone can have its own resistive reach setting, for this simple example they can all be set equal. This need not always be the case, it depends on the particular distance protection scheme used and the need to include Power Swing Blocking. Suitable settings are chosen to be 80% of the load resistance: R1 ph 78: R2 ph 78: R3 ph 78: 11.12.8 Earth Fault Impedance Reach Settings By default, the residual compensation factor as calculated in Section 11.12.2 is used to adjust the phase fault reach setting in the case of earth faults, and is applied to all zones. 11.12.9 Earth Fault Resistive Reach Settings The margin for avoiding the minimum load impedance need only be 20%. Hence the settings are: 11-22 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 11 ˜ Distance Protection © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 11-23 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 12 Distance Protection Schemes 12.1 12.2 12.3 12.4 12.5 12.6 Introduction Zone 1 Extension Scheme (Z1x Scheme) Transfer Tripping Schemes Blocking Overreaching Schemes Directional Comparison Unblocking Scheme Comparison of Transfer Trip and Blocking Relaying Schemes 12.1 INTRODUCTION Conventional time-stepped distance protection is illustrated in Figure 12.1. One of the main disadvantages of this scheme is that the instantaneous Zone 1 protection at each end of the protected line cannot be set to cover the whole of the feeder length and is usually set to about 80%. This leaves two ‘end zones’, each being about 20% of the protected feeder length. Faults in these zones are cleared in Zone 1 time by the protection at one end of the feeder and in Zone 2 time (typically 0.25 to 0.4 seconds) by the protection at the other end of the feeder. Relay A End Zone Z3A Z2A Z1A A F 0 B C Z1B Z2B Z3B Relay B End Zone (a) Stepped time/distance characteristics Z1 Z2 Z2T 0 Z3 Z3T 0 t1 Trip (b) Trip logic Figure 12.1: Conventional distance scheme This situation cannot be tolerated in some applications, for two main reasons: x faults remaining on the feeder for Zone 2 time may cause the system to become unstable x where high-speed auto-reclosing is used, the nonsimultaneous opening of the circuit breakers at both ends of the faulted section results in no 'dead time' during the auto-reclose cycle for the fault to be extinguished and for ionised gases to clear. This results Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 12-1 Network Protection & Automation Guide in the possibility that a transient fault will cause permanent lockout of the circuit breakers at each end of the line section Even where instability does not occur, the increased duration of the disturbance may give rise to power quality problems, and may result in increased plant damage. Unit schemes of protection that compare the conditions at the two ends of the feeder simultaneously positively identify whether the fault is internal or external to the protected section and provide high-speed protection for the whole feeder length. This advantage is balanced by the fact that the unit scheme does not provide the back up protection for adjacent feeders given by a distance scheme. The most desirable scheme is obviously a combination of the best features of both arrangements, that is, instantaneous tripping over the whole feeder length plus back-up protection to adjacent feeders. This can be achieved by interconnecting the distance protection relays at each end of the protected feeder by a communications channel. Communication techniques are described in detail in Chapter 8. The purpose of the communications channel is to transmit information about the system conditions from one end of the protected line to the other, including requests to initiate or prevent tripping of the remote circuit breaker. The former arrangement is generally known as a 'transfer tripping scheme' while the latter is generally known as a 'blocking scheme'. However, the terminology of the various schemes varies widely, according to local custom and practice. Z3A Z2A Z1A This scheme is intended for use with an auto-reclose facility, or where no communications channel is available, or the channel has failed. Thus it may be used on radial distribution feeders, or on interconnected lines as a fallback when no communications channel is available, e.g. due to maintenance or temporary fault. The scheme is shown in Figure 12.2. The Zone 1 elements of the distance relay have two settings. One is set to cover 80% of the protected line length as in the basic distance scheme. The other, known as 'Extended Zone 1’ or ‘Z1X’, is set to overreach the protected line, a setting of 120% of the protected line being common. The Zone 1 reach is normally controlled by the Z1X setting and is reset to the basic Zone 1 setting when a command from the auto-reclose relay is received. On occurrence of a fault at any point within the Z1X reach, the relay operates in Zone 1 time, trips the circuit breaker and initiates auto-reclosure. The Zone 1 reach of the distance relay is also reset to the basic value of 80%, prior to the auto-reclose closing pulse being applied to the breaker. This should also occur when the auto-reclose facility is out of service. Reversion to the Z1X reach setting occurs only at the end of the reclaim time. For interconnected lines, the Z1X scheme is established (automatically or manually) upon loss of the communications channel by selection of the appropriate relay setting (setting group in a numerical relay). If the fault is transient, the tripped circuit breakers will reclose successfully, but otherwise further tripping during the reclaim time is subject to the discrimination obtained with normal Zone 1 and Zone 2 settings. Z1extA B A Z1extB 12.2 ZONE 1 EXTENSION SCHEME (Z1X SCHEME) C Z1B Z2B Z3B (a) Distance/time characteristics The disadvantage of the Zone 1 extension scheme is that external faults within the Z1X reach of the relay result in tripping of circuit breakers external to the faulted section, increasing the amount of breaker maintenance needed and needless transient loss of supply to some consumers. This is illustrated in Figure 12.3(a) for a single circuit line where three circuit breakers operate and in Figure 12.3(b) for a double circuit line, where five circuit breakers operate. Auto-reclose Reset Zone 1ext Zone 1ext Zone 1 & 1 Trip (b) Simplified logic Figure 12.2: Zone 1 extension scheme 12-2 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 12 ˜ Distance Protection Schemes t1 Figure 12.4: Logic for direct underreach transfer tripping scheme A fault F in the end zone at end B in Figure 12.1(a) results in operation of the Zone 1 relay and tripping of the circuit breaker at end B. A request to trip is also sent to the relay at end A. The receipt of a signal at A initiates tripping immediately because the receive relay contact is connected directly to the trip relay. The disadvantage of this scheme is the possibility of undesired tripping by accidental operation or maloperation of signalling equipment, or interference on the communications channel. As a result, it is not commonly used. 12.3.2 Permissive Under-reach Transfer Tripping (PUP) Scheme Figure 12.3: Performance of Zone 1 extension scheme in conjunction with auto-reclose relays 12.3 TRANSFER TRIPPING SCHEMES The direct under-reach transfer tripping scheme described above is made more secure by supervising the received signal with the operation of the Zone 2 relay element before allowing an instantaneous trip, as shown in Figure 12.5. The scheme is then known as a 'permissive under-reach transfer tripping scheme' (sometimes abbreviated as a PUTT, PUR or PUP Z2 scheme) or ‘permissive underreach distance protection’, as both relays must detect a fault before the remote end relay is permitted to trip in Zone 1 time. A number of these schemes are available, as described below. Selection of an appropriate scheme depends on the requirements of the system being protected. 12.3.1 Direct Under-reach Transfer Tripping Scheme The simplest way of reducing the fault clearance time at the terminal that clears an end zone fault in Zone 2 time is to adopt a direct transfer trip or intertrip technique, the logic of which is shown in Figure 12.4. A contact operated by the Zone 1 relay element is arranged to send a signal to the remote relay requesting a trip. The scheme may be called a 'direct under-reach transfer tripping scheme’, ‘transfer trip under-reaching scheme', or ‘intertripping underreach distance protection scheme’, as the Zone 1 relay elements do not cover the whole of the line. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 12-3 Network Protection & Automation Guide t1 Figure 12.6: PUP scheme: Single-end fed close-up fault on double circuit line Figure 12.5: Permissive under-reach transfer tripping scheme A variant of this scheme, found on some relays, allows tripping by Zone 3 element operation as well as Zone 2, provided the fault is in the forward direction. This is sometimes called the PUP-Fwd scheme. Time delayed resetting of the 'signal received' element is required to ensure that the relays at both ends of a single-end fed faulted line of a parallel feeder circuit have time to trip when the fault is close to one end. Consider a fault F in a double circuit line, as shown in Figure 12.6. The fault is close to end A, so there is negligible infeed from end B when the fault at F occurs. The protection at B detects a Zone 2 fault only after the breaker at end A has tripped. It is possible for the Zone 1 element at A to reset, thus removing the permissive signal to B and causing the 'signal received' element at B to reset before the Zone 2 unit at end B operates. It is therefore necessary to delay the resetting of the 'signal received' element to ensure high speed tripping at end B. The PUP schemes require only a single communications channel for two-way signalling between the line ends, as the channel is keyed by the under-reaching Zone 1 elements. When the circuit breaker at one end is open, or there is a weak infeed such that the relevant relay element does not operate, instantaneous clearance cannot be achieved for end-zone faults near the 'breaker open' terminal unless special features are included, as detailed in Section 12.3.5. 12.3.3 Permissive Under-reaching Acceleration Scheme This scheme is applicable only to zone switched distance relays that share the same measuring elements for both Zone 1 and Zone 2. In these relays, the reach of the measuring elements is extended from Zone 1 to Zone 2 by means of a range change signal immediately, instead of after Zone 2 time. It is also called an ‘accelerated underreach distance protection scheme’. The under-reaching Zone 1 unit is arranged to send a signal to the remote end of the feeder in addition to tripping the local circuit breaker. The receive relay contact is arranged to extend the reach of the measuring element from Zone 1 to Zone 2. This accelerates the fault clearance at the remote end for faults that lie in the region between the Zone 1 and Zone 2 reaches. The scheme is shown in Figure 12.7. Most quality modern distance relays do not employ switched measuring elements, so the scheme is likely to fall into disuse. 12-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 12 ˜ Distance Protection Schemes t1 t1 Figure 12.8: Permissive over-reach transfer tripping scheme Figure 12.7: Permissive under-reaching acceleration scheme 12.3.4 Permissive Over-reach Transfer Tripping (POP) Scheme In this scheme, a distance relay element set to reach beyond the remote end of the protected line is used to send an intertripping signal to the remote end. However, it is essential that the receive relay contact is monitored by a directional relay contact to ensure that tripping does not take place unless the fault is within the protected section; see Figure 12.8. The instantaneous contacts of the Zone 2 unit are arranged to send the signal, and the received signal, supervised by Zone 2 operation, is used to energise the trip circuit. The scheme is then known as a 'permissive over-reach transfer tripping scheme' (sometimes abbreviated to POTT, POR or POP), 'directional comparison scheme', or ‘permissive overreach distance protection scheme’. Since the signalling channel is keyed by over-reaching Zone 2 elements, the scheme requires duplex communication channels - one frequency for each direction of signalling. If distance relays with mho characteristics are used, the scheme may be more advantageous than the permissive under-reaching scheme for protecting short lines, because the resistive coverage of the Zone 2 unit may be greater than that of Zone 1. To prevent operation under current reversal conditions in a parallel feeder circuit, it is necessary to use a current reversal guard timer to inhibit the tripping of the forward Zone 2 elements. Otherwise maloperation of the scheme may occur under current reversal conditions, see Section 12.3.2 for more details. It is necessary only when the Zone 2 reach is set greater than 150% of the protected line impedance. The timer is used to block the permissive trip and signal send circuits as shown in Figure 12.9. The timer is energised if a signal is received and there is no operation of Zone 2 elements. An adjustable time delay on pick-up (tp) is usually set to allow instantaneous tripping to take place for any internal faults, taking into account a possible slower operation of Zone 2. The timer will have operated and blocked the ‘permissive trip’ and ‘signal send’ circuits by the time the current reversal takes place. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 12-5 Network Protection & Automation Guide t1 t1 Figure 12.10: Weak Infeed Echo logic circuit Figure 12.9: Current reversal guard logic – permissive over-reach scheme Signal transmission can take place even after the remote end breaker has tripped. This gives rise to the possibility of continuous signal transmission due to lock-up of both signals. Timer T2 is used to prevent this. After this time delay, 'signal send' is blocked. The timer is de-energised if the Zone 2 elements operate or the 'signal received' element resets. The reset time delay (td) of the timer is set to cover any overlap in time caused by Zone 2 elements operating and the signal resetting at the remote end, when the current in the healthy feeder reverses. Using a timer in this manner means that no extra time delay is added in the permissive trip circuit for an internal fault. A variation on the Weak Infeed Echo feature is to allow tripping of the remote relay under the circumstances described above, providing that an undervoltage condition exists, due to the fault. This is known as the Weak Infeed Trip feature and ensures that both ends are tripped if the conditions are satisfied. The above scheme using Zone 2 relay elements is often referred to as a POP Z2 scheme. An alternative exists that uses Zone 1 elements instead of Zone 2, and this is referred to as the POP Z1 scheme. However POP Z1 is unusual as it requires Zone 1 to be set overreaching, which is not usual practice. 12.4 BLOCKING OVERREACHING SCHEMES 12.3.5 Weak Infeed Conditions In the standard permissive over-reach scheme, as with the permissive under-reach scheme, instantaneous clearance cannot be achieved for end-zone faults under weak infeed or breaker open conditions. To overcome this disadvantage, two possibilities exist. The Weak Infeed Echo feature available in some protection relays allows the remote relay to echo the trip signal back to the sending relay even if the appropriate remote relay element has not operated. This caters for conditions of the remote end having a weak infeed or circuit breaker open condition, so that the relevant remote relay element does not operate. Fast clearance for these faults is now obtained at both ends of the line. The logic is shown in Figure 12.10. A time delay (T1) is required in the echo circuit to prevent tripping of the remote end breaker when the local breaker is tripped by the busbar protection or breaker fail protection associated with other feeders connected to the busbar. The time delay ensures that the remote end Zone 2 element will reset by the time the echoed signal is received at that end. 12-6 The arrangements described so far have used the signalling channel(s) to transmit a tripping instruction. If the signalling channel fails or there is no Weak Infeed feature provided, endzone faults may take longer to be cleared. Blocking over-reaching schemes use an over-reaching distance scheme and inverse logic. Signalling is initiated only for external faults and signalling transmission takes place over healthy line sections. Fast fault clearance occurs when no signal is received and the over-reaching Zone 2 distance measuring elements looking into the line operate. The signalling channel is keyed by reverse-looking distance elements (Z3 in the diagram, though which zone is used depends on the particular relay, with a dedicated reverse zone such as Zone 4 now commonly-used in numerical relays). An ideal blocking scheme is shown in Figure 12.11. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 12 ˜ Distance Protection Schemes known as a ‘directional comparison blocking scheme’ or a ‘blocking over-reach distance protection scheme’. t1 t1 Figure 12.12: Signal logic for BOP Z2 scheme Operation of the scheme can be understood by considering the faults shown at F1, F2 and F3 in Figure 12.11 along with the signal logic of Figure 12.12. A fault at F1 is seen by the Zone 1 relay elements at both ends A and B; as a result, the fault is cleared instantaneously at both ends of the protected line. Signalling is controlled by the Z3 elements looking away from the protected section, so no transmission takes place, thus giving fast tripping via the forward-looking Zone 1 elements. Figure 12.11: Ideal distance protection blocking scheme The single frequency signalling channel operates both local and remote receive relays when a block signal is initiated at any end of the protected section. 12.4.1 Practical Blocking Schemes A blocking instruction has to be sent by the reverse-looking relay elements to prevent instantaneous tripping of the remote relay for Zone 2 faults external to the protected section. To achieve this, the reverse-looking elements and the signalling channel must operate faster than the forward-looking elements. In practice, this is seldom the case and to ensure discrimination, a short time delay is generally introduced into the blocking mode trip circuit. Either the Zone 2 or Zone 1 element can be used as the forward-looking element, giving rise to two variants of the scheme. 12.4.1.1 Blocking over-reaching protection scheme using Zone 2 element This scheme (sometimes abbreviated to ‘BLOCKING’ or BOP Z2) is based on the ideal blocking scheme of Figure 12.11, but has the signal logic illustrated in Figure 12.12. It is also A fault at F2 is seen by the forward-looking Zone 2 elements at ends A and B and by the Zone 1 elements at end B. No signal transmission takes place, since the fault is internal and the fault is cleared in Zone 1 time at end B and after the short time lag (STL) at end A. A fault at F3 is seen by the reverse-looking Z3 elements at end B and the forward looking Zone 2 elements at end A. The Zone 1 relay elements at end B associated with line section BC would normally clear the fault at F3. To prevent the Z2 elements at end A from tripping, the reverse-looking Zone 3 elements at end B send a blocking signal to end A. If the fault is not cleared instantaneously by the protection on line section B-C, the trip signal will be given at end B for section A-B after the Z3 time delay. The setting of the reverse-looking Zone 3 elements must be greater than that of the Zone 2 elements at the remote end of the feeder, otherwise there is the possibility of Zone 2 elements initiating tripping and the reverse looking Zone 3 elements failing to see an external fault. This would result in instantaneous tripping for an external fault. When the signalling channel is used for a stabilising signal, as in the above case, transmission takes place over a healthy line section if power line carrier is used. The signalling channel should then be more reliable when used in the blocking mode than in tripping mode. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 12-7 Network Protection & Automation Guide It is essential that the operating times of the various relays be skilfully co-ordinated for all system conditions, so that sufficient time is always allowed for the receipt of a blocking signal from the remote end of the feeder. If this is not done accurately, the scheme may trip for an external fault or alternatively, the end zone tripping times may be delayed longer than is necessary. 12.4.1.2 Blocking over-reaching protection scheme using Zone 1 element If the signalling channel fails, the scheme must be arranged to revert to conventional basic distance protection. Normally, the blocking mode trip circuit is supervised by a 'channel-inservice' contact so that the blocking mode trip circuit is isolated when the channel is out of service, as shown in Figure 12.12. 12.4.2 Weak Infeed Conditions In a practical application, the reverse-looking relay elements may be set with a forward offset characteristic to provide backup protection for busbar faults after the zone time delay. It is then necessary to stop the blocking signal being sent for internal faults. This is achieved by making the ‘signal send’ circuit conditional upon non-operation of the forward-looking Zone 2 elements, as shown in Figure 12.13. This is similar to the BOP Z2 scheme described above, except that an over-reaching Zone 1 element is used in the logic, instead of the Zone 2 element. It may also be known as the BOP Z1 scheme, although it is rarely used. The protection at the strong infeed terminal will operate for all internal faults, since a blocking signal is not received from the weak infeed terminal end. In the case of external faults behind the weak infeed terminal, the reverse-looking elements at that end will see the fault current fed from the strong infeed terminal and operate, initiating a block signal to the remote end. The relay at the strong infeed end operates correctly without the need for any additional circuits. The relay at the weak infeed end cannot operate for internal faults, and so tripping of that breaker is possible only by means of direct intertripping from the strong source end. 12.5 DIRECTIONAL COMPARISON UNBLOCKING SCHEME The permissive over-reach scheme described in Section 12.3.4 can be arranged to operate on a directional comparison unblocking principle by providing additional circuitry in the signalling equipment. In this scheme (also called a ’deblocking overreach distance protection scheme’), a continuous block (or guard) signal is transmitted. When the over-reaching distance elements operate, the frequency of the signal transmitted is shifted to an 'unblock' (trip) frequency. The receipt of the unblock frequency signal and the operation of over-reaching distance elements allow fast tripping to occur for faults within the protected zone. In principle, the scheme is similar to the permissive over-reach scheme. Figure 12.13: Blocking scheme using reverse-looking relays Blocking schemes, like the permissive over-reach scheme, are also affected by the current reversal in the healthy feeder due to a fault in a double circuit line. If current reversal conditions occur, as described in Section 12.3.2, it may be possible for the maloperation of a breaker on the healthy line to occur. To avoid this, the resetting of the ‘signal received’ element provided in the blocking scheme is time delayed. The timer with delayed resetting (td) is set to cover the time difference between the maximum resetting time of reverselooking Zone 3 elements and the signalling channel. So, if there is a momentary loss of the blocking signal during the current reversal, the timer does not have time to reset in the blocking mode trip circuit and no false tripping takes place. 12-8 The scheme is made more dependable than the standard permissive over-reach scheme by providing additional circuits in the receiver equipment. These allow tripping to take place for internal faults even if the transmitted unblock signal is short-circuited by the fault. This is achieved by allowing aided tripping for a short time interval, typically 100 to 150 milliseconds, after the loss of both the block and the unblock frequency signals. After this time interval, aided tripping is permitted only if the unblock frequency signal is received. This arrangement gives the scheme improved security over a blocking scheme, since tripping for external faults is possible only if the fault occurs within the above time interval of channel failure. Weak Infeed terminal conditions can be catered for by the techniques detailed in 12.3.5 Weak Infeed Conditions. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 12 ˜ Distance Protection Schemes In this way, the scheme has the dependability of a blocking scheme and the security of a permissive over-reach scheme. This scheme is generally preferred when power line carrier is used, except when continuous transmission of signal is not acceptable. 12.6 COMPARISON OF TRANSFER TRIP AND BLOCKING RELAYING SCHEMES On normal two-terminal lines the main deciding factors in the choice of the type of scheme, apart from the reliability of the signalling channel previously discussed, are operating speed and the method of operation of the system. Table 12.1 compares the important characteristics of the various types of scheme. Transfer Tripping Scheme Criterion Blocking Scheme Speed of operation Fast Not as fast Speed with in-service testing Slower As fast Suitable for auto-reclose Yes Yes Current reversal Special features required Special features required Loss of communications Poor Good Weak Infeed/Open CB Special features required Special features required Security against maloperation due to: Table 12.1: Comparison of different distance protection schemes Modern digital or numerical distance relays are provided with a choice of several schemes in the same relay. Thus scheme selection is now largely independent of relay selection, and the user is assured that a relay is available with all the required features to cope with changing system conditions. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 12-9 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 13 Protection of Complex Transmission Circuits 13.1 INTRODUCTION 13.1 Introduction 13.2 Parallel Feeders 13.3 Multi-Ended Feeders – Unit Protection Schemes 13.4 Multi-Ended Feeders - Distance Relays 13.5 Multi-Ended Feeders – Application of Distance Protection Schemes 13.6 Protection of Series Compensated Lines 13.7 Example 13.8 References Chapters 10-12 have covered the basic principles of protection for two terminal, single circuit lines whose circuit impedance is due solely to the conductors used. However parallel transmission circuits are often installed, either as duplicate circuits on a common structure, or as separate lines connecting the same two terminal points via different routes. Also, circuits may be multi-ended, a three-ended circuit being the most common. For economic reasons, transmission and distribution lines can be much more complicated, maybe having three or more terminals (multi-ended feeder), or with more than one circuit carried on a common structure (parallel feeders), as shown in Figure 13.1. Other possibilities are the use of series capacitors or direct-connected shunt reactors. The protection of such lines is more complicated and requires the basic schemes described in the above chapters to be modified. The purpose of this chapter is to explain the special requirements of some of these situations in respect of protection and identify which protection schemes are particularly appropriate for use in these situations. Figure 13.1: Parallel and Multi-ended feeders 13.2 PARALLEL FEEDERS If two overhead lines are supported on the same structures or are otherwise in close proximity over part or whole of their length, there is a mutual coupling between the two circuits. The positive and negative sequence coupling between the two circuits is small and is usually neglected. The zero sequence coupling can be strong and its effect cannot be ignored. The other situation that requires mutual effects to be taken into account is when there is an earth fault on a feeder when Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 13-1 Network Protection & Automation Guide the parallel feeder is out of service and earthed at both ends. An earth fault in the feeder that is in service can induce current in the earth loop of the earthed feeder, causing a misleading mutual compensation signal. 13.2.1 Unit Protection Systems Types of protection that use current only, for example unit protection systems, are not affected by the coupling between the feeders. Therefore, compensation for the effects of mutual coupling is not required for the relay tripping elements. If the relay has a distance-to-fault feature, mutual compensation is required for an accurate measurement. Refer to Section 13.2.2.3 for how this is achieved. 13.2.2 Distance Protection There are a number of problems applicable to distance relays, as described in the following sections. 13.2.2.1 Current Reversal on Double Circuit Lines When a fault is cleared sequentially on one circuit of a double circuit line with generation sources at both ends of the circuit, the current in the healthy line can reverse for a short time. Unwanted tripping of CBs on the healthy line can then occur if a Permissive Overreach or Blocking distance scheme (see Chapter 12) is used. Figure 13.2 shows how the situation can arise. The CB at D clears the fault at F faster than the CB at C. Before CB D opens, the Zone 2 elements at A may see the fault and operate, sending a permissive trip signal to the relay for CB B. The reverse looking element of the relay at CB B also sees the fault and inhibits tripping of CBs A and B. However, once CB D opens, the relay element at A starts to reset, while the forward looking elements at B pick up (due to current reversal) and could initiate tripping. If the reset time of the forward-looking elements of the relay at A is longer than the operating time of the forward-looking elements at B, the relays trip the healthy line. The solution is to incorporate a blocking time delay that prevents the tripping of the forwardlooking elements of the relays and is initiated by the reverselooking element. This time delay must be longer than the reset time of the relay elements at A. Figure 13.2: Fault current distribution in double-circuit line 13.2.2.2 Under-Reach on Parallel Lines If a fault occurs on a line that lies beyond the remote terminal end of a parallel line circuit, the distance relay under-reaches for those zones set to reach into the affected line. Analysis shows that under these conditions, because the relay sees only 50% (for two parallel circuits) of the total fault current for a fault in the adjacent line section, the relay sees the impedance of the affected section as twice the correct value. This may have to be allowed for in the settings of Zones 2 and 3 of conventionally set distance relays. Since the requirement for the minimum reach of Zone 2 is to the end of the protected line section and the under-reach effect only occurs for faults in the following line section(s), it is not usually necessary to adjust Zone 2 impedance settings to compensate. However, Zone 3 elements are intended to provide backup protection to adjacent line sections and hence the under-reaching effect must be allowed for in the impedance calculations. 13.2.2.3 Behaviour of Distance Relays with Earth Faults on the Protected Feeder When an earth fault occurs in the system, the voltage applied to the earth fault element of the relay in one circuit includes an induced voltage proportional to the zero sequence current in the other circuit. 13-2 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 13 ˜ Protection of Complex Transmission Circuits IB M Z L1 Z LO c Z Sc 1 ,Z SO cc Z Scc1 ,Z SO Z MO The true impedance to the fault is nZL1where n is the per unit fault position measured from R and ZL1 is the positive sequence impedance of a single circuit. The 'error' in measurement is determined from the fraction inside the bracket; this varies with the positive and zero sequence currents in circuit A and the zero sequence current in circuit B. These currents are expressed below in terms of the line and source parameters: IA Z L1 I B1 Z Scc1 Z Sc 1 I A1 1  n Z L1 nZ L1 I B0 I A0 nZ S'' 0  1  n Z S' 0 2  n Z S'' 0  1  n Z S' 0  Z L 0  Z M 0 I A1 2  n Z S'' 1  1  n Z S' 1  Z L1 I1 2 Z S' 1  Z S'' 1  Z L1 I A0 2  n Z S'' 0  1  n Z S' 0  Z L 0  Z M 0 I0 2 Z S' 0  Z S'' 0  Z L 0  Z M 0 I1 I BO c Z SO Z LO  Z M O 1  n Z MO nZ M O cc Z SO I AO n ZLO  Z M O 1  n Z LO  Z M O IO Figure 13.3: General parallel circuit fed from both ends As the current distribution in the two circuits is unaffected by the presence of mutual coupling, no similar variation in the current applied to the relay element takes place and, consequently, the relay measures the impedance to the fault incorrectly. Whether the apparent impedance to the fault is greater or less than the actual impedance depends on the direction of the current flow in the healthy circuit. For the common case of two circuits, A and B, connected at the local and remote busbars, as shown in Figure 13.3, the impedance of Line A measured by a distance relay, with the normal zero sequence current compensation from its own feeder, is given by: ZA ­ ° ° nZ L1 ®1  ° ° ¯ ZM 0 Z L1 and ZM0 = zero sequence mutual impedance between two circuits NOTE: For earth faults I1 = I0 All symbols in the above expressions are either self-explanatory from Figure 13.3 or have been introduced in Chapter 11. Using the above formulae, families of reach curves may be constructed, of which Figure 13.4 is typical. In this figure, n’ is the effective per unit reach of a relay set to protect 80% of the line. It has been assumed that an infinite busbar is located at each line end, that is, Z’S1 and Z”S1 are both zero. A family of curves of constant n’ has been plotted for variations in the source zero sequence impedances Z’S0 and Z”S0. ½ § I B0 · ¨¨ ¸¸ M ° ° © I A0 ¹ ¾ § I A1 · ¸ ¨ 2¨ K° ¸ ° © I A0 ¹ ¿ Equation 13.1 where: © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 13-3 Network Protection & Automation Guide VR IR 100 0 n' = 75 .6 n 68 0. '= 75 0. 10 n' = n' on e .8 85 0. = n' =0 . (Z when y x 1 5 x IA I A1  I A 2  I A0 The voltage and current fed into the relay are given by: Limit of n'=1 0.5 I A1Z L1  I A 2 Z L 2  I A0 Z L 0  I B 0 Z M 0 95 0. 0.5 0.1 0.1 VA Equation 13.2 n' = 1 =0 n' No m in al se tti ng y 1) 5 cc º ª Z SO « » ¬ Z LO ¼ For a solid phase to earth fault at the theoretical reach of the relay, the voltage and current in the faulty phase at the relaying point are given by: 7 0. n' = Z L1 9 50 Limit of n' =0.67 when y f x 0 10 50 0 f 100 ª Z SO º « » ¬ Z LO ¼ Figure 13.4: Typical reach curves showing the effect of mutual coupling Figure 13.4 shows that relay R can under-reach or over-reach, according to the relative values of the zero sequence source to line impedance ratios; the extreme effective per unit reaches for the relay are 0.67 and 1. Relay over-reach is not a problem, as the condition being examined is a fault in the protected feeder, for which relay operation is desirable. In Figure 13.4, relay R tends to under-reach whereas the relay at the opposite line end tends to over-reach. As a result, the Zone 1 characteristic of the relays at both ends of the feeder overlap for an earth fault anywhere in the feeder – see Section 13.2.2.5 for more details. Satisfactory protection can be obtained with a transfer trip, under-reach type distance scheme. Further, compensation for the effect of zero sequence mutual impedance is not necessary unless a distance-to-fault facility is provided. Some manufacturers compensate for the effect of the mutual impedance in the distance relay elements, while others may restrict the application of compensation to the distance-tofault function only. The latter is easy to implement in software for a digital/numerical relay but is impractical in relays using older technologies. Compensation is achieved by injecting a proportion of the zero sequence current flowing in the parallel feeder into the relay. However, some Utilities do not permit this due to the potential hazards associated with feeding a relay protecting one circuit from a CT located in a different circuit. For the relay to measure the line impedance accurately, the following condition must be met: VR VA IR I A  K R I A0  K M I B 0 Equation 13.3 where: K R = the residual compensation factor K M = the mutual compensation factor Thus: KR Z L 0  Z L1 Z L1 KM ZM 0 Z L1 13.2.2.4 Distance Relay Behaviour with Earth Faults on the Parallel Feeder Although distance relays with mutual compensation measure the correct distance to the fault, they may not operate correctly if the fault occurs in the adjacent feeder. Davison and Wright [13.1] have shown that while distance relays without mutual compensation do not over-reach for faults outside the protected feeder, the relays may see faults in the adjacent feeder if mutual compensation is provided. With reference to Figure 13.3, the amount of over-reach is highest when Z S'' 1 Z S'' 2 Z S'' 0 f. Under these conditions, faults occurring in the first 43% of feeder A appear to the distance relay in feeder B to be in its Zone 1 reach. The solution is to limit the mutual compensation applied to 150% of the zero sequence compensation. 13.2.2.5 Distance Relay Behaviour with Single-Circuit Operation If only one of the parallel feeders is in service, the protection in the remaining feeder measures the fault impedance correctly, 13-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 13 ˜ Protection of Complex Transmission Circuits except when the feeder that is not in service is earthed at both ends. In this case, the zero sequence impedance network is as shown in Figure 13.5. Humpage and Kandil [13.2] have shown that the apparent impedance presented to the relay under these conditions is given by: Z L1  ZR I A0 Z M2 0 I R Z L0 of earth fault relays to around 0.65ZL1 when lines are taken out of service for maintenance. However, the probability of having a fault on the first section of the following line while one line is out of service is very small, and many Utilities do not reduce the setting under this condition. It should be noted that the use of mutual compensation would not overcome the over-reaching effect since earthing clamps are normally placed on the line side of the current transformers. Typical values of zero sequence line impedances for HV lines in the United Kingdom are given in Table 13.1, where the Equation 13.4 2 §Z · maximum per unit over-reach error ¨¨ M 0 ¸¸ is also given. © Z L0 ¹ where: I R is the current fed into the relay I A  K R I A0 FO IO c Z SO cc Z SO 1  n Z LO nZ LO The over-reach values quoted in this table are maxima, and are found only in rare cases. In most cases, there is generation at both ends of the feeder and the amount of over-reach is therefore be reduced. In the calculations carried out by Humpage and Kandil, with more realistic conditions, the maximum error found in a 400kV double circuit line was 18.6%. I GO mZ LO Relay Location I HO 1  n Z MO Figure 13.5: Zero sequence impedance network during single circuit operation I A0 varies with the system conditions, reaching a IR maximum when the system is earthed behind the relay with no generation at that end. In this case, the ratio to I A0 is equal IR Z L1 , and the apparent impedance presented to the relay Z L0 is: ZR Line volts (in2) Z LO NO The ratio Conductor size § Z M2 0 · Z L1 ¨¨1  2 ¸¸ Z L0 ¹ © It is apparent from the above formulae that the relay has a tendency to over-reach. Care should be taken when Zone 1 settings are selected for the distance protection of lines in which this condition may be encountered. To overcome this possible over-reaching effect, some Utilities reduce the reach Zero sequence mutual impedance ZM0 Metric Ohms equiv. /mile 2 (mm ) Ohms /km Zero sequence line impedance ZL0 Ohms /mile Ohms /km Per unit over-reach error (ZM0/ZL0)2 132kV 0.4 258 0.3 + j0.81 0.19+ j0.5 0.41+j 1.61 0.25+ j1.0 0.264 275kV 2 x 0.4 516 0.18+ j0.69 0.11+ j0.43 0.24+ j1.3 0.15+ j0.81 0.292 400kV 4 x 0.4 1032 0.135+ j0.6 0.80+ j0.37 0.16+ j1.18 0.1+ j0.73 0.2666 Table 13.1: Maximum over-reach errors found during single circuit working 13.3 MULTI-ENDED FEEDERS – UNIT PROTECTION SCHEMES A multi-ended feeder is defined as one having three or more terminals, with either load or generation, or both, at any terminal. Those terminals with load only are usually known as ’taps’. The simplest multi-terminal feeders are three-ended, and are generally known as tee’d feeders. This is the type most commonly found in practice. The protection schemes described previously for the protection of two-ended feeders can also be used for multi-ended feeders. However, the problems involved in the application of these schemes to multi-ended feeders are much more complex and require special attention. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 13-5 Network Protection & Automation Guide The protection schemes that can be used with multi-ended feeders are unit protection and distance schemes. Each uses some form of signalling channel, such as fibre-optic cable, power line carrier or pilot wires. The specific problems that may be met when applying these protections to multi-ended feeders are discussed in the following sections. 13.3.1 Balanced Voltage Schemes for Tee’d Circuits Although pilot wire schemes are uncommon in the protection of transmission circuits (as per the strict title of this chapter), they are discussed here for completeness. The balanced voltage scheme is a modification of the MHOA04 / H0A4 scheme described in Section 10.7.1. Since it is necessary to maintain linearity in the balancing circuit, though not in the sending element, the voltage reference is derived from separate quadrature transformers, as shown in Figure 13.6. These are auxiliary units with summation windings energised by the main current transformers in series with the upper electromagnets of the sensing elements. The secondary windings of the quadrature current transformers at all ends are interconnected by the pilots in a series circuit that also includes the lower electromagnets of the relays. Secondary windings on the relay elements are not used, but these elements are fitted with bias loops in the usual way. feeder. When the phase angle difference exceeds a pre-set value, the ‘trip angle’, a trip signal is sent to the corresponding circuit breakers. To prevent incorrect operation for external faults, two different detectors, set at different levels, are used. The low-set detector starts the transmission of carrier signal, while the high-set detector is used to control the trip output. Without this safeguard, the scheme could operate incorrectly for external faults because of operating tolerances of the equipment and the capacitive current of the protected feeder. This condition is worse with multi-terminal feeders, since the currents at the feeder terminals can be very dissimilar for an external fault. In the case of the three-terminal feeder in Figure 13.7, if incorrect operation is to be avoided, it is necessary to make certain that the low-set detector at end A or end B is energised when the current at end C is high enough to operate the high-set detector at that end. As only one low-set starter, at end A or end B, needs to be energised for correct operation, the most unfavourable condition is when currents IA and IB are equal. To maintain stability under this condition, the high-set to low-set setting ratio of the fault detectors needs to be twice as large as that required when the scheme is applied to a plain feeder. This results in a loss of sensitivity, which may make the equipment unsuitable if the minimum fault level of the power system is low. The plain feeder settings are increased in the tee'd scheme by 50% for one tee and 75% for two. Figure 13.7: External fault conditions Figure 13.6: Balanced voltage Tee’d feeder scheme 13.3.2 Power Line Carrier Phase Comparison Schemes Figure 13.8: Internal fault with current flowing out at one line end The operating principle of these protection schemes has already been covered in detail in Section 10.9. It involves comparing the phase angles of signals derived from a combination of the sequence currents at each end of the A further unfavourable condition is that shown in Figure 13.8. If an internal fault occurs near one of the ends of the feeder (end B in Figure 13.8) and there is little or no generation at end C, the current at this end may be flowing outwards. The protection is then prevented from operating, since the fault 13-6 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 13 ˜ Protection of Complex Transmission Circuits current distribution is similar to that for an external fault; see Figure 13.7. The fault can be cleared only by the back-up protection and, if high speed of operation is required, an alternative type of primary protection must be used. A point that should also be considered when applying this scheme is the attenuation of carrier signal at the 'tee' junctions. This attenuation is a function of the relative impedances of the branches of the feeder at the carrier frequency, including the impedance of the receiving equipment. When the impedances of the second and third terminals are equal, a power loss of 50% takes place. In other words, the carrier signal sent from terminal A to terminal B is attenuated by 3dB by the existence of the third terminal C. If the impedances of the two branches corresponding to terminal B to C are not equal, the attenuation may be either greater or less than 3dB. 13.3.3 Differential Relay using Optical Fibre Signalling Current differential relays can provide unit protection for multiended circuits without the restrictions associated with other forms of protection. In Section 8.6.5, the characteristics of optical fibre cables and their use in protection signalling are outlined. Their use in a three-ended system is shown in Figure 13.9, where the relays at each line end are digital/numerical relays interconnected by optical fibre links so that each can send information to the others. In practice the optical fibre links can be dedicated to the protection system or multiplexed, in which case multiplexing equipment, not shown in Figure 13.9,is used to terminate the fibres. Trip DifferentiaI Current | Idiff | I di f f K I bi as Restrain IS Bias current | Ibias | Figure 13.10: Percentage biased differential protection characteristic If IA , IB , IC are the current vector signals at line ends A, B, C, then for a healthy circuit: I A  I B  IC 0 The basic principles of operation of the system are that each relay measures its local three phase currents and sends its values to the other relays. Each relay then calculates, for each phase, a resultant differential current and also a bias current, which is used to restrain the relay in the manner conventional for biased differential unit protection. The bias feature is necessary in this scheme because it is designed to operate from conventional current transformers that are subject to steady-state and transient transformation errors. The two quantities are: I diff I A  I B  IC I bias 1 I A  I B  IC 2 Figure 13.10 shows the percentage biased differential characteristic used, the tripping criteria being: I diff ! K I bias and I diff ! I S where: Figure 13.9: Current differential protection for tee’d feeders using optical fibre signalling K percentage bias setting IS minimum differential current setting If the magnitudes of the differential currents indicate that a fault has occurred, the relays trip their local circuit breaker. The relays also continuously monitor the communication channel performance and carry out self-testing and diagnostic © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 13-7 Network Protection & Automation Guide operations. The system measures individual phase currents and so single phase tripping can be used when required. Relays are provided with software to re-configure the protection between two and three terminal lines, so that modification of the system from two terminals to three terminals does not require relay replacement. Further, loss of a single communications link only degrades scheme performance slightly. The relays can recognise this and use alternate communications paths. Only if all communication paths from a relay fail does the scheme have to revert to backup protection. 13.4 MULTI-ENDED FEEDERS - DISTANCE RELAYS Distance protection is widely used at present for tee'd feeder protection. However, its application is not straightforward, requiring careful consideration and systematic checking of all the conditions described later in this section. Most of the problems found when applying distance protection to tee’d feeders are common to all schemes. A preliminary discussion of these problems will assist in the assessment of the performance of the different types of distance schemes. the currents IA and IC are in phase and their ratio is a real number. The apparent impedance presented to the relay in this case can be expressed in terms of the source impedances as follows: ZA Z LA  Z LB  Z SA  Z LA Z LB Z SC  Z LC The magnitude of the third term in this expression is a function of the total impedances of the branches A and B and can reach a relatively high value when the fault current contribution of branch C is much larger than that of branch A. Figure 13.12 shows how a distance relay with a mho characteristic located at A with a Zone 2 element set to 120% of the protected feeder AB, fails to see a fault at the remote busbar B. The ’tee’ point T in this example is halfway between substations A and B Z LA Z LB and the fault currents IA and IC have been assumed to be identical in magnitude and phase angle. With these conditions, the fault appears to the relay to be located at B' instead of at B so the relay underreaches. 13.4.1 Apparent Impedance Seen by Distance Relays The impedance seen by the distance relays is affected by the current infeeds in the branches of the feeders. Referring to Figure 13.11, for a fault at the busbars of the substation B, the voltage VA at busbar A is given by: VA I A Z LA  I B Z LB so the impedance ZA seen by the distance relay at terminal A is given by: Figure 13.11: Fault at substation B busbars X IB Z LB IA ZA VA IA Z LA  ZA Z LA  IB Z LB IA B' Or B Equation 13.5 T or ZA Z LA  Z LB  IC Z LB IA The apparent impedance presented to the relay has been § IC · ¸¸ Z LB . If the pre-fault load is zero, © IA ¹ modified by the term ¨¨ 13-8 A R Figure 13.12: Apparent impedance presented to the relay at substation A for a fault at substation B busbars The under-reaching effect in tee’d feeders can be found for any © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 13 ˜ Protection of Complex Transmission Circuits kind of fault. For the sake of simplicity, the equations and examples mentioned so far have been for balanced faults only. For unbalanced faults, especially those involving earth, the equations become somewhat more complicated, as the ratios of the sequence fault current contributions at terminals A and C may not be the same. An extreme example of this condition is found when the third terminal is a tap with no generation but with the star point of the primary winding of the transformer connected directly to earth, as shown in Figure 13.13. The corresponding sequence networks are shown in Figure 13.14. the reduction in zero sequence current. However, the solution has two possible limitations: x over-reach occurs when the transformer is not connected so operation for faults outside the protected zone may occur x the inherent possibility of maloperation of the earth fault elements for earth faults behind the relay location is increased 13.4.2 Effect of Pre-fault Load In all the previous discussions it has been assumed that the power transfer between terminals of the feeder immediately before the fault occurred was zero. If this is not the case, the fault currents IA and IC in Figure 13.11 may not be in phase, and the factor IC / IA in the equation for the impedance seen by the relay at A, is a complex quantity with a positive or a negative phase angle according to whether the current IC leads or lags the current IA. For the fault condition previously considered in Figure 13.11 and Figure 13.12, the pre-fault load current may displace the impedance seen by the distance relay to points such as B1 or B2 , shown in Figure 13.15, according to the phase angle and the magnitude of the prefault load current. Humpage and Lewis [13.3] have analysed the effect of pre-fault load on the impedances seen by distance relays for typical cases. Their results and conclusions point out some of the limitations of certain relay characteristics and schemes. ' Figure 13.13: Transformer tap with primary winding solidly earthed Z SA1 Z LA1 T1 I A1 A1 Z LB1 Z LJ1 EA Z SH1 B1 EB Z T1 ' Z M1 Z SA 2 Z LA 2 G1 Z SB2 Z LB2 T2 I A2 Z LC2 B2 ZT2 ZM2 Z SA O TO Z LA O AO I AO Z LBO Z LCO Z SBO BO I CO Z TO Figure 13.14: Sequence networks for a phase A to earth fault at busbar B in the system shown in Figure 13.13 Figure 13.14 shows that the presence of the tap has little effect in the positive and negative sequence networks. However, the zero sequence impedance of the branch actually shunts the zero sequence current in branch A. As a result, the distance relay located at terminal A tends to under-reach. One solution to the problem is to increase the residual current compensating factor in the distance relay, to compensate for Figure 13.15: effects of the pre-fault load on the apparent impedance presented to the relay 13.4.3 Effect of the Fault Current Flowing Outwards at One Terminal Up to this point it has been assumed that the fault currents at terminals A and C flow into the feeder for a fault at the busbar © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 13-9 Network Protection & Automation Guide B. Under some conditions, however, the current at one of these terminals may flow outwards instead of inwards. A typical case is shown in Figure 13.16; that of a parallel tapped feeder with one of the ends of the parallel circuit open at terminal A. A IA ZA B IB T ZB I'B IC I'C Fault 13.4.4 Maloperation with Reverse Faults Earth fault distance relays with a directional characteristic tend to lose their directional properties under reverse unbalanced fault conditions if the current flowing through the relay is high and the relay setting relatively large. These conditions arise principally from earth faults. The relay setting and the reverse fault current are now related, the first being a function of the maximum line length and the second depending mainly on the impedance of the shortest feeder and the fault level at that terminal. For instance, referring to Figure 13.18, the setting of the relay at terminal A depends on the impedance ZA+ZB and the fault current infeed IC, for a fault at B, while the fault current IA for a reverse fault may be quite large if the T point is near the terminals A and C. C Figure 13.16: Internal Fault at busbar B with current flowing out at terminal C A IA T IB B Fault Figure 13.18: External fault behind the relay at terminal A I'B A summary of the main problems met in the application of distance protection to tee'd feeders is given in Table 13.2 . Case IC I'C C Figure 13.17: Internal fault near busbar B with current flowing out at terminal C As the currents IA and IC now have different signs, the factor IC / IA becomes negative. Consequently, the distance relay at terminal A sees an impedance smaller than that of the protected feeder ZA+ZB and therefore has a tendency to overreach. In some cases the apparent impedance presented to the relay may be as low as 50% of the impedance of the protected feeder, and even lower if other lines exist between terminals B and C. If the fault is internal to the feeder and close to the busbar B, as shown in Figure 13.17, the current at terminal C may still flow outwards. As a result, the fault appears as an external fault to the distance relay at terminal C, which fails to operate. 13-10 Description Relevant figure number 1 Under-reaching effect for internal faults due to current infeed at the T point 2 Effect of pre-fault load on the impedance 'seen' 13.16 by the relay 3 Over-reaching effect for external faults, due to current flowing outwards at one terminal 13.17 4 Failure to operate for an internal fault, due to current flowing out at one terminal 13.18 5 Incorrect operation for an external fault, due to high current fed from nearest terminal 13.19 13.12 to 13.15 Table 13.2: Main problems met in the application of distance protection to tee'd feeders. 13.5 MULTI-ENDED FEEDERS – APPLICATION OF DISTANCE PROTECTION SCHEMES The schemes that have been described in Chapter 12 for the protection of plain feeders may also be used for tee'd feeder protection. However, the applications of some of these schemes are much more limited in this case. Distance schemes can be subdivided into two main groups; transfer trip schemes and blocking schemes. The usual © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 13 ˜ Protection of Complex Transmission Circuits considerations when comparing these schemes are security, that is, no operation for external faults, and dependability, that is, assured operation for internal faults. In addition, it should be borne in mind that transfer trip schemes require fault current infeed at all the terminals to achieve high-speed protection for any fault in the feeder. This is not the case with blocking schemes. While it is rare to find a plain feeder in high voltage systems where there is current infeed at one end only, it is not difficult to envisage a tee’d feeder with no current infeed at one end, for example when the tee’d feeder is operating as a plain feeder with the circuit breaker at one of the terminals open. Nevertheless, transfer trip schemes are also used for tee’d feeder protection, as they offer some advantages under certain conditions. 13.5.1 Transfer Trip Under-Reach Schemes The main requirement for transfer trip under-reach schemes is that the Zone 1 of the protection, at one end at least, shall see a fault in the feeder. To meet this requirement, the Zone 1 characteristics of the relays at different ends must overlap, either the three of them or in pairs. Cases 1, 2 and 3 in Table 13.2. should be checked when the settings for the Zone 1 characteristics are selected. If the conditions mentioned in case 4 are found, direct transfer tripping may be used to clear the fault; the alternative is to trip sequentially at end C when the fault current IC reverses after the circuit breaker at terminal B has opened; see Figure 13.17. Transfer trip schemes may be applied to feeders that have branches of similar length. If one or two of the branches are very short, and this is often the case in tee'd feeders, it may be difficult or impossible to make the Zone 1 characteristics overlap. Alternative schemes are then required. Another case for which under-reach schemes may be advantageous is the protection of tapped feeders, mainly when the tap is short and is not near one of the main terminals. Overlap of the Zone 1 characteristics is then easily achieved, and the tap does not require protection applied to the terminal. 13.5.2 Transfer Trip Over-Reach Schemes For correct operation when internal faults occur, the relays at the three ends should see a fault at any point in the feeder. This condition is often difficult to meet, since the impedance seen by the relays for faults at one of the remote ends of the feeder may be too large, as in case 1 in Table 13.2, increasing the possibility of maloperation for reverse faults, case 5 in Table 13.2. In addition, the relay characteristic might encroach on the load impedance. requirements mentioned later on, make transfer trip overreach schemes unattractive for multi-ended feeder protection. 13.5.3 Blocking Schemes Blocking schemes are particularly suited to the protection of multi-ended feeders, since high-speed operation can be obtained with no fault current infeed at one or more terminals. The only disadvantage is when there is fault current outfeed from a terminal, as shown in Figure 13.17. This is case 4 in Table 13.2. The protection units at that terminal may see the fault as an external fault and send a blocking signal to the remote terminals. Depending on the scheme logic either relay operation is blocked or clearance is in Zone 2 time. The directional unit should be set so that no maloperation can occur for faults in the reverse direction; case 5 in Table 13.2. 13.5.4 Signalling Channel Considerations The minimum number of signalling channels required depends on the type of scheme used. With under-reach and blocking schemes, only one channel is required, whereas a permissive over-reach scheme requires as many channels as there are feeder ends. The signalling channel equipment at each terminal should include one transmitter and (N-1) receivers, where N is the total number of feeder ends. This may not be a problem if fibre-optic cables are used, but could lead to problems otherwise. If frequency shift channels are used to improve the reliability of the protection schemes, mainly with transfer trip schemes, N additional frequencies are required for the purpose. Problems of signal attenuation and impedance matching should also be carefully considered when power line carrier frequency channels are used. 13.5.5 Directional Comparison Blocking Schemes The principle of operation of these schemes is the same as that of the distance blocking schemes described in the previous section. The main advantage of directional comparison schemes over distance schemes is their greater capability to detect high-resistance earth faults. The reliability of these schemes, in terms of stability for through faults, is lower than that of distance blocking schemes. However, with the increasing reliability of modern signalling channels, directional comparison blocking schemes offer good solutions to the many difficult problems encountered in the protection of multi-ended feeders. For further information see Chapter 12 and specific relay manuals. These considerations, in addition to the signalling channel © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 13-11 Network Protection & Automation Guide 13.6 PROTECTION OF SERIES COMPENSATED LINES The basic power transfer equation in Figure 13.19 shows that transmitted power is proportional to the system voltage level and load angle while being inversely proportional to system impedance. Series compensated lines are used in transmission networks where the required level of transmitted power can not be met, either from a load requirement or system stability requirement. Series compensated transmission lines introduce a series connected capacitor, which has the net result of reducing the overall inductive impedance of the line, hence increasing the prospective, power flow. Typical levels of compensation are 35%, 50% and 70%, where the percentage level dictates the capacitor impedance compared to the transmission line it is associated with. PT E A EB sin G XT Figure 13.19: Power transfer in a transmission line The introduction of a capacitive impedance to a network can give rise to several relaying problems. The most common of these is the situation of voltage inversion, which is shown in Figure 13.20. In this case a fault occurs on the protected line. The overall fault impedance is inductive and hence the fault current is inductive (shown lagging the system e.m.f. by 90 degrees in this case). However, the voltage measured by the relay is that across the capacitor and therefore lags the fault current by 90 degrees. The net result is that the voltage measured by the relay is in anti-phase to the system e.m.f. Whilst this view is highly simplistic, it adequately demonstrates potential relay problems, in that any protection reliant upon making a directional decision bases its decision on an inductive system i.e. one where a forward fault is indicated by fault current lagging the measured voltage. A good example of this is a distance relay, which assumes the transmission line is an evenly distributed inductive impedance. Presenting the relay with a capacitive voltage (impedance) can lead the relay to make an incorrect directional decision. 13-12 Figure 13.20: Voltage inversion on a transmission line A second problem is that of current inversion which is demonstrated in Figure 13.21. In this case, the overall fault impedance is taken to be capacitive. The fault current therefore leads the system e.m.f. by 90o whilst the measured fault voltage remains in phase with system e.m.f. Again this condition can give rise to directional stability problems for a variety of protection devices. Practically, the case of current inversion is difficult to obtain. To protect capacitors from high over voltages during fault conditions some form of voltage limiting device (usually in the form of MOVs) is installed to bypass the capacitor at a set current level. In the case of current inversion, the overall fault impedance has to be capacitive and is generally small. This leads to high levels of fault current, which triggers the MOVs and bypasses the capacitors, leaving an inductive fault impedance and preventing the current inversion. Figure 13.21: Current inversion in a transmission line The application of protective relays in a series compensated power system needs careful evaluation. The problems associated with the introduction of a series capacitor can be overcome by a variety of relaying techniques so it is important to ensure the suitability of the chosen protection. Each particular application requires careful investigation to determine the most appropriate solution in respect of protection – there are no general guidelines that can be given. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 13 ˜ Protection of Complex Transmission Circuits 13.7 EXAMPLE Relay Parameter In this section, an example calculation showing the solution to a problem mentioned in this chapter is given. Z1 Zo 0 . 17 7  j 0 . 4 0 2: / k m 0 .3 5 4  j 1 . 0 2 2: / km Parameter Value Units ZL1 (mag) 21.95  ZL1 (ang) Line positive sequence impedance (phase angle) 66.236 deg ZLO (mag) Line zero sequence impedance (magnitude) 54.1  ZLO (ang) Line zero sequence impedance (phase angle) 70.895 deg KZO (mag) Default residual compensation factor (magnitude) 0.49 - KZO (ang) Default residual compensation factor (phase angle) 7.8 deg Z1 (mag) Zone 1 reach impedance setting (magnitude) 17.56  Z1 (ang) Zone 1 reach impedance setting (phase angle) 66.3 deg Z2 (mag) Zone 2 reach impedance setting (magnitude) 30.73  Z2 (ang) Zone 2 reach impedance setting (phase angle) 66.3 deg Z3 (mag) Zone 3 reach impedance setting (magnitude) 131.8  Z3 (ang) Zone 3 reach impedance setting (phase angle) 66.3 deg R1ph Phase fault resistive reach value Zone 1 84.8  R2ph Phase fault resistive reach value Zone 2 84.8  R3ph Phase fault resistive reach value Zone 3 84.8  KZ1 (mag) Zone 1 residual compensation factor (magnitude) 0.426 - KZ1 (ang) Zone 1 residual compensation factor (phase angle) 9.2 deg KZ2 (mag) Zone 2 residual compensation factor (magnitude) not used - KZ2 (ang) Zone 2 residual compensation factor (phase angle) not used deg TZ1 Time delay - Zone 1 0 s TZ2 Time delay - Zone 2 0.25 s TZ3 Time delay - Zone 3 0.45 s R1G Earth fault resistive reach value Zone 1 84.8  R2G Earth fault resistive reach value Zone 2 84.8  R3G Earth fault resistive reach value Zone 3 84.8  13.7.1 Distance Relay applied to Parallel Circuits The system diagram shown in Figure 13.22 indicates a simple 110kV network supplied from a 220kV grid through two autotransformers. The following example shows the calculations necessary to check the suitability of three zone distance protection to the two parallel feeders interconnecting substations A and B, Line 1 being selected for this purpose. All relevant data for this exercise are given in the diagram. The MiCOM P441 relay with quadrilateral characteristics is used to provide the relay data for the example. Relay quantities used in the example are listed in Table 13.3, and calculations are carried out in terms of actual system impedances in ohms, rather than CT secondary quantities. This simplifies the calculations, and enables the example to be simplified by excluding considerations of CT ratios. Most modern distance relays permit settings to be specified in system quantities rather than CT secondary quantities, but older relays may require the system quantities to be converted to impedances as seen by the relay. Parameter Description Line positive sequence impedance (magnitude) Table 13.3: Distance relay settings Figure 13.22: Example network for distance relay setting calculation 13.7.1.1 Residual Compensation The relays used are calibrated in terms of the positive sequence impedance of the protected line. Since the earth fault impedance of Line 1 is different from the positive sequence © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 13-13 Network Protection & Automation Guide impedance, the impedance seen by the relay in the case of a fault involving earth is different to that seen for a phase fault. Therefore the reach of the earth fault elements of the relay needs to be different. For the relay used, this adjustment is provided by the residual (or neutral) compensation factor Kzo, set equal to: KZ0 Z 0  Z1 3Z1 ‘K Z 0 ‘ Z 0  Z1 3Z 1 0.354  j1.022: 1.082‘70.895D : Hence, 0.490 ‘K Z 0 7.8D Z 3 1.2 u 21.95‘66.3D  100 u 2 u 0.439‘66.3D : 131.8‘66.3D : 13.7.1.2 Zone Impedance Reach Settings – Phase Faults Firstly, the impedance reaches for the three relay zones are calculated. 13.7.1.3 Zone 1 Reach Zone 1 impedance is set to 80% of the impedance of the protected line. Hence, Z1 0.8 u 50 u 0.439‘66.236D : 0.8 u 21.95‘66.236D : 17.56‘66.236D : Use a value of 17.56‘66.3 D : 13.7.1.4 Zone 2 Reach Zone 2 impedance reach is set to cover the maximum of: i. 120% of Line 1 length ii. Line 1 + 50% of shortest line from Substation B i.e. 50% of Line 4 From the line impedances given, i. 13-14 30.73‘66.3D : The function of Zone 3 is to provide backup protection for uncleared faults in adjacent line sections. The criterion used is that the relay should be set to cover 120% of the impedance between the relay location and the end of the longest adjacent line, taking account of any possible fault infeed from other circuits or parallel paths. In this case, faults in Line 3 results in the relay under-reaching due to the parallel Lines 1 and 2, so the impedance of Line 3 should be doubled to take this effect into account. Therefore, 0.177  j 0.402: KZ0 Z2 13.7.1.5 Zone 3 Reach 0.439‘66.236D : Z L0 It is clear that condition (ii) governs the setting, and therefore the initial Zone 2 reach setting is: The effect of parallel Line 2 is to make relay 1 underreach for faults on adjacent line sections, as discussed in Section 11.9.3. This is not a problem for the phase fault elements because Line 1 is always protected. For Lines 1 and 2, Z L1 21.95‘66.236D  0.5 u 40 u 0.439‘66.236D : ii. 1.2 u 21.95‘66.236 D 26.34‘66.236 D : 13.7.1.6 Zone Time Delay Settings Proper co-ordination of the distance relay settings with those of other relays is required. Independent timers are available for the three zones to ensure this. For Zone 1, instantaneous tripping is normal. A time delay is used only in cases where large d.c. offsets occur and old circuit breakers, incapable of breaking the instantaneous d.c. component, are involved. The Zone 2 element has to grade with the relays protecting Lines 3 and 4 since the Zone 2 element covers part of these lines. Assuming that Lines 3/4 have distance, unit or instantaneous high-set overcurrent protection applied, the time delay required is that to cover the total clearance time of the downstream relays. To this must be added the reset time for the Zone 2 elements following clearance of a fault on an adjacent line, and a suitable safety margin. A typical time delay is 250ms, and the normal range is 200-300ms. The considerations for the Zone 3 element are the same as for the Zone 2 element, except that the downstream fault clearance time is that for the Zone 2 element of a distance relay or IDMT overcurrent protection. Assuming distance relays are used, a typical time is 450ms. In summary: TZ 1 = 0ms (instantaneous) © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 13 ˜ Protection of Complex Transmission Circuits TZ 2 = 250ms 13.7.1.9 Zone 1 Earth Fault Reach TZ 3 = 450ms Where distance protection is applied to parallel lines (as in this example), the Zone 1 earth fault elements may sometimes overreach and therefore operate when one line is out of service and earthed at both ends 13.7.1.7 Phase Fault Resistive Reach Settings With the use of a quadrilateral characteristic, the resistive reach settings for each zone can be set independently of the impedance reach settings. The resistive reach setting represents the maximum amount of additional fault resistance (in excess of the line impedance) for which a zone trips, regardless of the fault in the zone. The solution is to reduce the earth fault reach of the Zone 1 element to typically 80% of the default setting. Hence: K Z1 0.8 u K Z 0 0.8 u 0.532 0.426 Two constraints are imposed upon the settings, as follows: x it must be greater than the maximum expected phasephase fault resistance (principally that of the fault arc) In practice, the setting is selected by using an alternative setting group, selected when the parallel line is out of service and earthed. x it must be less than the apparent resistance measured due to the heaviest load on the line 13.7.1.10 Zone 2 Earth Fault Reach The minimum fault current at Substation B is of the order of 1.5kA, leading to a typical arc resistance Rarc using the van Warrington formula (equation 11.6) of 9. Using the current transformer ratio on Line 1 as a guide to the maximum expected load current, the minimum load impedance Zlmin is 106 . Typically, the resistive reaches are set to avoid the minimum load impedance by a 20% margin for the phase elements, leading to a maximum resistive reach setting of 84.8.. Therefore, the resistive reach setting lies between 9 and 84.8. While each zone can have its own resistive reach setting, for this simple example, all of the resistive reach settings can be set equal (depending on the particular distance protection scheme used and the need to include Power Swing Blocking, this need not always be the case). Suitable settings are chosen to be 80% of the load resistance: With parallel circuits, the Zone 2 element tends to under-reach due to the zero sequence mutual coupling between the lines. Maloperation may occur, particularly for earth faults occurring on the remote busbar. The effect can be countered by increasing the Zone 2 earth fault reach setting, but first it is necessary to calculate the amount of under-reach that occurs. Underreach = Z adj u I fltp I flt where: Z adj = impedance of adjacent line covered by Zone 2 I fltp = fault current in parallel line I flt = total fault current since the two parallel lines are identical, I fltp = 0.5 I flt and hence, for Lines 1 and 2, R3 ph = 84.8 Underreach = 8.78‘66.3 u 0.5 D R2 ph = 84.8 4.39‘66.3D % Underreach = Underreach / Reach of Protected Zone, and hence: R1 ph = 84.8 % Underreach =14.3% 13.7.1.8 Earth Fault Reach Settings By default, the residual compensation factor as calculated in section 13.7.1.1 is used to adjust the phase fault reach setting in the case of earth faults, and is applied to all zones. However, it is also possible to apply this compensation to zones individually. Two cases in particular require consideration, and are covered in this example This amount of under-reach is not significant and no adjustment need be made. If adjustment is required, this can be achieved by using the KZ2 relay setting, increasing it over the KZ0 setting by the percentage under-reach. When this is done, care must also be taken that the percentage over-reach during single circuit operation is not excessive – if it is then use can be made of the alternative setting groups provided in most modern distance relays to change the relay settings according © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 13-15 Network Protection & Automation Guide to the number of circuits in operation. 13.7.1.11 Earth Fault Resistive Reach Settings The same settings can be used as for the phase fault resistive reaches. Hence, R3G = 84.8 R2G = 84.8 R1G = 84.8 This completes the setting of the relay. Table 13.3 also shows the settings calculated. 13.8 REFERENCES [13.1] Some factors affecting the accuracy of distance type protective equipment under earth fault conditions. Davison, E.B. and Wright, A. Proc. IEE Vol. 110, No. 9, Sept. 1963, pp. 1678-1688. [13.2] Distance protection performance under conditions of single-circuit working in double-circuit transmission lines. Humpage, W.D. and Kandil, M.S. Proc. IEE. Vol. 117. No. 4, April 1970, pp. 766-770. [13.3] Distance protection of tee'd circuits. Humpage, W.A. and Lewis, D.W. Proc. IEE, Vol. 114, No. 10, Oct. 1967, pp. 1483-1498. 13-16 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 13 ˜ Protection of Complex Transmission Circuits © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 13-17 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 14 Auto-Reclosing 14.1 14.2 14.3 14.4 14.5 14.6 14.7 14.8 Introduction Application of Auto-Reclosing Auto-Reclosing on HV Distribution Networks Factors Influencing HV Auto-Reclose Schemes Auto-Reclosing on EHV Transmission Lines High Speed Auto-Reclosing on EHV Systems Single-Phase Auto-Reclosing High-Speed Auto-Reclosing on Lines Employing Distance Schemes 14.9 Delayed Auto-Reclosing on EHV Systems 14.10 Operating Features of Auto-Reclose Schemes 14.11 Auto-Close Schemes 14.12 Examples of Auto-Reclose Applications 14.1 INTRODUCTION Faults on overhead lines fall into one of three categories: x transient x semi-permanent x permanent 80-90% of faults on any overhead line network are transient in nature. The remaining 10%-20% of faults are either semipermanent or permanent. Transient faults are commonly caused by lightning or temporary contact with foreign objects, and immediate tripping of one or more circuit breakers clears the fault. Subsequent re-energisation of the line is usually successful. A small tree branch falling on the line could cause a semipermanent fault. The cause of the fault would not be removed by the immediate tripping of the circuit, but could be burnt away during a time-delayed trip. HV overhead lines in forest areas are prone to this type of fault. Permanent faults, such as broken conductors, and faults on underground cable sections, must be located and repaired before the supply can be restored. Use of an auto-reclose scheme to re-energise the line after a fault trip permits successful re-energisation of the line. Sufficient time must be allowed after tripping for the fault arc to de-energise before reclosing otherwise the arc will re-strike. Such schemes have been the cause of a substantial improvement in continuity of supply. A further benefit, particularly to EHV systems, is the maintenance of system stability and synchronism. A typical single-shot auto-reclose scheme is shown in Figure 14.1 and Figure 14.2. Figure 14.1 shows a successful reclosure in the event of a transient fault, and Figure 14.2 an unsuccessful reclosure followed by lockout of the circuit breaker if the fault is permanent. Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 14-1 Network Protection & Automation Guide Figure 14.1: Single-shot auto-reclose scheme operation for a transient fault Figure 14.2: Single-shot auto-reclose scheme operation for a permanent fault 14-2 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 14 ˜ Auto-Reclosing 14.2 APPLICATION OF AUTO-RECLOSING The most important parameters of an auto-reclose scheme are: x dead time x reclaim time x single or multi-shot These parameters are influenced by: x type of protection x type of switchgear x possible stability problems x effects on the various types of consumer loads The weighting given to the above factors is different for HV distribution networks and EHV transmission systems and therefore it is convenient to discuss them under separate headings. Sections 14.3 and 14.4 cover the application of auto-reclosing to HV distribution networks while Sections 14.5 to 14.9 cover EHV schemes. ensuing loss of supply to a number of healthy sections. Autoreclosing allows these circuit breakers to be reclosed within a few seconds. With transient faults, the overall effect would be loss of supply for a very short time but affecting a larger number of consumers. If only time-graded protection without auto-reclose were used, a smaller number of consumers might be affected, but for a longer time period. When instantaneous protection is used with auto-reclosing, the scheme is normally arranged to inhibit the instantaneous protection after the first trip. For a permanent fault, the timegraded protection will give discriminative tripping after reclosure, resulting in the isolation of the faulted section. Some schemes allow a number of reclosures and time-graded trips after the first instantaneous trip, which may result in the burning out and clearance of semi-permanent faults. A further benefit of instantaneous tripping is a reduction in circuit breaker maintenance by reducing pre-arc heating when clearing transient faults. The rapid expansion in the use of auto-reclosing has led to the existence of a variety of different control schemes. The various features in common use are discussed in Section 14.10. The related subject of auto-closing, that is, the automatic closing of normally open circuit breakers, is dealt with in Section 14.11. When considering feeders that are partly overhead line and partly underground cable, any decision to install auto-reclosing would be influenced by any data known on the frequency of transient faults. Where a significant proportion of faults are permanent, the advantages of auto-reclosing are small, particularly since reclosing on to a faulty cable is likely to aggravate the damage. 14.3 AUTO-RECLOSING ON HV DISTRIBUTION NETWORKS 14.4 FACTORS INFLUENCING HV AUTORECLOSE SCHEMES On HV distribution networks, auto-reclosing is applied mainly to radial feeders where problems of system stability do not arise, and the main advantages to be derived from its use can be summarised as follows: The factors that influence the choice of dead time, reclaim time, and the number of shots are now discussed. x reduction to a minimum of the interruptions of supply to the consumer Several factors affect the selection of system dead time as follows: x instantaneous fault clearance can be introduced, with the accompanying benefits of shorter fault duration, less fault damage, and fewer permanent faults As 80% of overhead line faults are transient, elimination of loss of supply from this cause by the introduction of auto-reclosing gives obvious benefits through: x improved supply continuity x reduction of substation visits Instantaneous tripping reduces the duration of the power arc resulting from an overhead line fault to a minimum. The chance of permanent damage occurring to the line is reduced. The application of instantaneous protection may result in nonselective tripping of a number of circuit breakers and an 14.4.1 Dead Time x system stability and synchronism x type of load x CB characteristics x fault path de-ionisation time x protection reset time These factors are discussed in the following sections. 14.4.1.1 System stability and synchronism To reclose without loss of synchronism after a fault on the interconnecting feeder, the dead time must be kept to the minimum permissible consistent with de-ionisation of the fault arc. Other time delays that contribute to the total system disturbance time must also be kept as short as possible. The © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 14-3 Network Protection & Automation Guide problem arises only on distribution networks with more than one power source, where power can be fed into both ends of an inter-connecting line. A typical example is embedded generation (see Chapter 17), or where a small centre of population with a local diesel generating plant may be connected to the rest of the supply system by a single tie-line. The use of high-speed protection, such as unit protection or distance schemes, with operating times of less than 0.05s is essential. The circuit breakers must have very short operation times and then be able to reclose the circuit after a dead time of the order of 0.3s - 0.6s to allow for fault-arc de-ionisation. It may be desirable in some cases to use synchronism check logic, so that auto-reclosing is prevented if the phase angle has moved outside specified limits. The matter is dealt with more fully in Section 14.9. 14.4.1.2 Type of load On HV systems, the main problem to be considered in relation to dead time is the effect on various types of consumer load. x Industrial consumers: Most industrial consumers operate mixed loads comprising induction motors, lighting, process control and static loads. Synchronous motors may also be used. The dead time has to be long enough to allow motor circuits to trip out on loss of supply. Once the supply is restored, restarting of drives can then occur under direction of the process control system in a safe and programmed manner, and can often be fast enough to ensure no significant loss of production or product quality x Domestic consumers: It is improbable that expensive processes or dangerous conditions will be involved with domestic consumers and the main consideration is that of inconvenience and compensation for supply interruption. A dead time of seconds or a few minutes is of little importance compared with the loss of cooking facilities, central heating, light and audio/visual entertainment resulting from a longer supply failure that could occur without auto-reclosing 14.4.1.3 Circuit breaker characteristics The time delays imposed by the circuit breaker during a tripping and reclosing operation must be taken into consideration, especially when assessing the possibility of applying high speed auto-reclosing. x Mechanism resetting time: Most circuit breakers are ‘trip free’, which means that the breaker can be tripped during the closing stroke. After tripping, a time of the order of 0.2s must be allowed for the trip-free 14-4 mechanism to reset before applying a closing impulse. Where high speed reclosing is required, a latch check interlock is desirable in the reclosing circuit x Closing time: This is the time interval between the energisation of the closing mechanism and the making of the contacts. Owing to the time constant of the solenoid and the inertia of the plunger, a solenoid closing mechanism may take 0.3s to close. A springoperated breaker, on the other hand, can close in less than 0.2s. Modern vacuum circuit breakers may have a closing time of less than 0.1s The circuit breaker mechanism imposes a minimum dead time made up from the sum of (a) and (b) above. Figure 14.3 shows the performance of modern HV/EHV circuit breakers in this respect. Older circuit breakers may require longer times than those shown. Arc extinguished Contacts separate Breaker fully open: Trip initiation closing circuit energised t1 t2 t3 Time (s) Contacts make Breaker fully closed t4 t6 t5 t1 t2 t3 t4 t5 t6 Oil 11kV 0.06 0.1 0.08 0.16 0.24 0.02 Vacuum 15kV 0.038 0.053 0.023 0.048 0.28 0.07 Oil 132kV 0.03 0.06 0.2 0.35 0.55 0.01 Air 380kV 0.035 0.045 0.235 0.065 0.3 0.02 SF6 132kV 0.04 0.07 0.03 0.08 0.11 0.12 SF6 380kV 0.02 0.05 0.01 0.06 0.07 0.04 Note: 380kV data applicable to 400kV also. All times in seconds Figure 14.3: Typical circuit breaker trip-close operation times 14.4.1.4 De-ionisation of the fault path As mentioned above, successful high speed reclosure requires the interruption of the fault by the circuit breaker to be followed by a time delay long enough to allow the ionised air to disperse. This time is dependent on the system voltage, cause of fault, weather conditions and so on, but at voltages up to 66kV, 0.1s - 0.2s should be adequate. On HV systems, therefore, fault de-ionisation time is of less importance than circuit breaker time delays. 14.4.1.5 Protection reset time If time delayed protection is used, it is essential that the timing device shall fully reset during the dead time, so that correct time discrimination will be maintained after reclosure on to a fault. The reset time of the electromechanical I.D.M.T. relay is © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 14 ˜ Auto-Reclosing 10 seconds or more when on maximum time setting, and dead times of at least this value may be required. When short dead times are required, the protection relays must reset almost instantaneously, a requirement that is easily met by the use of static, digital and numerical I.D.M.T. relays. 14.4.2 Reclaim Time Factors affecting the setting of the reclaim time are discussed in the following sections. 14.4.2.1 Type of protection The reclaim time must be long enough to allow the protection relays to operate when the circuit breaker is reclosed on to a permanent fault. The most common forms of protection applied to HV lines are I.D.M.T. or definite time over-current and earth-fault relays. The maximum operating time for the former with very low fault levels could be up to 30 seconds, while for fault levels of several times rating the operating time may be 10 seconds or less. In the case of definite time protection, settings of 3 seconds or less are common, with 10 seconds as an absolute maximum. It has been common practice to use reclaim times of 30 seconds on HV auto-reclose schemes. However, there is a danger with a setting of this length that during a thunderstorm, when the incidence of transient faults is high, the breaker may reclose successfully after one fault, and then trip and lock out for a second fault within this time. Use of a shorter reclaim time of, say, 15 seconds may enable the second fault to be treated as a separate incident, with a further successful reclosure. Where fault levels are low, it may be difficult to select I.D.M.T. time settings to give satisfactory grading with an operating time limit of 15 seconds, and the matter becomes a question of selecting a reclaim time compatible with I.D.M.T. requirements. It is common to fit sensitive earth-fault protection to supplement the normal protection to detect high resistance earth faults. This protection is usually set to have an operating time longer than that of the main protection. This longer time may have to be taken into consideration when deciding on a reclaim time. A broken overhead conductor in contact with dry ground or a wood fence may cause this type of fault. It is rarely if ever transient and may be a danger to the public. It is therefore common practice to use a contact on the sensitive earth fault relay to block auto-reclosing and lock out the circuit breaker. Where high-speed protection is used, reclaim times of 1 second or less would be adequate. However, such short times are rarely used in practice, to relieve the duty on the circuit breaker. 14.4.2.2 Spring winding time The reclaim time of motor-wound spring-closed breakers must be at least as long as the spring winding time, to ensure that the breaker is not subjected to a further reclosing operating with a partly wound spring. 14.4.3 Number of Shots There are no definite rules for defining the number of shots for any particular auto-reclose application, but a number of factors must be taken into account. 14.4.3.1 Circuit breaker limitations Important considerations are the ability of the circuit breaker to perform several trip and close operations in quick succession and the effect of these operations on the maintenance period. Maintenance periods vary according to the type of circuit breaker used and the fault current broken when clearing each fault. Use of modern numerical relays can assist, as they often have a CB condition-monitoring feature included that can be arranged to indicate to a Control Centre when maintenance is required. Auto-reclose may then be locked out until maintenance has been carried out. 14.4.3.2 System conditions If statistical information on a particular system shows a moderate percentage of semi-permanent faults that could be burned out during 2 or 3 time-delayed trips, a multi-shot scheme may be justified. This is often the case in forest areas. Multi-shot schemes may also be applicable where fused ‘tees’ are used and the fault level is low, since the fusing time may not discriminate with the main I.D.M.T. relay. The use of several shots will heat the fuse to such an extent that it would eventually blow before the main protection operated. 14.5 AUTO-RECLOSING ON EHV TRANSMISSION LINES The most important consideration in the application of autoreclosing to EHV transmission lines is the maintenance of system stability and synchronism. The problems involved are dependent on whether the transmission system is weak or strong. With a weak system, loss of a transmission link may lead quickly to an excessive phase angle across the CB used for re-closure, thus preventing a successful re-closure. In a relatively strong system, the rate of change of phase angle will be slow, so that delayed auto-reclose can be successfully applied. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 14-5 Network Protection & Automation Guide An illustration is the interconnector between two power systems as shown in Figure 14.4. Under healthy conditions, the amount of synchronising power transmitted, P, crosses the power/angle curve OAB at point X, showing that the phase displacement between the two systems is 0. Under fault conditions, the curve OCB is applicable, and the operating point changes to Y. Assuming constant power input to both ends of the line, there is now an accelerating power XY. As a result, the operating point moves to Z, with an increased phase displacement, 1, between the two systems. At this point the circuit breakers trip and break the connection. The phase displacement continues to increase at a rate dependent on the inertia of the two power sources. To maintain synchronism, the circuit breaker must be reclosed in a time short enough to prevent the phase angle exceeding 2. This angle is such that the area (2) stays greater than the area (1), which is the condition for maintenance of synchronism. 14.6 HIGH SPEED AUTO-RECLOSING ON EHV SYSTEMS The first requirement for the application of high-speed autoreclosing is knowledge of the system disturbance time that can be tolerated without loss of system stability. This will normally require transient stability studies to be conducted for a defined set of power system configurations and fault conditions. With knowledge of protection and circuit breaker operating characteristics and fault arc de-ionisation times, the feasibility of high-speed auto-reclosing can then be assessed. These factors are now discussed. 14.6.1 Protection Characteristics The use of high-speed protection equipment, such as distance or unit protection schemes, giving operating times of less than 40ms, is essential. In conjunction with fast operating circuit breakers, high-speed protection reduces the duration of the fault arc and thus the total system disturbance time. It is important that the circuit breakers at both ends of a fault line should be tripped as rapidly as possible. The time that the line is still being fed from one end represents an effective reduction in the dead time, and may well jeopardise the chances of a successful reclosure. When distance protection is used, and the fault occurs near one end of the line, special measures have to be adopted to ensure simultaneous tripping at each end. These are described in Section 14.8. 14.6.2 De-Ionisation of the Fault Arc It is important to know the time that must be allowed for complete de-ionisation of the arc, to prevent the arc restriking when the voltage is re-applied. Figure 14.4: Effect of high-speed three-phase auto-reclosing on system stability for a weak system This example, for a weak system, shows that the successful application of auto-reclosing in such a case needs high-speed protection and circuit breakers, and a short dead time. On strong systems, synchronism is unlikely to be lost by the tripping out of a single line. For such systems, an alternative policy of delayed auto-reclosing may be adopted. This enables the power swings on the system resulting from the fault to decay before reclosure is attempted. The various factors to be considered when using EHV autoreclose schemes are now dealt with. High-speed and delayed auto-reclose schemes are discussed separately. The de-ionisation time of an uncontrolled arc, in free air depends on the circuit voltage, conductor spacing, fault currents, fault duration, wind speed and capacitive coupling from adjacent conductors. Of these, the circuit voltage is the most important, and as a general rule, the higher the voltage the longer the time required for de-ionisation. Typical values for three-phase faults are given in Table 14.1. Line Voltage (kV) 66 Minimum De-energisation Time (Seconds) 0.2 110 0.28 132 0.3 220 0.35 275 0.38 400 0.45 525 0.55 Table 14.1: Fault-arc de-ionisation times 14-6 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 14 ˜ Auto-Reclosing If single-phase tripping and auto-reclosing is used, capacitive coupling between the healthy phases and the faulty phase tends to maintain the arc and hence extend the dead time required from the values given in the Table. This is a particular problem on long distance EHV transmission lines. However where shunt compensation is applied, a neutral reactor can often be used to balance system inter-phase capacitance and thus reduce the arcing time. 14.6.3 Circuit Breaker Characteristics The high fault levels involved in EHV systems impose a very severe duty on the circuit breakers used in high-speed autoreclose schemes. The accepted breaker cycle of break-makebreak requires the circuit breaker to interrupt the fault current, reclose the circuit after a time delay of upwards of 0.2s and then break the fault current again if the fault persists. The types of circuit breaker commonly used on EHV systems are oil, air blast and SF6 types. 14.6.3.1 Oil circuit breakers Oil circuit breakers are used for transmission voltages up to 300kV, and can be subdivided into the two types: ‘bulk oil’ and ‘small oil volume’. The latter is a design aimed at reducing the fire hazard associated with the large volume of oil contained in the bulk oil breaker. The operating mechanisms of oil circuit breakers are of two types, ‘fixed trip’ and ‘trip free’, of which the latter is the most common. With trip-free types, the reclosing cycle must allow time for the mechanism to reset after tripping before applying the closing impulse. Special means have to be adopted to obtain the short dead times required for high-speed auto-reclosing. Various types of tripping mechanism have been developed to meet this requirement. The three types of closing mechanism fitted to oil circuit breakers are: x solenoid x spring x pneumatic CBs with solenoid closing are not suitable for high-speed autoreclose due to the long time constant involved. Spring, hydraulic or pneumatic closing mechanisms are universal at the upper end of the EHV range and give the fastest closing time. Figure 14.3 shows the operation times for various types of EHV circuit breakers, including the dead time that can be attained. 14.6.3.2 Air blast circuit breakers Air blast breakers have been developed for voltages up to the highest at present in use on transmission lines. They fall into two categories: x pressurised head circuit breakers x non-pressurised head circuit breakers In pressurised head circuit breakers, compressed air is maintained in the chamber surrounding the main contacts. When a tripping signal is received, an auxiliary air system separates the main contacts and allows compressed air to blast through the gap to the atmosphere, extinguishing the arc. With the contacts fully open, compressed air is maintained in the chamber. Loss of air pressure could result in the contacts reclosing, or, if a mechanical latch is employed, restriking of the arc in the depressurised chamber. For this reason, sequential series isolators, which isolate the main contacts after tripping, are commonly used with air blast breakers. Since these are comparatively slow in opening, their operation must be inhibited when auto-reclosing is required. A contact on the auto-reclose relay is made available for this purpose. Non-pressurised head circuit breakers are slower in operation than the pressurised head type and are not usually applied in high-speed reclosing schemes. 14.6.3.3 SF6 circuit breakers Most EHV circuit breaker designs now manufactured use SF6 gas as an insulating and arc-quenching medium. The basic design of such circuit breakers is in many ways similar to that of pressurised head air blast circuit breakers. Voltage withstand capability depends on a minimum gas pressure being available, and gas pressure monitors are fitted and arranged to block CB operation in the event of low gas pressure occurring. Sequential series isolators are normally used, to prevent damage to the circuit breaker in the event of voltage transients due to lightning strikes, etc. occurring when the CB is open. Provision should therefore be made to inhibit sequential series isolation during an auto-reclose cycle. 14.6.4 Choice of Dead Time At voltages of 220kV and above, the de-ionisation time will probably dictate the minimum dead time, rather than any circuit breaker limitations. This can be deduced from Table 14.1. The dead time setting on a high-speed auto-reclose relay should be long enough to ensure complete de-ionisation of the arc. On EHV systems, an unsuccessful reclosure is more detrimental to the system than no reclosure at all. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 14-7 Network Protection & Automation Guide 14.6.5 Choice of Reclaim Time Where EHV oil circuit breakers are concerned, the reclaim time should take account of the time needed for the closing mechanism to reset ready for the next reclosing operation. 14.6.6 Number of Shots High-speed auto-reclosing on EHV systems is invariably single shot. Repeated reclosure attempts with high fault levels would have serious effects on system stability, so the circuit breakers are locked out after one unsuccessful attempt. Also, the incidence of semi-permanent faults that can be cleared by repeated reclosures is less likely than on HV systems. Multishot schemes have, however, occasionally been used on EHV systems, specifically to deal with bush fire faults prevalent in Africa. Single phase to earth faults account for the majority of overhead line faults. When three-phase auto-reclosing is applied to single circuit interconnectors between two power systems, the tripping of all three phases may cause the two systems to drift apart in phase, as described in Section 14.5. No interchange of synchronising power can take place during the dead time. If only the faulty phase is tripped, synchronising power can still be interchanged through the healthy phases. Any difference in phase between the two systems will be correspondingly less, leading to a reduction in the disturbance on the system when the circuit breaker recloses. For single-phase auto-reclosing each circuit breaker pole must be provided with its own closing and tripping mechanism; this is normal with EHV air blast and SF6 breakers. The associated tripping and reclosing circuitry is therefore more complicated, as it must be inherently phase-selective. On the occurrence of a phase-earth fault, single-phase autoreclose schemes trip and reclose only the corresponding pole of the circuit breaker. The auto-reclose function in a relay therefore has three separate elements, one for each phase. Operation of any element energises the corresponding dead timer, which in turn initiates a closing pulse for the appropriate pole of the circuit breaker. A successful reclosure results in the auto-reclose logic resetting at the end of the reclaim time, ready to respond to a further fault incident. If the fault is persistent and reclosure is unsuccessful, it is usual to trip and lock out all three poles of the circuit breaker. 14-8 x use of a selector switch to give a choice of single or three-phase reclosing x combined single and three-phase auto-reclosing; single phase to earth faults initiate single-phase tripping and reclosure, and phase-phase faults initiate three-phase tripping and reclosure Modern numerical relays often incorporate the logic for all of the above schemes for the user to select as required. Use can be made of any user-definable logic feature in a numerical relay to implement other schemes that may be required. The advantages of single-phase auto-reclosing are: x the maintenance of system integrity 14.7 SINGLE-PHASE AUTO-RECLOSING The above describes only one of many variants. possibilities are: x three-phase trip and lockout for phase-phase or 3phase faults, or if either of the remaining phases should develop a fault during the dead time x on multiple earth systems, negligible interference with the transmission of load. This is because the current in the unfaulted phases can continue to flow until the fault is cleared and the faulty phase restored The main disadvantage is the longer de-ionisation time resulting from capacitive coupling between the faulty and healthy lines. This leads to a longer dead time being required. Maloperation of earth fault relays on double circuit lines owing to the flow of zero sequence currents may also occur. These are induced by mutual induction between faulty and healthy lines (see Chapter 13 for details). 14.8 HIGH-SPEED AUTO-RECLOSING ON LINES EMPLOYING DISTANCE SCHEMES The importance of rapid tripping of the circuit breakers at each end of a faulted line where high-speed auto-reclosing is employed has already been covered in Section 14.6. Simple distance protection presents some difficulties in this respect. Owing to the errors involved in determining the ohmic setting of the distance relays, it is not possible to set Zone 1 of a distance relay to cover 100% of the protected line – see Chapter 11 for more details. Zone 1 is set to cover 80-85% of the line length, with the remainder of the line covered by timedelayed Zone 2 protection. Other © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 14 ˜ Auto-Reclosing 14.8.2 Zone 1 Extension In this scheme, the reach of Zone 1 is normally extended to 120% of the line length and is reset to 80% when a command from the auto-reclose logic is received. This auto-reclose logic signal should occur before a closing pulse is applied to the circuit breaker and remain operated until the end of the reclaim time. The logic signal should also be present when auto-reclose is out of service. 14.9 DELAYED AUTO-RECLOSING ON EHV SYSTEMS Figure 14.5: Typical three zone distance scheme Figure 14.5 shows this for a typical three-zone distance scheme covering two transmission lines. For this reason, a fault occurring in an end zone would be cleared instantaneously, by the protection at one end of the feeder. However, the CB at the other end opens in 0.3 - 0.4 seconds (Zone 2 time). High-speed auto-reclosing applied to the circuit breakers at each end of the feeder could result either in no dead time or in a dead time insufficient to allow deionisation of the fault arc. A transient fault could therefore be seen as a permanent one, resulting in the locking out of both circuit breakers. Two methods are available for overcoming this difficulty. Firstly, one of the transfer-trip or blocking schemes that involves the use of an intertrip signal between the two ends of the line can be used. Alternatively, a Zone 1 extension scheme may be used to give instantaneous tripping over the whole line length. Further details of these schemes are given in Chapter 12, but a brief description of how they are used in conjunction with an auto-reclose scheme is given below. 14.8.1 Transfer-Trip or Blocking Schemes This involves use of a signalling channel between the two ends of the line. Tripping occurs rapidly at both ends of the faulty line, enabling the use of high-speed auto-reclose. Some complication occurs if single-phase auto-reclose is used, as the signalling channel must identify which phase should be tripped, but this problem does not exist if a modern numerical relay is used. On highly interconnected transmission systems, where the loss of a single line is unlikely to cause two sections of the system to drift apart significantly and lose synchronism, delayed autoreclosing can be employed. Dead times of the order of 5s 60s are commonly used. No problems are presented by fault arc de-ionisation times and circuit breaker operating characteristics, and power swings on the system decay before reclosing. In addition, all tripping and reclose schemes can be three-phase only, simplifying control circuits in comparison with single-phase schemes. In systems on which delayed auto-reclosing is permissible, the chances of a reclosure being successful are somewhat greater with delayed reclosing than would be the case with high-speed reclosing. 14.9.1 Scheme Operation The sequence of operations of a delayed auto-reclose scheme can be best understood by reference to Figure 14.6. This shows a transmission line connecting two substations A and B, with the circuit beakers at A and B tripping out in the event of a line fault. Synchronism is unlikely to be lost in a system that employs delayed auto-reclose. However, the transfer of power through the remaining tie-lines on the system could result in the development of an excessive phase difference between the voltages at points A and B. The result, if reclosure takes place, is an unacceptable shock to the system. It is therefore usual practice to incorporate a synchronism check relay into the reclosing system to determine whether auto-reclosing should take place. Irrespective of the scheme used, it is customary to provide an auto-reclose blocking relay to prevent the circuit breakers auto-reclosing for faults seen by the distance relay in Zones 2 and 3. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 14-9 Network Protection & Automation Guide x phase angle difference B A ~ ~ x voltage x rate of change of slip frequency (a) Network diagram Protn. operated (local or intertrip) & AR in progress AR lockout 1 S Q _ R Q CB closed 0 1 ti & AR inhibit time Reclaim timer tR 0 CB open Protn. reset CB healthy System healthy & Dead time td 0 CB close command & S Q _ R Q tR: reclaim time ti: inhibit time td: dead time (b) Autoreclose logic for each CB Figure 14.6: Delayed auto-reclose scheme logic After tripping on a fault, it is normal procedure to reclose the breaker at one end first, a process known as ‘live bus/dead line charging’. Reclosing at the other and is then under the control of a synchronism check relay element for what is known as ‘live bus/live line reclosing’. For example, if it were decided to charge the line initially from station A, the dead time in the auto-reclose relay at A would be set at, say, 5 seconds, while the corresponding timer in the auto-reclose relay at B would be set at, say, 15 seconds. The circuit beaker at A would then reclose after 5 seconds provided that voltage monitoring relays at A indicated that the busbars were alive and the line dead. With the line recharged, the circuit breaker at B would then reclose with a synchronism check, after a 2 second delay imposed by the synchronism check relay element. If for any reason the line fails to ‘dead line charge’ from end A, reclosure from end B would take place after 15 seconds. The circuit breaker at A would then be given the opportunity to reclose with a synchronism check. 14.9.2 Synchronism Check Relays The synchronism check relay element commonly provides a three-fold check: 14-10 The phase angle setting is usually set to between 20 – 45, and reclosure is inhibited if the phase difference exceeds this value. The scheme waits for a reclosing opportunity with the phase angle within the set value, but locks out if reclosure does not occur within a defined period, typically 5s. A voltage check is incorporated to prevent reclosure under various circumstances. A number of different modes may be available. These are typically undervoltage on either of the two measured voltages, differential voltage, or both of these conditions. The logic also incorporates a frequency difference check, either by direct measurement or by using a timer in conjunction with the phase angle check. In the latter case, if a 2 second timer is employed, the logic gives an output only if the phase difference does not exceed the phase angle setting over a period of 2 seconds. This limits the frequency difference (in the case of a phase angle setting of 20) to a maximum of 0.11% of 50Hz, corresponding to a phase swing from +20 to -20 over the measured 2 seconds. While a significant frequency difference is unlikely to arise during a delayed auto-reclose sequence, the time available allows this check to be carried out as an additional safeguard. As well as ‘live bus/dead line’ and ‘live bus/live line’ reclosing, sometimes ‘live line/dead bus’ reclosing may need to be implemented. A numerical relay will typically allow any combination of these modes to be implemented. The voltage settings for distinguishing between ‘live’ and ‘dead’ conditions must be carefully chosen. In addition, the locations of the VTs must be known and checked so that the correct voltage signals are connected to the ‘line’ and ‘bus’ inputs. 14.10 OPERATING FEATURES OF AUTORECLOSE SCHEMES The extensive use of auto-reclosing has resulted in the existence of a wide variety of different control schemes. Some of the more important variations in the features provided are described below. 14.10.1 Initiation Modern auto-reclosing schemes are invariably initiated by the tripping command of a protection relay function. Some older schemes may employ a contact on the circuit breaker. Modern digital or numerical relays often incorporate a comprehensive auto-reclose facility, thus eliminating the need for a separate auto-reclose relay. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 14 ˜ Auto-Reclosing 14.10.2 Type of Protection On HV distribution systems, advantage is often taken of autoreclosing to use instantaneous protection for the first trip, followed by I.D.M.T. for subsequent trips in a single fault incident. In such cases, the auto-reclose relay must provide a means of isolating the instantaneous relay after the first trip. In older schemes, this may be done with a normally closed contact on the auto-reclose starting element wired into the connection between the instantaneous relay contact and the circuit breaker trip coil. With digital or numerical relays with in-built auto-reclose facilities, internal logic facilities will normally be used. For certain utility companies, it is the rule to fit tripping relays to every circuit breaker. If auto-reclosing is required, self or electrically reset tripping relays must be used. If the later is used, a contact must be provided either in the auto-reclose logic or by separate trip relay resetting scheme to energise the reset coil before reclosing can take place. 14.10.3 Dead Timer This will have a range of settings to cover the specified highspeed or delayed reclosing duty. Any interlocks that are needed to hold up reclosing until conditions are suitable can be connected into the dead timer circuit. Section 14.12.1 provides an example of this applied to transformer feeders. 14.10.4 Reclosing Impulse The duration of the reclosing impulse must be related to the requirements of the circuit breaker closing mechanism. On auto-reclose schemes using spring-closed breakers, it is sufficient to operate a contact at the end of the dead time to energise the latch release coil on the spring-closing mechanism. A circuit breaker auxiliary switch can be used to cancel the closing pulse and reset the auto-reclose relay. With solenoid operated breakers, it is usual to provide a closing pulse of the order of 1 - 2 seconds, to hold the solenoid energised for a short time after the main contacts have closed. This ensures that the mechanism settles in the fully latched-in position. The pneumatic or hydraulic closing mechanisms fitted to oil, air blast and SF6 circuit breakers use a circuit breaker auxiliary switch for terminating the closing pulse applied by the auto-reclose relay. 14.10.5 Anti-Pumping Devices The function of an anti-pumping device is to prevent the circuit breaker closing and opening several times in quick succession. This might be caused by the application of a closing pulse while the circuit breaker is being tripped via the protection relays. Alternatively, it may occur if the circuit breaker is closed on to a fault and the closing pulse is longer than the sum of protection relay and circuit breaker operating times. Circuit breakers with trip free mechanisms do not require this feature. 14.10.6 Reclaim Timer Electromechanical, static or software-based timers are used to provide the reclaim time, depending on the relay technology used. If electromechanical timers are used, it is convenient to employ two independently adjustable timed contacts to obtain both the dead time and the reclaim time on one timer. With static and software-based timers, separate timer elements are generally provided. 14.10.7 CB Lockout If reclosure is unsuccessful the auto-reclose relay locks out the circuit breaker. Some schemes provide a lockout relay with a flag, with provision of a contact for remote alarm. The circuit breaker can then only be closed by hand; this action can be arranged to reset the auto-reclose relay element automatically. Alternatively, most modern relays can be configured such that a lockout condition can be reset only by operator action. Circuit breaker manufacturers state the maximum number of operations allowed before maintenance is required. A number of schemes provide a fault trip counting function and give a warning when the total approaches the manufacturer's recommendation. These schemes will lock out when the total number of fault trips has reached the maximum value allowed. 14.10.8 Manual Closing It is undesirable to permit auto-reclosing if circuit breaker closing is manually initiated. Auto-reclose schemes include the facility to inhibit auto-reclose initiation for a set time following manual CB closure. The time is typically in the range of 2 - 5 seconds. 14.10.9 Multi-Shot Schemes Schemes providing up to three or four shots use timing circuits are often included in an auto-reclose relay to provide different, independently adjustable, dead times for each shot. Instantaneous protection can be used for the first trip, since each scheme provides a signal to inhibit instantaneous tripping after a set number of trips and selects I.D.M.T. protection for subsequent ones. The scheme resets if reclosure is successful within the chosen number of shots, ready to respond to further fault incidents. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 14-11 Network Protection & Automation Guide 14.11 AUTO-CLOSE SCHEMES Auto-close schemes are employed to close automatically circuit breakers that are normally open when the supply network is healthy. This may occur for a variety of reasons, for instance the fault level may be excessive if the CBs were normally closed. The circuits involved are very similar to those used for auto-reclosing. Two typical applications are described in the following sections. scheme. The auto-close relay used in practice is a variant of one of the standard auto-reclose relays. 14.12 EXAMPLES OF AUTO-RECLOSE APPLICATIONS The following sections describe auto-reclose facilities in common use for several standard substation configurations. 14.12.1 Double Busbar Substation 14.11.1 Standby Transformers Figure 14.7 shows a busbar station fed by three transformers, T1, T2 and T3. The loss of one transformer might cause serious overloading of the remaining two. However, connection of a further transformer to overcome this may increase the fault level to an unacceptable value. A typical double busbar station is shown in Figure 14.8. Each of the six EHV transmission lines brought into the station is under the control of a circuit breaker, CB1 to CB6 inclusive, and each transmission line can be connected either to the main or to the reserve busbars by manually operated isolators. Line 1 L1 Line 2 Line 3 Line 4 Line 5 Line 6 L2 L3 L4 L5 L6 CB2 CB3 CB4 CB5 CB6 T1 I T1 CB1A T2 T1 T3 T4 (Standby) T2 I T2 CB2A CB1 Bus C CB1 CB2 CB3 CB4 with auto-closing Main BC EHV Busbars Reserve Figure 14.7: Standby transformer with auto-closing Figure 14.8: Double busbar substation The solution is to have a standby transformer T4 permanently energised from the primary side and arranged to be switched into service if one of the others trips on fault. Bus section isolators enable sections of busbar to be isolated in the event of a fault and the bus coupler breaker BC permits sections of main and reserve bars to be interconnected. The starting circuits for breaker CB4 monitor the operation of transformer protection on any of the transformers T1, T2 and T3 together with the tripping of an associated circuit breaker CB1 - CB3. In the event of a fault, the auto-close circuit is initiated and circuit breaker CB4 closes, after a short time delay, to switch in the standby transformer. Some schemes employ an auto-tripping relay, so that when the faulty transformer is returned to service, the standby is automatically disconnected. 14.12.1.1 Basic scheme – banked transformers omitted 14.11.2 Bus Coupler or Bus Section Breaker If all four power transformers are normally in service for the system of Figure 14.7, and the bus sections are interconnected by a normally-open bus section breaker instead of the isolator, the bus section breaker should be auto-closed in the event of the loss of one transformer, to spread the load over the remaining transformers. This, of course, is subject to the fault level being acceptable with the bus-section breaker closed. Starting and auto-trip circuits are employed as in the stand-by 14-12 Each line circuit breaker is provided with an auto-reclose relay that recloses the appropriate circuit breakers in the event of a line fault. For a fault on Line 1, this would require opening of CB1 and the corresponding CB at the remote end of the line. The operation of either the busbar protection or a VT Buchholz relay is arranged to lock out the auto-reclosing sequence. In the event of a persistent fault on Line 1, the line circuit breakers trip and lock out after one attempt at reclosure. 14.12.1.2 Scheme with banked transformers Some utilities use a variation of the basic scheme in which Transformers T1 and T2 are banked off Lines 1 and 2, as shown in Figure 14.8. This provides some economy in the number of circuit breakers required. The corresponding transformer circuits 1 and 2 are tee'd off Lines 1 and 2 respectively. The transformer secondaries are connected to a separate HV busbar system via circuit breakers CB1A and CB2A. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 14 ˜ Auto-Reclosing Auto-reclose facilities can be extended to cover the circuits for banked transformers where these are used. For example, a fault on line 1 would cause the tripping of circuit breakers CB1, CB1A and the remote line circuit breaker. When Line 1 is reenergised, either by auto-reclosure of CB1 or by the remote circuit breaker, whichever is set to reclose first, transformer T1 is also energised. CB1A will not reclose until the appearance of transformer secondary voltage, as monitored by the secondary VT; it then recloses on to the HV busbars after a short time delay, with a synchronism check if required. In the event of a fault on transformer T1, the local and remote line circuit breakers and breaker CB1A trip to isolate the fault. Automatic opening of the motorised transformer isolator IT1 follows this. The line circuit breakers then reclose in the normal manner and circuit breaker CB1A locks out. A shortcoming of this scheme is that this results in healthy transformer T1 being isolated from the system; also, isolator L1 must be opened manually before circuit breakers CB1 and CB1A, can be closed to re-establish supply to the HV busbars via the transformer. A variant of this scheme is designed to instruct isolator L1 to open automatically following a persistent fault on Line 1 and provide a second auto-reclosure of CB1 and CB1A. The supply to Bus C is thereby restored without manual intervention. recloses again, followed by B1, so that both transformers T1 and T2 are then supplied from Line 2. A transformer fault causes the automatic opening of the appropriate transformer isolator, lock-out of the transformer secondary circuit breaker and reclosure of circuit breaker 120. Facilities for dead line charging or reclosure with synchronism check are provided for each circuit breaker. 14.12.3 Four-Switch Mesh Substation The mesh substation shown in Figure 14.10 is extensively used by some utilities, either in full or part. The basic mesh has a feeder at each corner, as shown at mesh corners MC2, MC3 and MC4. One or two transformers may also be banked at a mesh corner, as shown at MC1. Mesh corner protection is required if more than one circuit is fed from a mesh corner, irrespective of the CT locations – see Chapter 15 for more details. 14.12.2 Single Switch Substation The arrangement shown in Figure 14.9 consists basically of two transformer feeders interconnected by a single circuit breaker 120. Each transformer therefore has an alternative source of supply in the event of loss of one or other of the feeders. Figure 14.10: Four-switch mesh substation Considerable problems can are encountered in the application of auto-reclosing to the mesh substation. For example, circuit breakers 120 and 420 in Figure 14.10 are tripped out for a variety of different types of fault associated with mesh corner 1 (MC1), and each requires different treatment as far as autoreclosing is concerned. Further variations occur if the faults are persistent. Following normal practice, circuit breakers must be reclosed in sequence, so sequencing circuits are necessary for the four mesh breakers. Closing priority may be in any order, but is normally 120, 220, 320, and 420. Figure 14.9: Single switch substation For example, a transient fault on Line 1 causes tripping of circuit breakers 120 and B1 followed by reclosure of CB 120. If the reclosure is successful, Transformer T1 is re-energised and circuit breaker B1 recloses after a short time delay. If the line fault is persistent, 120 trips again and the motorised line isolator 103 is automatically opened. Circuit breaker 120 A summary of facilities is now given, based on mesh corner MC1 to show the inclusion of banked transformers; facilities at other corners are similar but omit the operation of equipment solely associated with the banked transformers. 14.12.3.1 Transient fault on Line 1 Tripping of circuit breakers 120, 420, G1A and G1B is followed by reclosure of 120 to give dead line charging of Line 1. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 14-13 Network Protection & Automation Guide Breaker 420 recloses in sequence, with a synchronism check. Breakers G1A, G1B reclose with a synchronism check if necessary. 14.12.3.2 Persistent fault on Line 1 Circuit breaker 120 trips again after the first reclosure and isolator 103 is automatically opened to isolate the faulted line. Breakers 120, 420, G1A, and G1B then reclose in sequence as above. 14.12.3.3 Transformer fault (local transformer 1A) Automatic opening of isolator 113A to isolate the faulted transformer follows tripping of circuit breakers 120, 420, G1A and G1B. Breakers 120, 420 and G1B then reclose in sequence, and breaker G1A is locked out. be energised from each diameter, shown as Line 1 and Line 2. It can therefore be seen that the ratio of circuit breakers to lines is one-and-a-half, or breaker and a half. The advantage of such a topology is that it reduces the number of costly circuit breakers required, compared to a double-bus installation, but also it means that for any line fault, the associated protection relay(s) must trip two circuit breakers to isolate it. Any autoreclose scheme will then need to manage the closure of two breakers (e.g. CB1 and CB2 for reclosing Line 1). Utilities usually select from one of three typical scheme philosophies in such a scenario: x Autoreclosure of an 'outer' (or 'diameter') breaker, leaving the closing of the centre breaker for manual remote control 14.12.3.4 Transformer fault (remote transformer) x A leader-follower autoreclosing scheme For a remote transformer fault, an intertrip signal is received at the local station to trip breakers 120, 420, G1A and G1B and inhibit auto-reclosing until the faulted transformer has been isolated at the remote station. If the intertrip persists for 60 seconds it is assumed that the fault cannot be isolated at the remote station. Isolator 103 is then automatically opened and circuit breakers 120, 420, G1A and G1B are reclosed in sequence. x Autoreclosure of both breakers simultaneously Bus 1 VT CB1 x 1 Line 1 Line VT CB2 3 x 14.12.3.5 Transient mesh corner fault A/R Relay Any fault covered by the mesh corner protection zone, shown in Figure 14.10, results in tripping of circuit breakers 120, 420, G1A and G1B. These are then reclosed in sequence. Line 2 CB3 There may be circumstances in which reclosure onto a persistent fault is not permitted – clearly it is not known in advance of reclosure if the fault is persistent or not. In these circumstances, scheme logic inhibits reclosure and locks out the circuit breakers. 14.12.3.6 Persistent mesh corner fault The sequence described in Section 14.12.3.5 is followed initially. When CB 120 is reclosed, it will trip again due to the fault and lock out. At this point, the logic inhibits the reclosure of CB’s 420, G1A and G1B and locks out these CBs. Line isolator 103 is automatically opened to isolate the fault from the remote station. 14.12.4Breaker and a Half Substations A simplistic example of a breaker and a half substation is shown in Figure 14.11. The substation has two busbars, Bus 1 and Bus 2, with lines being energised via a 'diameter' of three circuit breakers (CB1, CB2, CB3). Two line circuits can 14-14 1 x VT Bus 2 Figure 14.11: Breaker and a half example The first option offers re-energisation of the line, but leaves the final topology restoration task of closing CB2 to the control operator. A leader-follower scheme is one whereby just one circuit breaker is reclosed initially (CB1), and then only if this is successful, the second or 'follower' breaker (CB2) is reclosed after a set follower time delay. The advantage here is that for a persistent fault there is only the increased interrupting duty of a switch-on-to-fault trip for a single circuit breaker, not two. Should a trip and lockout occur for CB1, then CB2 will also be driven to lockout. Figure 14.11 shows how a single autoreclose relay, associated with Line 1, can exert control upon both CB1 and CB2 (it shares control of CB2 with the autoreclose relay for Line 2). It is also important that before each circuit breaker is closed, the appropriate synchronism © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 14 ˜ Auto-Reclosing check is made. For this reason, the relay requires two bus synchronising voltages as inputs, in addition to the threephase line VT input shown. CB1 can be permitted to close only if the voltage checks between Bus 1 and the Line VT are favourable, CB2 can be permitted to close only if the checks between Bus 2 and the Line VT are favourable If a utility opts for a scheme which closes two circuit breakers simultaneously, the line voltage checks against both bus voltages need to be satisfied before the relay issues synchronised closing commands. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 14-15 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 Busbar Protection 15.1 Introduction 15.2 Busbar Faults 15.3 Protection Requirements 15.4 Types of Protection System 15.5 System Protection Schemes 15.6 Frame-Earth Protection (Howard Protection) 15.7 Differential Protection Principles 15.8 High Impedance Differential Protection 15.9 Low Impedance Biased Differential Protection 15.10 Numerical Busbar Protection Schemes 15.11 Interlocked Overcurrent Busbar Schemes 15.12 Reference 15.1 INTRODUCTION The protection scheme for a power system should cover the whole system against all probable types of fault. Unrestricted forms of line protection, such as overcurrent and distance systems, meet this requirement, although faults in the busbar zone are cleared only after some time delay. But if unit protection is applied to feeders and plant, the busbars are not inherently protected. Busbars have often been left without specific protection, for one or more of the following reasons: x the busbars and switchgear have a high degree of reliability, to the point of being regarded as intrinsically safe x it was feared that accidental operation of busbar protection might cause widespread dislocation of the power system, which, if not quickly cleared, would cause more loss than would the very infrequent actual bus faults x it was hoped that system protection or back-up protection would provide sufficient bus protection if needed It is true that the risk of a fault occurring on modern metalclad gear is very small, but it cannot be entirely ignored. However, the damage resulting from one uncleared fault, because of the concentration of fault MVA, may be very extensive indeed, up to the complete loss of the station by fire. Serious damage to or destruction of the installation would probably result in widespread and prolonged supply interruption. Finally, system protection will frequently not provide the cover required. Such protection may be good enough for small distribution substations, but not for important stations. Even if distance protection is applied to all feeders, the busbar will lie in the second zone of all the distance protections, so a bus fault will be cleared relatively slowly, and the resultant duration of the voltage dip imposed on the rest of the system may not be tolerable. With outdoor switchgear the case is less clear since, although the likelihood of a fault is higher, the risk of widespread damage resulting is much less. In general then, busbar protection is required when the system protection does not Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-1 Network Protection & Automation Guide cover the busbars, or when, in order to maintain power system stability, high-speed fault clearance is necessary. Unit busbar protection provides this, with the further advantage that if the busbars are sectionalised, one section only need be isolated to clear a fault. The case for unit busbar protection is in fact strongest when there is sectionalisation. 15.2 BUSBAR FAULTS The majority of bus faults involve one phase and earth, but faults arise from many causes and a significant number are interphase clear of earth. In fact, a large proportion of busbar faults result from human error rather than the failure of switchgear components. With fully phase-segregated metalclad gear, only earth faults are possible, and a protection scheme need have earth fault sensitivity only. In other cases, an ability to respond to phase faults clear of earth is an advantage, although the phase fault sensitivity need not be very high. 15.3 PROTECTION REQUIREMENTS Although not basically different from other circuit protection, the key position of the busbar intensifies the emphasis put on the essential requirements of speed and stability. The special features of busbar protection are discussed below. 15.3.1 Speed Busbar protection is primarily concerned with: x limitation of consequential damage x removal of busbar faults in less time than could be achieved by back-up line protection, with the object of maintaining system stability Some early busbar protection schemes used a low impedance differential system having a relatively long operation time, of up to 0.5 seconds. The basis of most modern schemes is a differential system using either low impedance biased or high impedance unbiased relays capable of operating in a time of the order of one cycle at a very moderate multiple of fault setting. To this must be added the operating time of any tripping relays, but an overall tripping time of less than two cycles can be achieved. With high-speed circuit breakers, complete fault clearance may be obtained in approximately 0.1 seconds. When a frame-earth system is used, the operating speed is comparable. 15.3.2 Stability The stability of bus protection is of paramount importance. Bearing in mind the low rate of fault incidence, amounting to no more than an average of one fault per busbar in twenty 15-2 years, it is clear that unless the stability of the protection is absolute, the degree of disturbance to which the power system is likely to be subjected may be increased by the installation of bus protection. The possibility of incorrect operation has, in the past, led to hesitation in applying bus protection and has also resulted in application of some very complex systems. Increased understanding of the response of differential systems to transient currents enables such systems to be applied with confidence in their fundamental stability. The theory of differential protection is given later in section 15.7. Notwithstanding the complete stability of a correctly applied protection system, dangers exist in practice for a number of reasons. These are: x interruption of the secondary circuit of a current transformer will produce an unbalance, which might cause tripping on load depending on the relative values of circuit load and effective setting. It would certainly do so during a through fault, producing substantial fault current in the circuit in question x a mechanical shock of sufficient severity may cause operation, although the likelihood of this occurring with modern numerical schemes is reduced x accidental interference with the relay, arising from a mistake during maintenance testing, may lead to operation In order to maintain the high order of integrity needed for busbar protection, it is an almost invariable practice to make tripping depend on two independent measurements of fault quantities. Moreover, if the tripping of all the breakers within a zone is derived from common measuring relays, two separate elements must be operated at each stage to complete a tripping operation. The two measurements may be made by two similar differential systems, or one differential system may be checked by a frame-earth system, by earth fault relays energised by current transformers in the transformer neutral-earth conductors or by voltage or overcurrent relays. Alternatively, a frame-earth system may be checked by earth fault relays. If two systems of the unit or other similar type are used, they should be energised by separate current transformers in the case of high impedance unbiased differential schemes. The duplicate ring CT cores may be mounted on a common primary conductor but independence must be maintained throughout the secondary circuit. In the case of low impedance, biased differential schemes that cater for unequal ratio CTs, the scheme can be energised from either one or two separate sets of main current transformers. The criteria of double feature operation before tripping can be © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection maintained by the provision of two sets of ratio matching interposing CTs per circuit. When multi-contact tripping relays are used, these are also duplicated, one being energised from each discriminating relay; the contacts of the tripping relay are then series-connected in pairs to provide tripping outputs. Separate tripping relays, each controlling one breaker only, are usually preferred. The importance of such relays is then no more than that of normal circuit protection, so no duplication is required at this stage. Not least among the advantages of using individual tripping relays is the simplification of trip circuit wiring, compared with taking all trip circuits associated with a given bus section through a common multi-contact tripping relay. In double busbar installations, a separate protection system is applied to each section of each busbar. An overall check system is also provided, covering all sections of both busbars. The separate zones are arranged to overlap the busbar section switches, so that a fault on the section switch trips both the adjacent zones. This has sometimes been avoided in the past by giving the section switch a time advantage; the section switch is tripped first and the remaining breakers delayed by 0.5 seconds. Only the zone on the faulty side of the section switch will remain operated and trip, the other zone resetting and retaining that section in service. This gain, applicable only to very infrequent section switch faults, is obtained at the expense of seriously delaying the bus protection for all other faults. This practice is therefore not generally favoured. Some variations are dealt with later under the more detailed scheme descriptions. There are many combinations possible, but the essential principle is that no single accidental incident of a secondary nature shall be capable of causing an unnecessary trip of a bus section. Security against maloperation is only achieved by increasing the amount of equipment that is required to function to complete an operation; and this inevitably increases the statistical risk that a tripping operation due to a fault may fail. Such a failure, leaving aside the question of consequential damage, may result in disruption of the power system to an extent as great, or greater, than would be caused by an unwanted trip. The relative risk of failure of this kind may be slight, but it has been thought worthwhile in some instances to provide a guard in this respect as well. Security of both stability and operation is obtained by providing three independent channels (say X, Y and Z) whose outputs are arranged in a ‘two-out-of three’ voting arrangement, as shown in Figure 15.1. Figure 15.1: Two-out-of-three principle 15.4 TYPES OF PROTECTION SYSTEM A number of busbar protection systems have been devised: a. system protection used to cover busbars b. frame-earth protection c. differential protection d. phase comparison protection e. directional blocking protection Of these, (a) is suitable for small substations only. Type (d) is often seen nowadays only as a supervision check element within biased differential numerical schemes. Type (e) is receiving greater acceptance nowadays when implemented as IEC 61850 GOOSE-based schemes using overcurrent relays, as described in section 15.11. Detailed discussion of types (b) and (c) occupies most of this chapter. Early forms of biased differential protection for busbars, such as versions of 'Translay' protection and also a scheme using harmonic restraint, were superseded by unbiased high impedance differential protection. The relative simplicity of the latter, and more importantly the relative ease with which its performance can be calculated, have ensured its success up to the present day. But in the 1980’s the advances in semiconductor technology, coupled with a more pressing need to be able to accommodate CTs of unequal ratio, led to the re-introduction of biased schemes, generally using static relay designs, particularly for the most extensive and onerous applications. Frame-earth protection systems have been in use for many years, mainly associated with smaller busbar protection schemes at distribution voltages and for metalclad busbars (e.g. SF6 insulated busbars). However, it has often been quite common for a unit protection scheme to be used in addition, to provide two separate means of fault detection. The different types of protection are described in the following sections. 15.5 SYSTEM PROTECTION SCHEMES System protection that includes overcurrent or distance systems will inherently give protection cover to the busbars. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-3 Network Protection & Automation Guide Overcurrent protection will only be applied to relatively simple distribution systems, or as a back-up protection, set to give a considerable time delay. Distance protection will provide cover for busbar faults with its second and possibly subsequent zones. In both cases the busbar protection obtained is slow and suitable only for limiting the consequential damage. The only exception is the case of a mesh-connected substation, in which the current transformers are located at the circuit breakers. Here, the busbars are included, in sections, in the individual zones of the main circuit protection, whether this is of unit type or not. In the special case when the current transformers are located on the line side of the mesh, the circuit protection will not cover the busbars in the instantaneous zone and separate busbar protection, known as mesh-corner protection, is generally used see section 15.7.2 for details. 15.6 FRAME-EARTH PROTECTION (HOWARD PROTECTION) Frame leakage protection has been extensively used in the past in many different situations. There are several variations of frame leakage schemes available, providing busbar protection schemes with different capabilities. The following sections schemes have thus been retained for historical and general reference purposes. A considerable number of schemes are still in service and frame leakage may provide an acceptable solution in particular circumstances. However, the need to insulate the switchboard frame and provide cable gland insulation and the availability of alternative schemes using numerical relays, has contributed to a decline in use of frame leakage systems. 15.6.1 Single-Busbar Frame-Earth Protection This is purely an earth fault system and, in principle, involves simply measuring the fault current flowing from the switchgear frame to earth. A current transformer is mounted on the earthing conductor and is used to energise a simple instantaneous relay as shown in Figure 15.2. Figure 15.2: Single zone frame-earth protection No other earth connections of any type, including incidental connections to structural steelwork are allowed. This requirement is so that: x the principal earth connection and current transformer are not shunted, thereby raising the effective setting. An increased effective setting gives rise to the possibility of relay maloperation. This risk is small in practice x earth current flowing to a fault elsewhere on the system cannot flow into or out of the switchgear frame via two earth connections, as this might lead to a spurious operation The switchgear must be insulated as a whole, usually by standing it on concrete. Care must be taken that the foundation bolts do not touch the steel reinforcement; sufficient concrete must be cut away at each hole to permit grouting-in with no risk of touching metalwork. The insulation to earth finally achieved will not be high, a value of 10 ohms being satisfactory. When planning the earthing arrangements of a frame-leakage scheme, the use of one common electrode for both the switchgear frame and the power system neutral point is preferred, because the fault path would otherwise include the two earthing electrodes in series. If either or both of these are of high resistance or have inadequate current carrying capacity, the fault current may be limited to such an extent that the protection equipment becomes inoperative. In addition, if the electrode earthing the switchgear frame is the offender, the potential of the frame may be raised to a dangerous value. The use of a common earthing electrode of 15-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection adequate rating and low resistance ensures sufficient current for scheme operation and limits the rise in frame potential. When the system is resistance earthed, the earthing connection from the switchgear frame is made between the bottom of the earthing resistor and the earthing electrode. Figure 15.3 illustrates why a lower limit of 10 ohms insulation resistance between frame and earth is necessary. Outgoing feeder Switchgear frame Frame-leakage current transformer IF=I1+I2 frame is also sub-divided, the sections mutually insulated, and each provided with a separate earth conductor, current transformer and relay. Ideally, the section switch should be treated as a separate zone, as shown in Figure 15.4, and provided with either a separate relay or two secondaries on the frame-leakage current transformer, with an arrangement to trip both adjacent zones. The individual zone relays trip their respective zone and the section switch. Switchgear frame bonding bar Generator System earthing resistor Earth bar I1+I2 I1 I1 Frame insulation resistance to earth I2 Earthing electrode resistance Figure 15.3: Current distribution for external fault Under external fault conditions, the current IF flows through the frame-leakage current transformer. If the insulation resistance is too low, sufficient current may flow to operate the frame-leakage relay, and, as the check feature is unrestricted, this will also operate to complete the trip circuit. The earth resistance between the earthing electrode and true earth is seldom greater than 1:, so with 10: insulation resistance the current I1 is limited to 10% of the total earth fault current I1 and I2. For this reason, the recommended minimum setting for the scheme is about 30% of the minimum earth fault current. Figure 15.4: Three zone frame-earth scheme If it is inconvenient to insulate the section switch frame on one side, this switch may be included in that zone. It is then necessary to intertrip the other zone after approximately 0.5 seconds if a fault persists after the zone including the section switch has been tripped. This is illustrated in Figure 15.5. All cable glands must be insulated, to prevent the circulation of spurious current through the frame and earthing system by any voltages induced in the cable sheath. Preferably, the gland insulation should be provided in two layers or stages, with an interposing layer of metal, to facilitate the testing of the gland insulation. A test level of 5kV from each side is suitable. 15.6.2 Frame-Earth Protection - Sectioned Busbars Section 15.6.1 covered the basic requirements for a system to protect switchgear as a whole. When the busbar is divided into sections, these can be protected separately, provided the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-5 Network Protection & Automation Guide Insulation barriers Zone J M Zone H Zone G L j1 g1 h1 K j2 N Zone H relay I Zone G relay I _ + g1 K j1 M1 M2 Figure 15.5: Frame-earth scheme: bus section breaker insulated on one side only For the above schemes to function it is necessary to have a least one infeed or earthed source of supply, and in the latter case it is essential that this source of supply be connected to the side of the switchboard not containing the section switch. Further, if possible, it is preferable that an earthed source of supply be provided on both sides of the switchboard, in order to ensure that any faults that may develop between the insulating barrier and the section switch will continue to be fed with fault current after the isolation of the first half of the switchboard, and thus allow the fault to be removed. Of the two arrangements, the first is the one normally recommended, since it provides instantaneous clearance of busbar faults on all sections of the switchboard. 15.6.3 Frame-Earth Scheme - Double Bus Substation It is not generally feasible to separately insulate the metal enclosures of the main and auxiliary busbars. Protection is therefore generally provided as for single bus installations, but with the additional feature that circuits connected to the auxiliary bus are tripped for all faults, as shown in Figure 15.6. L1 Tripping relays L2 h1 N G HJ D.C. zone bus wires j2 Busbar isolator auxiliary switches Figure 15.6: Frame-earth scheme for double busbar substation 15.6.4 Frame-Earth Protection - Check System On all but the smallest equipments, a check system should be provided to guard against such contingencies as operation due to mechanical shock or mistakes made by personnel. Faults in the low voltage auxiliary wiring must also be prevented from causing operation by passing current to earth through the switchgear frame. A useful check is provided by a relay energised by the system neutral current, or residual current. If the neutral check cannot be provided, the frame-earth relays should have a short time delay. When a check system is used, instantaneous relays can be used, with a setting of 30% of the minimum earth fault current and an operating time at five times setting of 15 milliseconds or less. Figure 15.7 shows a frame-leakage scheme for a metalclad switchgear installation similar to that shown in Figure 15.4 and incorporating a neutral current check obtained from a suitable zero sequence current source, such as that shown in Figure 15.2. 15-6 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection + - Trip relays 64A-1 GH K 64B-1 In Out CSS-G 64CH-1 15.7 DIFFERENTIAL PROTECTION PRINCIPLES L1 CSS-H The Merz-Price principle is applicable to a multi-terminal zone such as a busbar. The principle is a direct application of Kirchhoff's first law. Usually, the circulating current arrangement is used, in which the current transformers and interconnections form an analogue of the busbar and circuit connections. A relay connected across the CT bus wires represents a fault path in the primary system in the analogue and hence is not energised until a fault occurs on the busbar; it then receives an input that, in principle at least, represents the fault current. L2 M L5 64A-2 64CH-2 I > 64B-2 74-1 74-2 In Out L3 L4 CSS-G L3 L4 CSS-H 74 CSS L3 L4 L5 L6 isolating switches - one switch per zone - are provided in the trip supply circuits and an alarm cancellation relay is used. L6 Alarm cancellation relay Control selector switch protection in/protection out Busbar protection in service lamp Busbar protection out of service lamp Tripping supply healthy lamp Alarm and indication supply healthy lamp The scheme may consist of a single relay connected to the bus wires connecting all the current transformers in parallel, one set per circuit, associated with a particular zone, as shown in Figure 15.8(a). This will give earth fault protection for the busbar. This arrangement has often been thought to be adequate. If the current transformers are connected as a balanced group for each phase together with a three-element relay, as shown in Figure 15.8(b), additional protection for phase faults can be obtained. Differential relay G H J K Id > Figure 15.7: Typical tripping and alarm circuits for a frame-leakage scheme The protection relays used for the discriminating and check functions are of the attracted armature type, with two normally open self reset contacts. The tripping circuits cannot be complete unless both the discriminating and check relays operate; this is because the discriminating and check relay contacts are connected in series. The tripping relays are of the attracted armature type. a) Basic circulating current scheme (earth fault protection only) G H It is usual to supervise the satisfactory operation of the protection scheme with audible and visual alarms and indications for the following: x busbar faults x busbar protection in service x busbar protection out of service A B C N Differential relay Id > Id > Id > x tripping supply healthy x alarm supply healthy To enable the protection equipment of each zone to be taken out of service independently during maintenance periods, b) Phase and earth fault circulating current scheme using three-element relay Figure 15.8: Circulating current scheme The phase and earth fault settings are identical, and this © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-7 Network Protection & Automation Guide scheme is recommended for its ease of application and good performance. 15.7.1 Differential Protection for Sectionalised and Duplicate Busbars Each section of a divided bus is provided with a separate circulating current system. The zones so formed are overlapped across the section switches, so that a fault on the latter will trip the two adjacent zones. This is illustrated in Figure 15.9. Tripping two zones for a section switch fault can be avoided by using the time-delayed technique of section 15.6.2. However instantaneous operation is the preferred choice. other and also the individual circuit protections. The overlap should occur across a circuit breaker, so that the latter lies in both zones. For this arrangement it is necessary to install current transformers on both sides of the circuit breakers, which is economically possible with many but not all types of switchgear. With both the circuit and the bus protection current transformers on the same side of the circuit breakers, the zones may be overlapped at the current transformers, but a fault between the CT location and the circuit breaker will not be completely isolated. This matter is important in all switchgear to which these conditions apply, and is particularly important in the case of outdoor switchgear where separately mounted, multi-secondary current transformers are generally used. The conditions are shown in Figure 15.10. (a) Zone A (b) Zone B Bus protection BS Fault BC BC Zone C Circuit protection Figure 15.9: Zones of protection for double bus station a. Current transformers mounted on both sides of breaker -no unprotected region For double bus installation, the two busbars will be treated as separate zones. The auxiliary busbar zone will overlap the appropriate main busbar zone at the bus coupler. b. Current transformers mounted on circuit side only of breaker -fault shown not cleared by circuit protection Figure 15.10: Unprotected zone with current transformers mounted on one side of the circuit breaker only Since any circuit may be transferred from one busbar to the other by isolator switches, these and the associated tripping circuit must also be switched to the appropriate zone by 'early make' and 'late break' auxiliary contacts. This is to ensure that when the isolators are closing, the auxiliary switches make before the main contacts of the isolator, and that when the isolators are opened, their main contacts part before the auxiliary switches open. The result is that the secondary circuits of the two zones concerned are briefly paralleled while the circuit is being transferred; these two zones have in any case been united through the circuit isolators during the transfer operation. Figure 15.10(a) shows the ideal arrangement in which both the circuit and busbar zones are overlapped leaving no region of the primary circuit unprotected. 15.7.2 Location of Current Transformers With reference to Figure 15.10(b), special ‘short zone’ protection can be provided to detect that the circuit breaker Ideally, the separate discriminating zones should overlap each 15-8 Figure 15.10(b) shows how mounting all current transformers on the circuit side of the breaker results in a small region of the primary circuit unprotected. This unprotected region is typically referred to as the ‘short zone’. The fault shown will cause operation of the busbar protection, tripping the circuit breaker, but the fault will continue to be fed from the circuit, if a source of power is present. It is necessary for the bus protection to intertrip the far end of the circuit protection, if the latter is of the unit type. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection has opened but that the fault current is still flowing. Under these conditions, the protection can initiate an intertrip to the remote end of the circuit. This technique may be used, particularly when the circuit includes a generator. In this case the intertrip proves that the fault is in the switchgear connections and not in the generator; the latter is therefore tripped electrically but not shut down on the mechanical side so as to be immediately ready for further service if the fault can be cleared. 15.7.2.1 CT locations for mesh-connected substations The protection of busbars in mesh connected substations gives rise to additional considerations in respect of CT location. A single mesh corner is shown in Figure 15.11(a). Where only one connection to the mesh is made at a corner, CTs located as shown will provide protection not only to the line but the corner of the mesh included between them. However, this arrangement cannot be used where more than one connection is made to a mesh corner. This is because a fault on any of the connected circuits would result in disconnection of them all, without any means of determining the faulted connection. Protection CTs must therefore be located on each connection, as shown in Figure 15.11(b). This leaves the corner of the mesh unprotected, so additional CTs and a relay to provide mesh-corner protection are added, as also shown in Figure 15.11(b). Mesh corner (Note 1) Line protection relay Note 1: Only 1 connection to the mesh corner permitted (a) CT arrangements for protection including mesh corner Transformer protection 15.8 HIGH IMPEDANCE DIFFERENTIAL PROTECTION This form of protection is still in common use. The considerations that have to be taken into account are detailed in the following sections. 15.8.1 Stability The incidence of fault current with an initial unilateral transient component causes an abnormal build-up of flux in a current transformer, as described in section 15.8.2. When throughfault current traverses a zone protected by a differential system, the transient flux produced in the current transformers is not detrimental as long as it remains within the substantially linear range of the magnetising characteristic. With fault current of appreciable magnitude and long transient time constant, the flux density will pass into the saturated region of the characteristic; this will not in itself produce a spill output from a pair of balancing current transformers provided that these are identical and equally burdened. A group of current transformers, though they may be of the same design, will not be completely identical, but a more important factor is inequality of burden. In the case of a differential system for a busbar, an external fault may be fed through a single circuit, the current being supplied to the busbar through all other circuits. The faulted circuit is many times more heavily loaded than the others and the corresponding current transformers are likely to be heavily saturated, while those of the other circuits are not. Severe unbalance is therefore probable, which, with a relay of normal burden, could exceed any acceptable current setting. For this reason such systems were at one time always provided with a time delay. This practice is, however, no longer acceptable. It is not feasible to calculate the spill current that may occur, but, fortunately, this is not necessary; an alternative approach provides both the necessary information and the technique required to obtain a high performance. An equivalent circuit, as in Figure 15.12, can represent a circulating current system. Mesh corner (Note 2) Line protection Mesh corner protection Note 2: Multiple circuits may be connected to the mesh corner (b) CT arrangements for protection - additional mesh corner protection required Figure 15.11: Mesh-corner protection © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-9 Network Protection & Automation Guide IR I f ( RLH  RCTH ) RR Vf RR Equation 15.3 or alternatively: G H RCTG RLG RLH I R RR ZEH Id > Figure 15.12: Equivalent circuit of circulating current system The current transformers are replaced in the diagram by ideal current transformers feeding an equivalent circuit that represents the magnetising losses and secondary winding resistance, and also the resistance of the connecting leads. These circuits can then be interconnected as shown, with a relay connected to the junction points to form the complete equivalent circuit. Saturation has the effect of lowering the exciting impedance, and is assumed to take place severely in current transformer H until, at the limit, the shunt impedance becomes zero and the CT can produce no output. This condition is represented by a short circuit, shown in broken line, across the exciting impedance. It should be noted that this is not the equivalent of a physical short circuit, since it is behind the winding resistance RCTH. Applying the Thévenin method of solution, the voltage developed across the relay will be given by: Vf I f RLH  RCTH Equation 15.1 The current through the relay is given by: IR Vf I f ( RLH  RCTH ) RR  RLH  RCTH RR  RLH  RCTH Equation 15.2 If RR is small, IR will approximate to If, which is unacceptable. On the other hand, if RR is large IR is reduced. Equation 15.2 can be written, with little error, as follows: 15-10 I f RLH  RCTH Equation 15.4 RCTH RR ZEG Vf It is clear that, by increasing RR, the spill current IR can be reduced below any specified relay setting. RR is frequently increased by the addition of a series-connected resistor which is known as the stabilising resistor. It can also be seen from Equation 15.4 that it is only the voltage drop in the relay circuit at setting current that is important. The relay can be designed as a voltage measuring device consuming negligible current; and provided its setting voltage exceeds the value Vf of Equation 15.4, the system will be stable. In fact, the setting voltage need not exceed Vf, since the derivation of Equation 15.4 involves an extreme condition of unbalance between the G and H current transformers that is not completely realised. So a safety margin is built-in if the voltage setting is made equal to Vf. It is necessary to realise that the value of If to be inserted in Equation 15.4 is the complete function of the fault current and the spill current IR through the relay, in the limiting condition, will be of the same form. If the relay requires more time to operate than the effective duration of the d.c. transient component, or has been designed with special features to block the d.c. component, then this factor can be ignored and only the symmetrical value of the fault current need be entered in Equation 15.4. If the relay setting voltage, VS , is made equal to Vf, that is, If (RL + RCT), an inherent safety factor of the order of two will exist. In the case of a faster relay, capable of operating in one cycle and with no special features to block the d.c. component, it is the r.m.s. value of the first offset wave that is significant. This value, for a fully offset waveform with no d.c. decrement, is 3If. If settings are then chosen in terms of the symmetrical component of the fault current, the 3 factor which has been ignored will take up most of the basic safety factor, leaving only a very small margin. Finally, if a truly instantaneous relay were used, the relevant value of If would be the maximum offset peak. In this case, the factor has become less than unity, possibly as low as 0.7. It is therefore possible to rewrite Equation 15.4 as: © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection I SL K u VS RL  RCT Equation 15.5 where: ISL = stability limit of scheme VS = relay circuit voltage setting RL + RCT = lead + CT winding resistance converted to the primary operating current by multiplying by the turns ratio of the current transformers. The operating current so determined should be considered in terms of the conditions of the application. For a phase and earth fault scheme the setting can be based on the fault current to be expected for minimum plant and maximum system outage conditions. However, it should be remembered that: K = factor depending on relay design (range 0.7 - 2.0) x phase-phase faults give only 86% of the three-phase fault current It remains to be shown that the setting chosen is suitable in section 15.8.2. x fault arc resistance and earth path resistance reduce fault currents somewhat The current transformers will have an excitation curve which has not so far been related to the relay setting voltage, the latter being equal to the maximum nominal voltage drop across the lead loop and the CT secondary winding resistance, with the maximum secondary fault current flowing through them. Under in-zone fault conditions it is necessary for the current transformers to produce sufficient output to operate the relay. This will be achieved provided the CT knee-point voltage exceeds the relay setting. In order to cater for errors, it is usual to specify that the current transformers should have a knee-point e.m.f. of at least twice the necessary setting voltage; a higher multiple is of advantage in ensuring a high speed of operation. 15.8.2 Effective Setting or Primary Operating Current The minimum primary operating current is a further criterion of the design of a differential system. The secondary effective setting is the sum of the relay minimum operating current and the excitation losses in all parallel connected current transformers, whether carrying primary current or not. This summation should strictly speaking be vectorial, but is usually done arithmetically. It can be expressed as: IR I S  nI eS Equation 15.6 where: IR = effective setting IS = relay circuit setting current IeS = CT excitation current at relay voltage setting n = number of parallel connected CTs Having established the relay setting voltage from stability considerations, as shown in section 15.8.1, and knowing the excitation characteristic of the current transformers, the effective setting can be computed. The secondary setting is x a reasonable margin should be allowed to ensure that relays operate quickly and decisively It is desirable that the primary effective setting should not exceed 30% of the prospective minimum fault current. In the case of a scheme exclusively for earth fault protection, the minimum earth fault current should be considered, taking into account any earthing impedance that might be present as well. Furthermore, in the event of a double phase to earth fault, regardless of the inter-phase currents, only 50% of the system e.m.f. is available in the earth path, causing a further reduction in the earth fault current. The primary operating current must therefore be not greater than 30% of the minimum single-phase earth fault current. In order to achieve high-speed operation, it is desirable that settings should be still lower, particularly in the case of the solidly earthed power system. The transient component of the fault current in conjunction with unfavourable residual flux in the CT can cause a high degree of saturation and loss of output, possibly leading to a delay of several cycles additional to the natural operating time of the element. This will not happen to any large degree if the fault current is a larger multiple of setting; for example, if the fault current is five times the scheme primary operating current and the CT knee-point e.m.f. is three times the relay setting voltage, the additional delay is unlikely to exceed one cycle. The primary operating current is sometimes designed to exceed the maximum expected circuit load in order to reduce the possibility of false operation under load current as a result of a broken CT lead. Desirable as this safeguard may be, it will be seen that it is better not to increase the effective current setting too much, as this will sacrifice some speed; the check feature in any case, maintains stability. An overall earth fault scheme for a large distribution board may be difficult to design because of the large number of current transformers paralleled together, which may lead to an © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-11 Network Protection & Automation Guide excessive setting. It may be advantageous in such a case to provide a three-element phase and earth fault scheme, mainly to reduce the number of current transformers paralleled into one group. + 87M1-1 M1 M2 R In Out CSS-M2 87R-1 a1 c1 96 D2 96 E CSS-R Extra-high-voltage substations usually present no such problem. Using the voltage-calibrated relay, the current consumption can be very small. A simplification can be achieved by providing one relay per circuit, all connected to the CT paralleling buswires. This enables the trip circuits to be confined to the least area and reduces the risk of accidental operation. b1 c2 96 F2 96 H2 D.C. Buswires 87CH-2 96 F1 96 G 96 H1 80 T 87M1-2 30 M1 87M2-2 30 M2 87R-2 95M1-1 95 M1X 95M2-1 95R-1 15.8.3 Check Feature 30M1-1 Any interruption of a CT secondary circuit up to the paralleling interconnections will cause an unbalance in the system, equivalent to the load being carried by the relevant primary circuit. Even though this degree of spurious output is below the effective setting the condition cannot be ignored, since it is likely to lead to instability under any through fault condition. 30M2-1 74-1 30R-1 95M1X-1 74-2 95 M2X 95 CHX 74 95M2X-1 95CHX-1 In Out L1 L2 CSS-M1 L1 L2 CSS-M2 L1 L2 CSS-R 30 74 80 87 95 80 I Zone indicating relay Alarm cancellation relay D.C. volts supervision relay High impedance circulating current relay Bus wires supervision relay 95X Zone bus wires shorting relay CSS Control selector switch L1 Indicating lamp protection in service L2 Indicating lamp protection out of service Figure 15.13: D.C. circuits for high impedance circulating current scheme Supervision can be carried out to detect such conditions by connecting a sensitive alarm relay across the bus wires of each zone. For a phase and earth fault scheme, an internal threephase rectifier can be used to effect a summation of the bus wire voltages on to a single alarm element; see Figure 15.14 and Figure 15.13. The alarm relay is set so that operation does not occur with the protection system healthy under normal load. Subject to this proviso, the alarm relay is made as sensitive as possible; the desired effective setting is 125 primary amperes or 10% of the lowest circuit rating, whichever is the greater. Since a relay of this order of sensitivity is likely to operate during through faults, a time delay, typically of three seconds, is applied to avoid unnecessary alarm signals. 15-12 30 R 95RX-1 For phase fault schemes, the check will usually be a similar type of scheme applied to the switchboard as a single overall zone. A set of current transformers separate from those used in the discriminating zones should be provided. No CT switching is required and no current transformers are needed for the check zone in bus-coupler and bus-section breakers. 15.8.4 Supervision of CT Secondary Circuits 95 RX 95CH-1 Schemes for earth faults only can be checked by a frame-earth system, applied to the switchboard as a whole, no subdivision being necessary. 87CH-1 96 D1 CSS-M1 87M2-1 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection Zone R c1 c2 H D Zone M1 Zone M2 b1 a1 E G F c1 c2 a1 Zone M1 Bus wires b1 A B C A B C A B C N A B C N Zone R Bus wires Check zone Bus wires Zone M2 Bus wires 95 CHX-2 95 CHX-3 Zone R relay same as check Zone M1 relay same as check M1 First main busbar M2 Second main busbar R Reserve busbar + _ 95 CHX-4 Zone M2 relay same as check Stabilising Resistor 95 CH v v Id Id Supervision Relay Metrosil (non-linear resistor) Figure 15.14: A.C. circuits for high impedance circulating current scheme for duplicate busbars 15.8.5 Arrangement of CT Connections It is shown in Equation 15.4 how the setting voltage for a given stability level is directly related to the resistance of the CT secondary leads. This should therefore be kept to a practical minimum. Taking into account the practical physical laying of auxiliary cables, the CT bus wires are best arranged in the form of a ring around the switchgear site. In a double bus installation, the CT leads should be taken directly to the isolator selection switches. The usual arrangement of cables on a double bus site is as follows: x current transformers to marshalling kiosk x marshalling kiosk to bus selection isolator auxiliary switches x interconnections between marshalling kiosks to form a closed ring The relay for each zone is connected to one point of the ring bus wire. For convenience of cabling, the main zone relays will be connected through a multicore cable between the relay v Id High Impedance Circulating Current Relay panel and the bus section-switch marshalling cubicle. The reserve bar zone and the check zone relays will be connected together by a cable running to the bus coupler circuit breaker marshalling cubicle. It is possible that special circumstances involving onerous conditions may over-ride this convenience and make connection to some other part of the ring desirable. Connecting leads will usually be not less than 7/0.67mm (2.5mm2), but for large sites or in other difficult circumstances it may be necessary to use cables of, for example 7/1.04mm (6mm2) for the bus wire ring and the CT connections to it. The cable from the ring to the relay need not be of the larger section. When the reserve bar is split by bus section isolators and the two portions are protected as separate zones, it is necessary to common the bus wires by means of auxiliary contacts, thereby making these two zones into one when the section isolators are closed. 15.8.6 Summary of Practical Details This section provides a summary of practical considerations when implementing a high-impedance busbar protection © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-13 Network Protection & Automation Guide scheme. 15.8.6.1 Designed stability level For normal circumstances, the stability level should be designed to correspond to the switchgear rating; even if the available short-circuit power in the system is much less than this figure, it can be expected that the system will be developed up to the limit of rating. 15.8.6.2 Current transformers Current transformers must have identical turns ratios, but a turns error of one in 400 is recognised as a reasonable manufacturing tolerance. Also, they should preferably be of similar design; where this is not possible the magnetising characteristics should be reasonably matched. Current transformers for use with high impedance protection schemes should meet the requirements of Class PX of IEC 60044-1. advantageous to keep the secondary fault current low; this is done by making the CT turns ratio high. It is common practice to use current transformers with a secondary rating of 1A. It can be shown that there is an optimum turns ratio for the current transformers; this value depends on all the application parameters but is generally about 2000/1. Although a lower ratio, for instance 400/1, is often employed, the use of the optimum ratio can result in a considerable reduction in the physical size of the current transformers. 15.8.6.7 Peak voltage developed by current transformers Under in-zone fault conditions, a high impedance relay constitutes an excessive burden to the current transformers, leading to the development of a high voltage; the voltage waveform will be highly distorted but the peak value may be many times the nominal saturation voltage. When the burden resistance is finite although high, an approximate formula for the peak voltage is: Vp 15.8.6.3 Setting voltage The setting voltage is given by the equation: VS t I f RL  RCT 2 2 VK (VF  VK ) Equation 15.7 where: where: Vp = peak Voltage developed If = Steady state through fault current VK = saturation Voltage VS = relay circuit voltage setting VF = prospective Voltage in absence of saturation RL = CT lead loop resistance This formula does not hold for the open circuit condition and is inaccurate for very high burden resistances that approximate to an open circuit, because simplifying assumptions used in the derivation of the formula are not valid for the extreme condition. RCT = CT secondary winding resistance 15.8.6.4 Knee-point voltage of current transformers This is given by the formula: Another approach applicable to the open circuit secondary condition is: VK t 2VS 15.8.6.5 Effective setting (secondary) Vp The effective setting of the relay is given by: IR If I ek VK Equation 15.8 I S  nI eS where: where: IS = relay circuit setting current IeS = CT excitation current at relay voltage setting n = number of parallel connected CTs For the primary fault setting multiply IR by the CT turns ratio. 15.8.6.6 Current transformer secondary rating It is clear from Equation 15.4 and Equation 15.6 that it is 15-14 2 If = fault current Iek = exciting current at knee-point voltage Vk = knee-point voltage Any burden connected across the secondary will reduce the voltage, but the value cannot be deduced from a simple combination of burden and exciting impedances. These formulae are therefore to be regarded only as a guide to © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection the possible peak voltage. With large current transformers, particularly those with a low secondary current rating, the voltage may be very high, above a suitable insulation voltage. The voltage can be limited without detriment to the scheme by connecting a ceramic non-linear resistor in parallel with the relay having a characteristic given by: V CI E addition of a stabilising resistor, having a value which may be calculated as follows. The through current will increase the effective relay minimum operating current for a biased relay as follows: IR I S  BI F where: where C is a constant depending on dimensions and  is a constant in the range 0.2 - 0.25. IR = effective minimum operating current The current passed by the non-linear resistor at the relay voltage setting depends on the value of C; in order to keep the shunting effect to a minimum it is recommended to use a nonlinear resistor with a value of C of 450 for relay voltages up to 175V and one with a value of C of 900 for setting voltages up to 325V. IF = through fault current 15.8.6.8 High impedance relay Instantaneous attracted armature relays or numeric relays that mimic the high impedance function are used. Simple fastoperating relays would have a low safety factor constant in the stability equation, Equation 15.5, as discussed in section 15.8.1. The performance is improved by series-tuning the relay coil, thereby making the circuit resistive in effect. Inductive reactance would tend to reduce stability, whereas the action of capacitance is to block the unidirectional transient component of fault current and so raise the stability constant. An alternative technique used in some relays is to apply the limited spill voltage principle shown in Equation 15.4. A tuned element is connected via a plug bridge to a chain of resistors; and the relay is calibrated in terms of voltage. 15.9 LOW IMPEDANCE BIASED DIFFERENTIAL PROTECTION The principles of low impedance differential protection have been described in section 10.4.2, including the principle advantages to be gained by the use of a bias technique. Most modern busbar protection schemes use this technique. The principles of a check zone, zone selection, and tripping arrangements can still be applied. Current transformer secondary circuits are not switched directly by isolator contacts but instead by isolator repeat relays after a secondary stage of current transformation. These switching relays form a replica of the busbar within the protection and provide the complete selection logic. 15.9.1 Stability With some biased relays, the stability is not assured by the through current bias feature alone, but is enhanced by the IS = relay setting current B = percentage restraint As IF is generally much greater than IS, the relay effective current, IR = BIF approximately. From Equation 15.4, the value of stabilising resistor is given by: RR I F RLH  RCTH IR RLH  RCTH B It is interesting to note that the value of the stabilising resistance is independent of current level, and that there would appear to be no limit to the through fault stability level. This has been identified [15.1] as ‘The Principle of Infinite Stability’. The stabilising resistor still constitutes a significant burden on the current transformers during internal faults. An alternative technique, used by the MBCZ system described in section 15.9.6, is to block the differential measurement during the portion of the cycle that a current transformer is saturated. If this is achieved by momentarily short-circuiting the differential path, a very low burden is placed on the current transformers. In this way the differential circuit of the relay is prevented from responding to the spill current. It must be recognised though that the use of any technique for inhibiting operation, to improve stability performance for through faults, must not be allowed to diminish the ability of the relay to respond to internal faults. 15.9.2 Effective Setting or Primary Operating Current For an internal fault, and with no through fault current flowing, the effective setting IR is raised above the basic relay setting IS by whatever biasing effect is produced by the sum of the CT magnetising currents flowing through the bias circuit. With low impedance biased differential schemes particularly where the busbar installation has relatively few circuits, these magnetising currents may be negligible, depending on the value of IS. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-15 Network Protection & Automation Guide The basic relay setting current was formerly defined as the minimum current required solely in the differential circuit to cause operation – Figure 15.15(a). This approach simplified analysis of performance, but was considered to be unrealistic, as in practice any current flowing in the differential circuit must flow in at least one half of the relay bias circuit causing the practical minimum operating current always to be higher than the nominal basic setting current. As a result, a later definition, as shown in Figure 15.15(b) was developed. Conversely, it needs to be appreciated that applying the later definition of relay setting current, which flows through at least half the bias circuit, the notional minimum operation current in the differential circuit alone is somewhat less, as shown in Figure 15.15(b). Using the definition presently applicable, the effective minimum primary operating current > N I s  B ¦ I es @ Where N = CT ratio IS Bia IB ine sL (B % ) IS I’S Bia ine sL (B % ) IB IS IB 15.9.3 Check Feature For some low impedance schemes, only one set of main CTs is required. This seems to contradict the general principle of all busbar protection systems with a check feature that complete duplication of all equipment is required, but it is claimed that the spirit of the checking principle is met by making operation of the protection dependent on two different criteria such as directional and differential measurements. In the MBCZ scheme, described in section 15.9.6, the provision of auxiliary CTs as standard for ratio matching also provides a ready means for introducing the check feature duplication at the auxiliary CTs and onwards to the relays. This may be an attractive compromise when only one set of main CTs is available. 15.9.4 Supervision of CT Secondary Circuits Iop Iop prevent the busbar protection from operating spuriously from load current should a secondary circuit wiring fault develop. This consideration is particularly important where the check feature is either not used or is fed from common main CTs. In low impedance schemes the integrity of the CT secondary circuits can also be monitored. A current operated auxiliary relay, or element of the main protection equipment, may be applied to detect any unbalanced secondary currents and give an alarm after a time delay. For optimum discrimination, the current setting of this supervision relay must be less than that of the main differential protection. In modern busbar protection schemes, the supervision of the secondary circuits typically forms only a part of a comprehensive supervision facility. IS 15.9.5 Arrangement of CT connections IR I S  BI B IR = IS B· § I 's ¨1  ¸ 2¹ © (a) Superseded definition (b) Current definition Figure 15.15: Definitions of relay setting current for biased relays Unless the minimum effective operating current of a scheme has been raised deliberately to some preferred value, it will usually be determined by the check zone, when present, as the latter may be expected to involve the greatest number of current transformers in parallel. A slightly more onerous condition may arise when two discriminating zones are coupled, transiently or otherwise, by the closing of primary isolators. It is generally desirable to attain an effective primary operating current that is just greater than the maximum load current, to 15-16 It is a common modern requirement of low impedance schemes that none of the main CT secondary circuits should be switched, in the previously conventional manner, to match the switching of primary circuit isolators. The usual solution is to route all the CT secondary circuits back to the protection panel or cubicle to auxiliary CTs. It is then the secondary circuits of the auxiliary CTs that are switched as necessary. So auxiliary CTs may be included for this function even when the ratio matching is not in question. In static protection equipment it is undesirable to use isolator auxiliary contacts directly for the switching without some form of insulation barrier. Position transducers that follow the opening and closing of the isolators may provide the latter. Alternatively, a simpler arrangement may be provided on multiple busbar systems where the isolators switch the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection auxiliary current transformer secondary circuits via auxiliary relays within the protection. These relays form a replica of the busbar and perform the necessary logic. It is therefore necessary to route all the current transformer secondary circuits to the relay to enable them to be connected into this busbar replica. Some installations have only one set of current transformers available per circuit. Where the facility of a check zone is still required, this can still be achieved with the low impedance biased protection by connecting the auxiliary current transformers at the input of the main and check zones in series, as shown in Figure 15.16. Figure 15.17: Type MBCZ busbar protection showing correlation between circuit breakers and protection modules The modules are interconnected via a multicore cable that is plugged into the back of the modules. There are five main groups of buswires, allocated for: x protection for main busbar x protection for reserve busbar x protection for the transfer busbar. When the reserve busbar is also used as a transfer bar then this group of buswires is used Figure 15.16: Alternative CT connections 15.9.6 Low Impedance Biased Differential Protection - Type MBCZ Numerical schemes are now prevalent in the majority of new busbar protection installations. However, in order to appreciate the historical installed base, and due to the similarity of the basic operating principles, this section now considers a static scheme example – the MBCZ. The Type MBCZ scheme conforms in general to the principles outlined earlier and comprises a system of standard modules that can be assembled to suit a particular busbar installation. Additional modules can be added at any time as the busbar is extended. A separate module is used for each circuit breaker and also one for each zone of protection. In addition to these there is a common alarm module and a number of power supply units. Ratio correction facilities are provided within each differential module to accommodate a wide range of CT mismatch. Figure 15.17 shows the correlation between the circuit breakers and the protection modules for a typical double busbar installation. x auxiliary connections used by the protection to combine modules for some of the more complex busbar configurations x protection for the check zone One extra module, not shown in this diagram, is plugged into the multicore bus. This is the alarm module, which contains the common alarm circuits and the bias resistors. The power supplies are also fed in through this module. 15.9.6.1 Bias All zones of measurement are biased by the total current flowing to or from the busbar system via the feeders. This ensures that all zones of measurement will have similar fault sensitivity under all load conditions. The bias is derived from the check zone and fixed at 20% with a characteristic generally as shown in Figure 15.15(b). Thus some ratio mismatch is tolerable. 15.9.6.2 Stability with saturated current transformers The traditional method for stabilising a differential relay is to add a resistor to the differential path. Whilst this improves stability it increases the burden on the current transformer for internal faults. The technique used in the MBCZ scheme overcomes this problem. The MBCZ design detects when a CT is saturated and shortcircuits the differential path for the portion of the cycle for © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-17 Network Protection & Automation Guide which saturation occurs. The resultant spill current does not then flow through the measuring circuit and stability is assured. This principle allows a very low impedance differential circuit to be developed that will operate successfully with relatively small CTs. Figure 15.19: Busbar protection trip logic 15.9.6.3 Operation for internal faults If the CTs carrying fault current are not saturated there will be ample current in the differential circuit to operate the differential relay quickly for fault currents exceeding the minimum operating level, which is adjustable between 20% 200% rated current. When the only CT(s) carrying internal fault current become saturated, it might be supposed that the CT saturation detectors may completely inhibit operation by short-circuiting the differential circuit. However, the resulting inhibit pulses remove only an insignificant portion of the differential current, so operation of the relay is therefore virtually unaffected. 15.9.6.4 Discrepancy alarm feature As shown in Figure 15.18, each measuring module contains duplicated biased differential elements and also a pair of supervision elements, which are a part of a comprehensive supervision facility. 15.9.6.5 Master/follower measuring units When two sections of a busbar are connected together by isolators it will result in two measuring elements being connected in parallel when the isolators are closed to operate the two busbar sections as a single bar. The fault current will then divide between the two measuring elements in the ratio of their impedances. If both of the two measuring elements are of low and equal impedance the effective minimum operating current of the scheme will be doubled. This is avoided by using a 'master/follower' arrangement. By making the impedance of one of the measuring elements very much higher than the other it is possible to ensure that one of the relays retains its original minimum operation current. Then to ensure that both the parallel-connected zones are tripped the trip circuits of the two zones are connected in parallel. Any measuring unit can have the role of 'master' or 'follower' as it is selectable by means of a switch on the front of the module. 15.9.6.6 Transfer tripping for breaker failure Differential t1 t1 t1 Figure 15.18: Block diagram of measuring unit This arrangement provides supervision of CT secondary circuits for both open circuit conditions and any impairment of the element to operate for an internal fault, without waiting for an actual system fault condition to show this up. For a zone to operate it is necessary for both the differential supervision element and the biased differential element to operate. For a circuit breaker to be tripped it requires the associated main zone to be operated and also the overall check zone, as shown in Figure 15.19. 15-18 Serious damage may result, and even danger to life, if a circuit breaker fails to open when called upon to do so. To reduce this risk breaker fail protection schemes were developed some years ago. These schemes are generally based on the assumption that if current is still flowing through the circuit breaker a set time after the trip command has been issued, then it has failed to function. The circuit breakers in the next stage back in the system are then automatically tripped. For a bus coupler or section breaker this would involve tripping all the infeeds to the adjacent zone, a facility that is included in the busbar protection scheme. 15.10 NUMERICAL BUSBAR PROTECTION SCHEMES The application of numeric relay technology to busbar protection has become the preferred solution, overtaking the use of static. The very latest developments in the technology can be included, such as extensive use of a data bus to link the various units involved, and fault tolerance against loss of a © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection particular link by providing multiple communications paths. The development process has been very rigorous, because the requirements for busbar protection in respect of immunity to maloperation are very high. A philosophy that can be adopted is one of distributed processing of the measured values, as shown in Figure 15.20. Feeders each have their own processing unit, which collects together information on the state of the feeder (currents, voltages, CB and isolator status, etc.) and communicates it over high-speed fibre-optic data links to a central processing unit. For large substations, more than one central processing unit may be used, while in the case of small installations, all of the units can be co-located, leading to the appearance of a traditional centralised architecture. Feeder 1 DFU Feeder 2 CT CT CT CT CB DFU CB DFU CB CB The feeder units have responsibility for collecting the required data, such as voltages and currents, and processing it into digital form for onwards transmission to the central processing unit. Modelling of the CT response is included, to eliminate errors caused by effects such as CT saturation. Disturbance recording for the monitored feeder is implemented, for later download as required. Because each feeder unit is concerned only with an individual feeder, the differential protection algorithms must reside in the central processing unit. The differential protection algorithm can be much more sophisticated than with earlier technology, due to improvements in processing power. In addition to calculating the sum of the measured currents, the algorithm can also evaluate differences between successive current samples, since a large change above a threshold may indicate a fault – the threshold being chosen such that normal load changes, apart from inrush conditions do not exceed the threshold. The same considerations can also be applied to the phase angles of currents, and incremental changes in them. Fibre optic link Personal Computer CFU Central Processing Unit CU System Communication Network DFU: Distributed Feeder Unit CFU: Central Feeder Unit Figure 15.20: Architecture for numerical protection scheme For simple feeders, interface units at a bay may be used with the data transmitted to a single centrally located feeder processing unit. The central processing unit performs the calculations required for the protection functions. Available protection functions are: One advantage gained from the use of numerical technology is the ability to easily re-configure the protection to cater for changes in configuration of the substation. For example, addition of an extra feeder involves the addition of an extra feeder unit, the fibre-optic connection to the central unit and entry via the HMI of the new configuration into the central processor unit. Figure 15.21 illustrates the latest numerical technology employed. x protection x backup overcurrent protection x breaker failure x dead zone protection (alternatively referred to as ‘short zone’ protection - see section 15.7.2) In addition, monitoring functions such as CB and isolator monitoring, disturbance recording and transformer supervision are provided. Because of the distributed topology used, synchronisation of the measurements taken by the Feeder Units is of vital importance. A high stability numerically-controlled oscillator is fitted in each of the central and feeder units, with time synchronisation between them. In the event of loss of the synchronisation signal, the high stability of the oscillator in the affected feeder unit(s) enables processing of the incoming data to continue without significant errors until synchronisation can be restored. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-19 Network Protection & Automation Guide relays, many of the functions of which are performed internally within the software algorithms  numerical schemes include sophisticated monitoring features which provide alarm facilities if the scheme is faulty. In certain cases, simulation of the scheme functions can be performed on line from the CT inputs through to the tripping outputs and thus scheme functions can be checked on a regular basis to ensure a full operational mode is available at all times Reliability analyses using fault tree analysis methods have examined issues of dependability (i.e. the ability to operate when required) and security (i.e. the ability not to provide spurious/indiscriminate operation). These analyses have shown that:  dependability of numerical schemes is better than conventional high impedance schemes  security of numerical and conventional high impedance schemes are comparable Figure 15.21: Busbar protection relay using the latest numerical technology (MiCOM P740 range) 15.10.1 Reliability Considerations In considering the introduction of numerical busbar protection schemes, users have been concerned with reliability issues such as security and availability. Conventional high impedance schemes have been one of the main protection schemes used for busbar protection. The basic measuring element is simple in concept and has few components. Calculation of stability limits and other setting parameters is straightforward and scheme performance can be predicted without the need for costly testing. Practically high impedance schemes have proved to be a very reliable form of protection. In contrast, modern numerical schemes are more complex with a much greater range of facilities and a higher component count. Based on low impedance bias techniques, and with a greater range of facilities to set, setting calculations can also be more complex. However studies of the comparative reliability of conventional high impedance schemes and modern numerical schemes have shown that assessing relative reliability is not quite so simple as it might appear. The numerical scheme has two advantages over its older counterpart:  there is a reduction in the number of external components such as switching and other auxiliary 15-20 In addition, an important feature of numerical schemes is the in-built monitoring system. This considerably improves the potential availability of numerical schemes compared to conventional schemes as faults within the equipment and its operational state can be detected and alarmed. With the conventional scheme, failure to re-instate the scheme correctly after maintenance may not be detected until the scheme is required to operate. In this situation, its effective availability is zero until it is detected and repaired. 15.11 INTERLOCKED OVERCURRENT BUSBAR SCHEMES Dedicated busbar protection, such as high impedance or biased differential, is commonplace for transmission and subtransmission systems. This ensures fast fault clearance, operating subcycle in some cases. The situation is a little different for distribution substations, where utilities take into account the large number of stations, the large number of feeder circuits, and may wish to consider an economical alternative solution. Interlocked overcurrent schemes, also described as ‘busbar blocking’ or ‘zone sequence interlocking’ schemes can offer that economical alternative. The advantage is that the busbar protection requires no dedicated relay(s) to be installed, as it is configured to operate using logic facilities already available in the feeder manager overcurrent relays installed on the incoming and outgoing feeders. As feeder protection must in any case be installed for all circuits emanating from the busbar, the only additional cost to configure the busbar protection is to design and install the means for the individual © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 15 ˜ Busbar Protection relays to communicate peer-to-peer with each other. Figure 15.22 shows a simple single incomer substation on a radial system, with four outgoing feeders. It can be appreciated that for any downstream fault, whether external to the substation, or in-zone on the busbar, the incoming feeder relay will detect the flow of fault current. The level of fault current can be similar, thus on the basis of overcurrent or earth fault detection alone, the incoming feeder relay cannot discriminate whether the fault is in-zone and requires a trip, or whether it is external (and tripping only by the correct outgoing feeder relay is required). RLYincomer RLYF1 RLYF2 RLYF3 RLYF4 Figure 15.22: Simple busbar blocking scheme (single incomer) However, most numerical feeder relays have the means to issue an instantaneous start output, to indicate that they are measuring an operating current above setting, and as such, their time-overcurrent function is in the process of timing out. Figure 15.22 shows how this facility can be enabled in the outgoing feeder relays, and communicated to the incomer relay as a ‘block’ signal. This block does not block the critical time-overcurrent function in the incomer relay, but merely blocks a definite-time high-set that has been speciallyconfigured to offer busbar protection. The high-set, measuring phase overcurrent, and often earthfault too, is delayed by a margin marked as ‘time to block’ in Figure 15.23. This deliberate delay on operation is necessary to allow enough time for an external fault to be detected by an outgoing feeder relay, and for it to be communicated as a ‘block’ command, and acted upon by the incomer relay. Only if the incoming feeder relay measures fault current above the high-set setting, and no block arrives, it determines that the fault must lie on the protected busbar, and a bus zone trip command is issued. Figure 15.23: High-set bus-zone tripping: element co-ordination The definite time delay - ‘time to block’ - will often be of the order of 50 to 100ms, meaning that the operating time for a genuine busbar fault will be of the order of 100ms. This delayed clearance may not be an issue, as system stability is typically not a primary concern for distribution systems. Indeed, 100ms operation would be much faster than waiting for the incoming feeder I.D.M.T. curve to time out, which would be the historical means by which the fault would be detected. Figure 15.22 indicated that block signals would be exchanged between relays by hardwiring, and this is still a valid solution for simplicity. A more contemporary implementation would be to make use of IEC 61850 GOOSE logic to exchange such commands via Ethernet. GOOSE application is detailed in Chapter 24 - The Digital Substation. Whether deployed as hardwired, or Ethernet schemes, circuit breaker failure is commonly applied too. Interlocked overcurrent busbar schemes may also be applied to sectionalised busbars, with more than one incomer, provided that directional relays are applied on any feeder which may act as an infeed, and at each bus section. However, such schemes are unlikely to be applicable in double busbar stations, where dedicated busbar protection is recommended. 15.12 REFERENCE [15.1] The Behaviour of Current Transformers subjected to Transient Asymmetric Currents and the Effects on Associated Protective Relays. J.W. Hodgkiss. CIGRE Paper Number 329, Session 15-25 June 1960. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 15-21 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 Transformer and Transformer Feeder Protection 16.1 INTRODUCTION 16.1 16.2 16.3 16.4 16.5 16.6 16.7 16.8 16.9 Introduction Winding Faults Magnetising Inrush Transformer Overheating Transformer Protection – Overview Transformer Overcurrent Protection Restricted Earth Fault Protection Differential Protection Differential Protection Stabilisation During Magnetising Inrush Conditions 16.10 Combined Differential and Restricted Earth Fault Schemes 16.11 Earthing Transformer Protection 16.12 Autotransformer Protection 16.13 Overfluxing Protection 16.14 Tank-Earth Protection 16.15 Oil and Gas Devices 16.16 Transformer-Feeder Protection 16.17 Intertripping 16.18 Condition Monitoring of Transformers 16.19 Examples of Transformer Protection 16.20 Transformer Asset Management The development of modern power systems has been reflected in the advances in transformer design. This has resulted in a wide range of transformers with sizes ranging from a few kVA to several hundred MVA being available for use in a wide variety of applications. The considerations for a transformer protection package vary with the application and importance of the transformer. To reduce the effects of thermal stress and electrodynamic forces, it is advisable to ensure that the protection package used minimises the time for disconnection in the event of a fault occurring within the transformer. Small distribution transformers can be protected satisfactorily, from both technical and economic considerations, by the use of fuses or overcurrent relays. This results in time-delayed protection due to downstream co-ordination requirements. However, timedelayed fault clearance is unacceptable on larger power transformers used in distribution, transmission and generator applications, due to system operation/stability and cost of repair/length of outage considerations. Transformer faults are generally classified into five categories: x winding and terminal faults x core faults x tank and transformer accessory faults x on–load tap changer faults x abnormal operating conditions x sustained or uncleared external faults For faults originating in the transformer itself, the approximate proportion of faults due to each of the causes listed above is shown in Figure 16.1. Figure 16.1: Transformer fault statistics 16.2 WINDING FAULTS A fault on a transformer winding is controlled in magnitude by the following factors: Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-1 Network Protection & Automation Guide x source impedance 16.2.2 Star-Connected Winding with Neutral Point Solidly Earthed x neutral earthing impedance x transformer leakage reactance x fault voltage x winding connection Several distinct cases arise and are examined below. 16.2.1 Star-Connected Winding with Neutral Point Earthed Through an Impedance The fault current is controlled mainly by the leakage reactance of the winding, which varies in a complex manner with the position of the fault. The variable fault point voltage is also an important factor, as in the case of impedance earthing. For faults close to the neutral end of the winding, the reactance is very low, and results in the highest fault currents. The variation of current with fault position is shown in Figure 16.3. The winding earth fault current depends on the earthing impedance value and is also proportional to the distance of the fault from the neutral point, since the fault voltage will be directly proportional to this distance. Percentage of respective maximum Single-Phase Earth fault current For a fault on a transformer secondary winding, the corresponding primary current will depend on the transformation ratio between the primary winding and the short-circuited secondary turns. This also varies with the position of the fault, so that the fault current in the transformer primary winding is proportional to the square of the fraction of the winding that is short-circuited. The effect is shown in Figure 16.2. Faults in the lower third of the winding produce very little current in the primary winding, making fault detection by primary current measurement difficult. 100 90 80 Fault current Figure 16.3: Earth fault current in solidly earthed star winding (IF) For secondary winding faults, the primary winding fault current is determined by the variable transformation ratio; as the secondary fault current magnitude stays high throughout the winding, the primary fault current is large for most points along the winding. 70 60 50 40 30 20 Primary Current (Ip) 10 0 10 20 30 40 50 60 70 80 90 100 Distance of fault from Neutral (percentage of winding) Ip IF Figure 16.2: Earth fault current in resistance-earthed star winding 16-2 16.2.3 Delta-Connected Winding No part of a delta-connected winding operates with a voltage to earth of less than 50% of the phase voltage. The range of fault current magnitude is therefore less than for a star winding. The actual value of fault current will still depend on the method of system earthing; it should also be remembered that the impedance of a delta winding is particularly high to fault currents flowing to a centrally placed fault on one leg. The impedance can be expected to be between 25% and 50%, based on the transformer rating, regardless of the normal balanced through-current impedance. As the prefault voltage to earth at this point is half the normal phase voltage, the earth fault current may be no more than the rated current, or even less than this value if the source or system earthing impedance is appreciable. The current will flow to the fault from each side through the two half windings, and will be © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection divided between two phases of the system. The individual phase currents may therefore be relatively low, resulting in difficulties in providing protection. 16.2.4 Phase to Phase Faults Faults between phases within a transformer are relatively rare; if such a fault does occur it will give rise to a substantial current comparable to the earth fault currents discussed in Section 16.2.2. 16.2.5 Interturn Faults In low voltage transformers, interturn insulation breakdown is unlikely to occur unless the mechanical force on the winding due to external short circuits has caused insulation degradation, or insulating oil (if used) has become contaminated by moisture. A high voltage transformer connected to an overhead transmission system will be subjected to steep fronted impulse voltages, arising from lightning strikes, faults and switching operations. A line surge, which may be of several times the rated system voltage, will concentrate on the end turns of the winding because of the high equivalent frequency of the surge front. Part-winding resonance, involving voltages up to 20 times rated voltage may occur. The interturn insulation of the end turns is reinforced, but cannot be increased in proportion to the insulation to earth, which is relatively great. Partial winding flashover is therefore more likely. The subsequent progress of the fault, if not detected in the earliest stage, may well destroy the evidence of the true cause. A short circuit of a few turns of the winding will give rise to a heavy fault current in the short-circuited loop, but the terminal currents will be very small, because of the high ratio of transformation between the whole winding and the shortcircuited turns. The graph in Figure 16.4 shows the corresponding data for a typical transformer of 3.25% impedance with the shortcircuited turns symmetrically located in the centre of the winding. Figure 16.4: Interturn fault current/number of turns short-circuited The additional core loss, although causing severe local heating, does not produce a noticeable change in input current and could not be detected by the normal electrical protection. However it is important that the condition is detected before a major fault has been created. In an oil-immersed transformer, core heating sufficient to cause winding insulation damage also causes breakdown of some of the oil with an accompanying evolution of gas. This gas escapes to the conservator and is used to operate a mechanical relay; see Section 16.15.3. 16.2.7 Tank Faults Loss of oil through tank leaks ultimately produces a dangerous condition, either because of a reduction in winding insulation or because of overheating on load due to the loss of cooling. Overheating may also occur due to prolonged overloading, blocked cooling ducts due to oil sludging or failure of the forced cooling system, if fitted. 16.2.8 Externally Applied Conditions Sources of abnormal stress in a transformer are: x overload 16.2.6 Core Faults x system faults A conducting bridge across the laminated structures of the core can permit sufficient eddy-current to flow to cause serious overheating. The bolts that clamp the core together are always insulated to avoid this trouble. If any portion of the core insulation becomes defective, the resultant heating may reach a magnitude sufficient to damage the winding. x overvoltage x reduced system frequency 16.2.8.1 Overload Overload causes increased 'copper loss' and a consequent temperature rise. Overloads can be carried for limited periods and recommendations for oil-immersed transformers are given in IEC 60354. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-3 Network Protection & Automation Guide The thermal time constant of naturally cooled transformers lies between 2.5-5 hours. Shorter time constants apply in the case of force-cooled transformers. 16.2.8.4 Reduced system frequency 16.2.8.2 System faults It follows that a transformer can operate with some degree of overvoltage with a corresponding increase in frequency, but operation must not be continued with a high voltage input at a low frequency. Operation cannot be sustained when the ratio of voltage to frequency, with these quantities given values in per unit of their rated values, exceeds unity by more than a small amount, for instance if V/f >1.1. If a substantial rise in system voltage has been catered for in the design, the base of 'unit voltage' should be taken as the highest voltage for which the transformer is designed. System short circuits produce a relatively intense rate of heating of the feeding transformers, the copper loss increasing in proportion to the square of the per unit fault current. The typical duration of external short circuits that a transformer can sustain without damage if the current is limited only by the self-reactance is shown in Table 16.1. IEC 60076 provides further guidance on short-circuit withstand levels. Transformer Reactance (%) Fault Current Permitted Fault (Multiple of Rating) Duration (seconds) Reduction of system frequency has an effect with regard to flux density, similar to that of overvoltage. 4 25 2 16.3 MAGNETISING INRUSH 5 20 2 6 16.6 2 7 14.2 2 The phenomenon of magnetising inrush is a transient condition that occurs primarily when a transformer is energised. It is not a fault condition, and therefore transformer protection must remain stable during the inrush transient. Table 16.1: Transformer fault current withstand data Maximum mechanical stress on windings occurs during the first cycle of the fault. Avoidance of damage is a matter of transformer design. 16.2.8.3 Overvoltages Overvoltage conditions are of two kinds: x transient surge voltages x power frequency overvoltage Transient overvoltages arise from faults, switching, and lightning disturbances and are liable to cause interturn faults, as described in Section 16.2.5. These overvoltages are usually limited by shunting the high voltage terminals to earth either with a plain rod gap or by surge diverters, which comprise a stack of short gaps in series with a non-linear resistor. The surge diverter, in contrast to the rod gap, has the advantage of extinguishing the flow of power current after discharging a surge, in this way avoiding subsequent isolation of the transformer. Power frequency overvoltage causes both an increase in stress on the insulation and a proportionate increase in the working flux. The latter effect causes an increase in the iron loss and a disproportionately large increase in magnetising current. In addition, flux is diverted from the laminated core into structural steel parts. The core bolts, which normally carry little flux, may be subjected to a large flux diverted from the highly saturated region of core alongside. This leads to a rapid temperature rise in the bolts, destroying their insulation and damaging coil insulation if the condition continues. 16-4 Figure 16.5(a) shows a transformer magnetising characteristic. To minimise material costs, weight and size, transformers are generally operated near to the ‘knee point’ of the magnetising characteristic. Consequently, only a small increase in core flux above normal operating levels will result in a high magnetising current. Under normal steady-state conditions, the magnetising current associated with the operating flux level is relatively small (Figure 16.5(b)). However, if a transformer winding is energised at a voltage zero, with no remanent flux, the flux level during the first voltage cycle (2 x normal flux) will result in core saturation and a high non-sinusoidal magnetising current waveform – see Figure 16.5(c). This current is referred to as magnetising inrush current and may persist for several cycles. Several factors affect the magnitude and duration of the magnetising current inrush: x residual flux – worst-case conditions result in the flux peak value attaining 280% of normal value x point on wave switching x number of banked transformers x transformer design and rating x system fault level © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection following negative half cycle of the voltage wave reduces the flux to the starting value, the current falling symmetrically to zero. The current wave is therefore fully offset and is only restored to the steady state condition by the circuit losses. The time constant of the transient has a range between 0.1 second (for a 100kVA transformer) to 1.0 second (for a large unit). As the magnetising characteristic is non-linear, the envelope of the transient current is not strictly of exponential form; the magnetising current can be observed to be still changing up to 30 minutes after switching on. Normal peak flux Magnetising current (a) Typical magnetising characteristic Transient flux 80% residual at switching Although correct choice of the point on the wave for a single– phase transformer will result in no transient inrush, mutual effects ensure that a transient inrush occurs in all phases for three-phase transformers. Transient flux no residual at switching 16.3.1 Harmonic Content of Inrush Waveform Steady-state flux Voltage Time (b) Steady and maximum offset fluxes Slow Decrement Zero axis (c) Typical inrush current Zero axis (d) Inrush without offset, due to yoke saturation Figure 16.5: Transformer magnetising inrush The very high flux densities quoted above are so far beyond the normal working range that the incremental relative permeability of the core approximates to unity and the inductance of the winding falls to a value near that of the 'aircored' inductance. The current wave, starting from zero, increases slowly at first, the flux having a value just above the residual value and the permeability of the core being moderately high. As the flux passes the normal working value and enters the highly saturated portion of the magnetising characteristic, the inductance falls and the current rises rapidly to a peak that may be 500% of the steady state magnetising current. When the peak is passed at the next voltage zero, the The waveform of transformer magnetising current contains a proportion of harmonics that increases as the peak flux density is raised to the saturating condition. The magnetising current of a transformer contains a third harmonic and progressively smaller amounts of fifth and higher harmonics. If the degree of saturation is progressively increased, not only will the harmonic content increase as a whole, but the relative proportion of fifth harmonic will increase and eventually exceed the third harmonic. At a still higher level the seventh would overtake the fifth harmonic but this involves a degree of saturation that will not be experienced with power transformers. The energising conditions that result in an offset inrush current produce a waveform that is asymmetrical. Such a wave typically contains both even and odd harmonics. Typical inrush currents contain substantial amounts of second and third harmonics and diminishing amounts of higher orders. As with the steady state wave, the proportion of harmonics varies with the degree of saturation, so that as a severe inrush transient decays, the harmonic makeup of the current passes through a range of conditions. 16.4 TRANSFORMER OVERHEATING The rating of a transformer is based on the temperature rise above an assumed maximum ambient temperature; under this condition no sustained overload is usually permissible. At a lower ambient temperature some degree of sustained overload can be safely applied. Short-term overloads are also permissible to an extent dependent on the previous loading conditions. IEC 60354 provides guidance in this respect. The only certain statement is that the winding must not overheat; a temperature of about 95°C is considered to be the normal maximum working value beyond which a further rise of © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-5 Network Protection & Automation Guide 8°- 10°C, if sustained, will halve the insulation life of the unit. Protection against overload is therefore based on winding temperature, which is usually measured by a thermal image technique. Protection is arranged to trip the transformer if excessive temperature is reached. The trip signal is usually routed via a digital input of a protection relay on one side of the transformer, with both alarm and trip facilities made available through programmable logic in the relay. Intertripping between the relays on the two sides of the transformer is usually applied to ensure total disconnection of the transformer. Winding temperature protection may be included as a part of a complete monitoring package. See Section 16.18 for more details. 16.5 TRANSFORMER PROTECTION – OVERVIEW The problems relating to transformers described in Section 16.4 require some means of protection. Table 16.2 summarises the problems and the possible forms of protection that may be used. The following sections provide more detail on the individual protection methods. It is normal for a modern relay to provide all of the required protection functions in a single package, in contrast to electromechanical types that would require several relays complete with interconnections and higher overall CT burdens. Fault Type Table 16.3 shows typical ratings of fuses for use with 11kV transformers Transformer Rating kVA Fuse Full Load Current (A) Rated Current (A) Operating Time at 3 x Rating (s) 100 5.25 16 3.0 200 10.5 25 3.0 315 15.8 36 10.0 500 26.2 50 20.0 1000 52.5 90 30.0 Table 16.3: Typical fuse ratings for use with distribution transformers This table should be taken only as a typical example; considerable differences exist in the time characteristics of different types of HRC fuses. Furthermore grading with protection on the secondary side has not been considered. Protection Used Primary winding Phase-phase fault Differential; Overcurrent Primary winding Phase-earth fault Differential; Overcurrent Secondary winding Phase-phase fault Differential Secondary winding Phase-earth fault Differential; Restricted Earth Fault Interturn Fault Differential, Buchholz Core Fault Differential, Buchholz Tank Fault Differential, Buchholz; Tank-Earth Overfluxing Overfluxing Overheating Thermal Table 16.2: Transformer fault types/protection methods 16.6 TRANSFORMER OVERCURRENT PROTECTION Fuses may adequately protect small transformers, but larger ones require overcurrent protection using a relay and CB, as fuses do not have the required fault breaking capacity. 16.6.1 Fuses Fuses commonly protect small distribution transformers typically up to ratings of 1MVA at distribution voltages. In many cases no circuit breaker is provided, making fuse 16-6 protection the only available means of automatic isolation. The fuse must have a rating well above the maximum transformer load current to withstand the short duration overloads that may occur. Also, the fuses must withstand the magnetising inrush currents drawn when power transformers are energised. High Rupturing Capacity (HRC) fuses, although very fast in operation with large fault currents, are extremely slow with currents of less than three times their rated value. It follows that such fuses will do little to protect the transformer, serving only to protect the system by disconnecting a faulty transformer after the fault has reached an advanced stage. 16.6.2 Overcurrent Relays With the advent of ring main units incorporating SF6 circuit breakers and isolators, protection of distribution transformers can now be provided by overcurrent trips (e.g. tripping controlled by time limit fuses connected across the secondary windings of in-built current transformers) or by relays connected to current transformers located on the transformer primary side. Overcurrent relays are also used on larger transformers provided with standard circuit breaker control. Improvement in protection is obtained in two ways; the excessive delays of the HRC fuse for lower fault currents are avoided and an earth-fault tripping element is provided in addition to the overcurrent feature. The time delay characteristic should be chosen to discriminate with circuit protection on the secondary side. A high-set instantaneous relay element is often provided, the current setting being chosen to avoid operation for a secondary short circuit. This enables high-speed clearance of primary terminal short circuits. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection 16.7 RESTRICTED EARTH FAULT PROTECTION Conventional earth fault protection using overcurrent elements fails to provide adequate protection for transformer windings. This applies particularly to a star-connected winding with an impedance-earthed neutral, as discussed in Section 16.2.1. The degree of protection is very much improved by the application of restricted earth fault protection (or REF protection). This is a unit protection scheme for one winding of the transformer. It can be a high impedance type as shown in Figure 16.6 or a biased low-impedance type. For the highimpedance type, the residual current of three line current transformers is balanced against the output of a current transformer in the neutral conductor. In the biased lowimpedance version, the three phase currents and the neutral current become the bias inputs to a differential element. The system is operative for faults within the region between current transformers, that is, for faults on the star winding in question. The system remains stable for all faults outside this zone. I Earth fault protection applied to a delta-connected or unearthed star winding is inherently restricted, since no zero sequence components can be transmitted through the transformer to the other windings. Both windings of a transformer can be protected separately with restricted earth fault protection, thereby providing highspeed protection against earth faults for the whole transformer with relatively simple equipment. A high impedance relay is used, giving fast operation and phase fault stability. 16.8 DIFFERENTIAL PROTECTION The restricted earth fault schemes described above in Section 16.7 depend entirely on the Kirchhoff principle that the sum of the currents flowing into a conducting network is zero. A differential system can be arranged to cover the complete transformer; this is possible because of the high efficiency of transformer operation, and the close equivalence of ampereturns developed on the primary and secondary windings. Figure 16.7 shows the principle. Current transformers on the primary and secondary sides are connected to form a circulating current system. > High impedance relay Figure 16.6: Restricted earth fault protection for a star winding The gain in protection performance comes not only from using an instantaneous relay with a low setting, but also because the whole fault current is measured, not merely the transformed component in the HV primary winding (if the star winding is a secondary winding). Hence, although the prospective current level decreases as fault positions progressively nearer the neutral end of the winding are considered, the square law which controls the primary line current is not applicable, and with a low effective setting, a large percentage of the winding can be covered. Restricted earth fault protection is often applied even when the neutral is solidly earthed. Since fault current then remains at a high value even to the last turn of the winding (Figure 16.2), virtually complete cover for earth faults is obtained. This is an improvement compared with the performance of systems that do not measure the neutral conductor current. Figure 16.7: Principle of transformer differential protection 16.8.1 Basic Considerations for Transformer Differential Protection In applying the principles of differential protection to transformers, a variety of considerations have to be taken into account. These include: x correction for possible phase shift across the transformer windings (phase correction) x the effects of the variety of earthing and winding arrangements (filtering of zero sequence currents) x correction for possible unbalance of signals from current transformers on either side of the windings (ratio correction) x the effect of magnetising inrush during initial energisation x the possible occurrence of overfluxing © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-7 Network Protection & Automation Guide In traditional transformer differential schemes, the requirements for phase and ratio correction were met by the application of external interposing current transformers (ICTs), as a secondary replica of the main winding connections, or by a delta connection of the main CTs to provide phase correction only. Digital/numerical relays implement ratio and phase correction in the relay software instead, thus enabling most combinations of transformer winding arrangements to be catered for, irrespective of the winding connections of the primary CTs. This avoids the additional space and cost requirements of hardware interposing CTs. 16.8.2 Line Current Transformer Primary Ratings Line current transformers have primary ratings selected to be approximately equal to the rated currents of the transformer windings to which they are applied. Primary ratings will usually be limited to those of available standard ratio CTs. 16.8.3 Phase Correction Correct operation of transformer differential protection requires that the transformer primary and secondary currents, as measured by the relay, are in phase. If the transformer is connected delta/star, as shown in Figure 16.8, balanced threephase through current suffers a phase change of 30°. If left uncorrected, this phase difference would lead to the relay seeing through current as an unbalanced fault current, and result in relay operation. Phase correction must be implemented. automatically. Caution is required if such a relay is used to replace an existing electromechanical or static relay, as the primary and secondary line CTs may not have the same winding configuration. Phase compensation and associated relay data entry requires more detailed consideration in such circumstances. Rarely, the available phase compensation facilities cannot accommodate the transformer winding connection, and in such cases interposing CTs must be used. 16.8.4 Filtering of Zero Sequence Currents As described in Chapter 10.8, it is essential to provide some form of zero sequence filtering where a transformer winding can pass zero sequence current to an external earth fault. This is to ensure that out-of-zone earth faults are not seen by the transformer protection as an in-zone fault. This is achieved by use of delta-connected line CTs or interposing CTs for older relays, and hence the winding connection of the line and/or interposing CTs must take this into account, in addition to any phase compensation necessary. For digital/numerical relays, the required filtering is applied in the relay software. Table 16.4 summarises the phase compensation and zero sequence filtering requirements. An example of an incorrect choice of ICT connection is given in Section 16.19.1. Transformer Connection Transformer Phase Shift Clock Phase HV Zero LV Zero Face Compensation Sequence Sequence Vector Required Filtering Filtering Yy0 Yes Zd0 Yes A Dz0 B Dd0 C Yz1 0° 0 0° Yes Zy1 Yes -30° Yd1 1 30° Yes Yy6 Yes Zd6 -180° 1 180° Id > Yes Dd6 Figure 16.8: Differential protection for two-winding delta/star transformer Yz11 Electromechanical and static relays use appropriate CT/ICT connections to ensure that the primary and secondary currents applied to the relay are in phase. Dy11 For digital and numerical relays, it is common to use starconnected line CTs on all windings of the transformer and compensate for the winding phase shift in software. Depending on relay design, the only data required in such circumstances may be the transformer vector group designation. Phase compensation is then performed 16-8 Yes Yes Dz6 Id > Yes Yes Dy1 Id > Yes Zy11 Yes 30° Yd11 11 -30° Yes Yes Yes YyH YzH YdH ZdH DzH DyH Yes (H / 12) x 360° Hour ‘H’ -(H / 12) x 360° Yes Yes Yes DdH Table 16.4: Current transformer connections for power transformers of various vector groups © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection 16.8.5 Ratio Correction 16.8.7 Transformers with Multiple Windings Correct operation of the differential element requires that currents in the differential element balance under load and through fault conditions. As the primary and secondary line CT ratios may not exactly match the transformer rated winding currents, digital/numerical relays are provided with ratio correction factors for each of the CT inputs. The correction factors may be calculated automatically by the relay from knowledge of the line CT ratios and the transformer MVA rating. However, if interposing CTs are used, ratio correction may not be such an easy task and may need to take into account a factor of 3 if delta-connected CTs or ICTs are involved. If the transformer is fitted with a tap changer, line CT ratios and correction factors are normally chosen to achieve current balance at the mid tap of the transformer. It is necessary to ensure that current mismatch due to off-nominal tap operation will not cause spurious operation. The unit protection principle remains valid for a system having more than two connections, so a transformer with three or more windings can still be protected by the application of the above principles. The example in Section 16.19.2 shows how ratio correction factors are used, and that of Section 16.19.3 shows how to set the ratio correction factors for a transformer with an unsymmetrical tap range. 16.8.6 Bias Setting Bias is applied to transformer differential protection for the same reasons as any unit protection scheme – to ensure stability for external faults while allowing sensitive settings to pick up internal faults. The situation is slightly complicated if a tap changer is present. With line CT/ICT ratios and correction factors set to achieve current balance at nominal tap, an offnominal tap may be seen by the differential protection as an internal fault. By selecting the minimum bias to be greater than sum of the maximum tap of the transformer and possible CT errors, maloperation due to this cause is avoided. Some relays use a bias characteristic with three sections, as shown in Figure 16.9. The first section is set higher than the transformer magnetising current. The second section is set to allow for off-nominal tap settings, while the third has a larger bias slope beginning well above rated current to cater for heavy through-fault conditions. When the power transformer has only one of its three windings connected to a source of supply, with the other two windings feeding loads, a relay with only two sets of CT inputs can be used, connected as shown in Figure 16.10(a). The separate load currents are summated in the CT secondary circuits, and will balance with the infeed current on the supply side. When more than one source of fault current infeed exists, there is a danger in the scheme of Figure 16.10(a) of current circulating between the two paralleled sets of current transformers without producing any bias. It is therefore important a relay is used with separate CT inputs for the two secondaries - Figure 16.10(b). When the third winding consists of a delta-connected tertiary with no connections brought out, the transformer may be regarded as a two winding transformer for protection purposes and protected as shown in Figure 16.10(c). Source Loads Id > (a) Three winding transformer (one power source) Source Possible fault infeed Id > (b) Three winding transformer (three power sources) Differential current ( Id ) Source Possible fault infeed Id > (c) Three winding transformer with unloaded delta tertiary Figure 16.10: Differential protection arrangements for three-winding transformers (shown single phase for simplicity) Figure 16.9: Typical bias characteristic © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-9 Network Protection & Automation Guide 16.9 DIFFERENTIAL PROTECTION STABILISATION DURING MAGNETISING INRUSH CONDITIONS The magnetising inrush phenomenon described in Section 16.3 produces current input to the energised winding which has no equivalent on the other windings. The whole of the inrush current appears, therefore, as unbalance and the differential protection is unable to distinguish it from current due to an internal fault. The bias setting is not effective and an increase in the protection setting to a value that would avoid operation would make the protection of little value. Methods of delaying, restraining or blocking of the differential element must therefore be used to prevent mal-operation of the protection. 16.9.1 Time Delay Since the phenomenon is transient, stability can be maintained by providing a small time delay. However, because this time delay also delays operation of the relay in the event of a fault occurring at switch-on, the method is no longer used. The second harmonic is therefore an attractive basis for a stabilising bias against inrush effects, but care must be taken to ensure that the current transformers are sufficiently large so that the harmonics produced by transient saturation do not delay normal operation of the relay. The differential current is passed through a filter that extracts the second harmonic; this component is then applied to produce a restraining quantity sufficient to overcome the operating tendency due to the whole of the inrush current that flows in the operating circuit. By this means a sensitive and high-speed system can be obtained. 16.9.3 Inrush Detection Blocking – Gap Detection Technique Another feature that characterises an inrush current can be seen from Figure 16.5 where the two waveforms (c) and (d) have periods in the cycle where the current is zero. The minimum duration of this zero period is theoretically one quarter of the cycle and is easily detected by a simple timer T1 that is set to 1 seconds. Figure 16.11 shows the circuit in 4f block diagram form. Timer T1 produces an output only if the 16.9.2 Harmonic Restraint The inrush current, although generally resembling an in-zone fault current, differs greatly when the waveforms are compared. The difference in the waveforms can be used to distinguish between the conditions. As stated before, the inrush current contains all harmonic orders, but these are not all equally suitable for providing bias. In practice, only the second harmonic is used. current is zero for a time exceeding 1 seconds. It is reset 4f when the instantaneous value of the differential current exceeds the setting reference. Figure 16.11: Block diagram to show waveform gap-detecting principle This component is present in all inrush waveforms. It is typical of waveforms in which successive half period portions do not repeat with reversal of polarity but in which mirror-image symmetry can be found about certain ordinates. As the zero in the inrush current occurs towards the end of the cycle, it is necessary to delay operation of the differential relay The proportion of second harmonic varies somewhat with the degree of saturation of the core, but is always present as long as the uni-directional component of flux exists. The amount varies according to factors in the transformer design. Normal fault currents do not contain second or other even harmonics, nor do distorted currents flowing in saturated iron cored coils under steady state conditions. detected if present. This is achieved by using a second timer T2 that is held reset by an output from timer T1. The output current of a current transformer that is energised into steady state saturation will contain odd harmonics but not even harmonics. However, should the current transformer be saturated by the transient component of the fault current, the resulting saturation is not symmetrical and even harmonics are introduced into the output current. This can have the advantage of improving the through fault stability performance of a differential relay. 16-10 by 1 seconds to ensure that the zero condition can be f When no current is flowing for a time exceeding 1 seconds, 4f timer T2 is held reset and the differential relay that may be controlled by these timers is blocked. When a differential current exceeding the setting of the relay flows, timer T1 is 1 reset and timer T2 times out to give a trip signal in seconds. f If the differential current is characteristic of transformer inrush then timer T2 will be reset on each cycle and the trip signal is blocked. Some numerical relays may use a combination of the harmonic restraint and gap detection techniques for magnetising inrush detection. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection 16.10 COMBINED DIFFERENTIAL AND RESTRICTED EARTH FAULT SCHEMES The advantages to be obtained by the use of restricted earth fault protection, discussed in Section 16.7 lead to the system being frequently used in conjunction with an overall differential system. The importance of this is shown in Figure 16.12 from which it will be seen that if the neutral of a star-connected winding is earthed through a resistance of one per unit, an overall differential system having an effective setting of 20% will detect faults in only 42% of the winding from the line end. Restricted earth fault relay Id Id Id I > Differential relay ec tio n Figure 16.13: Combined differential and earth fault protection using summation current transformer fa u lt pr ot 80 ea r th 60 40 R es tri ct ed Primary operating current (percentage of rated current) 100 20 0 100 80 60 tio ec t o pr ial t n re ffe i D 40 n 20 0 Percentage of winding protected Figure 16.12: Amount of winding protected when transformer is resistance earthed and ratings of transformer and resistor are equal Figure 16.14: Combined differential and restricted earth fault protection using auxiliary CTs Implementation of a combined differential/REF protection scheme is made easy if a numerical relay with software ratio/phase compensation is used. All compensation is made internally in the relay. 16.10.1 Application When an Earthing Transformer is Connected Within the Protected Zone Where software ratio/phase correction is not available, either a summation transformer or auxiliary CTs can be used. The connections are shown in Figure 16.13 and Figure 16.14 respectively. Care must be taken in calculating the settings, but the only significant disadvantage of the Combined Differential/REF scheme is that the REF element is likely to operate for heavy internal faults as well as the differential elements, thus making subsequent fault analysis somewhat confusing. However, the saving in CTs outweighs this disadvantage. A delta-connected winding cannot deliver any zero sequence current to an earth fault on the connected system, any current that does flow is in consequence of an earthed neutral elsewhere on the system and will have a 2-1-1 pattern of current distribution between phases. When the transformer in question represents a major power feed, the system may be earthed at that point by an earthing transformer or earthing reactor. They are frequently connected to the system, close to the main supply transformer and within the transformer protection zone. Zero sequence current that flows through the earthing transformer during system earth faults will flow through the line current transformers on this side, and, without an equivalent current in the balancing current transformers, will cause unwanted operation of the relays. The problem can be overcome by subtracting the appropriate component of current from the main CT output. The earthing transformer neutral current is used for this purpose. As this represents three times the zero sequence current flowing, ratio correction is required. This can take the form of interposing © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-11 Network Protection & Automation Guide CT’s of ratio 1/0.333, arranged to subtract their output from that of the line current transformers in each phase, as shown in Figure 16.15. The zero sequence component is cancelled, restoring balance to the differential system. Alternatively, numerical relays may use software to perform the subtraction, having calculated the zero sequence component internally. A B C Earthing transformer A B C Differential relay 1/0.333 Earthing transformer Differential relay Id > Id > Id > Id > Id > Figure 16.16: Differential protection with in-zone earthing transformer; no earth fault relay Id > I > Restricted earth fault relay Figure 16.15: Differential protection with in-zone earthing transformer, with restricted earth fault relay A high impedance relay element can be connected in the neutral lead between current transformers and differential relays to provide restricted earth fault protection to the winding. As an alternative to the above scheme, the circulating current system can be completed via a three-phase group of interposing transformers that are provided with tertiary windings connected in delta. This winding effectively shortcircuits the zero sequence component and thereby removes it from the balancing quantities in the relay circuit; see Figure 16.16. Provided restricted earth fault protection is not required, the scheme shown in Figure 16.16 has the advantage of not requiring a current transformer, with its associated mounting and cabling requirements, in the neutral-earth conductor. The scheme can also be connected as shown in Figure 16.17 when restricted earth fault protection is needed. 16-12 Figure 16.17: Differential protection with in-zone earthing transformer, with alternative arrangement of restricted earth fault relay 16.11 EARTHING TRANSFORMER PROTECTION Earthing transformers not protected by other means can use the scheme shown in Figure 16.18. The delta-connected current transformers are connected to an overcurrent relay having three phase-fault elements. The normal action of the earthing transformer is to pass zero sequence current. The transformer equivalent current circulates in the delta formed by the CT secondaries without energising the relay. The latter may therefore be set to give fast and sensitive protection against faults in the earthing transformer itself. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection If current transformers are fitted in each phase at the neutral end of the windings and a three-element relay is used, a differential system can be provided, giving full protection against phase and earth faults; see Figure 16.19(b). This provides high-speed sensitive protection. It is unaffected by ratio changes on the transformer due to tap-changing and is immune to the effects of magnetising inrush current. Figure 16.18: Earthing transformer protection 16.12 AUTOTRANSFORMER PROTECTION Autotransformers are used to couple EHV power networks if the ratio of their voltages is moderate. An alternative to Differential Protection that can be applied to autotransformers is protection based on the application of Kirchhoff's law to a conducting network, namely that the sum of the currents flowing into all external connections to the network is zero. A circulating current system is arranged between equal ratio current transformers in the two groups of line connections and the neutral end connections. If one neutral current transformer is used, this and all the line current transformers can be connected in parallel to a single element relay, providing a scheme responsive to earth faults only; see Figure 16.19(a). It does not respond to interturn faults, a deficiency that is serious in view of the high statistical risk quoted in Section 16.1. Such faults, unless otherwise cleared, will be left to develop into earth faults, by which time considerably more damage to the transformer will have occurred. In addition, this scheme does not respond to any fault in a tertiary winding. Unloaded delta-connected tertiary windings are often not protected; alternatively, the delta winding can be earthed at one point through a current transformer that energises an instantaneous relay. This system should be separate from the main winding protection. If the tertiary winding earthing lead is connected to the main winding neutral above the neutral current transformer in an attempt to make a combined system, there may be ‘blind spots’ which the protection cannot cover. 16.13 OVERFLUXING PROTECTION The effects of excessive flux density are described in Section 16.2.8. Overfluxing arises principally from the following system conditions: x high system voltage x low system frequency x geomagnetic disturbances The latter results in low frequency earth currents circulating through a transmission system. Since momentary system disturbances can cause transient overfluxing that is not dangerous, time delayed tripping is required. The normal protection is an IDMT or definite time characteristic, initiated if a defined V/f threshold is exceeded. Often separate alarm and trip elements are provided. The alarm function would be definite time-delayed and the trip function would be an IDMT characteristic. A typical characteristic is shown in Figure 16.20. Geomagnetic disturbances may result in overfluxing without the V/f threshold being exceeded. Some relays provide a 5th harmonic detection feature, which can be used to detect such a condition, as levels of this harmonic rise under overfluxing conditions. Figure 16.19: Protection of auto-transformer by high impedance differential relays © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-13 Network Protection & Automation Guide Operating time (s) 0.80.18uK t M12 1000 100 K=63 K=40 K=20 10 K=5 K=1 1 1 1.1 1.2 1.3 M 1.4 1.5 1.6 V f Set t i ng Figure 16.20: Typical IDMT characteristic for overfluxing protection 16.14 TANK-EARTH PROTECTION This is also known as Howard protection. If the transformer tank is nominally insulated from earth (an insulation resistance of 10 ohms being sufficient) earth fault protection can be provided by connecting a relay to the secondary of a current transformer the primary of which is connected between the tank and earth. This scheme is similar to the frame-earth fault busbar protection described in Chapter 15. 16.15 OIL AND GAS DEVICES All faults below oil in an oil-immersed transformer result in localised heating and breakdown of the oil; some degree of arcing will always take place in a winding fault and the resulting decomposition of the oil will release gases. When the fault is of a very minor type, such as a hot joint, gas is released slowly, but a major fault involving severe arcing causes a very rapid release of large volumes of gas as well as oil vapour. The action is so violent that the gas and vapour do not have time to escape but instead build up pressure and bodily displace the oil. When such faults occur in transformers having oil conservators, the fault causes a blast of oil to pass up the relief pipe to the conservator. A Buchholz relay is used to protect against such conditions. Devices responding to abnormally high oil pressure or rate-of-rise of oil pressure are also available and may be used in conjunction with a Buchholz relay. The surge of oil caused by a serious fault bursts the disc, so allowing the oil to discharge rapidly. Relieving and limiting the pressure rise avoids explosive rupture of the tank and consequent fire risk. Outdoor oil-immersed transformers are usually mounted in a catchment pit to collect and contain spilt oil (from whatever cause), thereby minimising the possibility of pollution. A drawback of the frangible disc is that the oil remaining in the tank is left exposed to the atmosphere after rupture. This is avoided in a more effective device, the sudden pressure relief valve, which opens to allow discharge of oil if the pressure exceeds a set level, but closes automatically as soon as the internal pressure falls below this level. If the abnormal pressure is relatively high, the valve can operate within a few milliseconds, and provide fast tripping when suitable contacts are fitted. The device is commonly fitted to power transformers rated at 2MVA or higher, but may be applied to distribution transformers rated as low as 200kVA, particularly those in hazardous areas. 16.15.2 Sudden Pressure Rise Relay This device detects rapid rise of pressure rather than absolute pressure and thereby can respond even quicker than the pressure relief valve to sudden abnormally high pressures. Sensitivities as low as 0.07bar/s are attainable, but when fitted to forced-cooled transformers the operating speed of the device may have to be slowed deliberately to avoid spurious tripping during circulation pump starts. Alternatively, sudden pressure rise relays may have their output supervised by instantaneous high-set overcurrent elements. 16.15.3 Buchholz Protection Buchholz protection is normally provided on all transformers fitted with a conservator. The Buchholz relay is contained in a cast housing which is connected in the pipe to the conservator, as in Figure 16.21. 3 x internal pipe diameter (min) Conservator 5 x internal pipe diameter (min) 16.15.1 Oil Pressure Relief Devices The simplest form of pressure relief device is the widely used ‘frangible disc’ that is normally located at the end of an oil relief pipe protruding from the top of the transformer tank. 16-14 76mm typical Transformer Figure 16.21: Buchholz relay mounting arrangement © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection A typical Buchholz relay will have two sets of contacts. One is arranged to operate for slow accumulations of gas, the other for bulk displacement of oil in the event of a heavy internal fault. An alarm is generated for the former, but the latter is usually direct-wired to the CB trip relay. 16.16 TRANSFORMER-FEEDER PROTECTION A transformer-feeder comprises a transformer directly connected to a transmission circuit without the intervention of switchgear. Examples are shown in Figure 16.22. HV LV The device will therefore give an alarm for the following fault conditions, all of which are of a low order of urgency. x hot spots on the core due to short circuit of lamination insulation x core bolt insulation failure LV HV HV LV x faulty joints x interturn faults or other winding faults involving only lower power infeeds x loss of oil due to leakage HV LV When a major winding fault occurs, this causes a surge of oil, which displaces the lower float and thus causes isolation of the transformer. This action will take place for: x all severe winding faults, either to earth or interphase Figure 16.22: Typical transformer-feeder circuits. x loss of oil if allowed to continue to a dangerous degree The saving in switchgear so achieved is offset by increased complication in the necessary protection. The primary requirement is intertripping, since the feeder protection remote from the transformer will not respond to the low current fault conditions that can be detected by restricted earth fault and Buchholz protections. An inspection window is usually provided on either side of the gas collection space. Visible white or yellow gas indicates that insulation has been burnt, while black or grey gas indicates the presence of, dissociated oil. In these cases the gas will probably be inflammable, whereas released air will not. A vent valve is provided on the top of the housing for the gas to be released or collected for analysis. Transformers with forced oil circulation may experience oil flow to/from the conservator on starting/stopping of the pumps. The Buchholz relay must not operate in this circumstance. Cleaning operations may cause aeration of the oil. Under such conditions, tripping of the transformer due to Buchholz operation should be inhibited for a suitable period. Because of its universal response to faults within the transformer, some of which are difficult to detect by other means, the Buchholz relay is invaluable, whether regarded as a main protection or as a supplement to other protection schemes. Tests carried out by striking a high voltage arc in a transformer tank filled with oil, have shown that operation times of 0.05s-0.1s are possible. Electrical protection is generally used as well, either to obtain faster operation for heavy faults, or because Buchholz relays have to be prevented from tripping during oil maintenance periods. Conservators are fitted to oil-cooled transformers above 1000kVA rating, except those to North American design practice that use a different technique. Either unrestricted or restricted protection can be applied; moreover, the transformer-feeder can be protected as a single zone or be provided with separate protections for the feeder and the transformer. In the latter case, the separate protections can both be unit type systems. An adequate alternative is the combination of unit transformer protection with an unrestricted system of feeder protection, plus an intertripping feature. 16.16.1 Non-Unit Schemes The following sections describe how non-unit schemes are applied to protect transformer-feeders against various types of fault. 16.16.1.1 Feeder phase and earth faults High-speed protection against phase and earth faults can be provided by distance relays located at the end of the feeder remote from the transformer. The transformer constitutes an appreciable lumped impedance. It is therefore possible to set a distance relay zone to cover the whole feeder and reach part way into the transformer impedance. With a normal tolerance on setting thus allowed for, it is possible for fast Zone 1 protection to cover the whole of the feeder with certainty © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-15 Network Protection & Automation Guide r I F1 without risk of over-reaching to a fault on the low voltage side. Although the distance zone is described as being set ’half way into the transformer’, it must not be thought that half the transformer winding will be protected. The effects of autotransformer action and variations in the effective impedance of the winding with fault position prevent this, making the amount of winding beyond the terminals which is protected very small. The value of the system is confined to the feeder, which, as stated above, receives high-speed protection throughout. Hence, 16.16.1.2 Feeder phase faults where: A distance scheme is not, for all practical purposes, affected by varying fault levels on the high voltage busbars and is therefore the best scheme to apply if the fault level may vary widely. In cases where the fault level is reasonably constant, similar protection can be obtained using high set instantaneous overcurrent relays. These should have a low transient overreach (t), defined as: r 1 .2 1  t I F 2 1.2 1  t 1 .2 1  t ZS  ZL Z S  Z L  ZT ZS  ZL 1  x ZS  ZL 1.2 1  t 1 x x ~ ZT ZS  ZL ZS ZT ZL IS  IF u 100% IF I> > IF1 IF2 where: Setting ratio r Is = setting current IF = steady state r.m.s value of the fault current, which when fully offset, just operates the relay. The instantaneous overcurrent relays must be set without risk of them operating for faults on the remote side of the transformer. Referring to Figure 16.23, the required setting to ensure that the relay will not operate for a fully offset fault IF2 is given by: Is 1.2 1  t I F 2 Where IF2 is the fault current under maximum source conditions, that is, when ZS is minimum, and the factor of 1.2 covers possible errors in the system impedance details used for calculation of IF2, together with relay and CT errors. As it is desirable for the instantaneous overcurrent protection to clear all phase faults anywhere within the feeder under varying system operating conditions, it is necessary to have a relay setting less than IF1 to ensure fast and reliable operation. Let the setting ratio resulting from setting Is be: r Therefore, 16-16 Is I F1 Transient over-reach (%) ZT x ZS  ZL IS I F1 5 25 50 100 0.25 1.01 1.20 1.44 1.92 0.5 0.84 1.00 1.20 1.60 1.0 0.63 0.75 0.90 1.20 2.0 0.42 0.50 0.60 0.80 4.0 0.25 0.30 0.36 0.48 8.0 0.14 0.17 0.20 0.27 IS = Relay setting = 1 .2 1  t I F2 t = Transient over-reach (p.u.) Figure 16.23: Over-reach considerations in the application of transformer-feeder protection It can be seen that for a given transformer size, the most sensitive protection for the line will be obtained by using relays with the lowest transient overreach. It should be noted that where r is greater than 1, the protection will not cover the whole line. Also, any increase in source impedance above the minimum value will increase the effective setting ratios above those shown. The instantaneous protection is usually applied with a time delayed overcurrent element having a lower current setting. In this way, instantaneous protection is provided for the feeder, with the time-delayed element covering faults on the transformer. When the power can flow in the transformer-feeder in either © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection direction, overcurrent relays will be required at both ends. In the case of parallel transformer-feeders, it is essential that the overcurrent relays on the low voltage side be directional, operating only for fault current fed into the transformer-feeder, as described in Section 9.14.3. 16.16.1.3 Earth faults Instantaneous restricted earth fault protection is normally provided. When the high voltage winding is delta connected, a relay in the residual circuit of the line current transformers gives earth fault protection which is fundamentally limited to the feeder and the associated delta-connected transformer winding. The latter is unable to transmit any zero sequence current to a through earth fault. When the feeder is associated with an earthed star-connected winding, normal restricted earth fault protection as described in Section 16.7 is not applicable because of the remoteness of the transformer neutral. Restricted protection can be applied using a directional earth fault relay. A simple sensitive and high-speed directional element can be used, but attention must be paid to the transient stability of the element. Alternatively, a directional IDMT relay may be used, the time multiplier being set low. The slight inverse time delay in operation will ensure that unwanted transient operation is avoided. When the supply source is on the high voltage star side, an alternative scheme that does not require a voltage transformer can be used. The scheme is shown in Figure 16.24. For the circuit breaker to trip, both relays A and B must operate, which will occur for earth faults on the feeder or transformer winding. External earth faults cause the transformer to deliver zero sequence current only, which will circulate in the closed delta connection of the secondary windings of the three auxiliary current transformers. No output is available to relay B. Through phase faults will operate relay B, but not the residual relay A. Relay B must have a setting above the maximum load. As the earthing of the neutral at a receiving point is likely to be solid and the earth fault current will therefore be comparable with the phase fault current, high settings are not a serious limitation. Figure 16.24: Instantaneous protection of transformer-feeder Earth fault protection of the low voltage winding will be provided by a restricted earth fault system using either three or four current transformers, according to whether the winding is delta or star-connected, as described in Section 16.7. 16.16.1.4 In-zone capacitance The feeder portion of the transformer-feeder will have an appreciable capacitance between each conductor and earth. During an external earth fault the neutral will be displaced, and the resulting zero sequence component of voltage will produce a corresponding component of zero sequence capacitance current. In the limiting case of full neutral displacement, this zero sequence current will be equal in value to the normal positive sequence current. The resulting residual current is equal to three times the zero sequence current and hence to three times the normal line charging current. The value of this component of in-zone current should be considered when establishing the effective setting of earth fault relays. 16.16.2 Unit Schemes The basic differences between the requirements of feeder and transformer protections lie in the limitation imposed on the transfer of earth fault current by the transformer and the need for high sensitivity in the transformer protection, suggesting that the two components of a transformer-feeder should be protected separately. This involves mounting current transformers adjacent to, or on, the high voltage terminals of the transformer. Separate current transformers are desirable for the feeder and transformer protections so that these can be arranged in two separate overlapping zones. The use of common current transformers is possible, but may involve the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-17 Network Protection & Automation Guide use of auxiliary current transformers, or special winding and connection arrangements of the relays. Intertripping of the remote circuit breaker from the transformer protection will be necessary, but this can be done using the communication facilities of the feeder protection relays. Although technically superior, the use of separate protection systems is seldom justifiable when compared with an overall system or a combination of non-unit feeder protection and a unit transformer system. An overall unit system must take into account the fact that zero sequence current on one side of a transformer may not be reproduced in any form on the other side. This represents little difficulty to a modern numerical relay using software phase/zero sequence compensation and digital communications to transmit full information on the phase and earth currents from one relay to the other. However, it does represent a more difficult problem for relays using older technology. The line current transformers can be connected to a summation transformer with unequal taps, as shown in Figure 16.25(a). This arrangement produces an output for phase faults and also some response for A and B phase-earth faults. However, the resulting settings will be similar to those for phase faults and no protection will be given for C phaseearth faults. An alternative technique is shown in Figure 16.25(b). The B phase is taken through a separate winding on another transformer or relay electromagnet, to provide another balancing system. The two transformers are interconnected with their counterparts at the other end of the feedertransformer by four pilot wires. Operation with three pilot cores is possible but four are preferable, involving little increase in pilot cost. 16.17 INTERTRIPPING To ensure that both the high and low voltage circuit breakers operate for faults within the transformer and feeder, it is necessary to operate both circuit breakers from protection normally associated with one. The technique for doing this is known as intertripping. The necessity for intertripping on transformer-feeders arises from the fact that certain types of fault produce insufficient current to operate the protection associated with one of the circuit breakers. These faults are: x faults in the transformer that operate the Buchholz relay and trip the local low voltage circuit breaker, while failing to produce enough fault current to operate the protection associated with the remote high voltage circuit breaker 16-18 Feeder A B C D D E E Differential relays D Bias winding E Operating winding (a) Circulating current system A B C Pilots Relay electromagnets (bias inherent) (b) Balanced voltage system Figure 16.25: Methods of protection for transformer-feeders using electromechanical static technology x earth faults on the star winding of the transformer, which, because of the position of the fault in the winding, again produce insufficient current for relay operation at the remote circuit breaker x earth faults on the feeder or high voltage deltaconnected winding which trip the high voltage circuit breaker only, leaving the transformer energised form the low voltage side and with two high voltage phases at near line-to-line voltage above earth. Intermittent arcing may follow and there is a possibility of transient overvoltage occurring and causing a further breakdown of insulation Several methods are available for intertripping; these are discussed in Chapter 8. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection 16.17.1 Neutral Displacement An alternative to intertripping is to detect the condition by measuring the residual voltage on the feeder. An earth fault occurring on the feeder connected to an unearthed transformer winding should be cleared by the feeder circuit, but if there is also a source of supply on the secondary side of the transformer, the feeder may be still live. The feeder will then be a local unearthed system, and, if the earth fault continues in an arcing condition, dangerous overvoltages may occur. A voltage relay is energised from the broken-delta connected secondary winding of a voltage transformer on the high voltage line, and receives an input proportional to the zero sequence voltage of the line, that is, to any displacement of the neutral point; see Figure 16.26. The relay normally receives zero voltage, but, in the presence of an earth fault, the broken-delta voltage will rise to three times the phase voltage. Earth faults elsewhere in the system may also result in displacement of the neutral and hence discrimination is achieved using definite or inverse time characteristics. maintenance, and detect early signs of deterioration that, if ignored, would lead to an internal fault occurring. Such techniques are an enhancement to, but are not a replacement for, the protection applied to a transformer. The extent to which condition monitoring is applied to transformers on a system will depend on many factors, amongst which will be the policy of the asset owner, the suitability of the design (existing transformers may require modifications involving a period out of service – this may be costly and not justified), the importance of the asset to system operation, and the general record of reliability. Therefore, it should not be expected that all transformers would be, or need to be, so fitted. A typical condition monitoring system for an oil-immersed transformer is capable of monitoring the condition of various transformer components as shown in Table 16.4. There can be some overlap with the measurements available from a digital/numerical relay. By the use of software to store and perform trend analysis of the measured data, the operator can be presented with information on the state of health of the transformer, and alarms raised when measured values exceed appropriate limits. This will normally provide the operator with early warning of degradation within one or more components of the transformer, enabling maintenance to be scheduled to correct the problem prior to failure occurring. The maintenance can obviously be planned to suit system conditions, provided the rate of degradation is not excessive. Monitored Equipment Measured Quantity Health Information Voltage Partial discharge measurement Insulation quality (wideband voltage) Loading Bushings Load current Permissible overload rating Hot-spot temperature Oil pressure Figure 16.26: Neutral displacement detection using voltage transformer. 16.18 CONDITION MONITORING OF TRANSFORMERS It is possible to provide transformers with measuring devices to detect early signs of degradation in various components and provide warning to the operator to avoid a lengthy and expensive outage due to failure. The technique, which can be applied to other plant as well as transformers, is called condition monitoring, as the intent is to provide the operator with regular information on the condition of the transformer. By reviewing the trends in the information provided, the operator can make a better judgement as to the frequency of Oil temperature Insulation quality Hot-spot temperature Permissible overload rating Tank Gas-in-oil content Oil quality Winding insulation condition Moisture-in-oil content Tap changer Oil quality Buchholz gas content Winding insulation condition Position Frequency of use of each tap position Drive power consumption OLTC health Total switched load current OLTC contact wear OLTC oil temperature OLTC health © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-19 Network Protection & Automation Guide Monitored Equipment Measured Quantity Health Information Oil temperature difference Cooling air temperature Coolers Cooler efficiency Ambient temperature Conservator Pump status Cooling plant health Oil level Tank integrity Table 16.4: Condition monitoring for transformers As asset owners become more conscious of the costs of an unplanned outage, and electric supply networks are utilised closer to capacity for long periods of time, the usefulness of this technique can be expected to grow. See Section 16.20 for further information on this topic. 16.19 EXAMPLES OF TRANSFORMER PROTECTION This section provides three examples of the application of modern relays to transformer protection. The latest MiCOM P640 series relay provides advanced software to simplify the calculations, so an earlier Alstom type KBCH relay is used to show the complexity of the required calculations. 16.19.1 Provision of Vector Group Compensation and Zero-Sequence Filtering Figure 16.27 shows a delta-star transformer to be protected using a unit protection scheme. With a main winding connection of Dyn11, suitable choices of primary and secondary CT winding arrangements, and software phase compensation are to be made. With the KBCH relay, phase compensation is selected by the user in the form of softwareimplemented ICTs. Primary CTs Dyn 11 Secondary CTs shift can be achieved either by use of ICT connections on the primary side having a phase shift of +30o or on the secondary side having a phase shift of –30o. There is a wide combination of primary and secondary ICT winding arrangements that can provide this, such as Yd10 (+60o) on the primary and Yd3 (90o) on the secondary. Another possibility is Yd11 (+30o) on the primary and Yy0 (0o) on the secondary. It is usual to choose the simplest arrangements possible, and therefore the latter of the above two possibilities might be selected. However, the distribution of current in the primary and secondary windings of the transformer due to an external earth fault on the secondary side of the transformer must now be considered. The transformer has an earth connection on the secondary winding, so it can deliver zero sequence current to the fault. Use of star connected main CTs and Yy0 connected ICTs provides a path for the zero sequence current to reach the protection relay. On the primary side of the transformer, the delta connected main primary winding causes zero-sequence current to circulate round the delta and hence will not be seen by the primary side main CTs. The protection relay will therefore not see any zero-sequence current on the primary side, and hence detects the secondary side zero sequence current incorrectly as an in-zone fault. The solution is to provide the ICTs on the secondary side of the transformer with a delta winding, so that the zero-sequence current circulates round the delta and is not seen by the relay. Therefore, a rule can be developed that a transformer winding with a connection to earth must have a delta-connected main or ICT for unit protection to operate correctly. Selection of Yy0 connection for the primary side ICTs and Yd1 (–30o) for the secondary side ICTs provides the required phase shift and the zero-sequence trap on the secondary side. Modern numerical MiCOM relays employ a setting wizard, needing only vector group and zero sequence data to be entered. The relay then automatically adapts itself to suit the application. 16.19.2 Unit Protection of a Delta-Star Transformer Id > Primary ICTs Unit Protection Relay Secondary ICTs Figure 16.27: Transformer zero sequence filtering example With the Dyn11 connection, the secondary voltages and currents are displaced by +30o from the primary. Therefore, the combination of primary, secondary and phase correction must provide a phase shift of –30o of the secondary quantities relative to the primary. Figure 16.28 shows a delta-star transformer to which unit protection is to be applied, including restricted earth fault protection to the star winding. Referring to the figure, the ICTs have already been correctly selected, and are conveniently applied in software. It therefore remains to calculate suitable ratio compensation (it is assumed that the transformer has no taps), transformer differential protection settings and restricted earth fault settings. For simplicity, the CTs on the primary and secondary windings of the transformer are connected in star. The required phase 16-20 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection Primary CT's Yy0, 250/1 Secondary CT's Yy0, 600/1 FLC = 175A FLC = 525A 600/1 Rstab R=1000A Differential current (A) 10MVA 33/11kV Z=10% Dyn11 Id > Unit protection relay Primary ICT's Yy0 Secondary ICT's Yd1 Figure 16.28: Transformer unit protection example 16.19.2.1 Ratio compensation Transformer HV full load current on secondary of main CTs is: 175 250 0.7 Ratio compensation = 1 0.7 1.428 Figure 16.29: Transformer unit protection characteristic 16.19.2.3 Restricted earth fault protection The KBCH relay implements high-impedance Restricted Earth Fault (REF) protection. Operation is required for a primary earth fault current of 25% rated earth fault current (i.e. 250A). The prime task in calculating settings is to calculate the value of the stabilising resistor Rstab and stability factor K. A stabilising resistor is required to ensure through fault stability when one of the secondary CTs saturates while the others do not. The requirements can be expressed as: Select nearest value = 1.43 VS 525 LV secondary current = 600 0.875 1 Ratio compensation = 0.875 1.14 I S Rstab And VS ! KI f Rct  2 Rl 16.19.2.2 Transformer unit protection settings A current setting of 20% of the rated relay current is recommended. This equates to 35A primary current. The KBCH relay has a dual slope bias characteristic with fixed bias slope settings of 20% up to rated current and 80% above that level. The corresponding characteristic is shown in Figure 16.29. where: VS = stability voltage setting VK = CT knee point voltage K = relay stability factor IS = relay current setting RCT = CT winding resistance R1 = CT lead resistance Rstab = stabilising resistor. For this example: VK = 97V RCT = 3.7 R1 = 0.057 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-21 Network Protection & Automation Guide For the relay used, the various factors are related by the graph of Figure 16.30. 0.1 I op 60 CTratio u I S  nI e where: 50 n = no of CTs in parallel (=4) 0.2 40 Overall Op Time 30 Unstable 20 Stable 10 0 1 2 3 4 5 6 Vk/Vs 7 0.3 0.4 K Factor Overall operation time - milliseconds 70 The required earth fault setting current Iop is 250A. The chosen E/F CT has an exciting current Ie of 1%, and hence using the equation: Is = 0.377, use 0.38 nearest settable value. The stabilising resistance Rstab can be calculated as 60.21:. The relay can only withstand a maximum of 3kV peak under fault conditions. A check is required to see if this voltage is exceeded – if it is, a non-linear resistor, known as a Metrosil, must be connected across the relay and stabilising resistor. The peak voltage is estimated using the formula: 0.5 K Factor 0.6 0.7 0.8 0.9 1 8 9 10 Figure 16.30: REF operating characteristic for KBCH relay V Starting with the desired operating time, the K ratio and K VS VP 2 2VK V f  VK Vf I f RCT  2 Rl  Rstab where: factor can be found. And An operating of 40ms (2 cycles at 50Hz) is usually acceptable, and hence, from Figure 16.30, If = fault current in secondary of CT circuit and substituting values, VP = 544V. Thus a Metrosil is not required. VK VS 4, K 16.19.3 Unit Protection for On-Load Tap Changing Transformer 0.5 The maximum earth fault current is limited by the earthing resistor to 1000A (primary). The maximum phase fault current can be estimated by assuming the source impedance to be zero, so it is limited only by transformer impedance to 5250A, or 10A secondary after taking account of the ratio compensation. Hence the stability voltage can be calculated as VS 0.5 u 10 3.7  2 u 0.057 19 .07 V Hence, Calculated VK However, 4 u 19.07 76.28V The previous example deals with a transformer having no taps. In practice, most transformers have a range of taps to cater for different loading conditions. While most transformers have an off-load tap-changer, transformers used for voltage control in a network are fitted with an on-load tap-changer. The protection settings must then take the variation of tap-change position into account to avoid the possibility of spurious trips at extreme tap positions. For this example, the same transformer as in Section 16.19.2 will be used, but with an on-load tapping range of +5% to -15%. The tap-changer is located on the primary winding, while the tap-step usually does not matter. 16.19.3.1 Ratio correction Actual VK = 91V and VK/VS = 4.77 Thus from Figure 16.30, with K = 0.5, the protection is unstable. By adopting an iterative procedure for values of VK/VS and K, a final acceptable result of VK VS 4.55, K 0.6 is In accordance with Section 16.8.4 the mid-tap position is used to calculate the ratio correction factors. The mid tap position is –5%, and at this tap position: Primary voltage to give rated secondary voltage: = 33 x 0.95 = 31.35kV and Rated Primary Current = 184A Transformer HV full load current on secondary of main CTs is: obtained. This results in an operating time faster than 40ms. 16-22 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 16 ˜ Transformer and Transformer Feeder Protection 184 250 of overloading will shorten the life-expectancy of the transformer, due to the elevated winding temperatures. 0.737 Ratio compensation = 1 1.36 0.737 LV secondary current = 525 600 0.875 Ratio compensation = 1 0.875 1.14 Both of the above values can be set in the relay. 16.19.3.2 Bias slope setting The on-load tapping range of +5% to -15% gives rise to a maximum excursion of r10% from the -5% mid-tap position. As the differential scheme notionally balances at this mid-tap, this means that as an approximation, the maximum differential current that can flow when at top or bottom tap is 10% of the load (or fault current which may flow to an external fault). Those relays having an adjustable k1 bias slope setting should ensure that it is at least 10% higher than the percentage excursion. Insulation deterioration is not uniform, and will be more pronounced at hot-spots within the transformer tank. Therefore, any asset management system intended to model the rate of deterioration and current estimated state of the insulation must do so based on simulated real-time hot spot temperature algorithms. These models may take ambient temperature, top-oil temperature, load current flowing, the status of oil pumps (pumping or not), and the status of radiator fans (forced cooling or not) as inputs. The MiCOM P640 provides such a loss of life monitoring facility, according to the thermal model defined in IEEE Standard C57.91. The protection algorithm determines the current rate of losing life, and uses that to indicate the remaining years or hours until critical insulation health statuses are likely to be reached. Such criticalities will relate typically to known percentage degradations in the tensile strength of the insulation, degradation in the degree of polymerisation, and other life-loss factors. The asset owner can be alerted in advance that an outage will be required for reconditioning or rewinding, such that investment budgeting can be made years and months ahead of time. 16.20 TRANSFORMER ASSET MANAGEMENT Due to the high capital cost of transformers, and the need for their in-service availability to be as high as possible to avoid constraining load flows demanded on the network, protection is no-longer the only concern. As cities expand, consumers’ lifestyle expectations raise, and electric vehicle recharging loads become more prevalent, these combine to increase the demand on the network - and it is through the transformers, between the different voltage levels on the system, that the demand is traditionally supplied. This increases the focus on knowing the health of transformers, real-time, to be able to schedule condition-based maintenance. Maintenance or reconditioning at a time of the asset-owner’s choosing is far more preferable than a forced unplanned outage due to failure. This section provides an overview of techniques commonly available in modern numerical transformer protection relays, which can extend to asset management of the protected transformer. 16.20.1 Loss of life monitoring Ageing of transformer insulation is a time-dependent function of temperature, moisture, and oxygen content. The moisture and oxygen contributions to insulation deterioration are minimised due to the preservation systems employed in the design of most modern transformers. Therefore, temperature is the key parameter in insulation ageing. Frequent excesses 16.20.2 Through-fault monitoring Loss of life monitoring serves to track the deterioration caused by long term, repeated overloading. However, it is not the right technique to monitor short-term heavy fault currents which flow through the transformer, out to an external fault on the downstream power system (e.g. fault IF2 in Figure 16.23). Through faults are a major cause of transformer damage and failure, as they stress the insulation and mechanical integrity such as the bracing of the windings. A specific through-fault monitor is recommended to monitor currents which are due to external faults passing through, and so may range from 3.5 times up to tens of times the rated current of the transformer. The MiCOM P640 performs an I2t calculation when the through current exceeds a user-set threshold, such that the heating effect of the square of the maximum phase current, and the duration of the fault event are calculated. Calculation results are added to cumulative values, and monitored so that utilities can schedule transformer maintenance or identify a need for system reinforcement. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 16-23 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 Generator and Generator Transformer Protection 17.1 INTRODUCTION 17.1 17.2 17.3 17.4 17.5 Introduction Generator Earthing Stator Winding Faults Stator Winding Protection Differential Protection of Direct Connected Generators 17.6 Differential Protection of GeneratorTransformers 17.7 Overcurrent Protection 17.8 Stator Earth Fault Protection 17.9 Overvoltage Protection 17.10 Undervoltage Protection 17.11 Low Forward Power/Reverse Power Protection 17.12 Unbalanced Loading 17.13 Protection Against Inadvertent Energisation 17.14 Under/Overfrequency/ Overfluxing Protection 17.15 Rotor Faults 17.16 Loss of Excitation Protection 17.17 Pole Slipping Protection 17.18 Stator Overheating 17.19 Mechanical Faults 17.20 Complete Generator Protection Schemes 17.21 Embedded Generation 17.22 Examples of Generator Protection Settings 17.23 Reference The core of an electric power system is the generation. With the exception of emerging fuel cell and solar-cell technology for power systems, the conversion of the fundamental energy into its electrical equivalent normally requires a 'prime mover' to develop mechanical power as an intermediate stage. The nature of this machine depends upon the source of energy and in turn this has some bearing on the design of the generator. Generators based on steam, gas, water or wind turbines, and reciprocating combustion engines are all in use. Electrical ratings extend from a few hundred kVA (or even less) for reciprocating engine and renewable energy sets, up to steam turbine sets exceeding 1200MVA. Small and medium sized sets may be directly connected to a power distribution system. A larger set may be associated with an individual transformer, through which it is coupled to the EHV primary transmission system. Switchgear may or may not be provided between the generator and transformer. In some cases, operational and economic advantages can be attained by providing a generator circuit breaker in addition to a high voltage circuit breaker, but special demands will be placed on the generator circuit breaker for interruption of generator fault current waveforms that do not have an early zero crossing. A unit transformer may be tapped off the interconnection between generator and transformer for the supply of power to auxiliary plant, as shown in Figure 17.1. The unit transformer could be of the order of 10% of the unit rating for a large fossilfuelled steam set with additional flue-gas desulphurisation plant, but it may only be of the order of 1% of unit rating for a hydro set. Figure 17.1: Generator-transformer unit Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-1 Network Protection & Automation Guide Industrial or commercial plants with a requirement for steam/hot water now often include generating plant utilising or producing steam to improve overall economics, as a Combined Heat and Power (CHP) scheme. The plant will typically have a connection to the public Utility distribution system, and such generation is referred to as ‘embedded’ generation. The generating plant may be capable of export of surplus power, or simply reduce the import of power from the supply Utility. This is shown in Figure 17.2. x overfluxing x inadvertent energisation x rotor electrical faults x loss of excitation x loss of synchronism x failure of prime mover x lubrication oil failure x overspeeding x rotor distortion x difference in expansion between rotating and stationary parts x excessive vibration x core lamination faults 17.2 GENERATOR EARTHING The neutral point of a generator is usually earthed to facilitate protection of the stator winding and associated system. Earthing also prevents damaging transient overvoltages in the event of an arcing earth fault or ferroresonance. For HV generators, impedance is usually inserted in the stator earthing connection to limit the magnitude of earth fault current. There is a wide variation in the earth fault current chosen, common values being: x rated current x 200A-400A (low impedance earthing) x 10A-20A (high impedance earthing) Figure 17.2: Embedded generation A modern generating unit is a complex system comprising the generator stator winding, associated transformer and unit transformer (if present), the rotor with its field winding and excitation system, and the prime mover with its associated auxiliaries. Faults of many kinds can occur within this system for which diverse forms of electrical and mechanical protection are required. The amount of protection applied will be governed by economic considerations, taking into account the value of the machine, and the value of its output to the plant owner. The main methods of impedance-earthing a generator are shown in Figure 17.3. Low values of earth fault current may limit the damage caused from a fault, but they simultaneously make detection of a fault towards the stator winding star point more difficult. Except for special applications, such as marine, LV generators are normally solidly earthed to comply with safety requirements. Where a step-up transformer is applied, the generator and the lower voltage winding of the transformer can be treated as an isolated system that is not influenced by the earthing requirements of the power system. The following problems require consideration from the point of view of applying protection: x stator electrical faults x overload x overvoltage x unbalanced loading 17-2 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection voltage above the rated value caused by a sudden loss of load or by field forcing must be considered, as well as flux doubling in the transformer due to the point-on-wave of voltage application. It is sufficient that the transformer be designed to have a primary winding knee-point e.m.f. equal to 1.3 times the generator rated line voltage. (a) Direct earthing Typical setting (% of earthing resistor rating) I>> 10 I> 5 17.3 STATOR WINDING FAULTS Failure of the stator windings or connection insulation can result in severe damage to the windings and stator core. The extent of the damage will depend on the magnitude and duration of the fault current. 17.3.1 Earth Faults (b) Resistance earthing The most probable mode of insulation failure is phase to earth. Use of an earthing impedance limits the earth fault current and hence stator damage. Loading resistor V> (c) Distribution transformer earthing with overvoltage relay. Loading resistor I> (d) Distribution transformer earthing with overcurrent relay Figure 17.3: Methods of generator earthing An earthing transformer or a series impedance can be used as the impedance. If an earthing transformer is used, the continuous rating is usually in the range 5-250kVA. The secondary winding is loaded with a resistor of a value which, when referred through the transformer ratio, will pass the chosen short-time earth-fault current. This is typically in the range of 5-20A. The resistor prevents the production of high transient overvoltages in the event of an arcing earth fault, which it does by discharging the bound charge in the circuit capacitance. For this reason, the resistive component of fault current should not be less than the residual capacitance current. This is the basis of the design, and in practice values of between 3-5 Ico are used. It is important that the earthing transformer never becomes saturated; otherwise a very undesirable condition of ferroresonance may occur. The normal rise of the generated An earth fault involving the stator core results in burning of the iron at the point of fault and welds laminations together. Replacement of the faulty conductor may not be a very serious matter (dependent on set rating/voltage/construction) but the damage to the core cannot be ignored, since the welding of laminations may result in local overheating. The damaged area can sometimes be repaired, but if severe damage has occurred, a partial core rebuild will be necessary. A flashover is more likely to occur in the end-winding region, where electrical stresses are highest. The resultant forces on the conductors would be very large and they may result in extensive damage, requiring the partial or total rewinding of the generator. Apart from burning the core, the greatest danger arising from failure to quickly deal with a fault is fire. A large portion of the insulating material is inflammable, and in the case of an aircooled machine, the forced ventilation can quickly cause an arc flame to spread around the winding. Fire will not occur in a hydrogen-cooled machine, provided the stator system remains sealed. In any case, the length of an outage may be considerable, resulting in major financial impact from loss of generation revenue and/or import of additional energy. 17.3.2 Phase-Phase Faults Phase-phase faults clear of earth are less common; they may occur on the end portion of stator coils or in the slots if the winding involves two coil sides in the same slot. In the latter case, the fault will involve earth in a very short time. Phase fault current is not limited by the method of earthing the neutral point. 17.3.3 Interturn Faults Interturn faults are rare, but a significant fault-loop current can © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-3 Network Protection & Automation Guide arise where such a fault does occur. Conventional generator protection systems would be blind to an interturn fault, but the extra cost and complication of providing detection of a purely interturn fault is not usually justified. In this case, an interturn fault must develop into an earth fault before it can be cleared. An exception may be where a machine has an abnormally complicated or multiple winding arrangement, where the probability of an interturn fault might be increased. 17.4 STATOR WINDING PROTECTION To respond quickly to a phase fault with damaging heavy current, sensitive, high-speed differential protection is normally applied to generators rated in excess of 1MVA. For large generating units, fast fault clearance will also maintain stability of the main power system. The zone of differential protection can be extended to include an associated step-up transformer. For smaller generators, IDMT/instantaneous overcurrent protection is usually the only phase fault protection applied. Sections 17.5 to 17.8 detail the various methods that are available for stator winding protection. 17.5 DIFFERENTIAL PROTECTION OF DIRECT CONNECTED GENERATORS The theory of circulating current differential protection is discussed fully in Section 10.4. High-speed phase fault protection is provided, by use of the connections shown in Figure 17.4. This depicts the derivation of differential current through CT secondary circuit connections. This protection may also offer earth fault protection for some moderate impedance-earthed applications. Either biased differential or high impedance differential techniques can be applied. A subtle difference with modern, biased, numerical generator protection relays is that they usually derive the differential currents and biasing currents by algorithmic calculation, after measurement of the individual CT secondary currents. In such relay designs, there is full galvanic separation of the neutral-tail and terminal CT secondary circuits, as indicated in Figure 17.5(a). This is not the case for the application of high-impedance differential protection. This difference can impose some special relay design requirements to achieve stability for biased differential protection in some applications. Figure 17.4: Stator differential protection 17.5.1 Biased Differential Protection The relay connections for this form of protection are shown in Figure 17.5(a) and a typical bias characteristic is shown in Figure 17.5(b). The differential current threshold setting Is1 can be set as low as 5% of rated generator current, to provide protection for as much of the winding as possible. The bias slope break-point threshold setting Is2 would typically be set to a value above generator rated current, say 120%, to achieve external fault stability in the event of transient asymmetric CT saturation. Bias slope K2 setting would typically be set at 150%. I diff I1  I 2 I bias I1  I 2 Figure 17.5: Typical generator biased differential protection 17-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 2 Chapter 17 ˜ Generator and Generator Transformer Protection 17.5.2 High Impedance Differential Protection This differs from biased differential protection by the manner in which relay stability is achieved for external faults and by the fact that the differential current must be attained through the electrical connections of CT secondary circuits. If the impedance of each relay in Figure 17.4 is high, the event of one CT becoming saturated by the through fault current (leading to a relatively low CT impedance), will allow the current from the unsaturated CT to flow mainly through the saturated CT rather than through the relay. This provides the required protection stability where a tuned relay element is employed. In practice, external resistance is added to the relay circuit to provide the necessary high impedance. The principle of high-impedance protection application is illustrated in Figure 17.6, together with a summary of the calculations required to determine the value of external stabilising resistance. Healthy CT Saturated CT Protected zone Figure 17.7: Relay connections for high impedance differential protection To calculate the primary operating current, the following expression is used: I op N u I s1  nI e where: Iop = primary operating current N = CT ratio Zm RCT2 RCT1 RL1 If Rst Is1 is typically set to 5% of generator rated secondary current. RL4 Voltage across relay circuit Vr n = number of CTs in parallel with relay element Ie = CT magnetising current at VS Vr Id > RL2 RL3 Is1 = relay setting I f RCT  2 RL and Vs KVr where 1 . 0  K d 1 .5 Stabilising resistor, Rst, limits spill current to <Is (relay setting) Vs  RR Rst Is where RR= relay burden It can be seen from the above that the calculations for the application of high impedance differential protection are more complex than for biased differential protection. However, the protection scheme is actually quite simple and it offers a high level of stability for through faults and external switching events. With the advent of multi-function numerical relays and with a desire to dispense with external components, high impedance differential protection is not as popular as biased differential protection in modern relaying practice. Figure 17.6: Principle of high impedance differential protection In some applications, protection may be required to limit voltages across the CT secondary circuits when the differential secondary current for an internal phase fault flows through the high impedance relay circuit(s), but this is not commonly a requirement for generator differential applications unless very high impedance relays are applied. Where necessary, shunt– connected, non-linear resistors, should be deployed, as shown in Figure 17.7. 17.5.3 CT Requirements The CT requirements for differential protection will vary according to the relay used. Modern numerical relays may not require CTs specifically designed for differential protection to IEC 60044-1 class PX (or BS 3938 class X). However, requirements in respect of CT knee-point voltage will still have to be checked for the specific relays used. High impedance differential protection may be more onerous in this respect than biased differential protection. Many factors affect this, including the other protection functions fed by the CTs and the knee-point requirements of the particular relay concerned. Relay manufacturers are able to provide detailed guidance on this matter. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-5 Network Protection & Automation Guide 17.6 DIFFERENTIAL PROTECTION OF GENERATOR-TRANSFORMERS A common connection arrangement for large generators is to operate the generator and associated step-up transformer as a unit without any intervening circuit breaker. The unit transformer supplying the generator auxiliaries is tapped off the connection between generator and step-up transformer. Differential protection can be arranged as follows. 17.6.1 Generator/Step-up Transformer Differential Protection The generator stator and step-up transformer can be protected by a single zone of overall differential protection (Figure 17.8). This will be in addition to differential protection applied to the generator only. The current transformers should be located in the generator neutral connections and in the transformer HV connections. Alternatively, CTs within the HV switchyard may be employed if the distance is not technically prohibitive. Even where there is a generator circuit breaker, overall differential protection can still be provided if desired. usually applied to balance the generator differential protection and prevent the unit transformer through current being seen as differential current. An exception might be where the unit transformer rating is extremely low in relation to the generator rating, e.g. for some hydro applications. The location of the third set of current transformers is normally on the primary side of the unit transformer. If located on secondary side of the unit transformer, they would have to be of an exceptionally high ratio, or exceptionally high ratio interposing CTs would have to be used. Thus, the use of secondary side CTs is not to be recommended. One advantage is that Unit Transformer faults would be within the zone of protection of the generator. However, the sensitivity of the generator protection to unit transformer phase faults would be considered inadequate, due to the relatively low rating of the transformer in relation to that of the generator. Thus, the unit transformer should have its own differential protection scheme. Protection for the Unit Transformer is covered in Chapter 16, including methods for stabilising the protection against magnetising inrush conditions. 17.7 OVERCURRENT PROTECTION Overcurrent protection of generators may take two forms. Plain overcurrent protection may be used as the principal form of protection for small generators, and back-up protection for larger ones where differential protection is used as the primary method of generator stator winding protection. Voltage dependent overcurrent protection may be applied where differential protection is not justified on larger generators, or where problems are met in applying plain overcurrent protection. Figure 17.8: Overall generator-transformer differential protection 17.7.1 Plain Overcurrent Protection The current transformers should be rated according to Section 16.8.2. Since a power transformer is included within the zone of protection, biased transformer differential protection, with magnetising inrush restraint should be applied, as discussed in Section 16.8.5. Transient overfluxing of the generator transformer may arise due to overvoltage following generator load rejection. In some applications, this may threaten the stability of the differential protection. In such cases, consideration should be given to applying protection with transient overfluxing restraint/blocking (e.g. based on a 5th harmonic differential current threshold). Protection against sustained overfluxing is covered in Section 17.4. It is usual to apply time-delayed plain overcurrent protection to generators. For generators rated less than 1MVA, this will form the principal stator winding protection for phase faults. For larger generators, overcurrent protection can be applied as remote back-up protection, to disconnect the unit from any uncleared external fault. Where there is only one set of differential main protection, for a smaller generator, the overcurrent protection will also provide local back-up protection for the protected plant, in the event that the main protection fails to operate. The general principles of setting overcurrent relays are given in Chapter 9. 17.6.2 Unit Transformer Differential Protection The current taken by the unit transformer must be allowed for by arranging the generator differential protection as a threeended scheme. Unit transformer current transformers are 17-6 In the case of a single generator feeding an isolated system, current transformers at the neutral end of the machine should energise the overcurrent protection, to allow a response to winding fault conditions. Relay characteristics should be selected to take into account the fault current decrement behaviour of the generator, with allowance for the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection performance of the excitation system and its field-forcing capability. Without the provision of fault current compounding from generator CTs, an excitation system that is powered from an excitation transformer at the generator terminals will exhibit a pronounced fault current decrement for a terminal fault. With failure to consider this effect, the potential exists for the initial high fault current to decay to a value below the overcurrent protection pick-up setting before a relay element can operate, unless a low current setting and/or time setting is applied. The protection would then fail to trip the generator. The settings chosen must be the best compromise between assured operation in the foregoing circumstances and discrimination with the system protection and passage of normal load current, but this can be impossible with plain overcurrent protection. In the more usual case of a generator that operates in parallel with others and which forms part of an extensive interconnected system, back-up phase fault protection for a generator and its transformer will be provided by HV overcurrent protection. This will respond to the higher-level backfeed from the power system to a unit fault. Other generators in parallel would supply this current and, being stabilised by the system impedance, it will not suffer a major decrement. This protection is usually a requirement of the power system operator. Settings must be chosen to prevent operation for external faults fed by the generator. It is common for the HV overcurrent protection relay to provide both time-delayed and instantaneous high-set elements. The time-delayed elements should be set to ensure that the protected items of plant cannot pass levels of through fault current in excess of their short-time withstand limits. The instantaneous elements should be set above the maximum possible fault current that the generator can supply, but less than the system-supplied fault current in the event of a generator winding fault. This back-up protection will minimise plant damage in the event of main protection failure for a generating plant fault and instantaneous tripping for an HVside fault will aid the recovery of the power system and parallel generation. are discussed in the following sections. The choice depends upon the power system characteristics and level of protection to be provided. Voltage-dependent overcurrent relays are often found applied to generators used on industrial systems, as an alternative to full differential protection. 17.7.2.1 Voltage Controlled Overcurrent Protection Voltage controlled overcurrent protection has two time/current characteristics which are selected according to the status of a generator terminal voltage measuring element. The voltage threshold setting for the switching element is chosen according to the following criteria. x during overloads, when the system voltage is sustained near normal, the overcurrent protection should have a current setting above full load current and an operating time characteristic that will prevent the generating plant from passing current to a remote external fault for a period in excess of the plant short-time withstand limits x under close-up fault conditions, the busbar voltage must fall below the voltage threshold so that the second protection characteristic will be selected. This characteristic should be set to allow relay operation with fault current decrement for a close-up fault at the generator terminals or at the HV busbars. The protection should also time-grade with external circuit protection. There may be additional infeeds to an external circuit fault that will assist with grading Typical characteristics are shown in Figure 17.9. 17.7.2 Voltage-Dependent Overcurrent Protection The plain overcurrent protection setting difficulty referred to in the previous section arises because allowance has to be made both for the decrement of the generator fault current with time and for the passage of full load current. To overcome the difficulty of discrimination, the generator terminal voltage can be measured and used to dynamically modify the basic relay current/time overcurrent characteristic for faults close to the generating plant. There are two basic alternatives for the application of voltage-dependent overcurrent protection, which Figure 17.9: Voltage controlled relay characteristics 17.7.2.2 Voltage Restrained Overcurrent Protection The alternative technique is to continuously vary the relay element pickup setting with generator voltage variation between upper and lower limits. The voltage is said to restrain © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-7 Network Protection & Automation Guide the operation of the current element. The effect is to provide a dynamic I.D.M.T. protection characteristic, according to the voltage at the machine terminals. Alternatively, the relay element may be regarded as an impedance type with a long dependent time delay. In consequence, for a given fault condition, the relay continues to operate more or less independently of current decrement in the machine. A typical characteristic is shown in Figure 17.10. 33% of the maximum earth fault current of the generator, and a lower setting would be preferable, depending on grading considerations. 17.8.1.2 Sensitive Earth Fault Protection This method is used in the following situations: a. direct-connected generators operating in parallel b. generators with high-impedance neutral earthing, the earth fault current being limited to a few tens of amps c. installations where the resistance of the ground fault path is very high, due to the nature of the ground In these cases, conventional earth fault protection as described in Section 17.8.1.1 is of little use. Figure 17.10: Voltage restrained relay characteristics 17.8 STATOR EARTH FAULT PROTECTION Earth fault protection must be applied where impedance earthing is employed that limits the earth fault current to less than the pick-up threshold of the overcurrent and/or differential protection for a fault located down to the bottom 5% of the stator winding from the star-point. The type of protection required will depend on the method of earthing and connection of the generator to the power system. 17.8.1 Direct-Connected Generators A single direct-connected generator operating on an isolated system will normally be directly earthed. However, if several direct-connected generators are operated in parallel, only one generator is normally earthed at a time. For the unearthed generators, a simple measurement of the neutral current is not possible, and other methods of protection must be used. The following sections describe the methods available. 17.8.1.1 Neutral Overcurrent Protection With this form of protection, a current transformer in the neutral-earth connection energises an overcurrent relay element. This provides unrestricted earth-fault protection and so it must be graded with feeder protection. The relay element will therefore have a time-delayed operating characteristic. Grading must be carried out in accordance with the principles detailed in Chapter 9. The setting should not be more than 17-8 The principles of sensitive earth fault protection are described in Sections 9.17.1, 9.18 and 9.19. The earth fault (residual) current can be obtained from residual connection of line CTs, a line-connected CBCT, or a CT in the generator neutral. The latter is not possible if directional protection is used. The polarising voltage is usually the neutral voltage displacement input to the relay, or the residual of the three phase voltages, so a suitable VT must be used. For Petersen Coil earthing, a wattmetric technique (Section 9.19) can also be used. For direct connected generators operating in parallel, directional sensitive earth fault protection may be necessary. This is to ensure that a faulted generator will be tripped before there is any possibility of the neutral overcurrent protection tripping a parallel healthy generator. When being driven by residually-connected phase CTs, the protection must be stabilised against incorrect tripping with transient spill current in the event of asymmetric CT saturation when phase fault or magnetising inrush current is being passed. Stabilising techniques include the addition of relay circuit impedance and/or the application of a time delay. Where the required setting of the protection is very low in comparison to the rated current of the phase CTs, it would be necessary to employ a single CBCT for the earth fault protection to ensure transient stability. Since any generator in the paralleled group may be earthed, all generators will require to be fitted with both neutral overcurrent protection and sensitive directional earth fault protection. The setting of the sensitive directional earth fault protection is chosen to co-ordinate with generator differential protection and/or neutral voltage displacement protection to ensure that 95% of the stator winding is protected. Figure 17.11 illustrates the complete scheme, including optional blocking signals where difficulties in co-ordinating the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection generator and downstream feeder earth-fault protection occur. Feeder I I > I >> Ursd > > I Ursd > > Block* I Block* > ~ I > unbalance voltage provides a means of detecting earth faults. The relay element must be insensitive to third harmonic voltages that may be present in the system voltage waveforms, as these will sum residually. As the protection is still unrestricted, the voltage setting of the relay must be greater than the effective setting of any downstream earth fault protection. It must also be timedelayed to co-ordinate with such protection. Sometimes, a second high-set element with short time delay is used to provide fast-acting protection against major winding earth faults. Figure 17.12 illustrates the possible connections that may be used. ~ Open Re Re Vph-n Minimum earth fault level = IF = R e * Optional interlocked earth-fault protection if grading problems exist Figure 17.11: Comprehensive earth-fault protection scheme for direct-connected generators operating in parallel For cases (b) and (c) above, it is not necessary to use a directional facility. Care must be taken to use the correct RCA setting – for instance if the earthing impedance is mainly resistive, this should be 0o. On insulated or very high impedance earthed systems, an RCA of –90o would be used, as the earth fault current is predominately capacitive. Figure 17.12: Neutral voltage displacement protection Directional sensitive earth-fault protection can also be used for detecting winding earth faults. In this case, the relay element is applied to the terminals of the generator and is set to respond to faults only within the machine windings. Hence earth faults on the external system do not result in relay operation. However, current flowing from the system into a winding earth-fault causes relay operation. It will not operate on the earthed machine, so that other types of earth-fault protection must also be applied. All generators must be so fitted, since any can be operated as the earthed machine. 17.8.2 Indirectly-Connected Generators 17.8.1.3 Neutral Voltage Displacement Protection A current transformer mounted on the neutral-earth conductor can drive an instantaneous and/or time delayed overcurrent relay element, as shown in Figure 17.13. It is impossible to provide protection for the whole of the winding, and Figure 17.13 also details how the percentage of winding covered can be calculated. For a relay element with an instantaneous setting, protection is typically limited to 90% of the winding. This is to ensure that the protection will not maloperate with zero sequence current during operation of a primary fuse for a VT earth fault or with any transient surge currents that could In a balanced network, the addition of the three phase-earth voltages produces a nominally zero residual voltage, since there would be little zero sequence voltage present. Any earth fault will set up a zero sequence system voltage, which will give rise to a non-zero residual voltage. This can be measured by a suitable relay element. The voltage signal must be derived from a VT that is suitable – i.e. it must be capable of transforming zero-sequence voltage, so 3-limb types and those without a primary earth connection are not suitable. This As noted in Section 17.2, a directly-earthed generatortransformer unit cannot interchange zero-sequence current with the remainder of the network, and hence an earth fault protection grading problem does not exist. The following sections detail the protection methods for the various forms of impedance earthing of generators. 17.8.2.1 High Resistance Earthing – Neutral Overcurrent Protection © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-9 Network Protection & Automation Guide flow through the interwinding capacitance of the step-up transformer for an HV system earth fault. A time-delayed relay is more secure in this respect, and it may have a setting to cover 95% of the stator winding. Since the generating units under consideration are usually large, instantaneous and time delayed relay elements are often applied, with settings of 10% and 5% of maximum earth fault current respectively; this is the optimum compromise in performance. The portion of the winding left unprotected for an earth fault is at the neutral end. Since the voltage to earth at this end of the winding is low, the probability of an earth fault occurring is also low. Hence additional protection is often not applied. If aV R IsR V (1  a min) u 100% a min Figure 17.13: Earth fault protection of high-resistance earthed generator stator winding using a current element 17.8.2.2 Distribution Transformer Earthing Using a Current Element In this arrangement, shown in Figure 17.14(a), the generator is earthed via the primary winding of a distribution transformer. The secondary winding is fitted with a loading resistor to limit the earth fault current. An overcurrent relay element energised from a current transformer connected in the resistor circuit is used to measure secondary earth fault current. The relay should have an effective setting equivalent to 5% of the maximum earth fault current at rated generator voltage, in order to protect 95% of the stator winding. The relay element response to third harmonic current should be limited to prevent incorrect operation when a sensitive setting is applied. 17-10 Figure 17.14: Generator winding earth-fault protection - distribution transformer earthing As discussed in Section 17.8.2.1, the protection should be time delayed when a sensitive setting is applied, in order to prevent maloperation under transient conditions. It also must grade with generator VT primary protection (for a VT primary earth fault). An operation time in the range 0.5s-3s is usual. Less sensitive instantaneous protection can also be applied to provide fast tripping for a heavier earth fault condition. 17.8.2.3 Distribution Transformer Earthing Using a Voltage Element Earth fault protection can also be provided using a voltagemeasuring element in the secondary circuit instead. The setting considerations would be similar to those for the current operated protection, but transposed to voltage. The circuit diagram is shown in Figure 17.14(b). Application of both voltage and current operated elements to a generator with distribution transformer earthing provides some advantages. The current operated function will continue to operate in the event of a short-circuited loading resistor and the voltage protection still functions in the event of an opencircuited resistor. However, neither scheme will operate in the event of a flashover on the primary terminals of the transformer or of the neutral cable between the generator and © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection the transformer during an earth fault. A CT could be added in the neutral connection close to the generator, to energise a high-set overcurrent element to detect such a fault, but the fault current would probably be high enough to operate the phase differential protection. 17.8.2.4 Neutral Voltage Displacement Protection This can be applied in the same manner as for directconnected generators (Section 17.8.1.3). The only difference is that the are no grading problems as the protection is inherently restricted. A sensitive setting can therefore be used, enabling cover of up to 95% of the stator winding to be achieved. 17.8.3 Restricted Earth Fault Protection This technique can be used on small generators not fitted with differential protection to provide fast acting earth fault protection within a defined zone that encompasses the generator. It is cheaper than full differential protection but only provides protection against earth faults. The principle is that used for transformer REF protection, as detailed in Section 16.7. However, in contrast to transformer REF protection, both biased low-impedance and high-impedance techniques can be used. 17.8.3.1 Low-Impedance Biased REF Protection This is shown in Figure 17.15. The main advantage is that the neutral CT can also be used in a modern relay to provide conventional earth-fault protection and no external resistors are used. Relay bias is required, as described in Section 10.4.2, but the formula for calculating the bias is slightly different and also shown in Figure 17.15. The initial bias slope is commonly set to 0% to provide maximum sensitivity, and applied up to the rated current of the generator. It may be increased to counter the effects of CT mismatch. The bias slope above generator rated current is typically set to 150% of rated value. The initial current setting is typically 5% of the minimum earth fault current for a fault at the machine terminals. 17.8.3.2 High Impedance REF Protection The principle of high impedance differential protection is given in Chapter 10 and also described further in Section 17.5.2. The same technique can be used for earth-fault protection of a generator, using three residually connected phase CTs balanced against a similar single CT in the neutral connection. Settings of the order of 5% of maximum earth fault current at the generator terminals are typical. The usual requirements in respect of stabilising resistor and non-linear resistor to guard against excessive voltage across the relay must be taken, where necessary. 17.8.4 Earth Fault Protection for the Entire Stator Winding All of the methods for earth fault protection detailed so far leave part of the winding unprotected. In most cases, this is of no consequence as the probability of a fault occurring in the 5% of the winding nearest the neutral connection is very low, due to the reduced phase to earth voltage. However, a fault can occur anywhere along the stator windings in the event of insulation failure due to localised heating from a core fault. In cases where protection for the entire winding is required, perhaps for alarm only, there are various methods available. 17.8.4.1 Measurement of Third Harmonic Voltage I BIAS highest of I A , I B , I C  IN × scaling factor 2 where scaling factor = IDIFF neutral CTratio 200 = = 0.2 phase CTratio 1000 I A  I B  I C  scaling factor u IN Figure 17.15: Low impedance biased REF protection of a generator One method is to measure the internally generated third harmonic voltage that appears across the earthing impedance due to the flow of third harmonic currents through the shunt capacitance of the stator windings etc. When a fault occurs in the part of the stator winding nearest the neutral end, the third harmonic voltage drops to near zero, and hence a relay element that responds to third harmonic voltage can be used to detect the condition. As the fault location moves progressively away from the neutral end, the drop in third harmonic voltage from healthy conditions becomes less, so that at around 20-30% of the winding distance, it no longer becomes possible to discriminate between a healthy and a faulty winding. Hence, a conventional earth-fault scheme should be used in conjunction with a third harmonic scheme, to provide overlapping cover of the entire stator winding. The measurement of third harmonic voltage can be taken either from a star-point VT or the generator line VT. In the latter © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-11 Network Protection & Automation Guide case, the VT must be capable of carrying residual flux, and this prevents the use of 3-limb types. If the third harmonic voltage is measured at the generator star point, an undervoltage characteristic is used. An overvoltage characteristic is used if the measurement is taken from the generator line VT. For effective application of this form of protection, there should be at least 1% third harmonic voltage across the generator neutral earthing impedance under all operating conditions. A problem encountered is that the level of third harmonic voltage generated is related to the output of the generator. The voltage is low when generator output is low. In order to avoid maloperation when operating at low power output, the relay element can be inhibited using an overcurrent or power elements (kW, kVAr or kVA) and internal programmable logic. 17.8.4.2 Use of Low-Frequency Voltage Injection Another method for protecting the entire stator winding of a generator is to deploy signal injection equipment to inject a low frequency voltage between the stator star point and earth. An earth fault at any winding location will result in the flow of a measurable injection current to cause protection operation. This form of protection can provide earth fault protection when the generator is at standstill, prior to run-up. It is also an appropriate method to apply to variable speed synchronous machines. Such machines may be employed for variable speed motoring in pumped-storage generation schemes or for starting a large gas turbine prime mover. 17.9 OVERVOLTAGE PROTECTION Overvoltages on a generator may occur due to transient surges on the network, or prolonged power frequency overvoltages may arise from a variety of conditions. Surge arrestors may be required to protect against transient overvoltages, but relay protection may be used to protect against power frequency overvoltages. A sustained overvoltage condition should not occur for a machine with a healthy voltage regulator, but it may be caused by the following contingencies: x defective operation of the automatic voltage regulator when the machine is in isolated operation x operation under manual control with the voltage regulator out of service. A sudden variation of the load, in particular the reactive power component, will give rise to a substantial change in voltage because of the large voltage regulation inherent in a typical alternator x sudden loss of load (due to tripping of outgoing feeders, leaving the set isolated or feeding a very small load) may cause a sudden rise in terminal voltage due to the trapped field flux and/or overspeed 17-12 Sudden loss of load should only cause a transient overvoltage while the voltage regulator and governor act to correct the situation. A maladjusted voltage regulator may trip to manual, maintaining excitation at the value prior to load loss while the generator supplies little or no load. The terminal voltage will increase substantially, and in severe cases it would be limited only by the saturation characteristic of the generator. A rise in speed simply compounds the problem. If load that is sensitive to overvoltages remains connected, the consequences in terms of equipment damage and lost revenue can be severe. Prolonged overvoltages may also occur on isolated networks, or ones with weak interconnections, due to the fault conditions listed earlier. For these reasons, it is prudent to provide power frequency overvoltage protection, in the form of a time-delayed element, either IDMT or definite time. The time delay should be long enough to prevent operation during normal regulator action, and therefore should take account of the type of AVR fitted and its transient response. Sometimes a high-set element is provided as well, with a very short definite-time delay or instantaneous setting to provide a rapid trip in extreme circumstances. The usefulness of this is questionable for generators fitted with an excitation system other than a static type, because the excitation will decay in accordance with the open-circuit time constant of the field winding. This decay can last several seconds. The relay element is arranged to trip both the main circuit breaker (if not already open) and the excitation; tripping the main circuit breaker alone is not sufficient. 17.10 UNDERVOLTAGE PROTECTION Undervoltage protection was historically rarely fitted to generators. It is sometimes used as an interlock element for another protection function or scheme, such as field failure protection or inadvertent energisation protection, where the abnormality to be detected leads directly or indirectly to an undervoltage condition. A transmission system undervoltage condition may arise when there is insufficient reactive power generation to maintain the system voltage profile and the condition must be addressed to avoid the possible phenomenon of system voltage collapse. However, it should be addressed by the deployment of ’system protection’ schemes. The generation should not be tripped. The greatest case for undervoltage protection being required would be for a generator supplying an isolated power system or to meet the public Utility demands for connection of embedded generation (see Section 17.21). In the case of generators feeding an isolated system, undervoltage may occur for several reasons, typically overloading or failure of the AVR. In some cases, the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection performance of generator auxiliary plant fed via a unit transformer from the generator terminals could be adversely affected by prolonged undervoltage. Where undervoltage protection is required, it should comprise an undervoltage element and an associated time delay. Settings must be chosen to avoid maloperation during the inevitable voltage dips during power system fault clearance or associated with motor starting. Transient reductions in voltage down to 80% or less may be encountered during motor starting. 17.11 LOW FORWARD POWER/REVERSE POWER PROTECTION Low forward power or reverse power protection may be required for some generators to protect the prime mover. Parts of the prime mover may not be designed to experience reverse torque or they may become damaged through continued rotation after the prime mover has suffered some form of failure. 17.11.1 Low Forward Power Protection Low forward power protection is often used as an interlocking function to enable opening of the main circuit breaker for nonurgent trips – e.g. for a stator earth fault on a high-impedance earthed generator, or when a normal shutdown of a set is taking place. This is to minimise the risk of plant overspeeding when the electrical load is removed from a high-speed cylindrical rotor generator. The rotor of this type of generator is highly stressed mechanically and cannot tolerate much overspeed. While the governor should control overspeed conditions, it is not good practice to open the main circuit breaker simultaneously with tripping of the prime mover for non-urgent trips. For a steam turbine, for example, there is a risk of overspeeding due to energy storage in the trapped steam, after steam valve tripping, or in the event that the steam valve(s) do not fully close for some reason. For urgent trip conditions, such as stator differential protection operation, the risk involved in simultaneous prime mover and generator breaker tripping must be accepted. 17.11.2 Reverse Power Protection Reverse power protection is applied to prevent damage to mechanical plant items in the event of failure of the prime mover. Table 17.1 gives details of the potential problems for various prime mover types and the typical settings for reverse power protection. For applications where a protection sensitivity of better than 3% is required, a metering class CT should be employed to avoid incorrect protection behaviour due to CT phase angle errors when the generator supplies a significant level of reactive power at close to zero power factor. Table 17.1: Generator reverse power problems The reverse power protection should be provided with a definite time delay on operation to prevent spurious operation with transient power swings that may arise following synchronisation or in the event of a power transmission system disturbance. 17.12 UNBALANCED LOADING A three-phase balanced load produces a reaction field that, to a first approximation, is constant and rotates synchronously with the rotor field system. Any unbalanced condition can be resolved into positive, negative and zero sequence components. The positive sequence component is similar to the normal balanced load. The zero sequence component produces no main armature reaction. 17.12.1 Effect of Negative Sequence Current The negative sequence component is similar to the positive sequence system, except that the resulting reaction field Motoring Power Prime Mover Diesel Engine (% of rated) 5-25 Possible Damage Protection Setting Fire/explosion due to unburnt fuel Mechanical damage to gearbox/shafts 10-15 (split shaft) Gas Turbine Gearbox damage >50% 50% of motoring power (single shaft) 0.2-2 (blades out of water) Hydro Blade and runner cavitation >2 (blades in water) Turbine blade damage Steam Turbine 0.5-6 Gearbox damage on geared sets rotates in the opposite direction to the d.c. field system. Hence, a flux is produced which cuts the rotor at twice the rotational velocity, thereby inducing double frequency currents in the field system and in the rotor body. The resulting eddycurrents are very large and cause severe heating of the rotor. So severe is this effect that a single-phase load equal to the normal three-phase rated current can quickly heat the rotor slot wedges to the softening point. They may then be extruded under centrifugal force until they stand above the rotor surface, when it is possible that they may strike the stator core. A generator is assigned a continuous negative sequence rating. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-13 Network Protection & Automation Guide For turbo-generators this rating is low; standard values of 10% and 15% of the generator continuous rating have been adopted. The lower rating applies when the more intensive cooling techniques are applied, for example hydrogen-cooling with gas ducts in the rotor to facilitate direct cooling of the winding. Short time heating is of interest during system fault conditions and it is usual in determining the generator negative sequence withstand capability to assume that the heat dissipation during such periods is negligible. Using this approximation it is possible to express the heating by the law: I 22t K where: I2 = negative sequence component (per unit of MCR) t = time (seconds) K = constant proportional to the thermal capacity of the generator rotor For heating over a period of more than a few seconds, it is necessary to allow for the heat dissipated. From a combination of the continuous and short time ratings, the overall heating characteristic can be deduced to be: M I2 I2R 1 2 1 e  I2 R t K where: I2R = negative phase sequence continuous rating in per unit of MCR The heating characteristics of various designs of generator are shown in Figure 17.16. Figure 17.16: Typical negative phase sequence current withstand of cylindrical rotor generators 17.12.2 Negative Phase Sequence Protection This protection is applied to prevent overheating due to negative sequence currents. Small salient-pole generators have a proportionately larger negative sequence capacity and may not require protection. Modern numerical relays derive the negative sequence current level by calculation, with no need for special circuits to extract the negative sequence component. A true thermal replica approach is often followed, to allow for: x standing levels of negative sequence current below the continuous withstand capability. This has the effect of shortening the time to reach the critical temperature after an increase in negative sequence current above the continuous withstand capability x cooling effects when negative sequence current levels are below the continuous withstand capability The advantage of this approach is that cooling effects are modelled more accurately, but the disadvantage is that the tripping characteristic may not follow the withstand characteristic specified by the manufacturer accurately. The typical relay element characteristic takes the form of 17-14 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection t  K I 22set ª §I log e «1  ¨¨ 2 set ¬ © I2 ·º ¸¸» ¹¼ Equation 17.1 where: t = time to trip K I 2 set § I flc Kg u ¨ ¨I © p · ¸ ¸ ¹ 2 § I flc · ¸u I I 2cmr u ¨ ¨I ¸ n p © ¹ element is used, and gated with a three-phase undervoltage element (fed from a VT on the generator side of the circuit breaker) to provide the protection. The overcurrent element can have a low setting, as operation is blocked when the generator is operating normally. The voltage setting should be low enough to ensure that operation cannot occur for transient faults. A setting of about 50% of rated voltage is typical. VT failure can cause maloperation of the protection, so the element should be inhibited under these conditions. 17.14 UNDER/OVERFREQUENCY/ OVERFLUXING PROTECTION These conditions are grouped together because these problems often occur due to a departure from synchronous speed. Kg = negative sequence withstand coefficient (Figure 17.16) I2cmr = generator maximum continuous I2 withstand Iflc = generator rated primary current Ip = CT primary current In = Relay rated current Figure 17.16 also shows the thermal replica time characteristic described by Equation 17.1, from which it will be seen that a significant gain in capability is achieved at low levels of negative sequence current. Such a protection element will also respond to phase-earth and phase-phase faults where sufficient negative sequence current arises. Grading with downstream power system protection relays is therefore required. A definite minimum time setting must be applied to the negative sequence relay element to ensure correct grading. A maximum trip time setting may also be used to ensure correct tripping when the negative sequence current level is only slightly in excess of the continuous withstand capability and hence the trip time from the thermal model may depart significantly from the rotor withstand limits. 17.13 PROTECTION AGAINST INADVERTENT ENERGISATION Accidental energisation of a generator when it is not running may cause severe damage to it. With the generator at standstill, closing the circuit breaker results in the generator acting as an induction motor; the field winding (if closed) and the rotor solid iron/damper circuits acting as rotor circuits. Very high currents are induced in these rotor components, and also occur in the stator, with resultant rapid overheating and damage. Protection against this condition is therefore desirable. A combination of stator undervoltage and overcurrent can be used to detect this condition. An instantaneous overcurrent 17.14.1 Overfluxing Overfluxing occurs when the ratio of voltage to frequency is too high. The iron saturates owing to the high flux density and results in stray flux occurring in components not designed to carry it. Overheating can then occur, resulting in damage. The problem affects both direct-and indirectly-connected generators. Either excessive voltage, or low frequency, or a combination of both can result in overfluxing, a voltage to frequency ratio in excess of 1.05p.u. normally being indicative of this condition. Excessive flux can arise transiently, which is not a problem for the generator. For example, a generator can be subjected to a transiently high power frequency voltage, at nominal frequency, immediately after full load rejection. Since the condition would not be sustained, it only presents a problem for the stability of the transformer differential protection schemes applied at the power station (see Chapter 16 for transformer protection). Sustained overfluxing can arise during run up, if excitation is applied too early with the AVR in service, or if the generator is run down, with the excitation still applied. Other overfluxing instances have occurred from loss of the AVR voltage feedback signal, due to a reference VT problem. Such sustained conditions must be detected by a dedicated overfluxing protection function that will raise an alarm and possibly force an immediate reduction in excitation. Most AVRs have an overfluxing protection facility included. This may only be operative when the generator is on open circuit, and hence fail to detect overfluxing conditions due to abnormally low system frequency. However, this facility is not engineered to protection relay standards, and should not be solely relied upon to provide overfluxing protection. A separate relay element is therefore desirable and provided in most modern relays. It is usual to provide a definite time-delayed alarm setting and an instantaneous or inverse time-delayed trip setting, to match © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-15 Network Protection & Automation Guide the withstand characteristics of the protected generator and transformer. It is very important that the VT reference for overfluxing protection is not the same as that used for the AVR. 17.14.2 Under/Overfrequency The governor fitted to the prime mover normally provides protection against overfrequency. Underfrequency may occur as a result of overload of generators operating on an isolated system, or a serious fault on the power system that results in a deficit of generation compared to load. This may occur if a grid system suffers a major fault on transmission lines linking two parts of the system, and the system then splits into two. It is likely that one part will have an excess of generation over load, and the other will have a corresponding deficit. Frequency will fall fairly rapidly in the latter part, and the normal response is load shedding, either by load shedding relays or operator action. However, prime movers may have to be protected against excessively low frequency by tripping of the generators concerned. F B2 A 8S where: A = area B = flux density It will be seen from Figure 17.17 that the flux is concentrated on one pole but widely dispersed over the other and intervening surfaces. The attracting force is in consequence large on one pole but very weak on the opposite one, while flux on the quadrature axis will produce a balancing force on this axis. The result is an unbalanced force that in a large machine may be of the order of 50-100 tons. A violent vibration is set up that may damage bearing surfaces or even displace the rotor by an amount sufficient to cause it to foul the stator. Field Winding Short Circuit With some prime movers, operation in narrow frequency bands that lie close to normal running speed (either above or below) may only be permitted for short periods, together with a cumulative lifetime duration of operation in such frequency bands. This typically occurs due to the presence of rotor torsional frequencies in such frequency bands. In such cases, monitoring of the period of time spent in these frequency bands is required. A special relay is fitted in such cases, arranged to provide alarm and trip facilities if either an individual or cumulative period exceeds a set time. 17.15 ROTOR FAULTS The field circuit of a generator, comprising the field winding of the generator and the armature of the exciter, together with any associated field circuit breaker if it exists, is an isolated d.c. circuit which is not normally earthed. If an earth fault occurs, there will be no steady-state fault current and the need for action will not be evident. Danger arises if a second earth fault occurs at a separate point in the field system, to cause the high field current to be diverted, in part at least, from the intervening turns. Serious damage to the conductors and possibly the rotor can occur very rapidly under these conditions. More damage may be caused mechanically. If a large portion of the winding is short-circuited, the flux may adopt a pattern such as that shown in Figure 17.17. The attracting force at the surface of the rotor is given by: Figure 17.17: Flux distribution on rotor with partial winding short circuit 17.15.1 Rotor Earth-Fault Protection Two methods are available to detect this type of fault. The first method is suitable for generators that incorporate brushes in the main generator field winding. The second method requires at least a slip-ring connection to the field circuit: x Potentiometer method x A.C. injection method 17.15.1.1 Potentiometer Method This is a scheme that was fitted to older generators, and it is illustrated in Figure 17.18. An earth fault on the field winding would produce a voltage across the relay, the maximum voltage occurring for faults at the ends of the winding. A ‘blind spot' would exist at the centre of the field winding. To avoid a fault at this location remaining undetected, the tapping 17-16 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection point on the potentiometer could be varied by a pushbutton or switch. The relay setting is typically about 5% of the exciter voltage. Figure 17.18: Earth fault protection of field circuit by potentiometer method 17.15.1.2 Injection Methods Two methods are in common use. The first is based on low frequency signal injection, with series filtering, as shown in Figure 17.19(a). It comprises an injection source that is connected between earth and one side of the field circuit, through capacitive coupling and the measurement circuit. The field circuit is subjected to an alternating potential at substantially the same level throughout. An earth fault anywhere in the field system will give rise to a current that is detected as an equivalent voltage across the adjustable resistor by the relay. The capacitive coupling blocks the normal d.c. field voltage, preventing the discharge of a large direct current through the protection scheme. The combination of series capacitor and reactor forms a low-pass tuned circuit, the intention being to filter higher frequency rotor currents that may occur for a variety of reasons. Other schemes are based on power frequency signal injection. An impedance relay element is used, a field winding earth fault reducing the impedance seen by the relay. These suffer the draw back of being susceptible to static excitation system harmonic currents when there is significant field winding and excitation system shunt capacitance. Greater immunity for such systems is offered by capacitively coupling the protection scheme to both ends of the field winding, where brush or slip ring access is possible (Figure 17.19(b)). The low–frequency injection scheme is also advantageous in that the current flow through the field winding shunt capacitance will be lower than for a power frequency scheme. Such current would flow through the machine bearings to cause erosion of the bearing surface. For power frequency schemes, a solution is to insulate the bearings and provide an earthing brush for the shaft. Figure 17.19: Earth fault protection of field circuit by a.c. injection 17.15.2 Rotor Earth Fault Protection for Brushless Generators A brushless generator has an excitation system consisting of: x a main exciter with rotating armature and stationary field windings x a rotating rectifier assembly, carried on the main shaft line out x a controlled rectifier producing the d.c. field voltage for the main exciter field from an a.c. source (often a small ‘pilot’ exciter) Hence, no brushes are required in the generator field circuit. All control is carried out in the field circuit of the main exciter. Detection of a rotor circuit earth fault is still necessary, but this must be based on a dedicated rotor-mounted system that has a telemetry link to provide an alarm/data. 17.15.3 Rotor Shorted Turn Protection As detailed in Section 17.15, a shorted section of field winding will result in an unsymmetrical rotor flux pattern and in © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-17 Network Protection & Automation Guide potentially damaging rotor vibration. Detection of such an electrical fault is possible using a probe consisting of a coil placed in the airgap. The flux pattern of the positive and negative poles is measured and any significant difference in flux pattern between the poles is indicative of a shorted turn or turns. Automated waveform comparison techniques can be used to provide a protection scheme, or the waveform can be inspected visually at regular intervals. An immediate shutdown is not normally required unless the effects of the fault are severe. The fault can be kept under observation until a suitable shutdown for repair can be arranged. Repair will take some time, since it means unthreading the rotor and dismantling the winding. Since short-circuited turns on the rotor may cause damaging vibration and the detection of field faults for all degrees of abnormality is difficult, the provision of a vibration a detection scheme is desirable – this forms part of the mechanical protection of the generator. 17.15.4 Protection Against Diode Failure A short-circuited diode will produce an a.c. ripple in the exciter field circuit. This can be detected by a relay monitoring the current in the exciter field circuit, however such systems have proved to be unreliable. The relay would need to be time delayed to prevent an alarm being issued with normal field forcing during a power system fault. A delay of 5-10 seconds may be necessary. Fuses to disconnect the faulty diode after failure may be fitted. The fuses are of the indicating type, and an inspection window can be fitted over the diode wheel to enable diode health to be monitored manually. A diode that fails open-circuit occurs less often. If there is more than one diode in parallel for each arm of the diode bridge, the only impact is to restrict the maximum continuous excitation possible. If only a single diode per bridge arm is fitted, some ripple will be present on the main field supply but the inductance of the circuit will smooth this to a degree and again the main effect is to restrict the maximum continuous excitation. The set can be kept running until a convenient shutdown can be arranged. 17.15.5 Field Suppression The need to rapidly suppress the field of a machine in which a fault has developed should be obvious, because as long as the excitation is maintained, the machine will feed its own fault even though isolated from the power system. Any delay in the decay of rotor flux will extend the fault damage. Braking the rotor is no solution, because of its large kinetic energy. The 17-18 field winding current cannot be instantaneously as it flows in a highly inductive circuit. Consequently, the flux energy must be dissipated to prevent an excessive inductive voltage rise in the field circuit. For machines of moderate size, it is satisfactory to open the field circuit with an air-break circuit breaker without arc blow-out coils. Such a breaker permits only a moderate arc voltage, which is nevertheless high enough to suppress the field current fairly rapidly. The inductive energy is dissipated partly in the arc and partly in eddy-currents in the rotor core and damper windings. With generators above about 5MVA rating, it is better to provide a more definite means of absorbing the energy without incurring damage. Connecting a ‘field discharge resistor’ in parallel with the rotor winding before opening the field circuit breaker will achieve this objective. The resistor, which may have a resistance value of approximately five times the rotor winding resistance, is connected by an auxiliary contact on the field circuit breaker. The breaker duty is thereby reduced to that of opening a circuit with a low L/R ratio. After the breaker has opened, the field current flows through the discharge resistance and dies down harmlessly. The use of a fairly high value of discharge resistance reduces the field time constant to an acceptably low value, though it may still be more than one second. Alternatively, generators fitted with static excitation systems may temporarily invert the applied field voltage to reduce excitation current rapidly to zero before the excitation system is tripped. 17.16 LOSS OF EXCITATION PROTECTION Loss of excitation may occur for a variety of reasons. If the generator was initially operating at only 20%-30% of rated power, it may settle to run super-synchronously as an induction generator, at a low level of slip. In doing so, it will draw reactive current from the power system for rotor excitation. This form of response is particularly true of salient pole generators. In these circumstances, the generator may be able to run for several minutes without requiring to be tripped. There may be sufficient time for remedial action to restore the excitation, but the reactive power demand of the machine during the failure may severely depress the power system voltage to an unacceptable level. For operation at high initial power output, the rotor speed may rise to approximately 105% of rated speed, where there would be low power output and where a high reactive current of up to 2.0p.u. may be drawn from the supply. Rapid automatic disconnection is then required to protect the stator windings from excessive current and to protect the rotor from damage caused by induced slip frequency currents. interrupted © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection 17.16.1 Protection against Loss of Excitation XG The protection used varies according to the size of generator being protected. The field undercurrent relay must have a setting below the minimum exciting current, which may be 8% of that corresponding to the MCR of the machine. Time delay relays are used to stabilise the protection against maloperation in response to transient conditions and to ensure that field current fluctuations due to pole slipping do not cause the protection to reset. If the generator field current is not measurable, then the technique detailed in the following section is utilised. 17.16.1.2 Large Generators (>5MVA) For generators above about 5MVA rating, protection against loss of excitation and pole slipping conditions is normally applied. Consider a generator connected to network, as shown in Figure 17.20. On loss of excitation, the terminal voltage will begin to decrease and the stator current will increase, resulting in a decrease of impedance viewed from the generator terminals and also a change in power factor. ZS ES A +jX 17.16.1.1 Small Generators ( d 5MVA) On the smaller machines, protection against asynchronous running has tended to be optional, but it may now be available by default, where the functionality is available within a modern numerical generator protection package. If fitted, it is arranged either to provide an alarm or to trip the generator. If the generator field current can be measured, a relay element can be arranged to operate when this drops below a preset value. However, depending on the generator design and size relative to the system, it may well be that the machine would be required to operate synchronously with little or no excitation under certain system conditions. XT EG D ZS EG 1 ES XG+XT+ZS XT ZR -R T +R A XG C -jX Figure 17.20: Basic interconnected system A relay to detect loss of synchronism can be located at point A. It can be shown that the impedance presented to the relay under loss of synchronism conditions (phase swinging or pole slipping) is given by: ZR X G  X T  Z S n n  cos T  j sin T n  cos T 2  sin 2 T  XG Equation 17.2 where: n EG ES generated voltage system  = angle by which EG leads ES If the generator and system voltages are equal the above expression becomes: ZR j cot T · § X G  X T  Z S ¨1  ¸ 2 ¹ ©  XG 2 The general case can be represented by a system of circles with centres on the line CD; see Figure 17.21. Also shown is a typical machine terminal impedance locus during loss of excitation conditions. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-19 Network Protection & Automation Guide EG ES EG ES . 15 1 the direct-axis value, the ratio of Xd/Xg being known as the saliency factor. This factor varies with the slip speed. The effect of this factor during asynchronous operation is to cause XG to vary at slip speed. In consequence, the loss of excitation impedance locus does not settle at a single point, but it continues to describe a small orbit about a mean point. A protection scheme for loss of excitation must operate decisively for this condition, but its characteristic must not inhibit stable operation of the generator. One limit of operation corresponds to the maximum practicable rotor angle, taken to be 120°. The locus of operation can be represented as a circle on the impedance plane, as shown in Figure 17.22, stable operation conditions lying outside the circle. Figure 17.21: Swing curves and loss of synchronism locus The special cases of EG=ES and EG=0 result in a straight-line locus that is the right-angled bisector of CD and in a circular locus that is shrunk to point C, respectively. When excitation is removed from a generator operating synchronously the flux dies away slowly, during which period the ratio of EG/ES is decreasing, and the rotor angle of the machine is increasing. The operating condition plotted on an impedance diagram therefore travels along a locus that crosses the power swing circles. At the same time, it progresses in the direction of increasing rotor angle. After passing the antiphase position, the locus bends round as the internal e.m.f. collapses, condensing on an impedance value equal to the machine reactance. The locus is illustrated in Figure 17.21. The relay location is displaced from point C by the generator reactance XG. One problem in determining the position of these loci relative to the relay location is that the value of machine impedance varies with the rate of slip. At zero slip XG is equal to Xd, the synchronous reactance, and at 100% slip XG is equal to X’’d, the sub-transient reactance. The impedance in a typical case has been shown to be equal to X’d, the transient reactance, at 50% slip, and to 2X’d with a slip of 0.33%. The slip likely to be experienced with asynchronous running is low, perhaps 1%, so that for the purpose of assessing the power swing locus it is sufficient to take the value XG=2Xd’. This consideration has assumed a single value for XG. However, the reactance Xq on the quadrature axis differs from 17-20 Figure 17.22: Locus of limiting operating conditions of synchronous machine On the same diagram the full load impedance locus for one per unit power can be drawn. Part of this circle represents a condition that is not feasible, but the point of intersection with the maximum rotor angle curve can be taken as a limiting operating condition for setting impedance-based loss of excitation protection. 17.16.2 Impedance-Based Protection Characteristics Figure 17.21 alludes to the possibility that a protection scheme for loss of excitation could be based on impedance measurement. The impedance characteristic must be appropriately set or shaped to ensure decisive operation for loss of excitation whilst permitting stable generator operation © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection within allowable limits. One or two offset mho under impedance elements (see Chapter 11 for the principles of operation) are ideally suited for providing loss of excitation protection as long as a generator operating at low power output (20-30%Pn) does not settle down to operate as an induction generator. The characteristics of a typical two-stage loss of excitation protection scheme are illustrated in Figure 17.23. The first stage, consisting of settings Xa1 and Xb1 can be applied to provide detection of loss of excitation even where a generator initially operating at low power output (20-30%Pn) might settle down to operate as an induction generator. x time delay on pick-up, td1 = 0.5s – 10s x time delay on drop-off, tdo1 = 0s If a fast excitation system is employed, allowing load angles of up to 120o to be used, the impedance diameter must be reduced to take account of the reduced generator impedance seen under such conditions. The offset also needs revising. In these circumstances, typical settings would be: x impedance element diameter Xb1 = 0.5Xd x impedance element offset Xa1 = -0.75X’d x time delay on pick-up, td1 = 0.5s – 10s x time delay on drop-off, tdo1 = 0s The typical impedance settings for the second element, if used, are: X b2 kV 2 MVA X a2 kV 2 0.5 X MVA ' d The time delay settings td2 and tdo2 are set to zero to give instantaneous operation and reset. 17.17 POLE SLIPPING PROTECTION Figure 17.23: Loss of excitation protection characteristics Pick-up and drop-off time delays td1 and tdo1 are associated with this impedance element. Timer td1 is used to prevent operation during stable power swings that may cause the impedance locus of the generator to transiently enter the locus of operation set by Xb1. However, the value must short enough to prevent damage as a result of loss of excitation occurring. If pole-slipping protection is not required (see Section 17.17.2), timer tdo1 can be set to give instantaneous reset. The second field failure element, comprising settings Xb1, Xb2, and associated timers td2 and tdo2 can be used to give instantaneous tripping following loss of excitation under full load conditions. 17.16.3 Protection Settings The typical setting values for the two elements vary according to the excitation system and operating regime of the generator concerned, since these affect the generator impedance seen by the relay under normal and abnormal conditions. For a generator that is never operated at leading power factor, or at load angles in excess of 90o the typical settings are: x impedance element diameter Xb1 = Xd x impedance element offset Xa1 = -0.5X’d A generator may pole-slip, or fall out of synchronism with the power system for a number of reasons. The principal causes are prolonged clearance of a heavy fault on the power system, when the generator is operating at a high load angle close to the stability limit, or partial or complete loss of excitation. Weak transmission links between the generator and the bulk of the power system aggravate the situation. It can also occur with embedded generators running in parallel with a strong Utility network if the time for a fault clearance on the Utility network is slow, perhaps because only IDMT relays are provided. Pole slipping is characterised by large and rapid oscillations in active and reactive power. Rapid disconnection of the generator from the network is required to ensure that damage to the generator is avoided and that loads supplied by the network are not affected for very long. Protection can be provided using several methods. The choice of method will depend on the probability of pole slipping occurring and on the consequences should it occur. 17.17.1 Protection Using Reverse Power Element During pole-slipping, there will be periods where the direction of active power flow will be in the reverse direction, so a reverse power relay element can be used to detect this, if not used for other purposes. However, since the reverse power © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-21 Network Protection & Automation Guide conditions are cyclical, the element will reset during the forward power part of the cycle unless either a very short pickup time delay and/or a suitable drop-off time delay is used to eliminate resetting. The main advantage of this method is that a reverse power element is often already present, so no additional relay elements are required. The main disadvantages are the time taken for tripping and the inability to control the system angle at which the generator breaker trip command would be issued, if it is a requirement to limit the breaker current interruption duty. There is also the difficulty of determining suitable settings. Determination of settings in the field, from a deliberate pole-slipping test is not possible and analytical studies may not discover all conditions under which poleslipping will occur. 17.17.3.1 Pole Slipping Protection by Impedance Measurement Although a mho type element for detecting the change in impedance during pole-slipping can be used in some applications, but with performance limits, a straight line ‘ohm’ characteristic is more suitable. The protection principle is that of detecting the passage of the generator impedance through a zone defined by two such impedance characteristics, as shown in Figure 17.24. The characteristic is divided into three zones, A, B, and C. Normal operation of the generator lies in zone A. When a pole-slip occurs, the impedance traverses zones B and C, and tripping occurs when the impedance characteristic enters zone C. +jX 17.17.2 Protection Using an Under Impedance Element With reference to Figure 17.21, a loss of excitation under impedance characteristic may also be capable of detecting loss of synchronism, in applications where the electrical centre of the power system and the generator lies ‘behind’ the relaying point. This would typically be the case for a relatively small generator that is connected to a power transmission system (XG >> (XT + XS)). With reference to Figure 17.23; if pole-slipping protection response is required, the drop-off timer tdo1 of the larger diameter impedance measuring element should be set to prevent its reset of in each slip cycle, until the td1 trip time delay has expired. As with reverse power protection, this would be an elementary form of pole-slipping protection. It may not be suitable for large machines where rapid tripping is required during the first slip cycle and where some control is required for the system angle at which the generator circuit breaker trip command is given. Where protection against pole-slipping must be guaranteed, a more sophisticated method of protection should be used. A typical reset timer delay for pole-slipping protection might be 0.6s. For generator transformer units, the additional impedance in front of the relaying point may take the system impedance outside the under impedance relay characteristic required for loss of excitation protection. Therefore, the acceptability of this pole-slipping protection scheme will be dependent on the application. 17.17.3 Dedicated Pole-Slipping Protection Large generator-transformer units directly connected to grid systems often require a dedicated pole-slipping protection scheme to ensure rapid tripping and with system angle control. Historically, dedicated protection schemes have usually been based on ohm-type impedance measurement characteristic. 17-22 ZS Relaying point XT Slip locus EG=ES XG C B A -R +R -jX Ohm relay 2 Ohm relay 1 Figure 17.24: Pole slipping detection by ohm relays Tripping only occurs if all zones are traversed sequentially. Power system faults should result in the zones not being fully traversed so that tripping will not be initiated. The security of this type of protection scheme is normally enhanced by the addition of a plain under impedance control element (circle about the origin of the impedance diagram) that is set to prevent tripping for impedance trajectories for remote power system faults. Setting of the ohm elements is such that they lie parallel to the total system impedance vector, and enclose it, as shown in Figure 17.24. 17.17.3.2 Use of Lenticular Characteristic A more sophisticated approach is to measure the impedance of the generator and use a lenticular impedance characteristic to determine if a pole-slipping condition exists. The lenticular characteristic is shown in Figure 17.25. The characteristic is divided into two halves by a straight line, called the blinder. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection The inclination, T, of the lens and blinder is determined by the angle of the total system impedance. The impedance of the system and generator-transformer determines the forward reach of the lens, ZA, and the transient reactance of the generator determines the reverse reach ZB. Blinder X ZA P P' R Figure 17.26: Definition of zones for lenticular characteristic Lens ZB Figure 17.25: Pole-slipping protection using lenticular characteristic and blinder The width of the lens is set by the angle D and the line PP’, perpendicular to the axis of the lens, is used to determine if the centre of the impedance swing during a transient is located in the generator or power system. Operation in the case of a generator is as follows. The characteristic is divided into 4 zones and 2 regions, as shown in Figure 17.26. Normal operation is with the measured impedance in zone R1. If a pole slip develops, the impedance locus will traverse though zones R2, R3, and R4. When entering zone R4, a trip signal is issued, provided the impedance lies below reactance line PP’ and hence the locus of swing lies within or close to the generator – i.e. the generator is pole slipping with respect to the rest of the system. If the impedance locus lies above line PP’, the swing lies far out in the power system – i.e. one part of the power system, including the protected generator, is swinging against the rest of the network. Tripping may still occur, but only if swinging is prolonged – meaning that the power system is in danger of complete break-up. Further confidence checks are introduced by requiring that the impedance locus spends a minimum time within each zone for the pole-slipping condition to be valid. The trip signal may also be delayed for a number of slip cycles even if a generator pole-slip occurs – this is to both provide confirmation of a pole-slipping condition and allow time for other relays to operate if the cause of the pole slip lies somewhere in the power system. Should the impedance locus traverse the zones in any other sequence, tripping is blocked. 17.18 STATOR OVERHEATING Overheating of the stator may result from: x overload x failure of the cooling system x overfluxing x core faults Accidental overloading might occur through the combination of full active load current component, governed by the prime mover output and an abnormally high reactive current component, governed by the level of rotor excitation and/or step-up transformer tap. With a modern protection relay, it is relatively simple to provide a current-operated thermal replica protection element to estimate the thermal state of the stator windings and to issue an alarm or trip to prevent damage. Although current-operated thermal replica protection cannot take into account the effects of ambient temperature or © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-23 Network Protection & Automation Guide uneven heat distribution, it is often applied as a back-up to direct stator temperature measuring devices to prevent overheating due to high stator current. With some relays, the thermal replica temperature estimate can be made more accurate through the integration of direct measuring resistance temperature devices. Irrespective of whether current-operated thermal replica protection is applied or not, it is a requirement to monitor the stator temperature of a large generator in order to detect overheating from whatever cause. Temperature sensitive elements, usually of the resistance type, are embedded in the stator winding at hot-spot locations envisaged by the manufacturer, the number used being sufficient to cover all variations. The elements are connected to a temperature sensing relay element arranged to provide alarm and trip outputs. The settings will depend on the type of stator winding insulation and on its permitted temperature rise. To minimise overspeed on load rejection and hence the mechanical stresses on the rotor, the following sequence is used whenever electrical tripping is not urgently required: x trip prime mover or gradually reduce power input to zero x allow generated power to decay towards zero x trip generator circuit breaker only when generated power is close to zero or when the power flow starts to reverse, to drive the idle turbine 17.19.3 Loss of Vacuum 17.19 MECHANICAL FAULTS A failure of the condenser vacuum in a steam turbine driven generator results in heating of the tubes. This then produces strain in the tubes, and a rise in temperature of the lowpressure end of the turbine. Vacuum pressure devices initiate progressive unloading of the set and, if eventually necessary, tripping of the turbine valves followed by the high voltage circuit breaker. The set must not be allowed to motor in the event of loss of vacuum, as this would cause rapid overheating of the low-pressure turbine blades. Various faults may occur on the mechanical side of a generating set. The following sections detail the more important ones from an electrical point of view. 17.20 COMPLETE GENERATOR PROTECTION SCHEMES 17.19.1 Failure of the Prime Mover When a generator operating in parallel with others loses its power input, it remains in synchronism with the system and continues to run as a synchronous motor, drawing sufficient power to drive the prime mover. This condition may not appear to be dangerous and in some circumstances will not be so. However, there is a danger of further damage being caused. Table 17.1 lists some typical problems that may occur. Protection is provided by a low forward power/reverse power relay, as detailed in Section 17.11. From the preceding sections, it is obvious that the protection scheme for a generator has to take account of many possible faults and plant design variations. Determination of the types of protection used for a particular generator will depend on the nature of the plant and upon economic considerations, which in turn is affected by set size. Fortunately, modern, multifunction, numerical relays are sufficiently versatile to include all of the commonly required protection functions in a single package, thus simplifying the decisions to be made. The following sections provide illustrations of typical protection schemes for generators connected to a grid network, but not all possibilities are illustrated, due to the wide variation in generator sizes and types. 17.19.2 Overspeed The speed of a turbo-generator set rises when the steam input is in excess of that required to drive the load at nominal frequency. The speed governor can normally control the speed, and, in any case, a set running in parallel with others in an interconnected system cannot accelerate much independently even if synchronism is lost. However, if load is suddenly lost when the HV circuit breaker is tripped, the set will begin to accelerate rapidly. The speed governor is designed to prevent a dangerous speed rise even with a 100% load rejection, but nevertheless an additional centrifugal overspeed trip device is provided to initiate an emergency mechanical shutdown if the overspeed exceeds 10%. 17-24 17.20.1 Direct-Connected Generator A typical protection scheme for a direct-connected generator is shown in Figure 17.27. It comprises the following protection functions: x stator differential protection x overcurrent protection – conventional or voltage dependent x stator earth fault protection x overvoltage protection x undervoltage protection © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection x overload/low forward power/reverse power protection (according to prime mover type) differential protection) may utilise a separate relay. Figure 17.28 shows a typical overall scheme. x unbalanced loading x overheating x pole slipping x loss of excitation x underfrequency x inadvertent energisation x overfluxing x mechanical faults Figure 17.27 illustrates which trips require an instantaneous electrical trip and which can be time delayed until electrical power has been reduced to a low value. The faults that require tripping of the prime mover as well as the generator circuit breaker are also shown. Figure 17.28: Typical tripping arrangements for generator-transformer unit 17.21 EMBEDDED GENERATION Figure 17.27: Typical protection arrangement for a direct-connected generator 17.20.2 Generator-Transformer Units These units are generally of higher output than directconnected generators, and hence more comprehensive protection is warranted. In addition, the generator transformer also requires protection, for which the protection detailed in Chapter 16 is appropriate. Overall biased generator/generator transformer differential protection is commonly applied in addition, or instead of, differential protection for the transformer alone. A single protection relay may incorporate all of the required functions, or the protection of the transformer (including overall generator/generator transformer In recent years, through de-regulation of the electricity supply industry and the ensuing commercial competition, many electricity users connected to MV power distribution systems have installed generating sets to operate in parallel with the public supply. The intention is either to utilise surplus energy from other sources, or to use waste heat or steam from the prime mover for other purposes. Parallel connection of generators to distribution systems did occur before deregulation, but only where there was a net power import from the Utility. Power export to Utility distribution systems was a relatively new aspect. Since generation of this type can now be located within a Utility distribution system, as opposed to being centrally dispatched generation connected to a transmission system, the term ‘Embedded Generation’ is often applied. Figure 17.2 illustrates such an arrangement. Depending on size, the embedded generator(s) may be synchronous or asynchronous types, and they may be connected at any voltage appropriate to the size of plant being considered. The impact of connecting generation to a Utility distribution system that was originally engineered only for downward power distribution must be considered, particularly in the area of protection requirements. In this respect, it is not important whether the embedded generator is normally capable of export © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-25 Network Protection & Automation Guide to the Utility distribution system or not, since there may exist fault conditions when this occurs irrespective of the design intent. If plant operation when disconnected from the Utility supply is required, underfrequency protection (Section 17.14.2) will become an important feature of the in-plant power system. During isolated operation, it may be relatively easy to overload the available generation, such that some form of load management system may be required. Similarly, when running in parallel with the Utility, consideration needs to be given to the mode of generator operation if reactive power import is to be controlled. The impact on the control scheme of a sudden break in the Utility connection to the plant main busbar also requires analysis. Where the in-plant generation is run using constant power factor or constant reactive power control, automatic reversion to voltage control when the Utility connection is lost is essential to prevent plant loads being subjected to a voltage outside acceptable limits. Limits may be placed by the Utility on the amount of power/reactive power import/export. These may demand the use of an in-plant Power Management System to control the embedded generation and plant loads accordingly. Some Utilities may insist on automatic tripping of the interconnecting circuit breakers if there is a significant departure outside permissible levels of frequency and voltage, or for other reasons. From a Utility standpoint, the connection of embedded generation may cause problems with voltage control and increased fault levels. The settings for protection relays in the vicinity of the plant may require adjustment with the emergence of embedded generation. It must also be ensured that the safety, security and quality of supply of the Utility distribution system is not compromised. The embedded generation must not be permitted to supply any Utility customers in isolation, since the Utility supply is normally the means of regulating the system voltage and frequency within the permitted limits. It also normally provides the only system earth connection(s), to ensure the correct performance of system protection in response to earth faults. If the Utility power infeed fails, it is also important to disconnect the embedded generation before there is any risk of the Utility power supply returning on to unsynchronised machines. In practice this generally requires the following protection functions to be applied at the ‘Point of Common Coupling’ (PCC) to trip the coupling circuit breaker: x overvoltage x undervoltage x overfrequency 17-26 x underfrequency x loss of Utility supply In addition, particular circumstances may require additional protection functions: x neutral voltage displacement x reverse power x directional overcurrent In practice, it can be difficult to meet the protection settings or performance demanded by the Utility without a high risk of nuisance tripping caused by lack of co-ordination with normal power system faults and disturbances that do not necessitate tripping of the embedded generation. This is especially true when applying protection specifically to detect loss of the Utility supply (also called ‘loss of mains’) to cater for operating conditions where there would be no immediate excursion in voltage or frequency to cause operation of conventional protection functions. 17.21.1 Protection Against Loss of Utility Supply If the normal power infeed to a distribution system, or to the part of it containing embedded generation is lost, the effects may be as follows: a. embedded generation may be overloaded, leading to generator undervoltage/ underfrequency b. embedded generation may be underloaded, leading to overvoltage/overfrequency c. little change to the absolute levels of voltage or frequency if there is little resulting change to the load flow through the PCC The first two effects are covered by conventional voltage and frequency protection. However, if condition (c) occurs, conventional protection may not detect the loss of Utility supply condition or it may be too slow to do so within the shortest possible auto-reclose dead-times that may be applied in association with Utility overhead line protection. Detection of condition (c) must be achieved if the requirements of the Utility are to be met. Many possible methods have been suggested, but the one most often used is the Rate of Change of Frequency (ROCOF) relay. Its application is based on the fact that the rate of change of small changes in absolute frequency, in response to inevitable small load changes, will be faster with the generation isolated than when the generation is in parallel with the public, interconnected power system. However, problems with nuisance tripping in response to national power system events, where the system is subject to significant frequency excursions following the loss of a large generator or a major power interconnector, have occurred. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection This is particularly true for geographically islanded power systems, such as those of the British Isles. An alternative to ROCOF protection is a technique sometimes referred to as ‘voltage vector shift’ protection. In this technique the rate of phase change between the directly measured generator bus voltage is compared with a memorised a.c. bus voltage reference. Sources of embedded generation are not normally earthed, which presents a potential safety hazard. In the event of an Utility system earth fault, the Utility protection should operate to remove the Utility power infeed. In theory, this should also result in removal of the embedded generation, through the action of the stipulated voltage/frequency protection and dependable ‘loss of mains’ protection. However, in view of safety considerations (e.g. fallen overhead line conductors in public areas), an additional form of earth fault protection may also be demanded to prevent the backfeed of an earth fault by embedded generation. The only way of detecting an earth fault under these conditions is to use neutral voltage displacement protection. The additional requirement is only likely to arise for embedded generation rated above 150kVA, since the risk of small embedded generators not being cleared by other means is negligible. 17.21.2 ROCOF Relay Description A ROCOF relay detects the rate of change of frequency in excess of a defined setpoint. The signal is obtained from a voltage transformer connected close to the Point of Common Coupling (PCC). The principal method used is to measure the time period between successive zero-crossings to determine the average frequency for each half-cycle and hence the rate of change of frequency. The result is usually averaged over a number of cycles. 17.21.3 Voltage Vector Shift Relay Description A voltage vector shift relay detects the drift in voltage phase angle beyond a defined setpoint as long as it takes place within a set period. Again, the voltage signal is obtained from a voltage transformer connected close to the Point of Common Coupling (PCC). The principal method used is to measure the time period between successive zero-crossings to determine the duration of each half-cycle, and then to compare the durations with the memorised average duration of earlier halfcycles in order to determine the phase angle drift. 17.21.4 Setting Guidelines Should loss of the Utility supply occur, it is extremely unlikely that there will be an exact match between the output of the embedded generator(s) and the connected load. A small frequency change or voltage phase angle change will therefore occur, to which can be added any changes due to the small natural variations in loading of an isolated generator with time. Once the rate of change of frequency exceeds the setting of the ROCOF relay for a set time, or once the voltage phase angle drift exceeds the set angle, tripping occurs to open the connection between the in-plant and Utility networks. While it is possible to estimate the rate of change of frequency from knowledge of the generator set inertia and MVA rating, this is not an accurate method for setting a ROCOF relay because the rotational inertia of the complete network being fed by the embedded generation is required. For example, there may be other embedded generators to consider. As a result, it is invariably the case that the relay settings are determined at site during commissioning. This is to ensure that the Utility requirements are met while reducing the possibility of a spurious trip under the various operating scenarios envisaged. However, it is very difficult to determine whether a given rate of change of frequency will be due to a ‘loss of mains’ incident or a load/frequency change on the public power network, and hence spurious trips are impossible to eliminate. Thus the provision of Loss of Utility Supply protection to meet power distribution Utility interface protection requirements, may actually conflict with the interests of the national power system operator. With the growing contribution of non-dispatched embedded generation to the aggregate national power demand, the loss of the embedded generation following a transmission system incident that may already challenge the security of the system can only aggravate the problem. There have been claims that voltage vector shift protection might offer better security, but it will have operation times that vary with the rate of change of frequency. As a result, depending on the settings used, operation times might not comply with Utility requirements under all circumstances. [Reference 17.1] provides further details of the operation of ROCOF relays and the problems that may be encountered. Nevertheless, because such protection is a common requirement of some Utilities, the ‘loss of mains’ protection may have to be provided and the possibility of spurious trips will have to be accepted in those cases. Site measurements over a period of time of the typical rates of frequency change occurring may assist in negotiations of the settings with the Utility, and with the fine-tuning of the protection that may already be commissioned. 17.22 EXAMPLES OF GENERATOR PROTECTION SETTINGS This section gives examples of the calculations required for generator protection. The first is for a typical small generator installed on an industrial system that runs in parallel with the © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-27 Network Protection & Automation Guide offset magnetising inrush or motor starting current waveforms with an r.m.s level close to rated current, and where there is a high L/R time constant for the offset, the use of a 0% bias slope may give rise to maloperation. Such waveforms can be encountered when plant of similar rating to the generator is being energised or started. Differences between CT designs or Utility supply. The second is for a larger generator-transformer unit connected to a grid system. 17.22.1 Protection Settings of a Small Industrial Generator Data KVA KW 6250 PF 5000 0.8 Rated Rated Rated Rated Prime Mover Voltage Current Frequency Speed Type 11000 328 50 1500 Steam Turbine Generator Parameters Generator Xd Xd' Type p.u. p.u. Salient Pole 2.349 CT Ratio 0.297 VT Ratio 500/1 11000/110 Network Data Earthing Maximum Earth Fault Minimum Phase Fault Maximum Downstream Phase Resistor Current Current Fault Current 31.7W 200A 145A 850A Existing Protection Overcurrent Settings CT Ratio 200/1 Characteristic SI Earth Fault Settings Setting 144A TMS 0.176 Characteristic SI Setting 48A TMS 0.15 Generator Salient details of the generator, network and protection required are given in Table 17.2. The example calculations are based on an Alstom MiCOM P343 relay in respect of setting ranges, etc. Table 17.2: Data for small generator protection example 17.22.1.1 Differential Protection Biased differential protection involves the determination of values for four setting values: Is1, Is2, K1 and K2 in Figure 17.5. Is1 can be set at 5% of the generator rating, in accordance with the recommendations for the relay, and similarly the values of Is2 (120%) and K2 (150%) of generator rating. It remains for the value of K1 to be determined. The recommended value is generally 0%, but this only applies where CTs that conform to IEC 60044-1 class PX (or the superseded BS 3938 Class X) are used – i.e. CTs specifically designed for use in differential protection schemes. In this application, the CTs are conventional class 5P CTs that meet the relay requirements in respect of knee-point voltage, etc. Where neutral tail and terminal CTs can saturate at different times due to transiently 17-28 differing remanent flux levels can lead to asymmetric saturation and the production of a differential spill current. Therefore, it is appropriate to select a non-zero setting for K1, and a value of 5% is usual in these circumstances. 17.22.1.2 Voltage Controlled Overcurrent Protection This protection is applied as remote backup to the downstream overcurrent protection in the event of protection or breaker failure conditions. This ensures that the generator will not continue to supply the fault under these conditions. At normal voltage, the current setting must be greater than the maximum generator load current of 328A. A margin must be allowed for resetting of the relay at this current (reset ratio = © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection 95%) and for the measurement tolerances of the relay (5% of Is under reference conditions), therefore the current setting is calculated as: 328 u 1.05 0.95 ! 362.5 A I vcset ! The nearest settable value is 365A, or 0.73In. The minimum phase-phase voltage for a close-up single-phase to earth fault is 57%, so the voltage setting VS must be less than this. A value of 30% is typically used, giving VS = 33V. The current setting multiplying factor K must be chosen such that KIS is less than 50% of the generator steady-state current contribution to an uncleared remote fault. This information is not available (missing data being common in protection studies). However, the maximum sustained close-up phase fault current (neglecting AVR action) is 145A, so that a setting chosen to be significantly below this value will suffice. A value of 87.5A (60% of the close-up sustained phase fault current) is therefore chosen, and hence K = 0.6. This is considered to be appropriate based on knowledge of the system circuit impedances. The TMS setting is chosen to co-ordinate with the downstream feeder protection such that: x for a close-up feeder three-phase fault, that results in almost total voltage collapse as seen by the relay x for a fault at the next downstream relay location, if the relay voltage is less than the switching voltage It should also be chosen so that the generator cannot be subjected to fault or overload current in excess of the stator short-time current limits. A curve should be provided by the manufacturer, but IEC 60034-1 demands that an AC generator should be able to pass 1.5 times rated current for at least 30 seconds. The operating time of the downstream protection for a three-phase fault current of 850A is 0.682s, so the voltage controlled relay element should have a minimum operating time of 1.09s (0.4s grading margin used as the relay technology used for the downstream relay is not stated – see Table 9.2). With a current setting of 87.5A, the operating time of the voltage controlled relay element at a TMS of 1.0 is: 0.14 § 850 · ¸ ¨ © 87.5 ¹ The maximum earth fault current, from Table 17.2, is 200A. Protection for 95% of the winding can be provided if the relay is set to detect a primary earth fault current of 16.4A, and this equates to a CT secondary current of 0.033A. The nearest relay setting is 0.04A, providing protection for 90% of the winding. The protection must grade with the downstream earth fault protection, the settings of which are also given in Table 17.2. At an earth fault current of 200A, the downstream protection has an operation time of 0.73s. The generator earth fault protection must therefore have an operation time of not less than 1.13s. At a TMS of 1.0, the generator protection relay operating time will be: º ª » « 0.14 »s « « § 200 · 0.02 » «¨ ¸  1» ¼ ¬ © 20 ¹ = 2.97s, so the required TMS is 1 1.13 2.97 0.38 . Use a setting of 0.4, nearest available setting. 17.22.1.4 Neutral Voltage Displacement Protection This protection is provided as back-up earth-fault protection for the generator and downstream system (direct-connected generator). It must therefore have a setting that grades with the downstream protection. The protection is driven from the generator star-connected VT, while the downstream protection is current operated. It is therefore necessary to translate the current setting of the downstream setting of the current-operated earth-fault protection into the equivalent voltage for the NVD protection. The equivalent voltage is found from the formula: Veff I pe u Z e u 3 VTratio 48 u 31.7 u 3 100 45.6V 3.01s 0.02 where: Veff = effective voltage setting Therefore a TMS of: 1.09 3.01 17.22.1.3 Stator Earth Fault Protection 0.362 is required. Use 0.375, nearest available setting. Ipe = downstream earth fault current setting Ze = earthing resistance Hence a setting of 48V is acceptable. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Time grading is 17-29 Network Protection & Automation Guide required, with a minimum operating time of the NVD protection of 1.13s at an earth fault current of 200A. Using the expression for the operation time of the NVD element: t K s M 1 M § V ¨¨ © Vsnvd where: · ¸¸ ¹ and V = voltage seen by relay Vsnvd = relay setting voltage the value of K can be calculated as 3.34. The nearest settable value is 3.5, giving an operation time of 1.18s. 17.22.1.5 Loss of Excitation Protection Loss of excitation is detected by a mho impedance relay element, as detailed in Section 17.16.2. The standard settings for the P340 series relay are: Xa § CTratio · 0.5'd u ¨ ¸ secondary quantities © VTratio ¹ 0.5 u 0.297 u 19.36 u 500 100 14.5: Xb § CTratio · X d' u ¨ ¸ © VTratio ¹ 2.349 u 19.36 u 500 100 227: The nearest settings provided by the relay are Xa 14.5: Xb 227: The time delay td1 should be set to avoid relay element operation on power swings and a typical setting of 3s is used. This value may need to be modified in the light of operating experience. To prevent cyclical pick-up of the relay element without tripping, such as might occur during pole-slipping conditions, a drop-off time delay tdo1 is provided and set to 0.5s. 17.22.1.6 Negative Phase Sequence Current Protection This protection is required to guard against excessive heating 17-30 from negative phase sequence currents, whatever the cause. The generator is of salient pole design, so from IEC 60034-1, the continuous withstand is 8% of rating and the I2t value is 20s. Using Equation 17.1, the required relay settings can found as I2>> = 0.05 and K = 8.6s. The nearest available values are I2>> = 0.05 and K = 8.6s. The relay also has a cooling time constant Kreset that is normally set equal to the value of K. To co-ordinate with clearance of heavy asymmetric system faults, that might otherwise cause unnecessary operation of this protection, a minimum operation time tmin should be applied. It is recommended to set this to a value of 1. Similarly, a maximum time can be applied to ensure that the thermal rating of the generator is not exceeded (as this is uncertain, data not available) and to take account of the fact that the P343 characteristic is not identical with that specified in IEC 60034. The recommended setting for tmax is 600s. 17.22.1.7 Overvoltage Protection This is required to guard against various failure modes, e.g. AVR failure, resulting in excessive stator voltage. A two-stage protection is available, the first being a low-set time-delayed stage that should be set to grade with transient overvoltages that can be tolerated following load rejection. The second is a high-set stage used for instantaneous tripping in the event of an intolerable overvoltage condition arising. Generators can normally withstand 105% of rated voltage continuously, so the low-set stage should be set higher than this value. A setting of 117.7V in secondary quantities (corresponding to 107% of rated stator voltage) is typically used, with a definite time delay of 10s to allow for transients due to load switch-off/rejection, overvoltages on recovery from faults or motor starting, etc. The second element provides protection in the event of a large overvoltage, by tripping excitation and the generator circuit breaker (if closed). This must be set below the maximum stator voltage possible, taking into account saturation. As the open circuit characteristic of the generator is not available, typical values must be used. Saturation will normally limit the maximum overvoltage on this type of generator to 130%, so a setting of 120% (132V secondary) is typically used. Instantaneous operation is required. Generator manufacturers are normally able to provide recommendations for the relay settings. For embedded generators, the requirements of the local Utility may also have to be taken into account. For both elements, a variety of voltage measurement modes are available to take account of possible VT connections (single or three-phase, etc.), and conditions to be protected against. In this example, a three-phase VT connection is used, and overvoltages on any phase are to be detected, so a selection of ‘Any’ is used for this setting. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection 17.22.1.8 Underfrequency Protection This is required to protect the generator from sustained overload conditions during periods of operation isolated from the Utility supply. The generating set manufacturer will normally provide the details of machine short-time capabilities. The example relay provides four stages of underfrequency protection. In this case, the first stage is used for alarm purposes and a second stage would be applied to trip the set. The alarm stage might typically be set to 49Hz, with a time delay of 20s, to avoid an alarm being raised under transient conditions, e.g. during plant motor starting. The trip stage might be set to 48Hz, with a time delay of 0.5s, to avoid tripping for transient, but recoverable, dips in frequency below this value. 17.22.1.9 Reverse Power Protection Protection Differential protection Stator earth fault Neutral Voltage Displacement Loss of excitation Voltage controlled overcurrent The relay setting is 5% of rated power. § 0.05 u 5 u 10 6 · ¸¸ ¨¨ © CTratio u VTratio ¹ § 0.05 u 5 u 10 6 · ¸¸ ¨¨ © 500 u 100 ¹ Negative phase sequence 5W This value can be set in the relay. A time delay is required to guard against power swings while generating at low power levels, so use a time delay of 5s. No reset time delay is required. Overvoltage A summary of the relay settings is given in Table 17.3. Underfrequency Reverse Power Quantity Value Is1 5% Is2 120% K1 5% K2 150% Ise 0.04 TMS 0.4 Vsnvd 48V K 3.5 Xa -14.5: Xb 227: td1 3s td01 0.5s Ivcset 0.73 Vs 33 K 0.6 TMS 0.375 I2>> 0.05 K 8.6s Kreset 8.6s tmin 1.5s tmax 600s V> meas mode three-phase V> operate mode any V>1 setting 107% V>1 function DT V>1 time delay 10s V>2 setting 120% V>2 function DT V>2 time delay 0sec F<1 setting 49Hz F<1 time delay 20s F<2 setting 48Hz F<2 time delay 0.5s P1 function reverse power P1 setting 5W P1 time delay 5s P1 DO time 0s Table 17.3: Small generator protection example – relay settings 17.22.2 Large Generator Transformer Unit Protection The data for this unit are given in Table 17.4. It is fitted with two main protection systems to ensure security of tripping in the event of a fault. To economise on space, the setting calculations for only one system, that using an Alstom MiCOM P343 relay are given. Settings are given in primary quantities throughout. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-31 Network Protection & Automation Guide Parameter Value Unit Generator MVA rating 187.65 MVA Generator MW rating 160 MW Generator voltage 18 kV Synchronous reactance 1.93 pu Direct-axis transient reactance 0.189 pu Minimum operating voltage 0.8 pu Generator negative sequence capability 0.08 pu VN I flt nR f 2  X d  X t  nX f Where Iflt = minimum generator primary current for a multi-phase feeder-end fault VN = no load phase-neutral generator voltage Xd = generator d-axis synchronous reactance Generator negative sequence factor, Kg 10 Generator third harmonic voltage under load 0.02 pu Generator motoring power 0.02 pu alarm 1.1 Rf = feeder resistance time delay 5 Xf = feeder reactance trip 1.3 n = number of parallel generators Generator overvoltage Generator undervoltage not required Max pole slipping frequency 10 Hz Generator transformer rating 360 MVA Generator transformer leakage reactance 0.244 pu Generator transformer overflux alarm 1.1 pu Generator transformer overflux alarm 1.2 pu Network resistance (referred to 18kV) 0.56 m: Network reactance (referred to 18kV) 0.0199 : System impedance angle (estimated) 80 deg Minimum load resistance 0.8 : Generator CT ratio 8000/1 Generator VT ratio 18000/120 Number of generators in parallel 2 Table 17.4: System data for large generator protection example 17.22.2.1 Biased Differential Protection The settings follow the guidelines previously stated. As 100% stator winding earth-fault protection is provided, high sensitivity is not required and hence Is1 can be set to 10% of generator rated current. This equates to 602A, and the nearest settable value on the relay is 640A (= 0.08 of rated CT current). The settings for K1, Is2 and K2 follow the guidelines in the relay manual. 17.22.2.2 Voltage Restrained Overcurrent Protection The setting current Iset has to be greater than the full-load current of the generator (6019A). A suitable margin must be allowed for operation at reduced voltage, so use a multiplying factor of 1.2. The nearest settable value is 7200A. The factor K is calculated so that the operating current is less than the current for a remote end three phase fault. The steady-state current and voltage at the generator for a remote-end threephase fault are given by the expressions: 17-32 2 Xt = generator transformer reactance Hence, I flt 2893 A 0.361I n and V flt VN 3 nR f nR f 2 2  X t  nX f 2  X d  X t  nX f 2 1304V 0.07VN A suitable value of K is therefore 0.361 1.2 0.3 . A suitable value of V2set is 120% of Vflt, giving a value of 1565V. The nearest settable value is 3000V, minimum allowable relay setting. The value of V1set is required to be above the minimum voltage seen by the generator for a closeup phase-earth fault. A value of 80% of rated voltage is used for V1set, 14400V. 17.2.2.3 Inadvertent Energisation Protection This protection is a combination of overcurrent with undervoltage, the voltage signal being obtained from a VT on the generator side of the system. The current setting used is that of rated generator current of 6019A, in accordance with IEEE C37.102 as the generator is for installation in the USA. Use 6000A nearest settable value. The voltage setting cannot be more than 85% of the generator rated voltage to ensure operation does not occur under normal operation. For this application, a value of 50% of rated voltage is chosen. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection 17.22.2.4 Negative Phase Sequence Protection The generator has a maximum steady-state capability of 8% of rating, and a value of Kg of 10. Settings of I2cmr = 0.06 (=480A) and Kg = 10 are therefore used. Minimum and maximum time delays of 1s and 1300s are used to co-ordinate with external protection and ensure tripping at low levels of negative sequence current are used. 17.22.2.5 Overfluxing Protection The generator-transformer following characteristics: Alarm Trip manufacturer supplied the V ! 1.1 f V ! 1.2 inverse time characteristic f Hence the alarm setting is 18000 u 1.05 60 315 V Hz A time delay of 5s is used to avoid alarms due to transient conditions. The trip setting is: 18000 u 1.2 60 360 V Hz The third harmonic undervoltage protection setting must be below this value, a factor of 80% is acceptable. Use a value of 166.3V and a time delay of 0.5s. Inhibition of the element at low generator output must be determined during commissioning. 17.22.2.7 Loss of Excitation Protection The client requires a two-stage loss of excitation protection function. The first is alarm only, while the second provides tripping under high load conditions. To achieve this, the first impedance element of the P343 loss of excitation protection can be set in accordance with the guidelines of Section 17.16.3 for a generator operating at rotor angles up to 120o,as follows: X b1 0.5 X d X a1 0.75 X d' 1.666: 0.245: Use nearest settable values of 1.669: and 0.253:. A time delay of 5s is used to prevent alarms under transient conditions. For the trip stage, settings for high load are used, as given in Section 17.16.3: X b2 X a2 kV 2 182 1.727: MVA 187.65 0.75 X d' 0.1406: A TMS value of 10 is selected, to match the withstand curve supplied by the manufacturer. The nearest settable value for Xb2 is 1.725:A time delay of 0.5s is used. 17.22.2.6 100% Stator Earth Fault Protection 17.22.2.8 Reverse Power Protection This is provided by a combination of neutral voltage displacement and third harmonic undervoltage protection. For the neutral voltage displacement protection to cover 90% of the stator winding, the minimum voltage allowing for generator operation at a minimum of 92% of rated voltage is: The manufacturer-supplied value for motoring power is 2% of rated power. The recommended setting is therefore 1.6MW. An instrumentation class CT is used in conjunction with the relay for this protection, to ensure accuracy of measurement. A time delay of 0.5s is used. The settings should be checked at the commissioning stage. 0.92 u 18kV u 0.1 956.1V 3 Use a value of 935.3V, nearest settable value that ensures 90% of the winding is covered. A 0.5s definite time delay is used to prevent spurious trips. The third harmonic voltage under normal conditions is 2% of rated voltage, giving a value of: 18kV u 0.01 3 207.8V 17.22.9 Over/Under-Frequency Protection For under-frequency protection, the client has specified the following characteristics: x Alarm: 59.3Hz, 0.5s time delay x 1st stage trip: 58.7Hz, 100s time delay x 2nd stage trip: 58.2Hz, 1s time delay Similarly, the overfrequency is required to be set as follows: x Alarm: 62Hz, 30s time delay x Trip: 63.5Hz, 10s time delay These characteristics can be set in the relay directly. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-33 Network Protection & Automation Guide to the principles described in Chapter 16. 17.22.2.10 Overvoltage Protection The generator manufacturers’ recommendation is: Protection 17.22.2.11 Pole Slipping Protection Z n  ZT 0% P1 time delay 0.5s K2 150% P1 DO time 0s 100% Stator earth fault Vn3H< 166.3V Dead Mach I> 6000A Vn3H delay 0.5s Dead Mach V< 9000V Neutral Voltage Displacement Vsnvd 935.3V Za 0.243W Time Delay 0.5s Zb 0.656W Xa1 -0.245W Xb1 1.666W td1 Loss of Excitation 0.02  0.22 0.24: Z B Z GEN x Forward Reach, 2 u X d' x Reverse Reach, Voltage restrained overcurrent 0.652: Z C 0.9 u Z t 0.9 u 0.22 0.198: x Reactance Line,, Negative phase sequence where: Zt = generator transformer leakage current Zn = network impedance The nearest settable values are 0.243: 0.656: and 0.206: respectively. The lens angle setting, D, is found from the equation: D min § 1.54  Rt min 180  2 tan ¨¨ © Z A  ZB 1 D · ¸¸ ¹ and, substituting values, D min Is1 8% Is2 100% K1 Reverse Power Inadvertent energisation Zc 0.206W a 90° 5s q 80° Xa2 -0.1406W T1 15ms Xb2 1.725W T2 15ms Pole Slipping Protection td2 0.5s F>1 setting 62Hz tDO1 0s F>1 time delay 30s Iset 7200A F>2 setting 63.5Hz K 3 F>2 time delay 10s V1set 14400V P1 function reverse power V2set 3000V P1 setting 1.6MW I2>> 0.06 P1 time delay 0.5s Kg 10 P1 DO time 0s Kreset 10 F<1 setting 59.3Hz tmin 1s F<1 time delay 0.5s tmax 1300s F<2 setting 58.7Hz V> meas mode threephase F<2 time delay 100s V> operate mode any F<3 setting 58.2Hz V>1 setting 19800V F<3 time delay 1s Overfrequency Reverse Power Underfrequency V>1 function DT Overvoltage V>1 time delay 5s V>2 setting 23400V V>2 function DT 62.5D o Use the minimum settable value of 90 . The blinder angle, T is estimated to be 80o, and requires checking during commissioning. Timers T1 and T2 are set to 15ms as experience has shown that these settings are satisfactory to detect pole slipping frequencies up to 10Hz. This completes the settings required for the generator, and the relay settings are given in Table 17.5. Of course, additional protection is required for the generator transformer, according 17-34 Value 1.6MW This is provided by the method described in Section 17.7.2.2. Detection at a maximum slip frequency of 10Hz is required. The setting data, according to the relay manual, is as follows: ZA Quantity P1 setting This translates into the following relay settings: x Trip: 23400V, 0.1s time delay Protection P1 function Differential protection x Alarm: 19800V, 5s time delay Value reverse power x Alarm: 110% voltage for 5s x Trip: 130% voltage, instantaneous Quantity V>2 time delay 0.1s Table 17.5: Relay settings for large generator protection example 17.23 REFERENCE [17.1] Survey of Rate of Change of Frequency Relays and Voltage Phase Shift Relays for Loss of Mains Protection. ERA Report 95-0712R, 1995. ERA Technology Ltd. © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 17 ˜ Generator and Generator Transformer Protection © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 17-35 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 18 Industrial and Commercial Power System Protection 18.1 INTRODUCTION 18.1 18.2 18.3 18.4 18.5 18.6 18.7 18.8 Introduction Busbar Arrangement Discrimination HRC Fuses Industrial Circuit Breakers Protection Relays Co-ordination Problems Fault Current Contribution from Induction Motors 18.9 Automatic Changeover Systems 18.10 Voltage and Phase Reversal Protection 18.11 Power Factor Correction and Protection of Capacitors 18.12 Examples 18.13 References As industrial and commercial operations processes and plants have become more complex and extensive (Figure 18.1), the requirement for improved reliability of electrical power supplies has also increased. The potential costs of outage time following a failure of the power supply to a plant have risen dramatically as well. The introduction of automation techniques into industry and commerce has naturally led to a demand for the deployment of more power system automation, to improve reliability and efficiency. Figure 18.1: Large modern industrial plant The protection and control of industrial power supply systems must be given careful attention. Many of the techniques that have been evolved for EHV power systems may be applied to lower voltage systems also, but typically on a reduced scale. However, industrial systems have many special problems that have warranted individual attention and the development of specific solutions. Many industrial plants have their own generation installed. Sometimes it is for emergency use only, feeding a limited number of busbars and with limited capacity. This arrangement is often adopted to ensure safe shutdown of process plant and personnel safety. In other plants, the nature of the process allows production of a substantial quantity of electricity, perhaps allowing export of any surplus to the public supply system – at either at sub-transmission or distribution voltage levels. Plants that run generation in parallel with the public supply distribution network are often referred to as cogeneration or embedded generation. Special protection arrangements may be demanded for the point of connection between the private and public utility plant (see Chapter 17 for further details). Alstom Grid © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 18-1 Network Protection & Automation Guide Industrial systems typically comprise numerous cable feeders and transformers. Chapter 16 covers the protection of transformers and Chapters 9/10 the protection of feeders. 18.2 BUSBAR ARRANGEMENT The arrangement of the busbar system is obviously very important, and it can be quite complex for some very large industrial systems. However, in most systems a single busbar divided into sections by a bus-section circuit breaker is common, as shown in Figure 18.2. Main and standby drives for a particular item of process equipment will be fed from different sections of the switchboard, or sometimes from different switchboards. Figure 18.2: Typical switchboard configuration for an industrial plant The main power system design criterion is that single outages on the electrical network within the plant will not cause loss of both the main and standby drives simultaneously. Considering a medium sized industrial supply system, shown in Figure 18.3, in more detail, it will be seen that not only are duplicate supplies and transformers used, but also certain important loads are segregated and fed from ‘Essential Services Board(s)’ (also known as ‘Emergency’ boards), distributed throughout the plant. This enables maximum utilisation of the standby generator facility. A standby generator is usually of the turbocharged diesel-driven type. On detection of loss of incoming supply at any switchboard with an emergency section, the generator is automatically started. The appropriate circuit breakers will close once the generating set is up to speed and rated voltage to restore supply to the Essential Services sections of the switchboards affected, provided that the normal incoming supply is absent - for a typical diesel generator set, the emergency supply would be available within 10-20 seconds from the start sequence command being issued. 18-2 Figure 18.3: Typical industrial power system The Essential Services Boards are used to feed equipment that is essential for the safe shut down, limited operation or preservation of the plant and for the safety of personnel. This will cover process drives essential for safe shutdown, venting systems, UPS loads feeding emergency lighting, process control computers, etc. The emergency generator may range in size from a single unit rated 20-30kW in a small plant up to several units of 2-10MW rating in a large oil refinery or similar plant. Large financial trading institutions may also have standby power requirements of several MW to maintain computer services. 18.3 DISCRIMINATION Protection equipment works in conjunction with switchgear. For a typical industrial system, feeders and plant will be protected mainly by circuit breakers of various types and by fused contactors. Circuit breakers will have their associated overcurrent and earth fault relays. A contactor may also be © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 18 ˜ Industrial and Commercial Power System Protection equipped with a protection device (e.g. motor protection), but associated fuses are provided to break fault currents in excess of the contactor interrupting capability. The rating of fuses and selection of relay settings is carried out to ensure that discrimination is achieved – i.e. the ability to select and isolate only the faulty part of the system. 18.4 HRC FUSES The protection device nearest to the actual point of power utilisation is most likely to be a fuse or a system of fuses and it is important that consideration is given to the correct application of this important device. The HRC fuse is a key fault clearance device for protection in industrial and commercial installations, whether mounted in a distribution fuseboard or as part of a contactor or fuse-switch. The latter is regarded as a vital part of LV circuit protection, combining safe circuit making and breaking with an isolating capability achieved in conjunction with the reliable shortcircuit protection of the HRC fuse. Fuses combine the characteristics of economy and reliability; factors that are most important in industrial applications. HRC fuses remain consistent and stable in their breaking characteristics in service without calibration and maintenance. This is one of the most significant factors for maintaining fault clearance discrimination. Lack of discrimination through incorrect fuse grading will result in unnecessary disconnection of supplies, but if both the major and minor fuses are HRC devices of proper design and manufacture, this need not endanger personnel or cables associated with the plant. 18.4.1 Fuse Characteristics The time required for melting the fusible element depends on the magnitude of current. This time is known as the ‘prearcing’ time of the fuse. Vaporisation of the element occurs on melting and there is fusion between the vapour and the filling powder leading to rapid arc extinction. Fuses have a valuable characteristic known as ‘cut-off’, shown in Figure 18.4. When an unprotected circuit is subjected to a short circuit fault, the r.m.s. current rises towards a ‘prospective’ (or maximum) value. The fuse usually interrupts the short circuit current before it can reach the prospective value, in the first quarter to half cycle of the short circuit. The rising current is interrupted by the melting of the fusible element, subsequently dying away dying away to zero during the arcing period. Figure 18.4: HRC fuse cut-off feature Since the electromagnetic forces on busbars and connections carrying short circuit current are related to the square of the current, it will be appreciated that ‘cut-off’ significantly reduces the mechanical forces produced by the fault current and which may distort the busbars and connections if not correctly rated. A typical example of ‘cut-off’ current characteristics is shown in Figure 18.5. It is possible to use this characteristic during the design stage of a project to utilise equipment with a lower fault withstand rating downstream of the fuse, than would be the case if ‘cut-off’ was ignored. This may save on costs, but appropriate documentation and maintenance controls are required to ensure that only replacement fuses of very similar characteristics are used throughout the lifetime of the plant concerned – otherwise a safety hazard may arise. 1000 1250A 710A 800A 500A 630A 400A 200A 315A 125A 80A 100 10 50A 35A 25A 16A 6A 1.0 2A 0.1 0.1 1.0 10 100 500 Figure 18.5: Typical fuse cut-off current characteristics © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 18-3 Network Protection & Automation Guide 18.4.2 Discrimination Between Fuses 18.4.5 Protection of Motors Fuses are often connected in series electrically and it is essential that they should be able to discriminate with each other at all current levels. Discrimination is obtained when the larger (‘major’) fuse remains unaffected by fault currents that are cleared by the smaller (‘minor’) fuse. The manufacturers' literature should also be consulted when fuses are to be applied to motor circuits. In this application, the fuse provides short circuit protection but must be selected to withstand the starting current (possibly up to 8 times full load current), and also carry the normal full load current continuously without deterioration. Tables of recommended fuse sizes for both ‘direct on line’ and ‘assisted start’ motor applications are usually given. Examples of protection using fuses are given in Section 18.12.1. The fuse operating time can be considered in two parts: x the time taken for fault current to melt the element, known as the ‘pre-arcing time’ x the time taken by the arc produced inside the fuse to extinguish and isolate the circuit, known as the ‘arcing time’ The total energy dissipated in a fuse during its operation consists of ‘pre-arcing energy’ and ‘arc energy’. The values are usually expressed in terms of I2t, where I is the current passing through the fuse and t is the time in seconds. Expressing the quantities in this manner provides an assessment of the heating effect that the fuse imposes on associated equipment during its operation under fault conditions. To obtain positive discrimination between fuses, the total I2t value of the minor fuse must not exceed the pre-arcing I2t value of the major fuse. In practice, this means that the major fuse will have to have a rating significantly higher than that of the minor fuse, and this may give rise to problems of discrimination. Typically, the major fuse must have a rating of at least 160% of the minor fuse for discrimination to be obtained. 18.5 INDUSTRIAL CIRCUIT BREAKERS Some parts of an industrial power system are most effectively protected by HRC fuses, but the replacement of blown fuse links can be particularly inconvenient in others. In these locations, circuit breakers are used instead, the requirement being for the breaker to interrupt the maximum possible fault current successfully without damage to itself. In addition to fault current interruption, the breaker must quickly disperse the resulting ionised gas away from the breaker contacts, to prevent re-striking of the arc, and away from other live parts of equipment to prevent breakdown. The breaker, its cable or busbar connections, and the breaker housing, must all be constructed to withstand the mechanical forces resulting from the magnetic fields and internal arc gas pressure produced by the highest levels of fault current to be encountered. The types of circuit breaker most frequently encountered in industrial system are described in the following sections. 18.4.3 Protection of Cables by Fuses 18.5.1 Miniature Circuit Breakers (MCBs) PVC cable is allowed to be loaded to its full nominal rating only if it has ‘close excess current protection’. This degree of protection can be given by means of a fuse link having a ‘fusing factor’ not exceeding 1.5, where: MCBs are small circuit breakers, both in physical size but more importantly, in ratings. The basic single pole unit is a small, manually closed, electrically or manually opened switch housed in a moulded plastic casing. They are suitable for use on 230V a.c. single-phase/400V a.c. three-phase systems and for d.c. auxiliary supply systems, with current ratings of up to 125A. Contained within each unit is a thermal element, in which a bimetal strip will trip the switch when excessive current passes through it. This element operates with a predetermined inverse-time/current characteristic. Higher currents, typically those exceeding 3-10 times rated current, trip the circuit breaker without intentional delay by actuating a magnetic trip overcurrent element. The operating time characteristics of MCBs are not adjustable. European Standard EN 60898-2 defines the instantaneous trip characteristics, while the manufacturer can define the inverse time thermal trip characteristic. Therefore, a typical tripping characteristic does not exist. The maximum a.c. breaking x Fusing factor = Minimum Fusing Current/Current Rating Cables constructed using other insulating materials (e.g. paper, XLPE) have no special requirements in this respect. 18.4.4 Effect of Ambient Temperature High ambient temperatures can influence the capability of HRC fuses. Most fuses are suitable for use in ambient temperatures up to 35°C, but for some fuse ratings, derating may be necessary at higher ambient temperatures. Manufacturers' published literature should be consulted for the de-rating factor to be applied. 18-4 © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. Chapter 18 ˜ Industrial and Commercial Power System Protection current permitted by the standard is 25kA. Single-pole units may be coupled mechanically in groups to form 2, 3 or 4 pole units, when required, by assembly on to a rail in a distribution board. The available ratings make MCBs suitable for industrial, commercial or domestic applications, for protecting equipment such as cables, lighting and heating circuits, and also for the control and protection of low power motor circuits. They may be used instead of fuses on individual circuits, and they are usually ‘backed-up’ by a device of higher fault interrupting capacity. Various accessory units, such as isolators, timers, and undervoltage or shunt trip release units may be combined with an MCB to suit the particular circuit to be controlled and protected. When personnel or fire protection is required, a residual current device (RCD) may be combined with the MCB. The RCD contains a miniature core balance current transformer that embraces all of the phase and neutral conductors to provide sensitivity to earth faults within a typical range of 0.05% to 1.5% of rated current, dependent on the RCD selected. The core balance CT energises a common magnetic trip actuator for the MCB assembly. It is also possible to obtain current-limiting MCBs. These types open prior to the prospective fault current being reached, and therefore have similar properties to HRC fuses. It is claimed that the extra initial cost is outweighed by lifetime savings in replacement costs after a fault has occurred, plus the advantage of providing improved protection against electric shock if an RCD is used. As a result of the increased safety provided by MCBs fitted with an RCD device, they are tending to replace fuses, especially in new installations. 18.5.2 Moulded Case Circuit Breakers (MCCBs) These circuit breakers are broadly similar to MCBs but have the following important differences: x the maximum ratings are higher, with voltage ratings up to 1000V a.c./1200V d.c. Current ratings of 2.5kA continuous/180kA r.m.s break are possible, dependent upon power factor x the breakers are larger, commensurate with the level of ratings. Although available as single, double or triple pole units, the multiple pole units have a common housing for all the poles. Where fitted, the switch for the neutral circuit is usually a separate device, coupled to the multi-pole MCCB x the operating levels of the magnetic and thermal protection elements may be adjustable, particularly in the larger MCCBs x because of their higher ratings, MCCBs are usually positioned in the power distribution system nearer to the power source than the MCBs x the appropriate European specification is EN 60947-2 Care must be taken in the short-circuit ratings of MCCBs. MCCBs are given two breaking capacities, the higher of which is its ultimate breaking capacity. The significance of this is that after breaking such a current, the MCCB may not be fit for continued use. The lower, or service, short circuit breaking capacity permits continued use without further detailed examination of the device. The standard permits a service breaking capacity of as little as 25% of the ultimate breaking capacity. While there is no objection to use of MCCBs to break short-circuit currents between the service and ultimate values, the inspection required after such a trip reduces the usefulness of the device in such circumstances. It is also clearly difficult to determine if the magnitude of the fault current was in excess of the service rating. The time-delay characteristics of the magnetic or thermal timed trip, together with the necessity for, or size of, a back-up device varies with make and size of breaker. Some MCCBs are fitted with microprocessor-controlled programmable trip characteristics offering a wide range of such characteristics. Time–delayed overcurrent characteristics may not be the same as the standard characteristics for dependent-time protection stated in IEC 60255-3. Hence, discrimination with other protection must be considered carefully. There can be problems where two or more MCBs or MCCBs are electrically in series, as obtaining selectivity between them may be difficult. There may be a requirement that the major device should have a rating of k times the minor device to allow discrimination, in a similar manner to fuses – the manufacturer should be consulted as to value of k. Careful examination of manufacturers’ literature is always required at the design stage to determine any such limitations that may be imposed by particular makes and types of MCCBs. An example of co-ordination between MCCBs, fuses and relays is given in Section 18.12.2. 18.5.3 Air Circuit Breakers (ACBs) Air circuit breakers are frequently encountered on industrial systems rated at 3.3kV and below. Modern LV ACBs are available in current ratings of up to 6.3kA with maximum breaking capacities in the range of 85kA-120kA r.m.s., depending on system voltage. This type of breaker operates on the principle that the arc produced when the main contacts open is controlled by directing it into an arc chute. Here, the arc resistance is increased and hence the current reduced to the point where © 2011 Alstom Grid. Single copies of this document may be filed or printed for personal non-commercial use and must include this copyright notice but may not be copied or displayed for commercial purposes without the prior written permission of Alstom Grid. 18-5 Network Protection & Automation Guide the circuit voltage cannot maintain the arc and the current reduces to zero. To assist in the quenching of low current arcs, an air cylinder may be fitted to each pole to direct a blast of air across the contact faces as the breaker opens, so reducing contact erosion. 18.5.4 Oil Circuit Breakers (OCBs) Air circuit breakers for industrial use are usually withdrawable and are constructed with a flush front plate making them ideal for inclusion together with fuse switches and MCBs/MCCBs in modular multi-tier distribution switchboards, so maximising the number of circuits within a given floor area. In this type of breaker, the main contacts are housed in an oilfilled tank, with the oil acting as the both the insulation and the arc-quenching medium. The arc produced during contact separation under fault conditions causes dissociation of the hydrocarbon insulating oil into hydrogen and carbon. The hydrogen extinguishes the arc. The carbon produced mixes with the oil. As the carbon is conductive, the oil must be changed after a prescribed number of fault clearances, when the degree of contamination reaches an unacceptable level. Older types using a manual or dependent manual closing mechanism are regarded as being a safety hazard. This arises under conditions of closing the CB when a fault exists on the circuit being controlled. During the close-trip operation, there is a danger of egress of the arc from the casing of the CB, with a consequent risk of injury to the operator. Such types may be required to be replaced with modern equivalents. Time (s) ACBs are normally fitted with integral overcurrent protection, thus avoiding the need for separate protection devices. However, the operating time characteristics of the integral protection are often designed to make discrimination with MCBs/MCCBs/fuses easier and so they may not be in accordance with the standard dependent time characteristics given in IEC 60255-3. Therefore, problems in co-ordination with discrete protection relays may still arise, but modern numerical relays have more flexible characteristics to alleviate such difficulties. ACBs will also have facilities for accepting an external trip signal, and this can be used in conjunction with an external relay if desired. Figure 18.6 shows the typical tripping characteristics available. Oil circuit breakers have been very popular for many years for industrial supply systems at voltages of 3.3kV and above. They are found in both ‘bulk oil’ and ‘minimum oil’ types, the only significant difference being the volume of oil in the tank. Because of the fire risk involved with oil, precautions such as the construction of fire/blast walls may have to be taken when OCBs are installed. 18.5.5 Vacuum Circuit Breakers (VCBs) In recent years, this type of circuit breaker, along with CBs using SF6, has replaced OCBs for new installations in industrial/commercial systems at voltages of 3.3kV and above. Compared with oil circuit breakers, vacuum breakers have no fire risk and they have high reliability with long maintenance free periods. A variation is the vacuum contactor with HRC