Network Protection And Automation Guide

‘Relay hardware is becoming even more standardised, to the point atwhich versions of a relay may differ only by the software they contain’.

This accurate prediction in the preface to the Third Edition of the ProtectiveRelay Application Guide (PRAG), 1987, has been followed by the rapiddevelopment of integrated protection and control devices. The change intechnology, together with significant changes in Utility, Industrial andCommercial organisations, has resulted in new emphasis on Secondary SystemsEngineering.

In addition to the traditional role of protection & control, secondary systemsare now required to provide true added value to organisations.

When utilised to its maximum, not only can the integration of protection &control functionality deliver the required reduction in life-time cost of capital,but the advanced features available (Quality of Supply, disturbance recordingand plant monitoring) enable system and plant performance to be improved,increasing system availability.

The evolution of all secondary connected devices to form digital controlsystems continues to greatly increase access to all information available withinthe substation, resulting in new methodologies for asset management.

In order to provide the modern practising substation engineer with referencematerial, the Network Protection & Automation Guide provides a substantiallyrevised and expanded edition of PRAG incorporating new chapters on all levelsof network automation. The first part of the book deals with the fundamentals,basic technology, fault calculations and the models of power system plant,including the transient response and saturation problems that affectinstrument transformers.

The typical data provided on power system plant has been updated andsignificantly expanded following research that showed its popularity.

The book then provides detailed analysis on the application of protectionsystems. This includes a new Chapter on the protection of a.c. electrifiedrailways. Existing chapters on distance, busbar and generator protection havebeen completely revised to take account of new developments, includingimprovements due to numerical protection techniques and the applicationproblems of embedded generation. The Chapter on relay testing andcommissioning has been completely updated to reflect modern techniques.Finally, new Chapters covering the fields of power system measurements,power quality, and substation and distribution automation are found, to reflectthe importance of these fields for the modern Power System Engineer.

The intention is to make NPAG the standard reference work in its’ subject area- while still helping the student and young engineer new to the field. We trustthat you find this book invaluable and assure you that any comments will becarefully noted ready for the next edition.

• 1 • Int roduct ion

N e t w o r k P r o t e c t i o n & A u t o m a t i o n G u i d e • 3 •

Chapt1-2-3 18/06/02 17:34 Page 3

Introduction 2.1

Protection equipment 2.2

Zones of protection 2.3

Reliability 2.4

Selectivity 2.5

Stability 2.6

Speed 2.7

Sensitivity 2.8

Primary and back-up protection 2.9

Relay output devices 2.10

Relay tripping circuits 2.11

Trip circuit supervision 2.12

• 2 • F u n d a m e n t a l so f P r o t e c t i o n P r a c t i c e

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2.1 INTRODUCTION

The purpose of an electrical power system is to generateand supply electrical energy to consumers. The systemshould be designed and managed to deliver this energyto the utilisation points with both reliability andeconomy. Severe disruption to the normal routine ofmodern society is likely if power outages are frequent orprolonged, placing an increasing emphasis on reliabilityand security of supply. As the requirements of reliabilityand economy are largely opposed, power system designis inevitably a compromise.

A power system comprises many diverse items ofequipment. Figure 2.2 shows a hypothetical powersystem; this and Figure 2.1 illustrates the diversity ofequipment that is found.

• 2 • Fundamentalso f P ro te c t i o n P ra c t i c e

Figure 2.1: Modern power station

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N e t w o r k P r o t e c t i o n & A u t o m a t i o n G u i d e

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Figur

e 2.Figure 2.2: Example power system

R1 R2

G1 G2

T1 T2T

R3 R4

G3 G4

T10 T11

T14

T16 T17

T15

T12 T13

R5 R6

G5 G6

T7 T8T

R7

G7

T9T

T5T T6T T3T T4T

L2

L3 L4

L1A

L7A

L5

L6

L8

L7B

L1B

A380kV

380kV380kV

110kV

Hydro power station

BC

B'33kVC'

380kV

CCGT power station

ED220kV

Steam power station

Gridsubstation

F

33kV D' 110kV

380kV

G'

G

Grid380kV F'

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Many items of equipment are very expensive, and so thecomplete power system represents a very large capitalinvestment. To maximise the return on this outlay, thesystem must be utilised as much as possible within theapplicable constraints of security and reliability ofsupply. More fundamental, however, is that the powersystem should operate in a safe manner at all times. Nomatter how well designed, faults will always occur on apower system, and these faults may represent a risk tolife and/or property. Figure 2.3 shows the onset of a faulton an overhead line. The destructive power of a fault arccarrying a high current is very great; it can burn throughcopper conductors or weld together core laminations ina transformer or machine in a very short time – sometens or hundreds of milliseconds. Even away from thefault arc itself, heavy fault currents can cause damage toplant if they continue for more than a few seconds. Theprovision of adequate protection to detect anddisconnect elements of the power system in the event offault is therefore an integral part of power systemdesign. Only by so doing can the objectives of the powersystem be met and the investment protected. Figure 2.4provides an illustration of the consequences of failure toprovide appropriate protection.

This is the measure of the importance of protectionsystems as applied in power system practice and of theresponsibility vested in the Protection Engineer.

2.2 PROTECTION EQUIPMENT

The definitions that follow are generally used in relationto power system protection:

a. Protection System: a complete arrangement ofprotection equipment and other devices required toachieve a specified function based on a protectionprincipal (IEC 60255-20)

b. Protection Equipment: a collection of protectiondevices (relays, fuses, etc.). Excluded are devicessuch as CT’s, CB’s, Contactors, etc.

c. Protection Scheme: a collection of protectionequipment providing a defined function andincluding all equipment required to make thescheme work (i.e. relays, CT’s, CB’s, batteries, etc.)

In order to fulfil the requirements of protection with theoptimum speed for the many different configurations,operating conditions and construction features of powersystems, it has been necessary to develop many types ofrelay that respond to various functions of the powersystem quantities. For example, observation simply ofthe magnitude of the fault current suffices in some casesbut measurement of power or impedance may benecessary in others. Relays frequently measure complexfunctions of the system quantities, which are only readilyexpressible by mathematical or graphical means.

Relays may be classified according to the technologyused:

a. electromechanical

b. static

c. digital

d. numerical

The different types have somewhat different capabilities,due to the limitations of the technology used. They aredescribed in more detail in Chapter 7.

Figure 2.3: Onset of an overhead line fault

Figure 2.4: Possible consequence of inadequate protection

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In many cases, it is not feasible to protect against allhazards with a relay that responds to a single powersystem quantity. An arrangement using severalquantities may be required. In this case, either severalrelays, each responding to a single quantity, or, morecommonly, a single relay containing several elements,each responding independently to a different quantitymay be used.

The terminology used in describing protection systemsand relays is given in Appendix 1. Different symbols fordescribing relay functions in diagrams of protectionschemes are used, the two most common methods (IECand IEEE/ANSI) are provided in Appendix 2.

2.3 ZONES OF PROTECTION

To limit the extent of the power system that isdisconnected when a fault occurs, protection is arrangedin zones. The principle is shown in Figure 2.5. Ideally, thezones of protection should overlap, so that no part of thepower system is left unprotected. This is shown in Figure2.6(a), the circuit breaker being included in both zones.

Figure 2.52.6

For practical physical and economic reasons, this ideal isnot always achieved, accommodation for currenttransformers being in some cases available only on oneside of the circuit breakers, as in Figure 2.6(b). Thisleaves a section between the current transformers and

the circuit breaker A that is not completely protectedagainst faults. In Figure 2.6(b) a fault at F would causethe busbar protection to operate and open the circuitbreaker but the fault may continue to be fed through thefeeder. The feeder protection, if of the unit type (seesection 2.5.2), would not operate, since the fault isoutside its zone. This problem is dealt with byintertripping or some form of zone extension, to ensurethat the remote end of the feeder is tripped also.

The point of connection of the protection with the powersystem usually defines the zone and corresponds to thelocation of the current transformers. Unit typeprotection will result in the boundary being a clearlydefined closed loop. Figure 2.7 illustrates a typicalarrangement of overlapping zones.

Figure 2.7

Alternatively, the zone may be unrestricted; the start willbe defined but the extent (or ‘reach’) will depend onmeasurement of the system quantities and will thereforebe subject to variation, owing to changes in systemconditions and measurement errors.

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Figure 2.7: Overlapping zonesof protection systems

~

~Figure 2.5: Division of power system

into protection zones

Feeder 2Feeder 1 Feeder 3Zone 6

Zone 5 Zone 7

Zone 4

Zone 3

Zone 2

Zone 1

AA

FF

Feederedprotection

Feederedprotection

Busbarprotectionec

Busbarprotectione

(a) CT's on both sides of circuit breaker

(b) CT's on circuit side of circuit breaker

Figure 2.6: CT Locations

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2.4 RELIABIL ITY

The need for a high degree of reliability is discussed inSection 2.1. Incorrect operation can be attributed to oneof the following classifications:

a. incorrect design/settings

b. incorrect installation/testing

c. deterioration in service

2.4.1 Design

The design of a protection scheme is of paramountimportance. This is to ensure that the system willoperate under all required conditions, and (equallyimportant) refrain from operating when so required(including, where appropriate, being restrained fromoperating for faults external to the zone beingprotected). Due consideration must be given to thenature, frequency and duration of faults likely to beexperienced, all relevant parameters of the power system(including the characteristics of the supply source, andmethods of operation) and the type of protectionequipment used. Of course, no amount of effort at thisstage can make up for the use of protection equipmentthat has not itself been subject to proper design.

2.4.2 Settings

It is essential to ensure that settings are chosen forprotection relays and systems which take into accountthe parameters of the primary system, including faultand load levels, and dynamic performance requirementsetc. The characteristics of power systems change withtime, due to changes in loads, location, type and amountof generation, etc. Therefore, setting values of relaysmay need to be checked at suitable intervals to ensurethat they are still appropriate. Otherwise, unwantedoperation or failure to operate when required may occur.

2.4.3 Installation

The need for correct installation of protection systems isobvious, but the complexity of the interconnections ofmany systems and their relationship to the remainder ofthe installation may make checking difficult. Site testingis therefore necessary; since it will be difficult toreproduce all fault conditions correctly, these tests mustbe directed to proving the installation. The tests shouldbe limited to such simple and direct tests as will provethe correctness of the connections, relay settings, andfreedom from damage of the equipment. No attemptshould be made to 'type test' the equipment or toestablish complex aspects of its technical performance.

2.4.4 Testing

Comprehensive testing is just as important, and thistesting should cover all aspects of the protectionscheme, as well as reproducing operational andenvironmental conditions as closely as possible. Typetesting of protection equipment to recognised standardsfulfils many of these requirements, but it may still benecessary to test the complete protection scheme (relays,current transformers and other ancillary items) and thetests must simulate fault conditions realistically.

2.4.5 Deterioration in Service

Subsequent to installation in perfect condition,deterioration of equipment will take place and mayeventually interfere with correct functioning. Forexample, contacts may become rough or burnt owing tofrequent operation, or tarnished owing to atmosphericcontamination; coils and other circuits may becomeopen-circuited, electronic components and auxiliarydevices may fail, and mechanical parts may seize up.

The time between operations of protection relays may beyears rather than days. During this period defects mayhave developed unnoticed until revealed by the failure ofthe protection to respond to a power system fault. Forthis reason, relays should be regularly tested in order tocheck for correct functioning.

Testing should preferably be carried out withoutdisturbing permanent connections. This can be achievedby the provision of test blocks or switches.

The quality of testing personnel is an essential featurewhen assessing reliability and considering means forimprovement. Staff must be technically competent andadequately trained, as well as self-disciplined to proceedin a systematic manner to achieve final acceptance.

Important circuits that are especially vulnerable can beprovided with continuous electrical supervision; sucharrangements are commonly applied to circuit breakertrip circuits and to pilot circuits. Modern digital andnumerical relays usually incorporate self-testing/diagnostic facilities to assist in the detection offailures. With these types of relay, it may be possible toarrange for such failures to be automatically reported bycommunications link to a remote operations centre, sothat appropriate action may be taken to ensurecontinued safe operation of that part of the powersystem and arrangements put in hand for investigationand correction of the fault.

2.4.6 Protection Performance

Protection system performance is frequently assessedstatistically. For this purpose each system fault is classed

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as an incident and only those that are cleared by thetripping of the correct circuit breakers are classed as'correct'. The percentage of correct clearances can thenbe determined.

This principle of assessment gives an accurate evaluationof the protection of the system as a whole, but it issevere in its judgement of relay performance. Manyrelays are called into operation for each system fault,and all must behave correctly for a correct clearance tobe recorded.

Complete reliability is unlikely ever to be achieved byfurther improvements in construction. If the level ofreliability 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 sothat either by itself can carry out the required function.If the probability of each equipment failing is x/unit, theresultant probability of both equipments failingsimultaneously, allowing for redundancy, is x2. Where xis small the resultant risk (x2) may be negligible.

Where multiple protection systems are used, the trippingsignal can be provided in a number of different ways.The two most common methods are:

a. all protection systems must operate for a trippingoperation to occur (e.g. ‘two-out-of-two’arrangement)

b. only one protection system need operate to causea trip (e.g. ‘one-out-of two’ arrangement)

The former method guards against maloperation whilethe latter guards against failure to operate due to anunrevealed fault in a protection system. Rarely, threemain protection systems are provided, configured in a‘two-out-of three’ tripping arrangement, to provide bothreliability of tripping, and security against unwantedtripping.

It has long been the practice to apply duplicateprotection systems to busbars, both being required tooperate to complete a tripping operation. Loss of abusbar may cause widespread loss of supply, which isclearly undesirable. In other cases, important circuits areprovided with duplicate main protection systems, eitherbeing able to trip independently. On critical circuits, usemay also be made of a digital fault simulator to modelthe relevant section of the power system and check theperformance of the relays used.

2.5 SELECTIVITY

When a fault occurs, the protection scheme is requiredto trip only those circuit breakers whose operation isrequired to isolate the fault. This property of selectivetripping is also called 'discrimination' and is achieved bytwo general methods.

2.5.1 Time Grading

Protection systems in successive zones are arranged tooperate in times that are graded through the sequence ofequipments so that upon the occurrence of a fault,although a number of protection equipments respond,only those relevant to the faulty zone complete thetripping function. The others make incompleteoperations and then reset. The speed of response willoften depend on the severity of the fault, and willgenerally be slower than for a unit system.

2.5.2 Unit Systems

It is possible to design protection systems that respondonly to fault conditions occurring within a clearlydefined zone. This type of protection system is known as'unit protection'. Certain types of unit protection areknown by specific names, e.g. restricted earth fault anddifferential protection. Unit protection can be appliedthroughout a power system and, since it does not involvetime grading, is relatively fast in operation. The speed ofresponse is substantially independent of fault severity.

Unit protection usually involves comparison of quantitiesat the boundaries of the protected zone as defined by thelocations of the current transformers. This comparisonmay be achieved by direct hard-wired connections ormay be achieved via a communications link. Howevercertain protection systems derive their 'restricted'property from the configuration of the power system andmay be classed as unit protection, e.g. earth faultprotection applied to the high voltage delta winding of apower transformer. Whichever method is used, it mustbe kept in mind that selectivity is not merely a matter ofrelay design. It also depends on the correct co-ordination of current transformers and relays with asuitable choice of relay settings, taking into account thepossible range of such variables as fault currents,maximum load current, system impedances and otherrelated factors, where appropriate.

2.6 STABIL ITY

The term ‘stability’ is usually associated with unitprotection schemes and refers to the ability of theprotection system to remain unaffected by conditionsexternal to the protected zone, for example through loadcurrent and external fault conditions.

2.7 SPEED

The function of protection systems is to isolate faults onthe power system as rapidly as possible. The mainobjective is to safeguard continuity of supply byremoving each disturbance before it leads to widespreadloss of synchronism and consequent collapse of thepower system.

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N e t w o r k P r o t e c t i o n & A u t o m a t i o n G u i d e • 1 1 •

As the loading on a power system increases, the phaseshift between voltages at different busbars on thesystem also increases, and therefore so does theprobability that synchronism will be lost when thesystem is disturbed by a fault. The shorter the time afault is allowed to remain in the system, the greater canbe the loading of the system. Figure 2.8 shows typicalrelations between system loading and fault clearancetimes for various types of fault. It will be noted thatphase faults have a more marked effect on the stabilityof the system than a simple earth fault and thereforerequire faster clearance.

Figure 2.8

System stability is not, however, the only consideration.Rapid operation of protection ensures that fault damageis minimised, as energy liberated during a fault isproportional to the square of the fault current times theduration of the fault. Protection must thus operate asquickly as possible but speed of operation must beweighed against economy. Distribution circuits, whichdo not normally require a fast fault clearance, are usuallyprotected by time-graded systems. Generating plant andEHV systems require protection gear of the highestattainable speed; the only limiting factor will be thenecessity for correct operation, and therefore unitsystems are normal practice.

2.8 SENSIT IV ITY

Sensitivity is a term frequently used when referring tothe minimum operating level (current, voltage, poweretc.) of relays or complete protection schemes. The relayor scheme is said to be sensitive if the primary operatingparameter(s) is low.

With older electromechanical relays, sensitivity wasconsidered in terms of the sensitivity of the measuringmovement and was measured in terms of its volt-ampereconsumption to cause operation. With modern digitaland numerical relays the achievable sensitivity is seldomlimited by the device design but by its application andCT/VT parameters.

2.9 PRIMARY AND BACK-UP PROTECTION

The reliability of a power system has been discussedearlier, including the use of more than one primary (or‘main’) protection system operating in parallel. In theevent of failure or non-availability of the primaryprotection some other means of ensuring that the faultis isolated must be provided. These secondary systemsare referred to as ‘back-up protection’.

Back-up protection may be considered as either being‘local’ or ‘remote’. Local back-up protection is achievedby protection which detects an un-cleared primarysystem fault at its own location and which then trips itsown circuit breakers, e.g. time graded overcurrent relays.Remote back-up protection is provided by protectionthat detects an un-cleared primary system fault at aremote location and then issues a local trip command,e.g. the second or third zones of a distance relay. In bothcases the main and back-up protection systems detect afault simultaneously, operation of the back-upprotection being delayed to ensure that the primaryprotection clears the fault if possible. Normally beingunit protection, operation of the primary protection willbe fast and will result in the minimum amount of thepower system being disconnected. Operation of theback-up protection will be, of necessity, slower and willresult in a greater proportion of the primary systembeing lost.

The extent and type of back-up protection applied willnaturally be related to the failure risks and relativeeconomic importance of the system. For distributionsystems where fault clearance times are not critical, timedelayed remote back-up protection may be adequate.For EHV systems, where system stability is at risk unlessa fault is cleared quickly, multiple primary protectionsystems, operating in parallel and possibly of differenttypes (e.g. distance and unit protection), will be used toensure fast and reliable tripping. Back-up overcurrentprotection may then optionally be applied to ensure thattwo separate protection systems are available duringmaintenance of one of the primary protection systems.

Back-up protection systems should, ideally, becompletely separate from the primary systems. Forexample a circuit protected by a current differential relaymay also have time graded overcurrent and earth faultrelays added to provide circuit breaker tripping in theevent of failure of the main primary unit protection. Tomaintain complete separation and thus integrity, currenttransformers, voltage transformers, relays, circuit breakertrip coils and d.c. supplies would be duplicated. Thisideal is rarely attained in practice. The followingcompromises are typical:

a. separate current transformers (cores and secondarywindings only) are provided. This involves little extracost or accommodation compared with the use of

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Figure 2.8: Typical power/time relationshipfor various fault types

Time

Load

pow

er

Phase-earth

Phase-phase

Three-phase

Phase-phase-earth

Chap2-4-15 21/06/02 10:45 Page 11


common current transformers that would have to belarger because of the combined burden. This practiceis becoming less common when digital or numericalrelays are used, because of the extremely low inputburden of these relay types

b. voltage transformers are not duplicated because ofcost and space considerations. Each protection relaysupply is separately protected (fuse or MCB) andcontinuously supervised to ensure security of the VToutput. An alarm is given on failure of the supply and,where appropriate, prevent an unwanted operation ofthe protection

c. trip supplies to the two protections should beseparately protected (fuse or MCB). Duplication oftripping batteries and of circuit breaker tripping coilsmay be provided. Trip circuits should be continuouslysupervised

d. it is desirable that the main and back-up protections (orduplicate main protections) should operate on differentprinciples, so that unusual events that may causefailure of the one will be less likely to affect the other

Digital and numerical relays may incorporate suitableback-up protection functions (e.g. a distance relay mayalso incorporate time-delayed overcurrent protectionelements as well). A reduction in the hardware required toprovide back-up protection is obtained, but at the risk thata common relay element failure (e.g. the power supply)will result in simultaneous loss of both main and back-upprotection. The acceptability of this situation must beevaluated on a case-by-case basis.

2.10 RELAY OUTPUT DEVICES

In order to perform their intended function, relays must befitted with some means of providing the various outputsignals required. Contacts of various types usually fulfilthis function.

2.10.1 Contact Systems

Relays may be fitted with a variety of contact systemsfor providing electrical outputs for tripping and remoteindication purposes. The most common typesencountered are as follows:

a. Self-resetThe contacts remain in the operated condition onlywhile the controlling quantity is applied, returningto their original condition when it is removed

b. Hand or electrical resetThese contacts remain in the operated conditionafter the controlling quantity is removed. They canbe reset either by hand or by an auxiliaryelectromagnetic element

The majority of protection relay elements have self-resetcontact systems, which, if so desired, can be modified toprovide hand reset output contacts by the use ofauxiliary elements. Hand or electrically reset relays areused when it is necessary to maintain a signal or lockoutcondition. Contacts are shown on diagrams in theposition corresponding to the un-operated or de-energised condition, regardless of the continuous servicecondition of the equipment. For example, anundervoltage relay, which is continually energised innormal circumstances, would still be shown in the de-energised condition.

A 'make' contact is one that closes when the relay picksup, whereas a 'break' contact is one that is closed whenthe relay is de-energised and opens when the relay picksup. Examples of these conventions and variations areshown in Figure 2.9.

A protection relay is usually required to trip a circuitbreaker, the tripping mechanism of which may be asolenoid with a plunger acting directly on themechanism latch or an electrically operated valve. Thepower required by the trip coil of the circuit breaker mayrange from up to 50 watts for a small 'distribution'circuit breaker, to 3000 watts for a large, extra-high-voltage circuit breaker.

The relay may therefore energise the tripping coildirectly, or, according to the coil rating and the numberof circuits to be energised, may do so through theagency of another multi-contact auxiliary relay.

The basic trip circuit is simple, being made up of a hand-trip control switch and the contacts of the protectionrelays in parallel to energise the trip coil from a battery,through a normally open auxiliary switch operated bythe circuit breaker. This auxiliary switch is needed toopen the trip circuit when the circuit breaker openssince the protection relay contacts will usually be quiteincapable of performing the interrupting duty. Theauxiliary switch will be adjusted to close as early aspossible in the closing stroke, to make the protectioneffective in case the breaker is being closed on to a fault.

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Figure 2.9: Contact types

Self reset

Hand reset

`make' contacts(normally open)

`break' contacts(normally open)

Time delay onpick up

Time delay ondrop-off

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Where multiple output contacts, or contacts withappreciable current-carrying capacity are required,interposing, contactor type elements will normally be used.

In general, static and microprocessor relays have discretemeasuring and tripping circuits, or modules. Thefunctioning of the measuring modules is independent ofoperation of the tripping modules. Such a relay isequivalent to a sensitive electromechanical relay with atripping contactor, so that the number or rating ofoutputs has no more significance than the fact that theyhave been provided.

For larger switchgear installations the tripping powerrequirement of each circuit breaker is considerable, andfurther, two or more breakers may have to be tripped byone protection system. There may also be remotesignalling requirements, interlocking with otherfunctions (for example auto-reclosing arrangements),and other control functions to be performed. Thesevarious operations may then be carried out by multi-contact tripping relays, which are energised by theprotection relays and provide the necessary number ofadequately rated output contacts.

2.10.2 Operation Indicators

Protection systems are invariably provided withindicating devices, called 'flags', or 'targets', as a guidefor operations personnel. Not every relay will have one,as indicators are arranged to operate only if a tripoperation is initiated. Indicators, with very fewexceptions, are bi-stable devices, and may be eithermechanical or electrical. A mechanical indicator consistsof a small shutter that is released by the protection relaymovement to expose the indicator pattern.

Electrical indicators may be simple attracted armatureelements, where operation of the armature releases ashutter to expose an indicator as above, or indicatorlights (usually light emitting diodes). For the latter, somekind of memory circuit is provided to ensure that theindicator remains lit after the initiating event has passed.

With the advent of digital and numerical relays, theoperation indicator has almost become redundant.Relays will be provided with one or two simple indicatorsthat indicate that the relay is powered up and whetheran operation has occurred. The remainder of theinformation previously presented via indicators isavailable by interrogating the relay locally via a ‘man-machine interface’ (e.g. a keypad and liquid crystaldisplay screen), or remotely via a communication system.

2.11 TRIPPING CIRCUITS

There are three main circuits in use for circuit breakertripping:

a. series sealing

b. shunt reinforcing

c. shunt reinforcement with sealing

These are illustrated in Figure 2.10.

For electromechanical relays, electrically operatedindicators, actuated after the main contacts have closed,avoid imposing an additional friction load on themeasuring element, which would be a serious handicapfor certain types. Care must be taken with directlyoperated indicators to line up their operation with theclosure of the main contacts. The indicator must haveoperated by the time the contacts make, but must nothave done so more than marginally earlier. This is to stopindication occurring when the tripping operation has notbeen completed.

With modern digital and numerical relays, the use ofvarious alternative methods of providing trip circuitfunctions is largely obsolete. Auxiliary miniaturecontactors are provided within the relay to provideoutput contact functions and the operation of thesecontactors is independent of the measuring system, asmentioned previously. The making current of the relayoutput contacts and the need to avoid these contactsbreaking the trip coil current largely dictates circuitbreaker trip coil arrangements. Comments on thevarious means of providing tripping arrangements are,however, included below as a historical referenceapplicable to earlier electromechanical relay designs.

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Figure 2.10: Typical relay tripping circuits

(a) Series sealing

PR TC

PR TC

PR TC

52a

(b) Shunt reinforcing

52a

(c) Shunt reinforcing with series sealing

52a

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2.11.1 Series sealing

The coil of the series contactor carries the trip currentinitiated by the protection relay, and the contactor closesa contact in parallel with the protection relay contact.This closure relieves the protection relay contact of furtherduty and keeps the tripping circuit securely closed, even ifchatter occurs at the main contact. The total tripping timeis not affected, and the indicator does not operate untilcurrent is actually flowing through the trip coil.

The main disadvantage of this method is that such serieselements must have their coils matched with the tripcircuit with which they are associated.

The coil of these contacts must be of low impedance,with about 5% of the trip supply voltage being droppedacross them.

When used in association with high-speed trip relays,which usually interrupt their own coil current, theauxiliary elements must be fast enough to operate andrelease the flag before their coil current is cut off. Thismay pose a problem in design if a variable number ofauxiliary elements (for different phases and so on) maybe required to operate in parallel to energise a commontripping relay.

2.11.2 Shunt reinforcing

Here the sensitive contacts are arranged to trip thecircuit breaker and simultaneously to energise theauxiliary unit, which then reinforces the contact that isenergising the trip coil.

Two contacts are required on the protection relay, sinceit is not permissible to energise the trip coil and thereinforcing contactor in parallel. If this were done, andmore than one protection relay were connected to tripthe same circuit breaker, all the auxiliary relays would beenergised in parallel for each relay operation and theindication would be confused.

The duplicate main contacts are frequently provided as athree-point arrangement to reduce the number ofcontact fingers.

2.11.3 Shunt reinforcement with sealing

This is a development of the shunt reinforcing circuit tomake it applicable to situations where there is apossibility of contact bounce for any reason.

Using the shunt reinforcing system under thesecircumstances would result in chattering on the auxiliaryunit, and the possible burning out of the contacts, notonly of the sensitive element but also of the auxiliaryunit. The chattering would end only when the circuitbreaker had finally tripped. The effect of contact bounce

is countered by means of a further contact on theauxiliary unit connected as a retaining contact.

This means that provision must be made for releasing thesealing circuit when tripping is complete; this is adisadvantage, because it is sometimes inconvenient tofind a suitable contact to use for this purpose.

2.12 TRIP C IRCUIT SUPERVIS ION

The trip circuit includes the protection relay and othercomponents, such as fuses, links, relay contacts, auxiliaryswitch contacts, etc., and in some cases through aconsiderable amount of circuit wiring with intermediateterminal boards. These interconnections, coupled withthe importance of the circuit, result in a requirement inmany cases to monitor the integrity of the circuit. Thisis known as trip circuit supervision. The simplestarrangement contains a healthy trip lamp, as shown inFigure 2.11(a).

The resistance in series with the lamp prevents thebreaker being tripped by an internal short circuit causedby failure of the lamp. This provides supervision whilethe circuit breaker is closed; a simple extension givespre-closing supervision.

Figure 2.11(b) shows how, the addition of a normallyclosed auxiliary switch and a resistance unit can providesupervision while the breaker is both open and closed.

• 2 •

Fun

dam

enta

ls o

fP

rote

ctio

n P

ract

ice

• 1 4 •

Figure 2.11: Trip circuit supervision circuits.

PR TC52a

PR TC

PR TC

52a

52b

(c) Supervision with circuit breaker open or closed with remote alarm (scheme H7)

52a

A

Alarm

52a

52b

TCCircuit breaker

Trip

Trip

(d) Implementation of H5 scheme in numerical relay

(a) Supervision while circuit breaker is closed (scheme H4)

(b) Supervision while circuit breaker is open or closed (scheme H5)

C

B

Chap2-4-15 21/06/02 10:45 Page 14


In either case, the addition of a normally open push-button contact in series with the lamp will make thesupervision indication available only when required.

Schemes using a lamp to indicate continuity are suitablefor locally controlled installations, but when control isexercised from a distance it is necessary to use a relaysystem. Figure 2.11(c) illustrates such a scheme, which isapplicable wherever a remote signal is required.

With the circuit healthy, either or both of relays A and Bare operated and energise relay C. Both A and B mustreset to allow C to drop-off. Relays A, B and C are timedelayed to prevent spurious alarms during tripping orclosing operations. The resistors are mounted separatelyfrom the relays and their values are chosen such that ifany one component is inadvertently short-circuited,tripping will not take place.

The alarm supply should be independent of the trippingsupply so that indication will be obtained in case offailure of the tripping supply.

The above schemes are commonly known as the H4, H5and H7 schemes, arising from the diagram references ofthe Utility specification in which they originallyappeared. Figure 2.11(d) shows implementation ofscheme H5 using the facilities of a modern numericalrelay. Remote indication is achieved through use ofprogrammable logic and additional auxiliary outputsavailable in the protection relay.

• 2 •F

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e

Chap2-4-15 21/06/02 10:45 Page 15

Introduction 5.1Synchronous machines 5.2

Armature reaction 5.3Steady state theory 5.4

Salient pole rotor 5.5Transient analysis 5.6

Asymmetry 5.7Machine reactances 5.8

Negative sequence reactance 5.9Zero sequence reactance 5.10

Direct and quadrature axis values 5.11Effect of saturation on machine reactances 5.12

Transformers 5.13Transformer positive sequence equivalent circuits 5.14

Transformer zero sequence equivalent circuits 5.15Auto-transformers 5.16

Transformer impedances 5.17Overhead lines and cables 5.18

Calculation of series impedance 5.19Calculation of shunt impedance 5.20

Overhead line circuits with or without earth wires 5.21OHL equivalent circuits 5.22

Cable circuits 5.23Overhead line and cable data 5.24

References 5.25

• 5 • E q u i v a l e n t C i r c u i t s a n d P a r a m e t e r s o f P o w e r S y s t e m P l a n t

Chapt 5-46-77 21/06/02 9:31 Page 46


5.1 INTRODUCTION

Knowledge of the behaviour of the principal electricalsystem plant items under normal and fault conditions isa prerequisite for the proper application of protection.This chapter summarises basic synchronous machine,transformer and transmission line theory and givesequivalent circuits and parameters so that a fault studycan be successfully completed before the selection andapplication of the protection systems described in laterchapters. Only what might be referred to as 'traditional'synchronous machine theory is covered, as that is all thatcalculations for fault level studies generally require.Readers interested in more advanced models ofsynchronous machines are referred to the numerouspapers on the subject, of which reference [5.1] is a goodstarting point.

Power system plant may be divided into two broadgroups - static and rotating.

The modelling of static plant for fault level calculationsprovides few difficulties, as plant parameters generallydo not change during the period of interest followingfault inception. The problem in modelling rotating plantis that the parameters change depending on theresponse 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 formeris confined to 2 and 4 pole turbine generators, whilesalient pole types are built with 4 poles upwards andinclude most classes of duty. Both classes of machineare similar in so far that each has a stator carrying athree-phase winding distributed over its inner periphery.Within the stator bore is carried the rotor which ismagnetised by a winding carrying d.c. current.

The essential difference between the two classes ofmachine lies in the rotor construction. The cylindricalrotor type has a uniformly cylindrical rotor that carriesits excitation winding distributed over a number of slots

• 5 • Equivalent Cir cuits and Parameters o f Pow e r System Plant

Chapt 5-46-77 21/06/02 9:31 Page 47

most common. Two-stroke diesel engines are oftenderivatives of marine designs with relatively large outputs(circa 30MW is possible) and may have running speeds ofthe order of 125rpm. This requires a generator with alarge number of poles (48 for a 125rpm, 50Hz generator)and consequently is of large diameter and short axiallength. This is a contrast to turbine-driven machines thatare of small diameter and long axial length.


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around its periphery. This construction is unsuited tomulti-polar machines but it is very sound mechanically.Hence it is particularly well adapted for the highestspeed electrical machines and is universally employed for2 pole units, plus some 4 pole units.

The salient pole type has poles that are physicallyseparate, each carrying a concentrated excitationwinding. This type of construction is in many wayscomplementary to that of the cylindrical rotor and isemployed in machines having 4 poles or more. Except inspecial cases its use is exclusive in machines having morethan 6 poles. Figure 5.1 illustrates a typical largecylindrical rotor generator installed in a power plant.

Two and four pole generators are most often used inapplications where steam or gas turbines are used as thedriver. This is because the steam turbine tends to besuited to high rotational speeds. Four pole steam turbinegenerators are most often found in nuclear powerstations as the relative wetness of the steam makes thehigh rotational speed of a two-pole design unsuitable.Most generators with gas turbine drivers are four polemachines to obtain enhanced mechanical strength in therotor- since a gearbox is often used to couple the powerturbine to the generator, the choice of synchronousspeed of the generator is not subject to the sameconstraints as with steam turbines.

Generators with diesel engine drivers are invariably offour or more pole design, to match the running speed ofthe driver without using a gearbox. Four-stroke dieselengines usually have a higher running speed than two-stroke engines, so generators having four or six poles are

Strong

N S

Direction of rotation

(a)

(b)

S NN

Weak Weak Strong

Figure 5.2: Distortion of fluxdue to armature reaction

Figure 5.1: Modern large synchronous generator

Chapt 5-46-77 21/06/02 9:31 Page 48


• 5 •

5.3 ARMATURE REACTION

Armature reaction has the greatest effect on theoperation of a synchronous machine with respect both tothe load angle at which it operates and to the amount ofexcitation that it needs. The phenomenon is most easilyexplained by considering a simplified ideal generatorwith full pitch winding operating at unity p.f., zero lagp.f. and zero lead p.f. When operating at unity p.f., thevoltage and current in the stator are in phase, the statorcurrent producing a cross magnetising magneto-motiveforce (m.m.f.) which interacts with that of the rotor,resulting in a distortion of flux across the pole face. Ascan be seen from Figure 5.2(a) the tendency is to weakenthe flux at the leading edge or effectively to distort thefield in a manner equivalent to a shift against thedirection of rotation.

If the power factor were reduced to zero lagging, thecurrent in the stator would reach its maximum 90° afterthe voltage and the rotor would therefore be in theposition shown in Figure 5.2(b). The stator m.m.f. is nowacting in direct opposition to the field.

Similarly, for operation at zero leading power factor, thestator m.m.f. would directly assist the rotor m.m.f. Thism.m.f. arising from current flowing in the stator is knownas 'armature reaction'.

5.4 . STEADY STATE THEORY

The vector diagram of a single cylindrical rotorsynchronous machine is shown in Figure 5.3, assumingthat the magnetic circuit is unsaturated, the air-gap isuniform and all variable quantities are sinusoidal.Further, since the reactance of machines is normally verymuch larger than the resistance, the latter has beenneglected.

The excitation ampere-turns, ATe, produces a flux Φacross the air-gap thereby inducing a voltage, Et, in thestator. This voltage drives a current I at a power factorcos-1φ and gives rise to an armature reaction m.m.f. ATarin phase with it. The m.m.f. ATf resulting from thecombination of these two m.m.f. vectors (see Figure5.3(a)) is the excitation which must be provided on therotor to maintain flux Φ across the air-gap. Rotating therotor m.m.f. diagram, Figure 5.3(a), clockwise untilcoincides with Et and changing the scale of the diagramso that ATe becomes the basic unit, where ATe = Et =1,results in Figure 5.3(b). The m.m.f. vectors have thusbecome, in effect, voltage vectors. For exampleATar /ATe is a unit of voltage that is directly proportionalto the stator load current. This vector can be fullyrepresented by a reactance and in practice this is called

'armature reaction reactance' and is denoted by Xad.Similarly, the remaining side of the triangle becomesATf /ATe , which is the per unit voltage produced onopen circuit by ampere-turns ATf . It can be consideredas the internal generated voltage of the machine and isdesignated Eo .

The true leakage reactance of the stator winding whichgives rise to a voltage drop or regulation has beenneglected. This reactance is designated XL (or Xa insome texts) and the voltage drop occurring in it, IXL, isthe difference between the terminal voltage V and thevoltage behind the stator leakage reactance, EL.

IZL is exactly in phase with the voltage drop due to Xad,as shown on the vector diagram Figure 5.3(c). It shouldbe noted that Xad and XL can be combined to give asimple equivalent reactance; this is known as the'synchronous reactance', denoted by Xd.

The power generated by the machine is given by theequation:

…Equation 5.1

where δ is the angle between the internal voltage andthe terminal voltage and is known as the load angle ofthe machine.

P VI VEXd

= =cos sinφ δ

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ATf

IXd

IXL

IXadEo

EL V

ATe

ATar

Et(=V)

Et=1=V

I

(a)

ATe

ATar

ATe

ATf

(c)

I

(b)

I

ATar

Figure 5.3: Vector diagramof synchronous machine

Chapt 5-46-77 21/06/02 9:31 Page 49

It follows from the above analysis that, for steady stateperformance, the machine may be represented by theequivalent circuit shown in Figure 5.4, where XL is a truereactance associated with flux leakage around the statorwinding and Xad is a fictitious reactance, being the ratioof armature reaction and open-circuit excitationmagneto-motive forces.

In practice, due to necessary constructional features of acylindrical rotor to accommodate the windings, thereactance Xa is not constant irrespective of rotorposition, and modelling proceeds as for a generator witha salient pole rotor. However, the numerical differencebetween the values of Xad and Xaq is small, much lessthan for the salient pole machine.

5.5 SALIENT POLE ROTOR

The preceding theory is limited to the cylindrical rotorgenerator. The basic assumption that the air-gap isuniform is very obviously not valid when a salient polerotor is being considered. The effect of this is that the fluxproduced by armature reaction m.m.f. depends on theposition of the rotor at any instant, as shown in Figure 5.5.

LagArmature

reaction M.M.F.

Lead

FluxFlux

Qua

drat

ure

axis

Qua

dr

Dire

ct a

xis

pole

ect

axis

po


When a pole is aligned with the assumed sine wavem.m.f. set up by the stator, a corresponding sine waveflux will be set up, but when an inter-polar gap is alignedvery severe distortion is caused. The difference is treatedby considering these two axes, that is thosecorresponding to the pole and the inter-polar gap,separately. They are designated the 'direct' and'quadrature' axes respectively, and the general theory isknown as the 'two axis' theory.

The vector diagram for the salient pole machine is similarto that for the cylindrical rotor except that the reactanceand currents associated with them are split into twocomponents. The synchronous reactance for the directaxis is Xd = Xad + XL, while that in the quadrature axisis Xq = Xaq + XL. The vector diagram is constructed asbefore but the appropriate quantities in this case areresolved along two axes. The resultant internal voltageis Eo, as shown in Figure 5.6.

In passing it should be noted that E ’0 is the internalvoltage which would be given, in cylindrical rotor theory,by vectorially adding the simple vectors IXd and V. Thereis very little difference in magnitude between E0 and E ’0but a substantial difference in internal angle; the simpletheory is perfectly adequate for calculation of excitationcurrents but not for stability considerations where loadangle is significant.

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Figure 5.5: Variation of armature reaction m.m.f.with pole position

V

Id

Iq

IdXd

IqXq

EO

IXd

E 'O

I

Pole axis

Figure 5.6: Vector diagram for salient pole machine

Figure 5.4: Equivalent circuit of elementary machine

Xad XL

Et VEo

Chapt 5-46-77 21/06/02 9:31 Page 50


5.6 TRANSIENT ANALYSIS

For normal changes in load conditions, steady statetheory is perfectly adequate. However, there areoccasions when almost instantaneous changes areinvolved, such as faults or switching operations. Whenthis happens new factors are introduced within themachine and to represent these adequately acorresponding new set of machine characteristics isrequired.

The generally accepted and most simple way toappreciate the meaning and derivation of thesecharacteristics is to consider a sudden three-phase shortcircuit applied to a machine initially running on opencircuit and excited to normal voltage E0.

This voltage will be generated by a flux crossing the air-gap. It is not possible to confine the flux to one pathexclusively in any machine, and as a result there will bea leakage flux ΦL that will leak from pole to pole andacross the inter-polar gaps without crossing the mainair-gap as shown in Figure 5.7. The flux in the pole willbe Φ + ΦL.

If the stator winding is then short-circuited, the powerfactor in it will be zero. A heavy current will tend toflow, as the resulting armature reaction m.m.f. isdemagnetising. This will reduce the flux and conditionswill settle until the armature reaction nearly balancesthe excitation m.m.f., the remainder maintaining a verymuch reduced flux across the air-gap which is justsufficient to generate the voltage necessary to overcomethe stator leakage reactance (resistance neglected). Thisis the simple steady state case of a machine operating onshort circuit and is fully represented by the equivalent ofFigure 5.8(a); see also Figure 5.4.

It might be expected that the fault current would begiven by E0 /(XL+Xad) equal to E0/Xd , but this is verymuch reduced, and the machine is operating with nosaturation. For this reason, the value of voltage used isthe value read from the air-gap line corresponding tonormal excitation and is rather higher than the normalvoltage. The steady state current is given by:

…Equation 5.2

where Eg = voltage on air gap line

An important point to note now is that between theinitial and final conditions there has been a severereduction of flux. The rotor carries a highly inductivewinding which links the flux so that the rotor fluxlinkages before the short circuit are produced by(Φ + ΦL). In practice the leakage flux is distributed overthe whole pole and all of it does not link all the winding.ΦL is an equivalent concentrated flux imagined to link allthe winding and of such a magnitude that the totallinkages are equal to those actually occurring. It is afundamental principle that any attempt to change theflux linked with such a circuit will cause current to flowin a direction that will oppose the change. In the presentcase the flux is being reduced and so the inducedcurrents will tend to sustain it.

IEXd

g

d

=

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2L

Figure 5.7: Flux paths of salient pole machine

Xad

Xad

Xad

Xf

XL

XL

XL

Xf

Xkd

(c) Subtransient reactance

(b) Transient reactance

(a) Synchronous reactance

Figure 5.8: Synchronous machine reactances

Chapt 5-46-77 21/06/02 9:31 Page 51


For the position immediately following the application ofthe short circuit, it is valid to assume that the flux linkedwith the rotor remains constant, this being broughtabout by an induced current in the rotor which balancesthe heavy demagnetising effect set up by the short-circuited armature. So (Φ + ΦL) remains constant, butowing to the increased m.m.f. involved, the flux leakagewill increase considerably. With a constant total rotorflux, this can only increase at the expense of that fluxcrossing the air-gap. Consequently, this generates areduced voltage, which, acting on the leakage reactance,gives the short circuit current.

It is more convenient for machine analysis to use therated voltage E0 and to invent a fictitious reactance thatwill give rise to the same current. This reactance iscalled the 'transient reactance' X’d and is defined by theequation:

Transient current

…Equation 5.3

It is greater than XL, and the equivalent circuit isrepresented by Figure 5.8(b) where:

and Xf is the leakage reactance of the field winding

The above equation may also be written as:

X’d = XL + X’f

where X’f = effective leakage reactance of field winding

The flux will only be sustained at its relatively high valuewhile the induced current flows in the field winding. Asthis current decays, so conditions will approach thesteady state. Consequently, the duration of this phasewill be determined by the time constant of the excitationwinding. This is usually of the order of a second or less- hence the term 'transient' applied to characteristicsassociated with it.

A further point now arises. All synchronous machineshave what is usually called a ‘damper winding’ orwindings. In some cases, this may be a physical winding(like a field winding, but of fewer turns and locatedseparately), or an ‘effective’ one (for instance, the solidiron 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 damperwinding located in slots in the pole faces).

Under short circuit conditions, there is a transfer of fluxfrom the main air-gap to leakage paths. This diversion is,to a small extent, opposed by the excitation winding andthe main transfer will be experienced towards the pole tips.

XX X

X XXd

ad f

ad fL' =

++

I EX

do

d

''

=

The damper winding(s) is subjected to the full effect offlux transfer to leakage paths and will carry an inducedcurrent tending to oppose it. As long as this current canflow, the air-gap flux will be held at a value slightlyhigher than would be the case if only the excitationwinding were present, but still less than the originalopen circuit flux Φ.

As before, it is convenient to use rated voltage and tocreate another fictitious reactance that is considered tobe 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 …Equation 5.4

where

or X’’d = XL + X’kd

and Xkd= leakage reactance of damper winding(s)

X’kd= effective leakage reactance of damper winding(s)

It is greater than XL but less than X ’d and thecorresponding equivalent circuit is shown in Figure5.8(c).

Again, the duration of this phase depends upon the timeconstant of the damper winding. In practice this isapproximately 0.05 seconds - very much less than thetransient - hence the term 'sub-transient'.

Figure 5.9 shows the envelope of the symmetricalcomponent of an armature short circuit currentindicating the values described in the preceding analysis.The analysis of the stator current waveform resultingfrom a sudden short circuit test is traditionally the

X XX X X

X X X X X Xd Lad f kd

ad f kd f ad kd

'' = ++ +

= EX

o

d''

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Curr

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Time

EoI''dX ''d

=

EoI 'dX 'd

=

Eair gapIdIdIXdX

=

Figure 5.9: Transient decay envelopeof short-circuit current

Chapt 5-46-77 21/06/02 9:31 Page 52


method by which these reactances are measured.However, the major limitation is that only direct axisparameters are measured. Detailed test methods forsynchronous machines are given in references [5.2] and[5.3], and include other tests that are capable ofproviding more detailed parameter information.

5.7 ASYMMETRY

The exact instant at which the short circuit is applied tothe stator winding is of significance. If resistance isnegligible compared with reactance, the current in a coilwill lag the voltage by 90°, that is, at the instant whenthe voltage wave attains a maximum, any currentflowing through would be passing through zero. If ashort circuit were applied at this instant, the resultingcurrent would rise smoothly and would be a simple a.c.component. However, at the moment when the inducedvoltage is zero, any current flowing must pass through amaximum (owing to the 90° lag). If a fault occurs at thismoment, the resulting current will assume thecorresponding relationship; it will be at its peak and inthe ensuing 180° will go through zero to maximum inthe reverse direction and so on. In fact the current mustactually start from zero and so will follow a sine wavethat is completely asymmetrical. Intermediate positionswill give varying degrees of asymmetry.

This asymmetry can be considered to be due to a d.c.component of current which dies away becauseresistance is present.

The d.c. component of stator current sets up a d.c. fieldin the stator which causes a supply frequency ripple onthe field current, and this alternating rotor flux has afurther effect on the stator. This is best shown byconsidering the supply frequency flux as beingrepresented by two half magnitude waves each rotating

in opposite directions at supply frequency relative to therotor. So, as viewed from the stator, one is stationaryand the other rotating at twice supply frequency. Thelatter sets up second harmonic currents in the stator.Further development along these lines is possible but theresulting harmonics are usually negligible and normallyneglected.

5.8 MACHINE REACTANCES

Table 5.1 gives values of machine reactances for salientpole and cylindrical rotor machines typical of latestdesign practice. Also included are parameters forsynchronous compensators – such machines are nowrarely built, but significant numbers can still be found inoperation.

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 XLcan be reduced by increasing the machine size (derating),or increased by artificially increasing the slot leakage,but it will be noted that XL is only about 10% of thetotal value of Xd and cannot exercise much influence.

The armature reaction reactance can be reduced bydecreasing the armature reaction of the machine, whichin design terms means reducing the ampere conductor orelectrical (as distinct from magnetic) loading - this willoften mean a physically larger machine. Alternativelythe excitation needed to generate open-circuit voltagemay be increased; this is simply achieved by increasingthe machine air-gap, but is only possible if the excitationsystem is modified to meet the increased requirements.

In general, control of Xd is obtained almost entirely byvarying Xad, and in most cases a reduction in Xd willmean a larger and more costly machine. It is also worth

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Table 5.1: Typical synchronous generator parameters

Type of machine

Salient Cylindrical rotor turbine generators Salient pole generators

pole synchronousAir Cooled Hydrogen Hydrogen/ 4 Pole Multi-pole

condensers Cooled Water Cooled

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 1.75-3.0 1.4-1.9

Quadrature axis synchronous reactance Xq (p.u.) 1.0-1.23 0.5-0.65 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 0.2-0.35 0.2-0.3 0.27-0.33 0.3-0.36 0.26-0.35 0.24-0.4

Direct axis sub-transient reactance X’’d (p.u.) 0.2-0.4 0.12-0.25 0.15-0.23 0.19-0.23 0.21-0.27 0.19-0.25 0.16-0.25

Quadrature axis sub-transient reactance X’’q (p.u.) 0.25-0.6 0.15-0.25 0.16-0.25 0.19-0.23 0.21-0.28 0.19-0.35 0.18-0.24

Negative sequence reactance X2 (p.u.) 0.25-0.5 0.14-0.35 0.16-0.23 0.19-0.24 0.21-0.27 0.16-0.27 0.16-0.23

Zero sequence reactance X0 (p.u.) 0.12-0.16 0.06-0.10 0.06-0.1 0.1-0.15 0.1-0.15 0.01-0.1 0.045-0.23

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’do (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) 0.04-0.9 0.05-0.10 0.013-0.022 0.017-0.025 0.022-0.03 0.02-0.04 0.02-0.06

Direct axis open circuit sub-transient time constant T’’do(s) 0.07-0.11 0.08-0.25 0.018-0.03 0.023-0.032 0.025-0.035 0.035-0.06 0.03-0.1

Quadrature axis short circuit sub-transient time constant T’’q (s) 0.04-0.6 0.05-0.6 0.013-0.022 0.018-0.027 0.02-0.03 0.025-0.04 0.025-0.08

Quadrature axis open circuit sub-transient time constant T’’qo (s) 0.1-0.2 0.2-0.9 0.026-0.045 0.03-0.05 0.04-0.065 0.13-0.2 0.1-0.35

NB all reactance values are unsaturated.

Chapt 5-46-77 21/06/02 9:31 Page 53

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 itapproximates to the short circuit ratio (S.C.R.), the onlydifference being that the S.C.R. takes saturation intoaccount whereas Xd is derived from the air-gap line.

5.8.2 Transient Reactance X’d = XL + X’f

The transient reactance covers the behaviour of amachine in the period 0.1-3.0 seconds after adisturbance. This generally corresponds to the speed ofchanges in a system and therefore X’d has a majorinfluence in transient stability studies.

Generally, the leakage reactance XL is equal to theeffective field leakage reactance X’f, about 0.1-0.25p.u.The principal factor determining the value of X’f is thefield leakage. This is largely beyond the control of thedesigner, in that other considerations are at present moresignificant than field leakage and hence take precedencein determining the field design.

XL can be varied as already outlined, and, in practice,control of transient reactance is usually achieved byvarying XL

5.8.3 Sub-transient Reactance X’’d = XL + X’kd

The sub-transient reactance determines the initialcurrent peaks following a disturbance and in the case ofa sudden fault is of importance for selecting the breakingcapacity of associated circuit breakers. The mechanicalstresses on the machine reach maximum values thatdepend on this constant. The effective damper windingleakage reactance X’kd is largely determined by theleakage of the damper windings and control of this isonly possible to a limited extent. X’kd normally has avalue between 0.05 and 0.15 p.u. The major factor is XLwhich, as indicated previously, is of the order of 0.1-0.25p.u., and control of the sub-transient reactance isnormally achieved by varying XL.

It should be noted that good transient stability isobtained by keeping the value of X’d low, whichtherefore also implies a low value of X’’d. The fault ratingof switchgear, etc. will therefore be relatively high. It isnot normally possible to improve transient stabilityperformance in a generator without adverse effects onfault levels, and vice versa.

5.9 NEGATIVE SEQUENCE REACTANCE

Negative sequence currents can arise whenever there isany unbalance present in the system. Their effect is toset up a field rotating in the opposite direction to themain field generated by the rotor winding, so subjectingthe rotor to double frequency flux pulsations. This gives

rise to parasitic currents and heating; most machines arequite limited in the amount of such current which theyare able to carry, both in the steady – state andtransiently.

An accurate calculation of the negative sequence currentcapability of a generator involves consideration of thecurrent paths in the rotor body. In a turbine generatorrotor, for instance, they include the solid rotor body, slotwedges, excitation winding and end-winding retainingrings. There is a tendency for local over-heating to occurand, although possible for the stator, continuous localtemperature measurement is not practical in the rotor.Calculation requires complex mathematical techniquesto be applied, and involves specialist software.

In practice an empirical method is used, based on thefact that a given type of machine is capable of carrying,for short periods, an amount of heat determined by itsthermal capacity, and for a long period, a rate of heatinput which it can dissipate continuously. Synchronousmachines are designed to be capable of operatingcontinuously on an unbalanced system such that, withnone of the phase currents exceeding the rated current,the ratio of the negative sequence current I2 to the ratedcurrent IN does not exceed the values given in Table 5.2.Under fault conditions, the machine shall also be capable

of operation with the product of and time in

seconds (t) not exceeding the values given.

II N

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motors 0.1 20

generators 0.08 20

synchronouscondensers

0.1 20

motors 0.08 15

generators 0.05 15

synchronous

condensers0.08 15

all 0.1 15

all 0.1 10

<=350 0.08 8

351-900 Note 1 Note 2

901-1250 Note 1 5

1251-1600 0.05 5

Machine Maximum MaximumRotor Cooling Type (SN) I2/IN for (I2/IN)2t for

/Rating continuous operation during(MVA) operation faults

indirect

direct

indirectly cooled (air)

indirectly cooled (hydrogen)

directly cooled

Salient

Cylindrical

Note 1: Calculate asI2 = 0.08-

SN-350IN 3 x 104

Note 2: Calculate as (I2 )2t = 8-0.00545(SN-350)IN

Table 5.2: Unbalanced operating conditions for synchronous machines(from IEC 60034-1)

N e t w o r k P r o t e c t i o n & A u t o m a t i o n G u i d e• 5 4 •

Rotor

construction

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5.10 ZERO SEQUENCE REACTANCE

If a machine is operating with an earthed neutral, asystem earth fault will give rise to zero sequencecurrents in the machine. This reactance represents themachine's contribution to the total impedance offered tothese currents. In practice it is generally low and oftenoutweighed by other impedances present in the circuit.

5.11 DIRECT AND QUADRATURE AXIS VALUES

The transient reactance is associated with the fieldwinding and since on salient pole machines this isconcentrated on the direct axis, there is nocorresponding quadrature axis value. The value ofreactance applicable in the quadrature axis is thesynchronous reactance, that is, X’q = Xq.

The damper winding (or its equivalent) is more widelyspread and hence the sub-transient reactance associatedwith this has a definite quadrature axis value X”q, whichdiffers significantly in many generators from X”d.

5.12 EFFECT OF SATURATIONON MACHINE REACTANCES

In general, any electrical machine is designed to avoidsevere saturation of its magnetic circuit. However, it isnot economically possible to operate at such low fluxdensities as to reduce saturation to negligibleproportions, and in practice a moderate degree ofsaturation is accepted.

Since the armature reaction reactance Xad is a ratioATar /ATe it is evident that ATe will not vary in a linearmanner for different voltages, while ATar will remainunchanged. The value of Xad will vary with the degree ofsaturation present in the machine, and for extremeaccuracy should be determined for the particularconditions involved in any calculation.

All the other reactances, namely XL , X’d and X’’d aretrue reactances and actually arise from flux leakage.Much of this leakage occurs in the iron parts of themachines and hence must be affected by saturation. Fora given set of conditions, the leakage flux exists as aresult of the net m.m.f. which causes it. If the ironcircuit is unsaturated its reactance is low and leakageflux is easily established. If the circuits are highlysaturated the reverse is true and the leakage flux isrelatively lower, so the reactance under saturatedconditions is lower than when unsaturated.

Most calculation methods assume infinite ironpermeability and for this reason lead to somewhatidealised unsaturated reactance values. The recognitionof a finite and varying permeability makes a solutionextremely laborious and in practice a simple factor ofapproximately 0.9 is taken as representing the reductionin reactance arising from saturation.

It is necessary to distinguish which value of reactance isbeing measured when on test. The normal instantaneousshort circuit test carried out from rated open circuitvoltage gives a current that is usually several times fullload value, so that saturation is present and thereactance measured will be the saturated value. Thisvalue is also known as the 'rated voltage' value since it ismeasured by a short circuit applied with the machineexcited to rated voltage.

In some cases, if it is wished to avoid the severemechanical strain to which a machine is subjected bysuch a direct short circuit, the test may be made from asuitably reduced voltage so that the initial current isapproximately full load value. Saturation is very muchreduced and the reactance values measured are virtuallyunsaturated values. They are also known as 'ratedcurrent' values, for obvious reasons.

5.13 TRANSFORMERS

A transformer may be replaced in a power system by anequivalent 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-circuitimpedance, and the column the excitation impedance. Itis rarely necessary in fault studies to consider excitationimpedance as this is usually many times the magnitudeof the short-circuit impedance. With these simplifyingassumptions a three-winding transformer becomes a starof three impedances and a four-winding transformer amesh of six impedances.

The impedances of a transformer, in common with otherplant, can be given in ohms and qualified by a basevoltage, or in per unit or percentage terms and qualifiedby a base MVA. Care should be taken with multi-winding transformers to refer all impedances to acommon base MVA or to state the base on which each isgiven. The impedances of static apparatus areindependent of the phase sequence of the appliedvoltage; in consequence, transformer negative sequenceand positive sequence impedances are identical. Indetermining the impedance to zero phase sequencecurrents, account must be taken of the windingconnections, earthing, and, in some cases, theconstruction type. The existence of a path for zerosequence currents implies a fault to earth and a flow ofbalancing currents in the windings of the transformer.

Practical three-phase transformers may have a phaseshift between primary and secondary windingsdepending on the connections of the windings – delta orstar. The phase shift that occurs is generally of nosignificance in fault level calculations as all phases areshifted equally. It is therefore ignored. It is normal tofind delta-star transformers at the transmitting end of a

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transmission system and in distribution systems for thefollowing reasons:

a. at the transmitting end, a higher step-up voltageratio is possible than with other windingarrangements, while the insulation to ground of thestar secondary winding does not increase by thesame ratio

b. in distribution systems, the star winding allows aneutral connection to be made, which may beimportant in considering system earthingarrangements

c. the delta winding allows circulation of zerosequence currents within the delta, thuspreventing transmission of these from thesecondary (star) winding into the primary circuit.This simplifies protection considerations

5.14 TRANSFORMER POSIT IVE SEQUENCE EQUIVALENT CIRCUITS

The transformer is a relatively simple device. However,the equivalent circuits for fault calculations need notnecessarily be quite so simple, especially where earthfaults are concerned. The following two sections discussthe equivalent circuits of various types of transformers.

5.14.1 Two-winding Transformers

The two-winding transformer has four terminals, but inmost system problems, two-terminal or three-terminalequivalent circuits as shown in Figure 5.10 can representit. In Figure 5.10(a), terminals A' and B' are assumed tobe at the same potential. Hence if the per unit self-impedances of the windings are Z11 and Z22 respectivelyand the mutual impedance between them Z12, the

transformer may be represented by Figure 5.10(b). Thecircuit in Figure 5.10(b) is similar to that shown in Figure3.14(a), and can therefore be replaced by an equivalent'T ' as shown in Figure 5.10(c) where:

…Equation 5.5

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 thewindings, usually represented by XM, the magnetizingreactance paralleled with the hysteresis and eddy currentloops 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,then the short-circuit impedance viewed from theterminals AA’ is ZT = Z1 + Z2 and the transformer canbe replaced by a two-terminal equivalent circuit asshown in Figure 5.10(e).

The relative magnitudes of ZT and XM are of the order of10% and 2000% respectively. ZT and XM rarely have tobe considered together, so that the transformer may berepresented either as a series impedance or as anexcitation impedance, according to the problem beingstudied.

A typical power transformer is illustrated in Figure 5.11.

5.14.2 Three-winding Transformers

If excitation impedance is neglected the equivalentcircuit of a three-winding transformer may berepresented by a star of impedances, as shown in Figure5.12, where P, T and S are the primary, tertiary andsecondary windings respectively. The impedance of anyof these branches can be determined by considering theshort-circuit impedance between pairs of windings withthe third open.

Z Z Z

Z Z Z

Z Z

1 11 12

2 22 12

3 12

= −

= −

=

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Zero bus(d) 'π' equivalent circuit

Zero bus(b) Equivalent circuit of model

Zero bus(c) 'T' equivalent circuit

Zero bus(e) Equivalent circuit: secondary winding s/c

R jXM

B'

B' C '

B'B' A'

B'A'

A'

A'

B CA

A'

B

BA

BA

BA

AZT =Z1+Z2

Z1 =Z11-Z12 Z2=Z22-Z12

Z3=Z12

r1+jx1 r2+jx2

Z12Z11 Z22LoadE

(a) Model of transformer

~

Figure 5.10: Equivalent circuitsfor a two-winding transformer

Zero bus

S

P

T

Zt

Zs

Zp

Tertiary

Secondary

Primary

Figure 5.12: Equivalent circuitfor a three-winding transformer

Chapt 5-46-77 21/06/02 9:40 Page 56


The exceptions to the general rule of neglectingmagnetising impedance occur when the transformer isstar/star and either or both neutrals are earthed. Inthese circumstances the transformer is connected to thezero bus through the magnetising impedance. Where athree-phase transformer bank is arranged withoutinterlinking magnetic flux (that is a three-phase shelltype, or three single-phase units) and provided there is apath for zero sequence currents, the zero sequenceimpedance is equal to the positive sequence impedance.In the case of three-phase core type units, the zerosequence fluxes produced by zero sequence currents canfind a high reluctance path, the effect being to reducethe zero sequence impedance to about 90% of thepositive sequence impedance.

However, in hand calculations, it is usual to ignore thisvariation and consider the positive and zero sequenceimpedances to be equal. It is common when usingsoftware to perform fault calculations to enter a value ofzero-sequence impedance in accordance with the aboveguidelines, if the manufacturer is unable to provide avalue.

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5.15 TRANSFORMER ZERO SEQUENCE EQUIVALENT CIRCUITS

The flow of zero sequence currents in a transformer isonly possible when the transformer forms part of aclosed loop for uni-directional currents and ampere-turnbalance is maintained between windings.

The positive sequence equivalent circuit is stillmaintained to represent the transformer, but now thereare certain conditions attached to its connection into theexternal circuit. The order of excitation impedance isvery much lower than for the positive sequence circuit;it will be roughly between 1 and 4 per unit, but still highenough to be neglected in most fault studies.

The mode of connection of a transformer to the externalcircuit is determined by taking account of each windingarrangement and its connection or otherwise to ground.If zero sequence currents can flow into and out of awinding, the winding terminal is connected to theexternal circuit (that is, link a is closed in Figure 5.13). Ifzero sequence currents can circulate in the windingwithout flowing in the external circuit, the windingterminal is connected directly to the zero bus (that is,link b is closed in Figure 5.13). Table 5.3 gives the zerosequence connections of some common two- and three-winding transformer arrangements applying the above rules.

Figure 5.11: Modern large transformer

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Table 5.3: Zero sequence equivalent circuit connections

Zero busb

ZTa

b

a

Zero busb

ZTa

b

a

Zero busb

ZTa

b

a

Zero busb

ZTa

b

a

Zero busb

ZTa

b

a

Zero bus

Zero bus

b

ZT

ZT

ab b

a

b

a

Zero bus

Zt

Zs

Zp

ab b

a

b

a

Zero bus

Zt

Zs

Zp

ab b

a

b

a

Zero bus

Zt

Zs

Zp

ab b

a

b

a

Zero bus

Zt

Zs

Zp

ab b

a

b

a

Zero bus

Zt

Zs

Zp

a

b

a

Zero phase sequence networkConnections and zero phase sequence currents

Chapt 5-46-77 21/06/02 9:40 Page 58


5.16 AUTO-TRANSFORMERS

The auto-transformer is characterised by a singlecontinuous winding, part of which is shared by both thehigh and low voltage circuits, as shown in Figure 5.14(a).The 'common' winding is the winding between the lowvoltage terminals whereas the remainder of the winding,belonging exclusively to the high voltage circuit, isdesignated the 'series' winding, and, combined with the'common' winding, forms the 'series-common' windingbetween the high voltage terminals. The advantage ofusing an auto-transformer as opposed to a two-windingtransformer is that the auto-transformer is smaller andlighter for a given rating. The disadvantage is thatgalvanic isolation between the two windings does notexist, giving rise to the possibility of large overvoltageson the lower voltage system in the event of majorinsulation breakdown.

Three-phase auto-transformer banks generally have starconnected main windings, the neutral of which isnormally connected solidly to earth. In addition, it iscommon practice to include a third winding connected indelta called the tertiary winding, as shown in Figure5.14(b).

5.16.1 Positive Sequence Equivalent Circuit

The positive sequence equivalent circuit of a three-phaseauto-transformer bank is the same as that of a two- orthree-winding transformer. The star equivalent for athree-winding transformer, for example, is obtained inthe same manner, with the difference that theimpedances between windings are designated as follows:

…Equation 5.8

where:Zsc-t = impedance between 'series common' and tertiary

windings

Zsc-c = impedance between 'series common' and'common' windings

Zsc-t = impedance between 'common' and tertiarywindings

When no load is connected to the delta tertiary, the pointT will be open-circuited and the short-circuit impedanceof the transformer becomes ZL + ZH = Zsc-c’ , that is,similar to the equivalent circuit of a two-windingtransformer, with magnetising impedance neglected; seeFigure 5.14(c).

Z Z Z Z

Z Z Z Z

Z Z Z Z

L sc c c t sc t

H sc c sc t c t

T sc t c t sc c

= + −( )

= + −( )

= + −( )

− − −

− − −

− − −

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Zero potential bus

a

b

Ze

Zt

Zp

Zs

Ze

bb

a

a

(b) Three windings

(a) Two windings

Zero potential bus

b

aa

b

ZT2

ZT2

Figure 5.13: Zero sequence equivalent circuits

H

L

N

L

N

T

H

T

HL HL

T

Zero potential bus

Zero potential bus(e) Equivalent circuit with isolated neutral

L H

T

ZHT

ZLH

ZX

ZZ

ZYZH

IH IL

IL-IH

IL-IH

VLVH

IH

IH

ILIL IT

INZN

ZL

ZT

ZLT

IL0 IH0

IL0

IT0IT1

IL1 IH0IH1

IT0

(c) Positive sequence impedance (d) Zero sequence equivalent circuit

(a) Circuit diagram (b) Circuit diagram with tertiary winding

Figure 5.14: Equivalent circuitof auto-transformer

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5.16.2 Zero Sequence Equivalent Circuit

The zero sequence equivalent circuit is derived in asimilar manner to the positive sequence circuit, exceptthat, as there is no identity for the neutral point, thecurrent in the neutral and the neutral voltage cannot begiven directly. Furthermore, in deriving the branchimpedances, account must be taken of an impedance inthe neutral Zn, as shown in the following equations,where Zx, Zy and Zz are the impedances of the low, highand tertiary windings respectively and N is the ratiobetween the series and common windings.

…Equation 5.9

Figure 5.14(d) shows the equivalent circuit of thetransformer bank. Currents ILO and IHO are thosecirculating in the low and high voltage circuits respectively.The difference between these currents, expressed inamperes, is the current in the common winding.

The current in the neutral impedance is three times thecurrent in the common winding.

5.16.3 Special Conditions of Neutral Earthing

With a solidly grounded neutral, Zn = O, the branchimpedances Zx, Zy, Zz, become ZL, ZH, ZT, that is,identical to the corresponding positive sequenceequivalent circuit, except that the equivalent impedanceZT of the delta tertiary is connected to the zero potentialbus in the zero sequence network.

When the neutral is ungrounded Zn = ∞ and theimpedances of the equivalent star also become infinitebecause there are apparently no paths for zero sequencecurrents between the windings, although a physicalcircuit exists and ampere-turn balance can be obtained.A solution is to use an equivalent delta circuit (see Figure5.14(e)), and evaluate the elements of the delta directlyfrom the actual circuit. The method requires threeequations corresponding to three assumed operatingconditions. Solving these equations will relate the deltaimpedances to the impedance between the series andtertiary windings, as follows:

…Equation 5.10

Z Z NN

Z Z N

Z Z NN

LH s t

LT s t

HT s t

=+( )

=

=+( )

−

−

−

2

1

1

Z Z Z NN

Z Z Z N

N

Z Z ZN

x L n

y H n

z T n

= ++( )

= −+( )

= ++( )

31

31

3 11

2

With the equivalent delta replacing the star impedancesin the auto-transformer zero sequence equivalent circuitthe transformer can be combined with the systemimpedances in the usual manner to obtain the systemzero sequence diagram.

5.17 TRANSFORMER IMPEDANCES

In the vast majority of fault calculations, the ProtectionEngineer is only concerned with the transformer leakageimpedance; the magnetising impedance is neglected, asit is very much higher. Impedances for transformersrated 200MVA or less are given in IEC 60076 andrepeated in Table 5.4, together with an indication of X/Rvalues (not part of IEC 60076). These impedances arecommonly used for transformers installed in industrialplants. Some variation is possible to assist in controllingfault levels or motor starting, and typically up to ±10%variation on the impedance values given in the table ispossible without incurring a significant cost penalty. Forthese transformers, the tapping range is small, and thevariation of impedance with tap position is normallyneglected in fault level calculations.

For transformers used in electricity distributionnetworks, the situation is more complex, due to anincreasing trend to assign importance to the standing (orno-load) losses represented by the magnetisingimpedance. This can be adjusted at the design stage butthere is often an impact on the leakage reactance inconsequence. In addition, it may be more important tocontrol fault levels on the LV side than to improve motorstarting voltage drops. Therefore, departures from theIEC 60076 values are commonplace.

IEC 60076 does not make recommendations of nominalimpedance in respect of transformers rated over200MVA, while generator transformers and a.c. tractionsupply transformers have impedances that are usuallyspecified as a result of Power Systems Studies to ensuresatisfactory performance. Typical values of transformerimpedances covering a variety of transformer designs aregiven in Tables 5.5 – 5.9. Where appropriate, theyinclude an indication of the impedance variation at theextremes of the taps given. Transformers designed towork at 60Hz will have substantially the sameimpedance as their 50Hz counterparts.

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MVA Z% HV/LV X/R Tolerance 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

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MVA Primary Primary Taps Secondary kV Z% HV/LV X/R ratio MVA Primary kV Primary Taps Secondary kV Z% HV/LV X/R ratio

7.5 33 +5.72% -17.16% 11 7.5 15 24 33 ±10% 6.9 24 25

7.5 33 +5.72% -17.16% 11 7.5 17 30 33 +5.72% -17.16% 11 30 40

8 33 +5.72% -17.16% 11 8 9 30 132 +10% -20% 11 21.3 43

11.5 33 +5.72% -17.16% 6.6 11.5 24 30 132 +10% -20% 11 25 30

11.5 33 +5.72% -17.16% 6.6 11.5 24 30 132 +10% -20% 11 23.5 46

11.5 33 +5.72% -17.16% 11 11.5 24 40 132 +10% -20% 11 27.9 37

11.5 33 +5.72% -17.16% 11 11.5 26 45 132 +10% -20% 33 11.8 18

11.5 33 +4.5% -18% 6.6 11.5 24 60 132 +10% -20% 33 16.7 28

12 33 +5% -15% 11.5 12 27 60 132 +10% -20% 33 17.7 26

12 33 ±10% 11.5 12 27 60 132 +10% -20% 33 14.5 25

12 33 ±10% 11.5 12 25 60 132 +10% -20% 66 11 25

15 66 +9% -15% 11.5 15 14 60 132 +10% -20% 11/11 35.5 52

15 66 +9% -15% 11.5 15 16 60 132 +9.3% -24% 11/11 36 75

16 33 ±10% 11.5 16 16 60 132 +9.3% -24% 11/11 35.9 78

16 33 +5.72% -17.16% 11 16 30 65 140 +7.5% -15% 11 12.3 28

16 33 +5.72% -17.16% 6.6 16 31 90 132 +10% -20% 33 24.4 60

19 33 +5.72% -17.16% 11 19 37 90 132 +10% -20% 66 15.1 41

30 33 +5.72% -17.16% 11 30 40

MVA Primary Primary Secondary Tertiary Z% X/RkV Taps kV kV HV/LV ratio

20 220 +12.5% -7.5% 6.9 - 9.9 18

20 230 +12.5% -7.5% 6.9 - 10-14 13

57 275 ±10% 11.8 7.2 18.2 34

74 345 +14.4% -10% 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 22

180 275 ±15% 66 13 22.2 38

255 230 +10% 16.5 - 14.8 43

Table 5.6: Impedances of two winding distribution transformers– Primary voltage >200kV

MVA Primary Primary Secondary Z% X/RkV Taps kV HV/LV ratio

95 132 ±10% 11 13.5 46

140 157.5 ±10% 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

(a) Three-phase units

MVA/ Primary Primary Secondary Z% X/Rphase kV Taps kV HV/LV ratio

266.7 432/√-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

(b) Single-phase units

Table 5.7: Impedances of generator transformers

Table 5.5: Impedances of two winding distribution transformers – Primary voltage <200kV

MVA Primary Primary Secondary Secondary Tertiary Z% X/RkV Taps kV Taps kV HV/LV ratio

100 66 - 33 - - 10.7 28

180 275 - 132 ±15% 13 15.5 55

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

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 ±10% 230√−3 - 22 18.2 101

Table 5.8: Autotransformer data

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5.18 OVERHEAD L INES AND CABLES

In this section a description of common overhead linesand cable systems is given, together with tables of theirimportant characteristics. The formulae for calculatingthe characteristics are developed to give a basic idea ofthe factors involved, and to enable calculations to bemade for systems other than those tabulated.

A transmission circuit may be represented by anequivalent π or T network using lumped constants asshown 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 thebrackets in Figure 5.15 are correction factors that allowfor the fact that in the actual circuit the parameters aredistributed over the whole length of the circuit and notlumped, as in the equivalent circuits.

With short lines it is usually possible to ignore the shuntadmittance, which greatly simplifies calculations, but onlonger lines it must be included. Another simplificationthat can be made is that of assuming the conductorconfiguration to be symmetrical. The self-impedance ofeach conductor becomes Zp , and the mutual impedance

between conductors becomes Zm. However, for rigorouscalculations a detailed treatment is necessary, withaccount being taken of the spacing of a conductor inrelation to its neighbour and earth.

5.19 CALCULATION OF SERIES IMPEDANCE

The self impedance of a conductor with an earth returnand the mutual impedance between two parallelconductors with a common earth return are given by theCarson equations:

…Equation 5.11

where:

R = conductor a.c. 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√p/f where p is earth resistivity (ohms/cm3)

The above formulae give the impedances in ohms/km. Itshould be noted that the last terms in Equation 5.11 arevery similar to the classical inductance formulae for longstraight conductors.

The geometric means radius (GMR) of a conductor is anequivalent radius that allows the inductance formula tobe reduced to a single term. It arises because theinductance of a solid conductor is a function of theinternal flux linkages in addition to those external to it.If the original conductor can be replaced by anequivalent that is a hollow cylinder with infinitesimallythin walls, the current is confined to the surface of theconductor, and there can be no internal flux. Thegeometric mean radius is the radius of the equivalentconductor. If the original conductor is a solid cylinderhaving a radius r its equivalent has a radius of 0.779r.

It can be shown that the sequence impedances for asymmetrical three-phase circuit are:

…Equation 5.12

where Zp and Zm are given by Equation 5.11.Substituting Equation 5.11 in Equation 5.12 gives:

…Equation 5.13

Z Z R j f Ddc

Z R f j f DdcD

oe

1 2 10

1023

0 0029

0 00296 0 00869

= = +

= + +

. log

. . log

Z Z Z Z

Z Z Z

p m

o p m

1 2

2

= = −

= +

Z R f j f Ddc

Z f j f DD

pe

me

= + +

= +

0 000988 0 0029

0 000988 0 0029

10

10

. . log

. . log

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(a) Actual transmission circuit

R XR X

BGBG

Series impedance Z = R + jX per unit lengthShunt admittance Y = G + jB per unit length

(b) π Equivalent

(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.

...5040120

Z2Y2

Z2Y2

Z3Y3

17Z3Y3

6

ZY

ZY

1ZY

ZY

ZY

ZY

sinh++++=

...2016012012

1tanh

+++-=

2

2

2 ZY

ZYtanhY 2

2

2 ZY

ZYtanhY

2

2

2 ZY

ZYtanhZ 2

2

2 ZY

ZYtanhZ

ZY

ZYsinhY

ZY

ZYsinhZ

Figure 5.15: Transmission circuit equivalents

Chapt 5-46-77 21/06/02 9:50 Page 62


In the formula for Z0 the expression 3√dcD2 is the

geometric mean radius of the conductor group.Where the circuit is not symmetrical, the usual case,symmetry can be maintained by transposing theconductors so that each conductor is in each phaseposition for one third of the circuit length. If A, B and Care the spacings between conductors bc, ca and ab thenD in the above equations becomes the geometric meandistance between conductors, equal to 3√ABC.

Writing Dc = 3√dcD2, the sequence impedances inohms/km at 50Hz become:

…Equation 5.14

5.20 CALCULATION OF SHUNT IMPEDANCE

It can be shown that the potential of a conductor aabove ground due to its own charge qa and a charge -qaon its image is:

…Equation 5.15

where h is the height above ground of the conductor andr is the radius of the conductor, as shown in Figure 5.16.

Similarly, it can be shown that the potential of aconductor a due to a charge qb on a neighbouringconductor b and the charge -qb on its image is:

…Equation 5.16

where D is the spacing between conductors a and b andD’ is the spacing between conductor b and the image ofconductor a as shown in Figure 5.14.

Since the capacitance C=q/V and the capacitivereactance Xc=1/ωC, it follows that the self and mutualcapacitive reactance of the conductor system in Figure5.16 can be obtained directly from Equations 5.15 and5.16. Further, as leakage can usually be neglected, theself and mutual shunt impedances Z’p and Z’m inmegohm-km at a system frequency of 50Hz are:

…Equation 5.17

Where the distances above ground are great in relation

Z j hr

Z j DD

p

m

'

''

=−

=−

0 132 2

0 132

10

10

. log

. log

V qb DDa e''

=2 log

V qa hra e=2 2log

Z Z R j ABCdc

Z R j DDo

e

c

1 2 10

3

10

0 145

0 148 0 434

= = +

= +( )+

. log

. . log

to the conductor spacing, which is the case with overheadlines, 2h=D’. From Equation 5.12, the sequenceimpedances of a symmetrical three-phase circuit are:

…Equation 5.18

It should be noted that the logarithmic terms above aresimilar to those in Equation 5.13 except that r is theactual radius of the conductors and D’ is the spacingbetween the conductors and their images.

Again, where the conductors are not symmetricallyspaced but transposed, Equation 5.18 can be re-writtenmaking use of the geometric mean distance betweenconductors, 3√ABC, and giving the distance of eachconductor above ground, that is, ha , h2 , hc , as follows:

…Equation 5.19

Z Z j ABCr

Z j h h h

r A B Ca b b

1 2 10

3

0 10 2 2 23

0 132

0 132 8

= = −

= −

. log

. log

Z Z j Dr

Z j DrD

o

1 2 10

1023

0 132

0 396

= =−

=−

. log

. log'

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Earth

a'

h

h

a b

D '

D

ConductorRadius r

Figure 5.16 Geometry of two parallel conductorsa and b and the image of a (a')

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Figure 5.17: Typical OHL configurations (not to scale)

2.75

R1

Y

2.753.10

W

R1

Y

a

b

a

3.30

3.30

d

2.00 - N1.75 - K

c

W

a b c d

1.43.03.73.063 kV(K)

90 kV (N) 3.1 3.8 3.8 1.85

Y

W

R1

2.50

2.70

6.6

a2.50

Double circuitUn= 170kV


Single circuitUn= 110kV

Single circuitUn= 63kV/90kV


Double circuitUn= 63kV/90kV

Double circuitUn= 63kV/66kV/90kV

Single circuitUn= 63kV/66kV/90kVSingle circuit

3.93.9

4.24.2

5.80

6.20

Y

W

3.7

R1

a

b

4.1a

3.4

1.40

1.85

1.40

(m)

63

66

nU (kV) a

90

A=3.5m

AA

A CBa a

3.3

6.6

11

22

33

U n (kV)

1

1.25

0.55

0.8

0.67

a (m)

R1

Y

X

W

R2

6.0

0.50

3.80

2.8 2.8

8.08.0

3.5 3.5

3.0 3.0

3.50

3.50

4.00

a

90

63

(kV)nU

1.85

1.4

(m)a

22

6.60 22

a=3.7m

b=4.6m

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Figure 5.17(cont): Typical OHL configurations (not to scale)

W

R1

R2

b

a

5.0d

2.5

c6.0

6.0

7.5

X

W

X

R1

2.40

9.74

32.48.5

25.1

9.2

11.3

7.0

X

W

R1

7.7

5.0

8.0

9.5

10.0

9.5

23.0

12.0

7.4

8.5

7.8

7.4

6.7

7.8

6.7

8.5

8.5

n1n

9.8

9.5

5.0

5.0

n2 p

6.3

6.3

4.8

4.5n

n1

p

5.20

7.50

8.45

n2

12.0

37.0

20.00

0 0 0

0

Y

X

W

R1

16.4

12.2

1.755.0

9.5

7.5

16.0

8.0

2.8

2.8

d

3.5

a

4.2

cb

4.5

3.8

4.8

4.1A

4.84.54.2 2.8

B

C










Chapt 5-46-77 21/06/02 9:50 Page 65


5.21 OVERHEAD L INE CIRCUITSWITH OR WITHOUT EARTH WIRES

Typical configurations of overhead line circuits are givenin Figure 5.17. Tower heights are not given as they varyconsiderably according to the design span and nature ofthe ground. As indicated in some of the tower outlines,some tower designs are designed with a number of baseextensions for this purpose. Figure 5.18 shows a typicaltower.

In some cases, the phase conductors are notsymmetrically disposed to each other and therefore, aspreviously indicated, electrostatic and electromagneticunbalance will result, which can be largely eliminated bytransposition. Modern practice is to build overhead lineswithout transposition towers to reduce costs; this mustbe taken into account in rigorous calculations of theunbalances. In other cases, lines are formed of bundledconductors, that is conductors formed of two, three orfour separate conductors. This arrangement minimiseslosses when voltages of 220kV and above are involved.

It should be noted that the line configuration andconductor spacings are influenced, not only by voltage,but also by many other factors including type ofinsulators, type of support, span length, conductor sagand the nature of terrain and external climatic loadings.Therefore, there can be large variations in spacingsbetween different line designs for the same voltage level,so those depicted in Figure 5.17 are only typicalexamples.

When calculating the phase self and mutual impedances,Equations 5.11 and 5.17 may be used, but it should beremembered that in this case Zp is calculated for eachconductor and Zm for each pair of conductors. Thissection is not, therefore, intended to give a detailedanalysis, but rather to show the general method offormulating the equations, taking the calculation ofseries impedance as an example and assuming a singlecircuit line with a single earth wire.

The phase voltage drops Va,Vb,Vb of a single circuit linewith a single earth wire due to currents Ia, Ib, Ib flowingin the phases and Ie in the earth wire are:

…Equation 5.20

where:

and so on.

The equation required for the calculation of shuntvoltage drops is identical to Equation 5.20 in form,except that primes must be included, the impedancesbeing derived from Equation 5.17.

Z f j f DDab

e= +0 000988 0 0029 10. . log

Z R f j f Ddcaa

e= + +0 000988 0 0029 10. . log

V Z I Z I Z I Z I

V Z I Z I Z I Z I

V Z I Z I Z I Z I

Z I Z I Z I Z I

a aa a ab b ac c ae e

b ba a bb b bc c be e

c ca a cb b cc c ce e

ea a eb b ec c ee e

= + + +

= + + +

= + + +

= + + +

0

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Figure 5.18: Typical overhead line tower

Chapt 5-46-77 21/06/02 9:51 Page 66


From Equation 5.20 it can be seen that:

Making use of this relation, the self and mutualimpedances of the phase conductors can be modifiedusing the following formula:

…Equation 5.21

For example:

and so on.

So Equation 5.20 can be simplified while still taking accountof the effect of the earth wire by deleting the fourth row andfourth column and substituting Jaa for Zaa, Jab for Zab , andso on, calculated using Equation 5.21. The single circuit linewith a single earth wire can therefore be replaced by anequivalent single circuit line having phase self and mutualimpedances Jaa , Jab and so on.

It can be shown from the symmetrical component theorygiven in Chapter 4 that the sequence voltage drops of ageneral three-phase circuit are:

…Equation 5.22

And, from Equation 5.20 modified as indicated above andEquation 5.22, the sequence impedances are:

V Z I Z I Z I

V Z I Z I Z I

V Z I Z I Z I

0 00 0 01 1 02 2

1 10 0 11 1 12 2

2 20 0 21 1 22 2

= + +

= + +

= + +

J Z Z ZZab abae be

ee

= −

J Z ZZaa aa

ae

ee

= −2

J Z Z ZZnm nmne me

ee

= −

− = + +I ZZ

I ZZ

I ZZ

Ieea

eea

eb

eeb

ec

eec

The development of these equations for double circuitlines with two earth wires is similar except that moreterms are involved.

The sequence mutual impedances are very small and canusually be neglected; this also applies for double circuitlines except for the mutual impedance between the zerosequence circuits, namely (ZOO’ = ZO’O). Table 5.10 givestypical values of all sequence self and mutual impedancessome single and double circuit lines with earth wires. Allconductors are 400mm2 ACSR, except for the 132kVdouble circuit example where they are 200mm2.

5.22 OHL EQUIVALENT CIRCUITS

Consider an earthed, infinite busbar source behind alength of transmission line as shown in Figure 5.19(a).An earth fault involving phase A is assumed to occur atF. If the driving voltage is E and the fault current is Ia

Z J J J J J J

Z J J J J J J

Z J a J aJ aJ a J J

Z J aJ a J a J aJ

aa bb cc ab bc ac

aa bb cc ab bc ac

aa bb cc ab ac bc

aa bb cc ab ac

00

11

12 2 2

21 2 2

13

23

13

13

13

23

13

23

= + +( )+ + +( )

= + +( )− + +( )

= + +( )+ + +( )

= + +( )+ + ++( )

= + +( )− + +( )

= + +( )− + +( )=

=

=

J

Z J a J aJ aJ a J J

Z J aJ a J a J aJ Jbc

Z Z

Z Z

Z Z

bc

aa bb cc ab ac bc

aa bb cc ab ac

20 2 2

10 2 2

22 11

01 20

02 10

13

13

13

13

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132kV 380kV 132kV 275kV

Sequence impedance Single circuit line Single circuit line Double circuit line Double circuit line

(400 mm2) (400 mm2) (200 mm2) (400 mm2)

Z00 = (Z0’0’) 1.0782 ∠ 73°54’ 0.8227 ∠ 70°36’ 1.1838 ∠ 71°6’ 0.9520 ∠ 76°46’

Z11 = Z22 = (Z1’1’) 0.3947 ∠ 78°54’ 0.3712 ∠ 75°57’ ∠ 66°19’ 0.3354 ∠ 74°35’

(Z0’0 =Z00’) - - 0.6334 ∠ 71°2’ 0.5219 ∠ 75°43’

Z01 = Z20 = (Z0’1’ = Z2’0’) 0.0116 ∠ -166°52’ 0.0094 ∠ -39°28’ 0.0257 ∠ -63°25’ 0.0241 ∠ -72°14’

Z02 = Z10 = (Z0’2’ = Z1’0’) ∠ 5°8’ 0.0153 ∠ 28°53’ 0.0197 ∠ -94°58’ 0.0217 ∠ -100°20’

Z12 = (Z1’2’) 0.0255 ∠ -40°9’ 0.0275 ∠ 147°26’ 0.0276 ∠ 161°17’ 0.0281 ∠ 149°46’

Z21 = (Z2’1’) 0.0256 ∠ -139°1’ 0.0275 ∠ 27°29’ 0.0277 ∠ 37°13’ 0.0282 ∠ 29°6’

(Z11’=Z1’1 = Z22’ = Z2’2) - - 0.0114 ∠ 88°6’ 0.0129 ∠ 88°44’

(Z02’ = Z0’2 = Z1’0 = Z10’) - - 0.0140 ∠ -93°44’ 0.0185 ∠ -91°16’

(Z02’ = Z0’2 = Z1’0 = Z10’ - - 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 5.10: Sequence self and mutual impedancesfor various lines

…Equation 5.23

Chapt 5-46-77 21/06/02 9:51 Page 67


then the earthfault impedance is Ze . From symmetrical componenttheory (see Chapter 4):

thus

since, as shown, Z1 = Z2 for a transmission circuit. FromEquations 5.12, Z1=Zp-Zm and ZO=Zp+2Zm. Thus,substituting these values in the above equation givesZe=Zp. This relation is physically valid because Zp is theself-impedance of a single conductor with an earth return.Similarly, for a phase fault between phases B and C at F:

where √_3E is the voltage between phases and 2Z is the

impedance of the fault loop.

Making use of the above relations a transmission circuitmay be represented, without any loss in generality, bythe equivalent of Figure 5.19(b), where Z1 is the phaseimpedance to the fault and (Z0-Z1)/3 is the impedanceof the earth path, there being no mutual impedancebetween the phases or between phase and earth. Theequivalent is valid for single and double circuit linesexcept that for double circuit lines there is zero sequencemutual impedance, hence Z0=(Z00-Z0’0).

The equivalent circuit of Figure 5.19(b) is valuable in

I I EZb c=− = 3

2 1

Z Z Ze = +2

31 0

I EZ Z Za =

+ +3

1 2 0

distance relay applications because the phase and earthfault relays are set to measure Z2 and are compensatedfor the earth return impedance (Z0-Z1)/3.

It is customary to quote the impedances of atransmission circuit in terms of Z1 and the ratio Z0/Z1 ,since in this form they are most directly useful. Bydefinition, the positive sequence impedance Z1 is afunction of the conductor spacing and radius, whereasthe Z0/Z1 ratio is dependent primarily on the level ofearth resistivity ρ. Further details may be found inChapter 12.

5.23 CABLE CIRCUITS

The basic formulae for calculating the series and shuntimpedances of a transmission circuit, Equations 5.11 and5.17 may be applied for evaluating cable parameters;since the conductor configuration is normallysymmetrical GMD and GMR values can be used withoutrisk of appreciable errors. However, the formulae mustbe modified by the inclusion of empirical factors to takeaccount of sheath and screen effects. A useful generalreference on cable formulae is given in reference [5.4];more detailed information on particular types of cablesshould be obtained direct from the manufacturers. Theequivalent circuit for determining the positive andnegative sequence series impedances of a cable is shownin Figure 5.20. From this circuit it can be shown that:

…Equation 5.24

where Rc, Rs are the core and sheath (screen) resistancesper unit length, Xc and Xs core and sheath (screen)reactances per unit length and Xcs the mutual reactancebetween core and sheath (screen) per unit length. Xcs isin general equal to Xs.

The zero sequence series impedances are obtaineddirectly using Equation 5.11 and account can be taken ofthe sheath in the same way as an earth wire in the caseof an overhead line.

The shunt capacitances of a sheathed cable can becalculated from the simple formula:

…Equation 5.25

where d is the overall diameter for a round conductor, Tcore insulation thickness and ε permittivity of dielectric.When the conductors are oval or shaped, an equivalent

Cd T

d

F km=+

0 0241 12

.log

/ε µ

Z Z R R XR X

j X X XR X

c scs

s s

c scs

s s

1 2

2

2 2

2

2 2

= = ++

+ −+

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(a) Actual circuit

C

B

A

E

Source LineF

B

C

FS IcIcI Z1

Z1

Z1

(Z0-Z )/3

IbIbI

IaIaIA

E

(b) Equivalent circuit

3E

~

~

~

Figure 5.19: Three-phase equivalentof a transmission circuit

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diameter d’ may be used where d’=(1/π) x periphery ofconductor. No simple formula exists for belted orunscreened cables, but an empirical formula that givesreasonable results is:

…Equation 5.26

where G is a geometric factor which is a function of core andbelt insulation thickness and overall conductor diameter.

5.24 OVERHEAD L INE AND CABLE DATA

The following tables contain typical data on overheadlines and cables that can be used in conjunction with thevarious equations quoted in this text. It is not intendedthat this data should replace that supplied bymanufacturers. Where the results of calculations areimportant, reliance should not be placed on the data inthese Tables and data should be sourced directly from amanufacturer/supplier.

At the conceptual design stage, initial selection of overheadline conductor size will be determined by four factors:

a. maximum load to be carried in MVAb. length of linec. conductor material and hence maximum

temperatured. cost of losses

Table 5.21 gives indicative details of the capability ofvarious sizes of overhead lines using the above factors,for AAAC and ACSR conductor materials. It is based oncommonly used standards for voltage drop and ambienttemperature. Since these factors may not be appropriatefor any particular project, the Table should only be usedas a guide for initial sizing, with appropriately detailedcalculations carried out to arrive at a final proposal.

CG

F km= 0 0555. /ε µ

Table 5.12: GMR for aluminium conductor steelreinforced (ACSR) (r = conductor radius)

Number of Layers Number of Al Strands GMR1 6 0.5r*1 12 0.75r*2 18 0.776r2 24 0.803r2 26 0.812r2 30 0.826r2 32 0.833r3 36 0.778r3 45 0.794r3 48 0.799r3 54 0.81r3 66 0.827r4 72 0.789r4 76 0.793r4 84 0.801r

* - Indicative values only, since GMR for single layer conductors is affected by cyclicmagnetic flux, which depends on various factors.

Xcs Per unit length

Ic

Is

Rs'Xs Per unit length

Rc'Xc Per unit length

V

V is voltage per unit length

Sheath circuit (s) Core circuit (c)

Figure 5.20: Equivalent circuit for determiningpositive or negative impedance of cables

Number of Strands GMR

7 0.726r

19 0.758r

37 0.768r

61 0.772r

91 0.774r

127 0.776r

169 0.776r

Solid 0.779r

Table 5.11: GMR for stranded copper, aluminium andaluminium alloy conductors (r = conductor radius)

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Stranding and wire Sectional area Total Approx. RDCDesignation diameter (mm) (mm2) area overall at 20 °C

(mm2) diameter (Ohm/km)Aluminium Steel Aluminium Steel (mm)

Gopher 6 2.36 1 2.36 26.2 4.4 30.6 7.08 1.093

Weasel 6 2.59 1 2.59 31.6 5.3 36.9 7.77 0.908

Ferret 6 3 1 3 42.4 7.1 49.5 9 0.676

Rabbit 6 3.35 1 3.35 52.9 8.8 61.7 10.05 0.542

Horse 12 2.79 7 2.79 73.4 42.8 116.2 13.95 0.393

Dog 6 4.72 7 1.57 105.0 13.6 118.5 14.15 0.273

Tiger 30 2.36 7 2.36 131.2 30.6 161.9 16.52 0.220

Wolf 30 2.59 7 2.59 158.1 36.9 194.9 18.13 0.182

Dingo 18 3.35 1 3.35 158.7 8.8 167.5 16.75 0.181

Lynx 30 2.79 7 2.79 183.4 42.8 226.2 19.53 0.157

Caracal 18 3.61 1 3.61 184.2 10.2 194.5 18.05 0.156

Jaguar 18 3.86 1 3.86 210.6 11.7 222.3 19.3 0.137

Panther 30 3 7 3 212.1 49.5 261.5 21 0.136

Zebra 54 3.18 7 3.18 428.9 55.6 484.5 28.62 0.067



Sparrow 6 2.67 1 2.67 33.6 5.6 39.2 8.01 0.854

Robin 6 3 1 3 42.4 7.1 49.5 9 0.677

Raven 6 3.37 1 3.37 53.5 8.9 62.4 10.11 0.536

Quail 6 3.78 1 3.78 67.4 11.2 78.6 11.34 0.426

Pigeon 6 4.25 1 4.25 85.0 14.2 99.2 12.75 0.337

Penguin 6 4.77 1 4.77 107.2 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 2.21 152.0 26.9 178.9 17.28 0.191

Merlin 18 3.47 1 3.47 170.5 9.5 179.9 17.35 0.169

Lark 30 2.92 7 2.92 201.4 46.9 248.3 20.44 0.144

Hawk 26 3.44 7 2.67 241.7 39.2 280.9 21.79 0.120

Dove 26 3.72 7 2.89 282.0 45.9 327.9 23.55 0.103

Teal 30 3.61 19 2.16 306.6 69.6 376.2 25.24 0.095

Swift 36 3.38 1 3.38 322.3 9.0 331.2 23.62 0.089

Tern 45 3.38 7 2.25 402.8 27.8 430.7 27.03 0.072

Canary 54 3.28 7 3.28 456.1 59.1 515.2 29.52 0.064

Curlew 54 3.52 7 3.52 523.7 68.1 591.8 31.68 0.055

Finch 54 3.65 19 2.29 565.0 78.3 643.3 33.35 0.051

Bittern 45 4.27 7 2.85 644.5 44.7 689.2 34.17 0.045

Falcon 54 4.36 19 2.62 805.7 102.4 908.1 39.26 0.036

Kiwi 72 4.41 7 2.94 1100.0 47.5 1147.5 44.07 0.027

(a) to ASTM B232

(b) to BS 215.2

Table 5.14: Overhead line conductor data - aluminiumconductors steel reinforced (ACSR).

Overall RDCStranding Wire Diameter Diameter (20°C) area (mm2) (mm) (mm) (Ohm/km)

10.6 7 1.38 4.17 1.73421.2 7 1.96 5.89 0.86526.7 7 2.20 6.60 0.68633.6 7 7.00 7.42 0.54442.4 7 2.77 8.33 0.43153.5 7 3.12 9.35 0.34267.4 7 3.50 10.52 0.27185.0 7 3.93 11.79 0.215107.2 7 4.42 13.26 0.171126.6 19 2.91 14.58 0.144152.0 19 3.19 15.98 0.120177.3 19 3.45 17.25 0.103202.7 19 3.69 18.44 0.090228.0 37 2.80 19.61 0.080253.3 37 2.95 20.65 0.072278.7 37 3.10 21.67 0.066304.3 37 3.23 22.63 0.060329.3 61 2.62 23.60 0.056354.7 61 2.72 24.49 0.052380.0 61 2.82 25.35 0.048405.3 61 2.91 26.19 0.045456.0 61 3.09 27.79 0.040506.7 61 3.25 29.26 0.036

(a) ASTM Standards

Overall RDCStranding Wire Diameter Diameter (20°C) area (mm2) (mm) (mm) (Ohm/km)

11.0 1 3.73 3.25 1.61713.0 1 4.06 4.06 1.36514.0 1 4.22 4.22 1.26914.5 7 1.63 4.88 1.23116.1 1 4.52 4.52 1.10318.9 1 4.90 4.90 0.93823.4 1 5.46 5.46 0.75632.2 1 6.40 6.40 0.54938.4 7 2.64 7.92 0.46647.7 7 2.95 8.84 0.37565.6 7 3.45 10.36 0.27370.1 1 9.45 9.45 0.25297.7 7 4.22 12.65 0.183129.5 19 2.95 14.73 0.139132.1 7 4.90 14.71 0.135164.0 7 5.46 16.38 0.109165.2 19 3.33 16.64 0.109

(b) BS Standards

Table 5.13: Overhead line conductor - hard drawn copper

Chapt 5-46-77 21/06/02 9:53 Page 70

(d) to NF C34-120

Table 5.14: Overhead line conductor data - aluminiumconductors steel reinforced (ACSR).


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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 1.44 69.9 11.4 81.3 11.7 0.413

95/15 26 2.15 7 1.67 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 2.33 183.8 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 2.49 263.7 34.1 297.7 22.4 0.109

305/40 54 2.68 7 2.68 304.6 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

560/50 48 3.86 7 3 561.7 49.5 611.2 32.2 0.051

650/45 45 4.3 7 2.87 653.5 45.3 698.8 34.4 0.044

1045/45 72 4.3 7 2.87 1045.6 45.3 1090.9 43 0.028

Stranding and wire Sectional area Total Approxi. RDCDesignation diameter (mm) (mm2) area overall at 20 °C


CANNA 59.7 12 2 7 2 37.7 22.0 59.7 10 0.765

CANNA 75.5 12 2.25 7 2.25 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 94.2 22.0 116.2 14 0.306

CROCUS 116.2 30 2 7 2 94.2 22.0 116.2 14 0.306

CANNA 147.1 30 2.25 7 2.25 119.3 27.8 147.1 15.75 0.243

CROCUS 181.6 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

CROCUS 297 36 2.8 19 2.25 221.7 75.5 297.2 22.45 0.131

CANNA 288 30 3.15 7 3.15 233.8 54.6 288.3 22.05 0.124

CROCUS 288 30 3.15 7 3.15 233.8 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 2.65 507.8 104.8 612.6 32.03 0.057

CROCUS 865 66 3.72 19 3.15 717.3 148.1 865.4 38.01 0.040

(c) to DIN 48204

No. Wire Sectional Overall RDCStandard Designation of Al diameter area diameter at 20°C

Strands (mm) (mm2) (mm) (Ohm/km)

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

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

BS 3242 Upas 37 3.53 362.1 24.7 0.092

BS 3242 Yew 37 4.06 479.0 28.4 0.069

BS 3242 Totara 37 4.14 498.1 29.0 0.067

BS 3242 Rubus 61 3.5 586.9 31.5 0.057

BS 3242 Araucaria 61 4.14 821.1 28.4 0.040

No. Wire Sectional Overall RDCStandard Designation of Al diameter area diameter at 20°C


ASTM B-397 Kench 7 2.67 39.2 8.0 0.838

ASTM B-397 Kibe 7 3.37 62.4 10.1 0.526

ASTM B-397 Kayak 7 3.78 78.6 11.4 0.418

ASTM B-397 Kopeck 7 4.25 99.3 12.8 0.331

ASTM B-397 Kittle 7 4.77 125.1 14.3 0.262

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

ASTM B-397 Remex 19 4.36 283.7 21.8 0.116

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

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

(a) ASTM

(b) BS

Table 5.15: Overhead line conductor data - aluminium alloy.

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No. of Wire Sectional Overall RDCStandard Designation Al diameter area diameter at 20°C


NF C34-125 ASTER 22 7 2 22.0 6.0 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

No. of Wire Sectional Overall RDCStandard Designation Al diameter area diameter at 20°C


DIN 48201 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

No. Wire Sectional Overall RDCStandard Design. of Al diameter area diameter at 20°C


CSA C49.1-M87 10 7 1.45 11.5 4.3 2.863

CSA C49.1-M87 16 7 1.83 18.4 5.5 1.788

CSA C49.1-M87 25 7 2.29 28.8 6.9 1.142

CSA C49.1-M87 40 7 2.89 46.0 8.7 0.716

CSA C49.1-M87 63 7 3.63 72.5 10.9 0.454

CSA C49.1-M87 100 19 2.78 115.1 13.9 0.287

CSA C49.1-M87 125 19 3.1 143.9 15.5 0.230

CSA C49.1-M87 160 19 3.51 184.2 17.6 0.180

CSA C49.1-M87 200 19 3.93 230.2 19.6 0.144

CSA C49.1-M87 250 19 4.39 287.7 22.0 0.115

CSA C49.1-M87 315 37 3.53 362.1 24.7 0.092

CSA C49.1-M87 400 37 3.98 460.4 27.9 0.072

CSA C49.1-M87 450 37 4.22 517.9 29.6 0.064

CSA C49.1-M87 500 37 4.45 575.5 31.2 0.058

CSA C49.1-M87 560 37 4.71 644.5 33.0 0.051

CSA C49.1-M87 630 61 3.89 725.0 35.0 0.046

CSA C49.1-M87 710 61 4.13 817.2 37.2 0.041

CSA C49.1-M87 800 61 4.38 920.8 39.5 0.036

CSA C49.1-M87 900 61 4.65 1035.8 41.9 0.032

CSA C49.1-M87 1000 91 4.01 1150.9 44.1 0.029

CSA C49.1-M87 1120 91 4.25 1289.1 46.7 0.026

CSA C49.1-M87 1250 91 4.49 1438.7 49.4 0.023

CSA C49.1-M87 1400 91 4.75 1611.3 52.2 0.021

CSA C49.1-M87 1500 91 4.91 1726.4 54.1 0.019

(c) CSA

(d) DIN

(e) NF

Table 5.15 (cont): Overhead line conductor data - aluminium alloy.

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Standard Designationdiameter (mm) (mm2)

Alloy Steel Alloy Steel

NF C34-125 PHLOX 116.2 18 2 19 2 56.5 59.7 116.2 14 0.591

NF C34-125 PHLOX 147.1 18 2.25 19 2.25 71.6 75.5 147.1 15.75 0.467

NF C34-125 PASTEL 147.1 30 2.25 7 2.25 119.3 27.8 147.1 15.75 0.279

NF C34-125 PHLOX 181.6 18 2.5 19 2.5 88.4 93.3 181.6 17.5 0.378

NF C34-125 PASTEL 181.6 30 2.5 7 2.5 147.3 34.4 181.6 17.5 0.226

NF C34-125 PHLOX 228 18 2.8 19 2.8 110.8 117.0 227.8 19.6 0.300

NF C34-125 PASTEL 228 30 2.8 7 2.8 184.7 43.1 227.8 19.6 0.180

NF C34-125 PHLOX 288 18 3.15 19 3.15 140.3 148.1 288.3 22.05 0.238

NF C34-125 PASTEL 288 30 3.15 7 3.15 233.8 54.6 288.3 22.05 0.142

NF C34-125 PASTEL 299 42 2.5 19 2.5 206.2 93.3 299.4 22.45 0.162

NF C34-125 PHLOX 376 24 2.8 37 2.8 147.8 227.8 375.6 26.4 0.226

Stranding and wire Sectional area



DIN 48206 70/12 26 1.85 7 1.44 69.9 11.4 81.3 11.7 0.479

DIN 48206 95/15 26 2.15 7 1.67 94.4 15.3 109.7 13.6 0.355

DIN 48206 125/30 30 2.33 7 2.33 127.9 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 2.33 183.8 29.8 213.6 19 0.182

DIN 48206 210/50 30 3 7 3 212.1 49.5 261.5 21 0.158

DIN 48206 230/30 24 3.5 7 2.33 230.9 29.8 260.8 21 0.145

DIN 48206 265/35 24 3.74 7 2.49 263.7 34.1 297.7 22.4 0.127

DIN 48206 305/40 54 2.68 7 2.68 304.6 39.5 344.1 24.1 0.110

DIN 48206 380/50 54 3 7 3 381.7 49.5 431.2 27 0.088

DIN 48206 450/40 48 3.45 7 2.68 448.7 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

(b) DIN

(c) NF

Table 5.16: Overhead line conductor data – aluminiumalloy conductors, steel re-inforced (AACSR)

Stranding and wire Sectional area



ASTM B711 26 2.62 7 2.04 140.2 22.9 163.1 7.08 0.240

ASTM B711 26 2.97 7 2.31 180.1 29.3 209.5 11.08 0.187

ASTM B711 30 2.76 7 2.76 179.5 41.9 221.4 12.08 0.188

ASTM B711 26 3.13 7 2.43 200.1 32.5 232.5 13.08 0.168

ASTM B711 30 3.08 7 3.08 223.5 52.2 275.7 16.08 0.151

ASTM B711 26 3.5 7 2.72 250.1 40.7 290.8 17.08 0.135

ASTM B711 26 3.7 7 2.88 279.6 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 2.33 354.7 81.0 435.7 24.08 0.095

ASTM B711 30 4.12 19 2.47 399.9 91.0 491.0 26.08 0.084

ASTM B711 54 3.26 19 1.98 450.7 58.5 509.2 27.08 0.075

ASTM B711 54 3.63 19 2.18 558.9 70.9 629.8 29.08 0.060

ASTM B711 54 3.85 19 2.31 628.6 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 2.47 1119.9 91.0 1210.9 35.08 0.030

ASTM B711 84 4.35 19 2.61 1248.4 101.7 1350.0 36.08 0.027

(a) ASTM

Totalarea

(mm2)

Approximateoverall diameter

(mm)

RDC at 20 °C(ohm/km)

Totalarea

(mm2)


(mm)


Totalarea

(mm2)


(mm)


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XAC at 50 Hz XAC at 50 Hz and shunt capacitance

66kV 132kV

Sectional RDC RAC at 3.3kV 6.6kV 11kV 22kV 33kV Flat Double Triangle Double Double Flatarea of (20°C) 50Hz circuit vertical vertical triangle circuit

aluminium @ 20°C

X C X C X C X C X C X C X C

mm2 Ω/km Ω/km Ω/km Ω/km Ω/km Ω/km Ω/km nF/km Ω/km nF/km Ω/km nF/km Ω/km nF/km Ω/km nF/km Ω/km nF/km Ω/km nF/km

13.3 2.1586 2.159 0.395 0.409 0.420 0.434 0.445 8.7 0.503 7.6 0.513 7.4 0.520 7.3 0.541 7.0 0.528 7.2 0.556 6.8

15.3 1.8771 1.877 0.391 0.405 0.415 0.429 0.441 8.8 0.499 7.7 0.508 7.5 0.515 7.4 0.537 7.1 0.523 7.3 0.552 6.9

21.2 1.3557 1.356 0.381 0.395 0.405 0.419 0.430 9.0 0.488 7.8 0.498 7.7 0.505 7.6 0.527 7.2 0.513 7.4 0.542 7.0

23.9 1.2013 1.201 0.376 0.390 0.401 0.415 0.426 9.1 0.484 7.9 0.494 7.8 0.501 7.6 0.522 7.3 0.509 7.5 0.537 7.1

26.2 1.0930 1.093 0.374 0.388 0.398 0.412 0.424 9.2 0.482 8.0 0.491 7.8 0.498 7.7 0.520 7.3 0.506 7.5 0.535 7.1

28.3 1.0246 1.025 0.352 0.366 0.377 0.391 0.402 9.4 0.460 8.2 0.470 8.0 0.477 7.8 0.498 7.5 0.485 7.7 0.513 7.3

33.6 0.8535 0.854 0.366 0.380 0.390 0.404 0.416 9.4 0.474 8.1 0.484 7.9 0.491 7.8 0.512 7.5 0.499 7.7 0.527 7.2

37.7 0.7647 0.765 0.327 0.341 0.351 0.365 0.376 9.7 0.435 8.4 0.444 8.2 0.451 8.1 0.473 7.7 0.459 7.9 0.488 7.4

42.4 0.6768 0.677 0.359 0.373 0.383 0.397 0.409 9.6 0.467 8.3 0.476 8.1 0.483 7.9 0.505 7.6 0.491 7.8 0.520 7.3

44.0 0.6516 0.652 0.320 0.334 0.344 0.358 0.369 9.9 0.427 8.5 0.437 8.3 0.444 8.2 0.465 7.8 0.452 8.0 0.481 7.5

47.7 0.6042 0.604 0.319 0.333 0.344 0.358 0.369 9.9 0.427 8.5 0.437 8.3 0.444 8.2 0.465 7.8 0.452 8.1 0.480 7.6

51.2 0.5634 0.564 0.317 0.331 0.341 0.355 0.367 10.0 0.425 8.6 0.434 8.4 0.441 8.2 0.463 7.9 0.449 8.1 0.478 7.6

58.9 0.4894 0.490 0.313 0.327 0.337 0.351 0.362 10.1 0.421 8.7 0.430 8.5 0.437 8.3 0.459 7.9 0.445 8.2 0.474 7.7

63.1 0.4545 0.455 0.346 0.360 0.371 0.385 0.396 9.9 0.454 8.5 0.464 8.3 0.471 8.2 0.492 7.8 0.479 8.0 0.507 7.5

67.4 0.4255 0.426 0.344 0.358 0.369 0.383 0.394 10.0 0.452 8.5 0.462 8.3 0.469 8.2 0.490 7.8 0.477 8.1 0.505 7.6

73.4 0.3930 0.393 0.306 0.320 0.330 0.344 0.356 10.3 0.414 8.8 0.423 8.6 0.430 8.5 0.452 8.1 0.438 8.3 0.467 7.8

79.2 0.3622 0.362 0.339 0.353 0.363 0.377 0.389 10.1 0.447 8.7 0.457 8.4 0.464 8.3 0.485 7.9 0.472 8.2 0.500 7.6

85.0 0.3374 0.338 0.337 0.351 0.361 0.375 0.387 10.2 0.445 8.7 0.454 8.5 0.461 8.4 0.483 7.9 0.469 8.2 0.498 7.7

94.4 0.3054 0.306 0.302 0.316 0.327 0.341 0.352 10.3 0.410 8.8 0.420 8.6 0.427 8.4 0.448 8.0 0.435 8.3 0.463 7.8

105.0 0.2733 0.274 0.330 0.344 0.355 0.369 0.380 10.4 0.438 8.8 0.448 8.6 0.455 8.5 0.476 8.1 0.463 8.3 0.491 7.8

121.6 0.2371 0.237 0.294 0.308 0.318 0.332 0.344 10.6 0.402 9.0 0.412 8.8 0.419 8.6 0.440 8.2 0.427 8.4 0.455 7.9

127.9 0.2254 0.226 0.290 0.304 0.314 0.328 0.340 10.7 0.398 9.0 0.407 8.8 0.414 8.7 0.436 8.2 0.422 8.5 0.451 8.0

131.2 0.2197 0.220 0.289 0.303 0.313 0.327 0.339 10.7 0.397 9.1 0.407 8.8 0.414 8.7 0.435 8.3 0.421 8.5 0.450 8.0

135.2 0.2133 0.214 0.297 0.311 0.322 0.336 0.347 10.5 0.405 9.0 0.415 8.8 0.422 8.6 0.443 8.2 0.430 8.4 0.458 7.9

148.9 0.1937 0.194 0.288 0.302 0.312 0.326 0.338 10.8 0.396 9.1 0.406 8.9 0.413 8.7 0.434 8.3 0.420 8.6 0.449 8.0

158.7 0.1814 0.182 0.292 0.306 0.316 0.330 0.342 10.7 0.400 9.1 0.410 8.9 0.417 8.7 0.438 8.3 0.425 8.5 0.453 8.0

170.5 0.1691 0.170 0.290 0.304 0.314 0.328 0.340 10.8 0.398 9.1 0.407 8.9 0.414 8.8 0.436 8.3 0.422 8.6 0.451 8.0

184.2 0.1565 0.157 0.287 0.302 0.312 0.326 0.337 10.9 0.395 9.2 0.405 9.0 0.412 8.8 0.433 8.4 0.420 8.6 0.449 8.1

201.4 0.1438 0.144 0.280 0.294 0.304 0.318 0.330 11.0 0.388 9.3 0.398 9.1 0.405 8.9 0.426 8.5 0.412 8.8 0.441 8.2

210.6 0.1366 0.137 0.283 0.297 0.308 0.322 0.333 11.0 0.391 9.3 0.401 9.1 0.408 8.9 0.429 8.4 0.416 8.7 0.444 8.1

221.7 0.1307 0.131 0.274 0.288 0.298 0.312 0.323 11.3 0.381 9.5 0.391 9.3 0.398 9.1 0.419 8.6 0.406 8.9 0.435 8.3

230.9 0.1249 0.126 0.276 0.290 0.300 0.314 0.326 11.2 0.384 9.4 0.393 9.2 0.400 9.0 0.422 8.6 0.408 8.9 0.437 8.3

241.7 0.1193 0.120 0.279 0.293 0.303 0.317 0.329 11.2 0.387 9.4 0.396 9.2 0.403 9.0 0.425 8.5 0.411 8.8 0.440 8.2

263.7 0.1093 0.110 0.272 0.286 0.296 0.310 0.321 11.3 0.380 9.5 0.389 9.3 0.396 9.1 0.418 8.6 0.404 8.9 0.433 8.3

282.0 0.1022 0.103 0.274 0.288 0.298 0.312 0.324 11.3 0.382 9.5 0.392 9.3 0.399 9.1 0.420 8.6 0.406 8.9 0.435 8.3

306.6 0.0945 0.095 0.267 0.281 0.291 0.305 0.317 11.5 0.375 9.7 0.384 9.4 0.391 9.2 0.413 8.7 0.399 9.1 0.428 8.4

322.3 0.0895 0.090 0.270 0.284 0.294 0.308 0.320 11.5 0.378 9.6 0.387 9.4 0.394 9.2 0.416 8.7 0.402 9.0 0.431 8.4

339.3 0.085 0.086 0.265 0.279 0.289 0.303 0.315 11.6 0.373 9.7 0.383 9.5 0.390 9.3 0.411 8.8 0.398 9.1 0.426 8.5

362.6 0.0799 0.081 0.262 0.276 0.286 0.300 0.311 11.7 0.369 9.8 0.379 9.6 0.386 9.4 0.408 8.9 0.394 9.2 0.423 8.5

386.0 0.0747 0.076 0.261 0.275 0.285 0.299 0.311 11.8 0.369 9.8 0.379 9.6 0.386 9.4 0.407 8.9 0.393 9.2 0.422 8.6

402.8 0.0719 0.073 0.261 0.275 0.285 0.299 0.310 11.8 0.368 9.9 0.378 9.6 0.385 9.4 0.407 8.9 0.393 9.2 0.422 8.6

428.9 0.0671 0.068 0.267 0.281 0.291 0.305 0.316 11.5 0.374 9.7 0.384 9.4 0.391 9.2 0.413 8.7 0.399 9.0 0.428 8.4

448.7 0.0642 0.066 0.257 0.271 0.281 0.295 0.306 11.9 0.364 10.0 0.374 9.7 0.381 9.5 0.402 9.0 0.389 9.3 0.418 8.7

456.1 0.0635 0.065 0.257 0.271 0.281 0.295 0.307 12.0 0.365 10.0 0.374 9.7 0.381 9.5 0.403 9.0 0.389 9.3 0.418 8.7

483.4 0.0599 0.061 0.255 0.269 0.279 0.293 0.305 12.0 0.363 10.0 0.372 9.8 0.379 9.6 0.401 9.0 0.387 9.4 0.416 8.7

494.4 0.0583 0.060 0.254 0.268 0.279 0.293 0.304 12.1 0.362 10.0 0.372 9.8 0.379 9.6 0.400 9.0 0.387 9.4 0.415 8.7

510.5 0.0565 0.058 0.252 0.266 0.277 0.291 0.302 12.1 0.360 10.1 0.370 9.8 0.377 9.6 0.398 9.1 0.385 9.4 0.413 8.7

523.7 0.0553 0.057 0.252 0.266 0.277 0.291 0.302 12.1 0.360 10.1 0.370 9.8 0.377 9.6 0.398 9.1 0.385 9.4 0.413 8.7

Table 5.17: Feeder circuits data - overhead lines

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XAC at 50 Hz XAC at 50 Hz and shunt capacitance

66kV 132kV

Sectional RDC RAC at 3.3kV 6.6kV 11kV 22kV 33kV Flat Double Triangle Double Double Flatarea of (20°C) 50Hz circuit vertical vertical triangle circuit

aluminium @ 20°C

X C X C X C X C X C X C X C

mm2 Ω/km Ω/km Ω/km Ω/km Ω/km Ω/km Ω/km nF/km Ω/km nF/km Ω/km nF/km Ω/km nF/km Ω/km nF/km Ω/km nF/km Ω/km nF/km

13.3 2.1586 2.159 0.474 0.491 0.503 0.520 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

15.3 1.8771 1.877 0.469 0.486 0.498 0.515 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

21.2 1.3557 1.356 0.457 0.474 0.486 0.503 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

23.9 1.2013 1.201 0.452 0.469 0.481 0.498 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

26.2 1.0930 1.093 0.449 0.466 0.478 0.495 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

28.3 1.0246 1.025 0.423 0.440 0.452 0.469 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

33.6 0.8535 0.854 0.439 0.456 0.468 0.485 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

37.7 0.7647 0.765 0.392 0.409 0.421 0.438 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

42.4 0.6768 0.677 0.431 0.447 0.460 0.477 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

44.0 0.6516 0.652 0.384 0.400 0.413 0.429 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

47.7 0.6042 0.604 0.383 0.400 0.412 0.429 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

51.2 0.5634 0.564 0.380 0.397 0.409 0.426 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

58.9 0.4894 0.490 0.375 0.392 0.404 0.421 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

63.1 0.4545 0.455 0.416 0.432 0.445 0.462 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

67.4 0.4255 0.426 0.413 0.430 0.442 0.459 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

73.4 0.3930 0.393 0.367 0.384 0.396 0.413 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

79.2 0.3622 0.362 0.407 0.424 0.436 0.453 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

85.0 0.3374 0.338 0.404 0.421 0.433 0.450 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

94.4 0.3054 0.306 0.363 0.380 0.392 0.409 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

105.0 0.2733 0.274 0.396 0.413 0.426 0.442 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

121.6 0.2371 0.238 0.353 0.370 0.382 0.399 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

127.9 0.2254 0.226 0.348 0.365 0.377 0.394 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

131.2 0.2197 0.220 0.347 0.364 0.376 0.393 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

135.2 0.2133 0.214 0.357 0.374 0.386 0.403 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

148.9 0.1937 0.194 0.346 0.362 0.375 0.392 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

158.7 0.1814 0.182 0.351 0.367 0.380 0.397 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

170.5 0.1691 0.170 0.348 0.365 0.377 0.394 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

184.2 0.1565 0.157 0.345 0.362 0.374 0.391 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

201.4 0.1438 0.145 0.336 0.353 0.365 0.382 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

210.6 0.1366 0.137 0.340 0.357 0.369 0.386 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

221.7 0.1307 0.132 0.328 0.345 0.357 0.374 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

230.9 0.1249 0.126 0.331 0.348 0.360 0.377 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

241.7 0.1193 0.120 0.335 0.351 0.364 0.381 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

263.7 0.1093 0.110 0.326 0.343 0.355 0.372 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

282.0 0.1022 0.103 0.329 0.346 0.358 0.375 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

306.6 0.0945 0.096 0.320 0.337 0.349 0.366 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

322.3 0.0895 0.091 0.324 0.341 0.353 0.370 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

339.3 0.0850 0.086 0.318 0.335 0.347 0.364 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

362.6 0.0799 0.081 0.314 0.331 0.343 0.360 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

386.0 0.0747 0.076 0.313 0.330 0.342 0.359 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

402.8 0.0719 0.074 0.313 0.330 0.342 0.359 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

428.9 0.0671 0.069 0.320 0.337 0.349 0.366 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

448.7 0.0642 0.066 0.308 0.325 0.337 0.354 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

456.1 0.0635 0.065 0.305 0.322 0.334 0.351 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

483.4 0.0599 0.062 0.306 0.323 0.335 0.352 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

494.4 0.0583 0.060 0.305 0.322 0.334 0.351 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

510.5 0.0565 0.059 0.303 0.320 0.332 0.349 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

523.7 0.0553 0.057 0.303 0.320 0.332 0.349 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 5.17 (cont): Feeder circuits data - overhead lines

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Conductor size mm2

25 35 50 70 95 120 150 185 240 300 400 *500 *630 *800 *1000 *1200 *1600

Series Resistance R (Ω/km) 0.927 0.669 0.494 0.342 0.247 0.196 0.158 0.127 0.098 0.08 0.064 0.051 0.042

3.3kV Series Reactance X (Ω/km) 0.097 0.092 0.089 0.083 0.08 0.078 0.076 0.075 0.073 0.072 0.071 0.088 0.086

Susceptance ωC (mS/km) 0.059 0.067 0.079 0.09 0.104 0.111 0.122 0.133 0.146 0.16 0.179 0.19 0.202


6.6kV Series Reactance X (Ω/km) 0.121 0.113 0.108 0.102 0.096 0.093 0.091 0.088 0.086 0.085 0.083 0.088 0.086



11kV Series Reactance X (Ω/km) 0.128 0.119 0.114 0.107 0.101 0.098 0.095 0.092 0.089 0.087 0.084 0.089 0.086


Series Resistance R (Ω/km) - 0.669 0.494 0.348 0.247 0.196 0.158 0.127 0.098 0.08 0.064 0.051 0.042

22kV Series Reactance X (Ω/km) - 0.136 0.129 0.121 0.114 0.11 0.107 0.103 0.1 0.094 0.091 0.096 0.093

Susceptance ωC (mS/km) 0.053 0.057 0.065 0.072 0.078 0.084 0.091 0.1 0.109 0.12 0.128 0.141

Series Resistance R (Ω/km) - 0.669 0.494 0.348 0.247 0.196 0.158 0.127 0.098 0.08 0.064 0.051 0.042

33kV Series Reactance X (Ω/km) - 0.15 0.143 0.134 0.127 0.122 0.118 0.114 0.109 0.105 0.102 0.103 0.1

Susceptance ωC (mS/km) 0.042 0.045 0.05 0.055 0.059 0.063 0.068 0.075 0.081 0.089 0.094 0.103

Series Resistance R (Ω/km) - - - - - - - - - - - 0.0387 0.031 0.0254 0.0215

66kV* Series Reactance X (Ω/km) - - - - - - - - - - - 0.117 0.113 0.109 0.102

Susceptance ωC (mS/km) 0.079 0.082 0.088 0.11

Series Resistance R (Ω/km) - - - - - - - - - - - 0.0387 0.031 0.0254 0.0215

145kV* Series Reactance X (Ω/km) - - - - - - - - - - - 0.13 0.125 0.12 0.115

Susceptance ωC (mS/km) 0.053 0.06 0.063 0.072

Series Resistance R (Ω/km) 0.0487 0.0387 0.0310 0.0254 0.0215 0.0161 0.0126

245kV* Series Reactance X (Ω/km) 0.145 0.137 0.134 0.128 0.123 0.119 0.113

Susceptance ωC (mS/km) 0.044 0.047 0.05 0.057 0.057 0.063 0.072

Series Resistance R (Ω/km) 0.0310 0.0254 0.0215 0.0161 0.0126

420kV* Series Reactance X (Ω/km) 0.172 0.162 0.156 0.151 0.144

Susceptance ωC (mS/km) 0.04 0.047 0.05 0.057 0.063

For aluminium conductors of the same cross-section, the resistance increases by 60-65 percent, the series reactance and shunt capacitance is virtually unaltered.* - single core cables in trefoil.Different values apply if laid in spaced flat formation.Series Resistance - a.c. resistance @ 90°C. Series reactance - equivalent star reactance.Data for 245kV and 420kV cables may vary significantly from that given, dependent on manufacturer and construction.

Table 5.18: Characteristics of polyethyleneinsulated cables (XLPE)

Conductor Size (mm2)

10 16 25 35 50 70 95 120 150 185 240 300 400 *500 *630 *800 *1000

Series Resistance R (Ω/km) 206 1303 825.5 595 439.9 304.9 220.4 174.5 142.3 113.9 87.6 70.8 56.7 45.5 37.1 31.2 27.2

3.3kV Series Reactance X (Ω/km) 87.7 83.6 76.7 74.8 72.5 70.2 67.5 66.6 65.7 64.7 63.8 62.9 62.4 73.5 72.1 71.2 69.8

Susceptance ωC (mS/km)

Series Resistance R (Ω/km) 514.2 326 206.4 148.8 110 76.2 55.1 43.6 35.6 28.5 21.9 17.6 14.1 11.3 9.3 7.8 6.7

6.6kV Series Reactance X (Ω/km) 26.2 24.3 22 21.2 20.4 19.6 18.7 18.3 17.9 17.6 17.1 16.9 16.5 18.8 18.4 18 17.8


Series Resistance R (Ω/km) - 111 0.87 0.63 0.46 0.32 0.23 0.184 0.15 0.12 0.092 0.074 0.059 0.048 0.039 0.033 0.028

11kV Series Reactance X (Ω/km) - 9.26 0.107 0.1 0.096 0.091 0.087 0.085 0.083 0.081 0.079 0.077 0.076 0.085 0.083 0.081 0.08


Series Resistance R (Ω/km) - - 17.69 12.75 9.42 6.53 4.71 3.74 3.04 2.44 1.87 1.51 1.21 0.96 0.79 0.66 0.57

22kV Series Reactance X (Ω/km) - - 2.89 2.71 2.6 2.46 2.36 2.25 2.19 2.11 2.04 1.97 1.92 1.9 1.84 1.8 1.76


Series Resistance R (Ω/km) - - - - 4.19 2.9 2.09 0.181 0.147 0.118 0.09 0.073 0.058 0.046 0.038 0.031 0.027

33kV Series Reactance X (Ω/km) - - - - 1.16 1.09 1.03 0.107 0.103 0.101 0.097 0.094 0.09 0.098 0.097 0.092 0.089

Susceptance ωC (mS/km) 0.104 0.116 0.124 0.194 0.151 0.281 0.179 0.198 0.22 0.245

Cables are of the solid type, 3 core except for those marked *. Impedances at 50Hz frequency

Table 5.19: Characteristics of paper insulated cables

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5.25 REFERENCES

5.1 Physical significance of sub-subtransientquantities in dynamic behaviour of synchronousmachines. I.M. Canay. Proc. IEE, Vol. 135, Pt. B,November 1988.

5.2 IEC 60034-4. Methods for determiningsynchronous machine quantities from tests.

5.3 IEEE Standards 115/115A. IEEE Test Proceduresfor Synchronous Machines.

5.4 Power System Analysis. J.R.Mortlock andM.W.Humphrey Davies (Chapman & Hall,London).

Conductor size (mm2)3.3kV

R Ω/km X Ω/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 0.084

3 core Copper conductors, 50Hz values. * - single core cables in trefoilTable 5.20: 3.3 kV PVC insulated cables

Table 5.21: OHL capabilities

Voltage LevelSurge Impedance Voltage Drop Indicative Thermal

Cross Sectional Conductors Loading Loading Loading

Un kV Um kV Area mm2 per phase MVA MWkm MV A

30 1 0.3 11 2.9 151

50 1 0.3 17 3.9 204

11 12 90 1 0.4 23 5.1 268

120 1 0.5 27 6.2 328

150 1 0.5 30 7.3 383

1 1.2 44 5.8 151

50 1 1.2 66 7.8 204

24 30 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

33 3690 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

66 72.5150 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

132 145 250 2 58 7160 230 1004

400 1 56 6274 160 698

400 2 73 9057 320 1395

400 1 130 15600 247 648

220 245 400 2 184 22062 494 1296

400 4 260 31200 988 2592

400 2 410 58100 850 1296

380 420400 4 582 82200 1700 2590

550 2 482 68200 1085 1650

550 3 540 81200 1630 2475

Chapt 5-46-77 21/06/02 9:53 Page 77

Introduction 6.1

Electromagnetic voltagetransformers 6.2

Capacitor voltagetransformers 6.3

Current transformers 6.4

Novel instrumenttransformers 6.5

• 6 • C u r r e n t a n d V o l t a g eT r a n s f o r m e r s

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6.1 INTRODUCTION

Whenever the values of voltage or current in a powercircuit are too high to permit convenient directconnection of measuring instruments or relays, couplingis made through transformers. Such 'measuring'transformers are required to produce a scaled downreplica of the input quantity to the accuracy expectedfor the particular measurement; this is made possible bythe high efficiency of the transformer. The performanceof measuring transformers during and following largeinstantaneous changes in the input quantity isimportant, in that this quantity may depart from thesinusoidal waveform. The deviation may consist of astep change in magnitude, or a transient componentthat persists for an appreciable period, or both. Theresulting effect on instrument performance is usuallynegligible, although for precision metering a persistentchange in the accuracy of the transformer may besignificant.

However, many protection systems are required tooperate during the period of transient disturbance in theoutput of the measuring transformers that follows asystem fault. The errors in transformer output mayabnormally delay the operation of the protection, orcause unnecessary operations. The functioning of suchtransformers must, therefore, be examined analytically.

It can be shown that the transformer can be representedby the equivalent circuit of Figure 6.1, where allquantities are referred to the secondary side.

• 6 • Cur rent and VoltageTransfor me rs


BurdenZe

Rp Lp Rs Ls1/1

Figure 6.1: Equivalent circuit of transformer

Chap6-78-97 21/06/02 9:20 Page 79

When the transformer is not 1/1 ratio, this condition canbe represented by energising the equivalent circuit with anideal transformer of the given ratio but having no losses.

6.1.1 Measuring Transformers

Voltage and current transformers for low primary voltageor current ratings are not readily distinguishable; forhigher ratings, dissimilarities of construction are usual.Nevertheless the differences between these devices lieprincipally in the way they are connected into the powercircuit. Voltage transformers are much like small powertransformers, differing only in details of design thatcontrol ratio accuracy over the specified range of output.Current transformers have their primary windingsconnected in series with the power circuit, and so also inseries with the system impedance. The response of thetransformer is radically different in these two modes ofoperation.

6.2 ELECTROMAGNETIC VOLTAGE TRANSFORMERS

In the shunt mode, the system voltage is applied acrossthe input terminals of the equivalent circuit of Figure 6.1.The vector diagram for this circuit is shown in Figure 6.2.

The secondary output voltage Vs is required to be anaccurate scaled replica of the input voltage Vp over aspecified range of output. To this end, the winding

voltage drops are made small, and the normal fluxdensity in the core is designed to be well below thesaturation density, in order that the exciting current maybe low and the exciting impedance substantiallyconstant with a variation of applied voltage over thedesired operating range including some degree ofovervoltage. These limitations in design result in a VT fora given burden being much larger than a typical powertransformer of similar rating. The exciting current, inconsequence, will not be as small, relative to the ratedburden, as it would be for a typical power transformer.

6.2.1 Errors

The ratio and phase errors of the transformer can becalculated using the vector diagram of Figure 6.2.

The ratio error is defined as:

where:Kn is the nominal ratio

Vp is the primary voltage

Vs is the secondary voltage

If the error is positive, the secondary voltage exceeds thenominal value. The turns ratio of the transformer neednot be equal to the nominal ratio; a small turnscompensation will usually be employed, so that the errorwill be positive for low burdens and negative for highburdens.

The phase error is the phase difference between thereversed secondary and the primary voltage vectors. It ispositive when the reversed secondary voltage leads theprimary vector. Requirements in this respect are set outin IEC 60044-2. All voltage transformers are required tocomply with one of the classes in Table 6.1.

For protection purposes, accuracy of voltagemeasurement may be important during fault conditions,as the system voltage might be reduced by the fault to alow value. Voltage transformers for such types of servicemust comply with the extended range of requirementsset out in Table 6.2.

( )%

K VVn s

p

× 100

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0.8 - 1.2 x rated voltage0.25 - 1.0 x rated burden at 0.8pf

voltage ratio error phase displacement(%) (minutes)

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

Accuracyclass

VppVpV

-VsVsV

EpE

IeIeI

IIeIeIIcIcI

ImImI

IsIsI

IsIsI XsXs sXsX

IsIsI Rs

VsVsV

Es

Es

ΦIe Ie I = exciting currentIm Im IIIθ = phase angle error

IIIpIpIps s IIII = secondary currentpII = primary current

pIpIpI L

IpIpI XpXp pXpX

IpIpI RpR

θ

Φ

Figure 6.2: Vector diagram for voltage transformer

Chap6-78-97 21/06/02 9:20 Page 80

6.2.2 Voltage Factors

The quantity Vf in Table 6.2 is an upper limit of operatingvoltage, expressed in per unit of rated voltage. This isimportant for correct relay operation and operationunder unbalanced fault conditions on unearthed orimpedance earthed systems, resulting in a rise in thevoltage on the healthy phases.

Voltage factors, with the permissible duration of themaximum voltage, are given in Table 6.3.

6.2.3 Secondary Leads

Voltage transformers are designed to maintain thespecified accuracy in voltage output at their secondaryterminals. To maintain this if long secondary leads arerequired, a distribution box can be fitted close to the VTto supply relay and metering burdens over separateleads. If necessary, allowance can be made for theresistance of the leads to individual burdens when theparticular equipment is calibrated.

6.2.4 Protection of Voltage Transformers

Voltage Transformers can be protected by H.R.C. fuses onthe primary side for voltages up to 66kV. Fuses do notusually have a sufficient interrupting capacity for usewith higher voltages. Practice varies, and in some casesprotection on the primary is omitted.

The secondary of a Voltage Transformer should always beprotected 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 circuitwiring will produce a current of many times the ratedoutput and cause excessive heating. Even where primaryfuses can be fitted, these will usually not clear asecondary side short circuit because of the low value ofprimary current and the minimum practicable fuse rating.

6.2.5 Construction

The construction of a voltage transformer takes intoaccount the following factors:

a. output – seldom more than 200-300VA. Cooling israrely a problem

b. insulation – designed for the system impulsevoltage level. Insulation volume is often largerthan the winding volume

c. mechanical design – not usually necessary towithstand short-circuit currents. Must be small tofit the space available within switchgear

Three-phase units are common up to 36kV but for highervoltages single-phase units are usual. Voltagetransformers for medium voltage circuits will have drytype insulation, but for high and extra high voltagesystems, oil immersed units are general. Resinencapsulated designs are in use on systems up to 33kV.Figure 6.3 shows a typical voltage transformer.

6.2.6 Residually Connected Voltage Transformers

The three voltages of a balanced system summate tozero, but this is not so when the system is subject to asingle-phase earth fault. The residual voltage of asystem is measured by connecting the secondarywindings of a VT in 'broken delta' as shown in Figure 6.4.

The output of the secondary windings connected inbroken delta is zero when balanced sinusoidal voltagesare applied, but under conditions of unbalance a residual

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0.25 - 1.0 x rated burden at 0.8pf0.05 - Vf x rated primary voltage

voltage ratio error phase displacement(%) (%)

3P +/- 3.0 +/- 120

6P +/- 6.0 +/- 240

Table 6.2: Additional limits for protection voltage transformers.

Accuracyclass

Voltage factor Time Primary winding connection/systemVf rating earthing conditions

Between lines in any network.1.2 continuous Between transformer star point and

earth in any network

1.2 continuous Between line and earth in an 1.5 30 s effectively earthed network

1.2 continuous Between line and earth in

1.9 30 sa non-effectively earthed neutral system

with automatic earth fault tripping

1.2 continuous Between line and earth in an isolatedneutral system without automatic earth fault

1.9 8 hours tripping, or in a resonant earthed systemwithout automatic earth fault tripping

Table 6.3: Voltage transformers: Permissible durationof maximum voltage

Figure 6.3: Typical voltage transformer

Chap6-78-97 21/06/02 9:21 Page 81

voltage equal to three times the zero sequence voltage ofthe system will be developed.

In order to measure this component, it is necessary for azero sequence flux to be set up in the VT, and for this tobe possible there must be a return path for the resultantsummated flux. The VT core must have one or moreunwound limbs linking the yokes in addition to the limbscarrying windings. Usually the core is madesymmetrically, with five limbs, the two outermost onesbeing unwound. Alternatively, three single-phase unitscan be used. It is equally necessary for the primarywinding neutral to be earthed, for without an earth, zerosequence exciting current cannot flow.

A VT should be rated to have an appropriate voltagefactor as described in Section 6.2.2 and Table 6.3, tocater for the voltage rise on healthy phases during earthfaults.

Voltage transformers are often provided with a normalstar-connected secondary winding and a broken-deltaconnected ‘tertiary’ winding. Alternatively the residualvoltage can be extracted by using a star/broken-deltaconnected group of auxiliary voltage transformersenergised from the secondary winding of the main unit,providing the main voltage transformer fulfils all therequirements for handling a zero sequence voltage aspreviously described. The auxiliary VT must also besuitable for the appropriate voltage factor. It should benoted that third harmonics in the primary voltage wave,which are of zero sequence, summate in the broken-delta winding.

6.2.7 Transient Performance

Transient errors cause few difficulties in the use ofconventional voltage transformers although some dooccur. Errors are generally limited to short time periodsfollowing the sudden application or removal of voltagefrom the VT primary.

If a voltage is suddenly applied, an inrush transient willoccur, as with power transformers. The effect will,however, be less severe than for power transformersbecause of the lower flux density for which the VT isdesigned. If the VT is rated to have a fairly high voltagefactor, little inrush effect will occur. An error will appearin the first few cycles of the output current in proportionto the inrush transient that occurs.

When the supply to a voltage transformer is interrupted,the core flux will not readily collapse; the secondarywinding will tend to maintain the magnetising force tosustain this flux, and will circulate a current through theburden which will decay more or less exponentially,possible with a superimposed audio-frequencyoscillation due to the capacitance of the winding.Bearing in mind that the exciting quantity, expressed inampere-turns, may exceed the burden, the transientcurrent may be significant.

6.2.8 Cascade Voltage Transformers

The capacitor VT (section 6.3) was developed because ofthe high cost of conventional electromagnetic voltagetransformers but, as shown in Section 6.3.2, thefrequency and transient responses are less satisfactorythan those of the orthodox voltage transformers. Anothersolution to the problem is the cascade VT (Figure 6.5).

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Residualvoltage

A B C

Figure 6.4: Residual voltage connection

N

Sn

a

A

C

P

C

C

C

C

P - primary winding

C - coupling windings

S - secondary winding

Figure 6.5: Schematic diagram of typical cascadevoltage transformer

Chap6-78-97 21/06/02 9:21 Page 82

The conventional type of VT has a single primary winding,the insulation of which presents a great problem forvoltages above about 132kV. The cascade VT avoidsthese difficulties by breaking down the primary voltagein several distinct and separate stages.

The complete VT is made up of several individualtransformers, the primary windings of which areconnected in series, as shown in Figure 6.5. Eachmagnetic core has primary windings (P) on two oppositesides. The secondary winding (S) consists of a singlewinding on the last stage only. Coupling windings (C)connected in pairs between stages, provide lowimpedance circuits for the transfer of load ampere-turnsbetween stages and ensure that the power frequencyvoltage is equally distributed over the several primarywindings.

The potentials of the cores and coupling windings arefixed at definite values by connecting them to selectedpoints on the primary windings. The insulation of eachwinding is sufficient for the voltage developed in thatwinding, which is a fraction of the total according to thenumber of stages. The individual transformers aremounted on a structure built of insulating material,which provides the interstage insulation, accumulatingto a value able to withstand the full system voltageacross the complete height of the stack. The entireassembly is contained in a hollow cylindrical porcelainhousing with external weather-sheds; the housing isfilled with oil and sealed, an expansion bellows beingincluded to maintain hermetic sealing and to permitexpansion with temperature change.

6.3 CAPACITOR VOLTAGE TRANSFORMERS

The size of electromagnetic voltage transformers for thehigher voltages is largely proportional to the ratedvoltage; the cost tends to increase at a disproportionaterate. The capacitor voltage transformer (CVT) is oftenmore economic.

This device is basically a capacitance potential divider.As with resistance-type potential dividers, the outputvoltage is seriously affected by load at the tapping point.The capacitance divider differs in that its equivalentsource impedance is capacitive and can therefore becompensated by a reactor connected in series with thetapping point. With an ideal reactor, such anarrangement would have no regulation and could supplyany value of output.

A reactor possesses some resistance, which limits theoutput that can be obtained. For a secondary outputvoltage of 110V, the capacitors would have to be verylarge to provide a useful output while keeping errorswithin the usual limits. The solution is to use a highsecondary voltage and further transform the output to

the normal value using a relatively inexpensiveelectromagnetic transformer. The successive stages ofthis reasoning are indicated in Figure 6.6.

There are numerous variations of this basic circuit. Theinductance L may be a separate unit or it may beincorporated in the form of leakage reactance in thetransformer T. Capacitors C1 and C2 cannot convenientlybe made to close tolerances, so tappings are provided forratio adjustment, either on the transformer T, or on aseparate auto-transformer in the secondary circuit.Adjustment of the tuning inductance L is also needed;this can be done with tappings, a separate tappedinductor in the secondary circuit, by adjustment of gapsin the iron cores, or by shunting with variablecapacitance. A simplified equivalent circuit is shown inFigure 6.7.

It will be seen that the basic difference between Figure6.7 and Figure 6.1 is the presence of C and L. At normalfrequency when C and L are in resonance and therefore

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L

Zb

ZbZb

C2

C1

C2

C1

C2

C1

L

T

(a) Basic capacitivevoltage divider

(b) Capacitive divider withinductive compensation

(c) Divider with E/M VT output stage

Figure 6.6: Development of capacitorvoltage transformer

Vi ZeZb

RsRpLC

L - tuning inductanceRp - primary winding resistance (plus losses)Ze - exciting impedance of transformer TRs - secondary circuit resistanceZb - burden impedanceC - C1 + C2 (in Figure 6.6)

Figure 6.7: Simplified equivalent circuitof capacitor voltage transformer

Chap6-78-97 21/06/02 9:21 Page 83

cancel, the circuit behaves in a similar manner to aconventional VT. At other frequencies, however, areactive component exists which modifies the errors.

Standards generally require a CVT used for protection toconform to accuracy requirements of Table 6.2 within afrequency range of 97-103% of nominal. Thecorresponding frequency range of measurement CVT’s ismuch less, 99%-101%, as reductions in accuracy forfrequency deviations outside this range are lessimportant than for protection applications.

6.3.1 Voltage Protection of Auxiliary Capacitor

If the burden impedance of a CVT were to be short-circuited, the rise in the reactor voltage would be limitedonly by the reactor losses and possible saturation, that is,to Q x E2 where E2 is the no-load tapping point voltageand Q is the amplification factor of the resonant circuit.This value would be excessive and is therefore limited bya spark gap connected across the auxiliary capacitor. Thevoltage on the auxiliary capacitor is higher at full ratedoutput than at no load, and the capacitor is rated forcontinuous service at this raised value. The spark gap willbe set to flash over at about twice the full load voltage.

The effect of the spark gap is to limit the short-circuitcurrent which the VT will deliver and fuse protection ofthe secondary circuit has to be carefully designed with thispoint in mind. Facilities are usually provided to earth thetapping point, either manually or automatically, beforemaking any adjustments to tappings or connections.

6.3.2 Transient Behaviour of Capacitor VoltageTransformers

A CVT is a series resonant circuit. The introduction of theelectromagnetic transformer between the intermediatevoltage and the output makes possible further resonanceinvolving the exciting impedance of this unit and thecapacitance of the divider stack. When a sudden voltagestep is applied, oscillations in line with these differentmodes take place, and will persist for a period governedby the total resistive damping that is present. Anyincrease in resistive burden reduces the time constant ofa transient oscillation, although the chance of a largeinitial amplitude is increased.

For very high-speed protection, transient oscillationsshould be minimised. Modern capacitor voltagetransformers are much better in this respect than theirearlier counterparts, but high performance protectionschemes may still be adversely affected.

6.3.3 Ferro-Resonance

The exciting impedance Ze of the auxiliary transformer T

and the capacitance of the potential divider togetherform a resonant circuit that will usually oscillate at asub-normal frequency. If this circuit is subjected to avoltage impulse, the resulting oscillation may passthrough a range of frequencies. If the basic frequency ofthis circuit is slightly less than one-third of the systemfrequency, it is possible for energy to be absorbed fromthe system and cause the oscillation to build up. Theincreasing flux density in the transformer core reducesthe inductance, bringing the resonant frequency nearerto the one-third value of the system frequency.

The result is a progressive build-up until the oscillationstabilizes as a third sub-harmonic of the system, whichcan be maintained indefinitely. Depending on the valuesof components, oscillations at fundamental frequency orat other sub-harmonics or multiples of the supplyfrequency are possible but the third sub-harmonic is theone most likely to be encountered.

The principal manifestation of such an oscillation is a risein output voltage, the r.m.s. value being perhaps 25%-50% above the normal value; the output waveformwould generally be of the form shown in Figure 6.8.

Such oscillations are less likely to occur when the circuitlosses are high, as is the case with a resistive burden, andcan be prevented by increasing the resistive burden.Special anti-ferro-resonance devices that use a parallel-tuned circuit are sometimes built into the VT. Althoughsuch arrangements help to suppress ferro-resonance,they tend to impair the transient response, so that thedesign is a matter of compromise.

Correct design will prevent a CVT that supplies a resistiveburden from exhibiting this effect, but it is possible fornon-linear inductive burdens, such as auxiliary voltagetransformers, to induce ferro-resonance. Auxiliaryvoltage transformers for use with capacitor voltagetransformers should be designed with a low value of fluxdensity that prevents transient voltages from causingcore saturation, which in turn would bring high excitingcurrents.

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Time

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Figure 6.8: Typical secondary voltagewaveform with third sub-harmonic oscillation.

Chap6-78-97 21/06/02 9:21 Page 84

6.4 CURRENT TRANSFORMERS

The primary winding of a current transformer isconnected in series with the power circuit and theimpedance is negligible compared with that of the powercircuit. The power system impedance governs thecurrent passing through the primary winding of thecurrent transformer. This condition can be representedby inserting the load impedance, referred through theturns ratio, in the input connection of Figure 6.1.

This approach is developed in Figure 6.9, taking thenumerical example of a 300/5A CT applied to an 11kV powersystem. The system is considered to be carrying ratedcurrent (300A) and the CT is feeding a burden of 10VA.

A study of the final equivalent circuit of Figure 6.9(c),taking note of the typical component values, will reveal allthe properties of a current transformer. It will be seen that:

a. the secondary current will not be affected bychange of the burden impedance over aconsiderable range

b. the secondary circuit must not be interrupted whilethe primary winding is energised. The inducedsecondary e.m.f. under these circumstances will behigh enough to present a danger to life and insulation

c. the ratio and phase angle errors can be calculatedeasily if the magnetising characteristics and theburden impedance are known

6.4.1 Errors

The general vector diagram (Figure 6.2) can be simplifiedby the omission of details that are not of interest incurrent measurement; see Figure 6.10. Errors arisebecause of the shunting of the burden by the excitingimpedance. This uses a small portion of the input currentfor exciting the core, reducing the amount passed to theburden. So Is = Ip - Ie, where Ie is dependent on Ze, theexciting impedance and the secondary e.m.f. Es, given bythe equation Es = Is (Zs + Zb), where:

Zs = the self-impedance of the secondary winding,which can generally be taken as the resistivecomponent Rs only

Zb = the impedance of the burden

6.4.1.1 Current or Ratio Error

This is the difference in magnitude between Ip and Is and isequal 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 inquadrature with Is and results in the phase error .

The values of the current error and phase error depend onthe phase displacement between Is and Ie, but neithercurrent nor phase error can exceed the vectorial error Ie.It will be seen that with a moderately inductive burden,resulting in Is and Ie approximately in phase, there will

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E = Secondary induced e.m.f.VsVsV Secondary output voltagepIIθ Phase angle error

IeIeIr IsIsIIqI IsIsI

IeIeI

IsIsI

IrIrIIqI

IpIpIVsVsV

EsIsIsI XsXs sXsX

IsIsI Rs

θ

Φ

Figure 6.10: Vector diagram for currenttransformer (referred to secondary)

(c) Equivalent circuit, all quantities referredto secondary side

'Ideal'CT

(b) Equivalent circuit of (a)

(a) Physical arrangement

Burden10VA

Z=21.2Ω

Z=21.2Ω

E=6350V 300/5A

E=6350V

0.2Ω

0.4Ω150Ωj50Ω r=300/5

0.2Ω

150Ω j50Ω 0.4Ω

E2r =21.2Ω x 602

=76.2kΩ

Er =6350V x 60 =381kV

Figure 6.9: Derivation of equivalent circuitof a current transformer

Chap6-78-97 21/06/02 9:21 Page 85

be little phase error and the exciting component willresult almost entirely in ratio error.

A reduction of the secondary winding by one or twoturns is often used to compensate for this. For example,in the CT corresponding to Figure 6.9, the worst error dueto the use of an inductive burden of rated value wouldbe about 1.2%. If the nominal turns ratio is 2:120,removal of one secondary turn would raise the output by0.83% leaving the overall current error as -0.37%.

For lower value burden or a different burden powerfactor, the error would change in the positive direction toa maximum of +0.7% at zero burden; the leakagereactance of the secondary winding is assumed to benegligible. No corresponding correction can be made forphase error, but it should be noted that the phase erroris small for moderately reactive burdens.

6.4.2 Composite Error

This is defined in IEC 60044-1 as the r.m.s. value of thedifference between the ideal secondary current and theactual secondary current. It includes current and phaseerrors and the effects of harmonics in the excitingcurrent. The accuracy class of measuring currenttransformers is shown in Table 6.4.

6.4.3 Accuracy Limit Current of ProtectionCurrent Transformers

Protection equipment is intended to respond to faultconditions, and is for this reason required to function atcurrent values above the normal rating. Protection classcurrent transformers must retain a reasonable accuracyup to the largest relevant current. This value is known asthe ‘accuracy limit current’ and may be expressed inprimary or equivalent secondary terms. The ratio of theaccuracy limit current to the rated current is known asthe 'accuracy limit factor'.

The accuracy class of protection current transformers isshown in Table 6.5.

Even though the burden of a protection CT is only a fewVA at rated current, the output required from the CT maybe considerable if the accuracy limit factor is high. Forexample, with an accuracy limit factor of 30 and aburden of 10VA, the CT may have to supply 9000VA tothe secondary circuit.

Alternatively, the same CT may be subjected to a highburden. For overcurrent and earth fault protection, withelements of similar VA consumption at setting, the earthfault element of an electromechanical relay set at 10%would have 100 times the impedance of the overcurrentelements set at 100%. Although saturation of the relayelements somewhat modifies this aspect of the matter, itwill be seen that the earth fault element is a severeburden, and the CT is likely to have a considerable ratioerror in this case. So it is not much use applying turnscompensation to such current transformers; it isgenerally simpler to wind the CT with turnscorresponding to the nominal ratio.

Current transformers are often used for the dual duty ofmeasurement and protection. They will then need to berated according to a class selected from both Tables 6.4and 6.5. The applied burden is the total of instrumentand relay burdens. Turns compensation may well beneeded to achieve the measurement performance.Measurement ratings are expressed in terms of ratedburden and class, for example 15VA Class 0.5. Protectionratings are expressed in terms of rated burden, class, andaccuracy limit factor, for example 10VA Class 10P10.

6.4.4 Class PX Current Transformers

The classification of Table 6.5 is only used for overcurrentprotection. Class PX is the definition in IEC 60044-1 forthe quasi-transient current transformers formerlycovered by Class X of BS 3938, commonly used with unitprotection schemes.

Guidance was given in the specifications to theapplication of current transformers to earth faultprotection, but for this and for the majority of otherprotection applications it is better to refer directly to themaximum useful e.m.f. that can be obtained from the CT.In this context, the 'knee-point' of the excitation curve isdefined as 'that point at which a further increase of 10%of secondary e.m.f. would require an increment ofexciting current of 50%’; see Figure 6.11.

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Accuracy +/- Percentage current +/- Phase displacementclass (ratio) error (minutes)

% current 5 20 100 120 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

(a) Limits of error accuracy for error classes 0.1 - 1.0

Accuracy +/- current (ratio) error, %class

% current 50 120

3 3 3

5 5 5

(b) Limits of error for error classes 3 and 5

Table 6.4: CT error classes

Class Current error at Phase displacement Composite error atrated primary at rated current rated accuracy limitcurrent (%) (minutes) primary current (%)

5P +/-1 +/-60 5

10P +/-3 10

Standard accuracy limit factors are 5, 10, 15, 20, and 30

Table 6.5: Protection CT error limits for classes 5P and 10P

Chap6-78-97 21/06/02 9:21 Page 86

Design requirements for current transformers for generalprotection purposes are frequently laid out in terms ofknee-point e.m.f., exciting current at the knee-point (orsome other specified point) and secondary windingresistance. Such current transformers are designatedClass PX.

6.4.5 CT Winding Arrangements

A number of CT winding arrangements are used. Theseare described in the following sections.

6.4.5.1 Wound primary type

This type of CT has conventional windings formed ofcopper wire wound round a core. It is used for auxiliarycurrent transformers and for many low or moderate ratiocurrent transformers used in switchgear of up to 11kVrating.

6.4.5.2 Bushing or bar primary type

Many current transformers have a ring-shaped core,sometimes built up from annular stampings, but oftenconsisting of a single length of strip tightly wound toform a close-turned spiral. The distributed secondarywinding forms a toroid which should occupy the wholeperimeter of the core, a small gap being left betweenstart and finish leads for insulation.

Such current transformers normally have a singleconcentrically placed primary conductor, sometimespermanently built into the CT and provided with the

necessary primary insulation. In other cases, the bushingof a circuit breaker or power transformer is used for thispurpose. At low primary current ratings it may bedifficult to obtain sufficient output at the desiredaccuracy. This is because a large core section is neededto provide enough flux to induce the secondary e.m.f. inthe small number of turns, and because the excitingampere-turns form a large proportion of the primaryampere-turns available. The effect is particularlypronounced when the core diameter has been madelarge so as to fit over large EHV bushings.

6.4.5.3 Core-balance current transformers

The core-balance CT (or CBCT) is normally of the ringtype, through the centre of which is passed cable thatforms the primary winding. An earth fault relay,connected to the secondary winding, is energised onlywhen there is residual current in the primary system.

The advantage in using this method of earth faultprotection lies in the fact that only one CT core is usedin place of three phase CT's whose secondary windingsare residually connected. In this way the CT magnetisingcurrent at relay operation is reduced by approximatelythree-to-one, an important consideration in sensitiveearth fault relays where a low effective setting isrequired. The number of secondary turns does not needto be related to the cable rated current because nosecondary current would flow under normal balancedconditions. This allows the number of secondary turns tobe chosen such as to optimise the effective primary pick-up current.

Core-balance transformers are normally mounted over acable at a point close up to the cable gland of switchgearor other apparatus. Physically split cores ('slip-over'types) are normally available for applications in whichthe cables are already made up, as on existingswitchgear.

6.4.5.4 Summation current transformers

The summation arrangement is a winding arrangementused in a measuring relay or on an auxiliary currenttransformer to give a single-phase output signal havinga specific relationship to the three-phase current input.

6.4.5.5 Air-gapped current transformers

These are auxiliary current transformers in which a smallair gap is included in the core to produce a secondaryvoltage output proportional in magnitude to current inthe primary winding. Sometimes termed 'transactors'and 'quadrature current transformers', this form ofcurrent transformer has been used as an auxiliarycomponent of unit protection schemes in which theoutputs into multiple secondary circuits must remainlinear for and proportioned to the widest practical rangeof input currents.

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Exciting voltage (IeIeI )

Exci

ting

volta

ge (V

sV

sV

)

+ 50%IeKIeKI

+ 10%VVVKVKV

IeKIeKI

Figure 6.11: Definition of knee-pointof excitation curve

Chap6-78-97 21/06/02 9:21 Page 87

6.4.6 Line Current CT’s

CT’s for measuring line currents fall into one of three types.

6.4.6.1 Overdimensioned CT’s

Overdimensioned CT’s are capable of transforming fullyoffset fault currents without distortion. In consequence,they are very large, as can be deduced from Section6.4.10. They are prone to errors due to remanent fluxarising, for instance, from the interruption of heavy faultcurrents.

6.4.6.2 Anti-remanence CT’s

This is a variation of the overdimensioned currenttransformer and has small gap(s) in the core magneticcircuit, thus reducing the possible remanent flux fromapproximately 90% of saturation value to approximately10%. These gap(s) are quite small, for example 0.12mmtotal, and so the excitation characteristic is notsignificantly changed by their presence. However, theresulting decrease in possible remanent core fluxconfines any subsequent d.c. flux excursion, resultingfrom primary current asymmetry, to within the coresaturation limits. Errors in current transformation aretherefore significantly reduced when compared withthose with the gapless type of core.

Transient protection current transformers are included in IEC60044-6 as types TPX, TPY and TPZ and this specificationgives good guidance to their application and use.

6.4.6.3 Linear current transformers

The 'linear' current transformer constitutes an even moreradical departure from the normal solid core CT in that itincorporates an appreciable air gap, for example 7.5-

10mm. As its name implies the magnetic behaviourtends to linearisation by the inclusion of this gap in themagnetic circuit. However, the purpose of introducingmore reluctance into the magnetic circuit is to reducethe value of magnetising reactance. This in turn reducesthe secondary time-constant of the CT, thereby reducingthe overdimensioning factor necessary for faithfultransformation. Figure 6.12 shows a typical modern CTfor use on MV systems.

6.4.7 Secondary Winding Impedance

As a protection CT may be required to deliver high valuesof secondary current, the secondary winding resistancemust be made as low as practicable. Secondary leakagereactance also occurs, particularly in wound primarycurrent transformers, although its precise measurementis difficult. The non-linear nature of the CT magneticcircuit makes it difficult to assess the definite ohmicvalue representing secondary leakage reactance.

It is, however, normally accepted that a currenttransformer is of the low reactance type provided thatthe following conditions prevail:

a. the core is of the jointless ring type (includingspirally wound cores)

b. the secondary turns are substantially evenlydistributed along the whole length of the magneticcircuit

c. the primary conductor(s) passes through theapproximate centre of the core aperture or, ifwound, is approximately evenly distributed alongthe whole length of the magnetic circuit

d. flux equalising windings, where fitted to therequirements of the design, consist of at least fourparallel-connected coils, evenly distributed alongthe whole length of the magnetic circuit, each coiloccupying one quadrant

Alternatively, when a current transformer does notobviously comply with all of the above requirements, itmay be proved to be of low-reactance where:

e. the composite error, as measured in the acceptedway, does not exceed by a factor of 1.3 that errorobtained directly from the V-I excitationcharacteristic of the secondary winding

6.4.8 Secondary Current Rating

The choice of secondary current rating is determinedlargely by the secondary winding burden and thestandard practice of the user. Standard CT secondarycurrent ratings are 5A and 1A. The burden at ratedcurrent imposed by digital or numerical relays or

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Figure 6.12: Typical modern CT for use on MV systems

Chap6-78-97 21/06/02 15:21 Page 88

instruments is largely independent of the rated value ofcurrent. This is because the winding of the device has todevelop a given number of ampere-turns at ratedcurrent, so that the actual number of turns is inverselyproportional to the current, and the impedance of thewinding varies inversely with the square of the currentrating. However, electromechanical or static earth-faultrelays may have a burden that varies with the currenttapping used.

Interconnection leads do not share this property,however, being commonly of standard cross-sectionregardless of rating. Where the leads are long, theirresistance may be appreciable, and the resultant burdenwill vary with the square of the current rating. Forexample a CT lead run of the order of 200 metres, atypical distance for outdoor EHV switchgear, could havea 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 ofperhaps 10VA for an electromechanical relay, but lessthan 1VA for a numerical relay), making a total of 85VA.Such a burden would require the CT to be very large andexpensive, particularly if a high accuracy limit factorwere also applicable.

With a 1A CT secondary rating, the lead burden isreduced to 3VA, so that with the same relay burden thetotal becomes a maximum of 13VA. This can be providedby a CT of normal dimensions, resulting in a saving insize, weight and cost. Hence modern CT’s tend to havesecondary windings of 1A rating. However, where theprimary rating is high, say above 2000A, a CT of highersecondary rating may be used, to limit the number ofsecondary turns. In such a situation secondary ratings of2A, 5A or, in extreme cases, 20A, might be used.

6.4.9 Rated Short-Time Current

A current transformer is overloaded while system short-circuit currents are flowing and will be short-time rated.Standard times for which the CT must be able to carryrated short-time current (STC) are 0.25, 0.5, 1.0, 2.0 or3.0 seconds.

A CT with a particular short-time current/ time ratingwill carry a lower current for a longer time in inverseproportion to the square of the ratio of current values.The converse, however, cannot be assumed, and largercurrent values than the S.T.C. rating are not permissiblefor any duration unless justified by a new rating test toprove the dynamic capability.

6.4.10 Transient Response of a Current Transformer

When accuracy of response during very short intervals isbeing studied, it is necessary to examine what happens

when the primary current is suddenly changed. Theeffects are most important, and were first observed inconnection with balanced forms of protection, whichwere liable to operate unnecessarily when short-circuitcurrents were suddenly established.

6.4.10.1 Primary current transient

The power system, neglecting load circuits, is mostlyinductive, so that when a short circuit occurs, the faultcurrent that flows is given by:

…Equation 6.1

where:

Ep = peak system e.m.f.

R = system resistance

L = system inductance

β = initial phase angle governed by instant of fault occurrence

α = system power factor angle

= tan-1ωL/R

The first term of Equation 6.1 represents the steady statealternating current, while the second is a transientquantity responsible for displacing the waveformasymmetrically.

is the steady state peak current Ip.The maximum transient occurs when sin = (α - β) = 1;no other condition need be examined.So:

...Equation 6.2

When the current is passed through the primary windingof a current transformer, the response can be examinedby replacing the CT with an equivalent circuit as shownin Figure 6.9(b).

As the 'ideal' CT has no losses, it will transfer the entirefunction, and all further analysis can be carried out interms of equivalent secondary quantities (is and Is). Asimplified solution is obtainable by neglecting theexciting current of the CT.

The flux developed in an inductance is obtained byintegrating the applied e.m.f. through a time interval:

…Equation 6.3For the CT equivalent circuit, the voltage is the drop on

= ∫K vdtt

t

1

2

i I t ep pR L t= −

+

− ( )sin ω π2

E

R L

p

2 2 2+ ω

sin sinω β α α βt e R L t+ −( ) + −( )[ ]− ( )

iE

R Lp

p=+2 2 2ω

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the burden resistance Rb.

Integrating for each component in turn, the steady statepeak flux is given by:

...Equation 6.4

The transient flux is given by:

...Equation 6.5

Hence, the ratio of the transient flux to the steady statevalue is:

where X and R are the primary system reactance andresistance values.

The CT core has to carry both fluxes, so that:

...Equation 6.6

The term (1+X/R) has been called the 'transient factor'(TF), the core flux being increased by this factor duringthe transient asymmetric current period. From this it canbe seen that the ratio of reactance to resistance of thepower system is an important feature in the study of thebehaviour of protection relays.

Alternatively, L/R is the primary system time constant T,so that the transient factor can be written:

Again, fT is the time constant expressed in cycles of thea.c. quantity T’, so that:

TF = 1 + 2πfT = 1 + 2πT’

This latter expression is particularly useful whenassessing a recording of a fault current, because the timeconstant in cycles can be easily estimated and leadsdirectly to the transient factor. For example, a systemtime constant of three cycles results in a transient factorof (1+6π), or 19.85; that is, the CT would be required tohandle almost twenty times the maximum flux producedunder steady state conditions.

The above theory is sufficient to give a general view ofthe problem. In this simplified treatment, no reversevoltage is applied to demagnetise the CT, so that the fluxwould build up as shown in Figure 6.13.

= + = +1 1ω ωLR

T

C A B AXR

= + = +ÊËÁ

ˆ¯

1

wB

A

LR

XR

= =

α

B b sR L t b sKR I e dt

KR I LR

= =− ( )∫ 0

= KR Ib s

ω

ω π

π ω

π ω

A b sKR I t dt= −

∫ sin

2

3 2

Since a CT requires a finite exciting current to maintaina flux, it will not remain magnetised (neglectinghysteresis), and for this reason a complete representationof the effects can only be obtained by including thefinite inductance of the CT in the calculation. Theresponse of a current transformer to a transientasymmetric current is shown in Figure 6.14.

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0.1

Time0

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

-0.1

IeIeI

IeIeI = Transient exciting current

i's

e

e-

-

1T

1T1

Figure 6.14: Response of a currenttransformer to a transient asymmetric current

Flux

(mul

tiple

s of

ste

ady

valu

e)

0 0.2

20

16

12

8

4

0.150.10.05

Time (seconds)

T = 0.06s

T - time constant of primary circuit

Figure 6.13: Response of a CT ofinfinite shunt impedance to transient asymmetric

primary current

Chap6-78-97 21/06/02 15:25 Page 90

Let:is = the nominal secondary current

i’s = the actual secondary output current

ie = the exciting current

then:is = ie + i’s ...Equation 6.7

also,

...Equation 6.8whence:

...Equation 6.9which gives for the transient term

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 followingreasons:

a. no account has been taken of secondary leakage orburden inductance. This is usually small comparedwith Le so that it has little effect on the maximumtransient flux

b. iron loss has not been considered. This has theeffect of reducing the secondary time constant, butthe value of the equivalent resistance is variable,depending upon both the sine and exponentialterms. Consequently, it cannot be included in anylinear theory and is too complicated for asatisfactory treatment to be evolved

c. the theory is based upon a linear excitationcharacteristic. This is only approximately true up tothe knee-point of the excitation curve. A precisesolution allowing for non-linearity is not practicable.Solutions have been sought by replacing the excitationcurve with a number of chords; a linear analysis canthen be made for the extent of each chord

The above theory is sufficient, however, to give a goodinsight into the problem and to allow most practicalissues to be decided.

d. the effect of hysteresis, apart from loss asdiscussed under (b) above, is not included.Hysteresis makes the inductance different for fluxbuild up and decay, so that the secondary timeconstant is variable. Moreover, the ability of the

i I TT T

e eet T t T=

−−( )− −

11

1

didt

R iL

R iL

e b e

e

b s

e

+ =

Ldidt

R iee

b s= ′

core to retain a 'remanent' flux means that thevalue of B developed in Equation 6.5 has to beregarded as an increment of flux from any possibleremanent value positive or negative. The formulawould then be reasonable provided the appliedcurrent transient did not produce saturation

It will be seen that a precise calculation of the flux andexcitation current is not feasible; the value of the study isto explain the observed phenomena. The asymmetric (ord.c.) component can be regarded as building up the meanflux over a period corresponding to several cycles of thesinusoidal component, during which period the lattercomponent produces a flux swing about the varying'mean level' established by the former. The asymmetricflux ceases to increase when the exciting current is equalto the total asymmetric input current, since beyond thispoint the output current, and hence the voltage dropacross the burden resistance, is negative. Saturationmakes the point of equality between the excitationcurrent and the input occur at a flux level lower thanwould be expected from linear theory.

When the exponential component drives the CT intosaturation, the magnetising inductance decreases,causing a large increase in the alternating component ie.

The total exciting current during the transient period isof the form shown in Figure 6.15 and the correspondingresultant distortion in the secondary current output, dueto saturation, is shown in Figure 6.16.

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Curr

ent

Time

Primary currentreferred tosecondary

Secondary currentResidual flux = 0Resistive burdenPower system T.C. = 0.05s

0

Figure 6.16: Distortion in secondary currentdue to saturation

Exci

ting

curr

ent

Time

Figure 6.15: Typical exciting current of CTduring transient asymmetric input current

Chap6-78-97 21/06/02 15:25 Page 91

The presence of residual flux varies the starting point ofthe transient flux excursion on the excitationcharacteristic. Remanence of like polarity to thetransient will reduce the value of symmetric current ofgiven time constant which the CT can transform withoutsevere saturation; conversely, reverse remanence willgreatly increase the ability of a CT to transform transientcurrent.

If the CT were the linear non-saturable device consideredin the analysis, the sine current would be transformedwithout loss of accuracy. In practice the variation inexcitation inductance caused by transferring the centreof the flux swing to other points on the excitation curvecauses an error that may be very large. The effect onmeasurement is of little consequence, but for protectionequipment that is required to function during faultconditions, the effect is more serious. The output currentis reduced during transient saturation, which mayprevent the relays from operating if the conditions arenear to the relay setting. This must not be confused withthe increased r.m.s. value of the primary current due tothe asymmetric transient, a feature which sometimesoffsets the increase ratio error. In the case of balancedprotection, during through faults the errors of the severalcurrent 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 theexcitation impedance causes some distortion of theoutput waveform; such a waveform will contain, inaddition to the fundamental current, odd harmonics only.

When, however, the CT is saturated uni-directionallywhile being simultaneously subjected to a small a.c.quantity, as in the transient condition discussed above,the output will contain both odd and even harmonics.Usually the lower numbered harmonics are of greatestamplitude and the second and third harmoniccomponents may be of considerable value. This mayaffect relays that are sensitive to harmonics.

6.4.12 Test Windings

On-site conjunctive testing of current transformers andthe apparatus that they energise is often required. Itmay be difficult, however, to pass a suitable value ofcurrent through the primary windings, because of thescale of such current and in many cases because accessto the primary conductors is difficult. Additionalwindings may be provided to make such tests easier,these windings usually being rated at 10A. The testwinding will inevitably occupy appreciable space and the

CT will cost more. This fact should be weighed againstthe convenience achieved; very often it will be foundthat the tests in question can be replaced by alternativeprocedures.

6.5 NOVEL INSTRUMENT TRANSFORMERS

The preceding types of instrument transformers have allbeen based on electromagnetic principles using amagnetic core. There are now available several newmethods of transforming the measured quantity usingoptical and mass state methods.

6.5.1 Optical Instrument Transducers

The key features of a freestanding optical instrumenttransducer can be illustrated with the functionaldiagram of Figure 6.17.

Optical converters and optical glass fibre channelsimplement the link between the sensor and the low-voltage output. The fundamental difference between aninstrument transducer and a conventional instrumenttransformer is the electronic interface needed for itsoperation. This interface is required both for the sensingfunction and for adapting the new sensor technology tothat of the secondary output currents and voltages.

Non-conventional optical transducers lend themselves tosmaller, lighter devices where the overall size and powerrating of the unit does not have any significant bearingon the size and the complexity of the sensor. Small,lightweight insulator structures may be tailor-made to

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+O/E converter

Communication

Secondaryoutput

Communication

E/O converter+

Sensor

HVBus

Sensingfunction

functionInsulating

InstrumentTransformer

Optical link(fibre optics)

interfaceElectronic

Figure 6.17: Functional diagram ofoptical instrument transducer

Chap6-78-97 21/06/02 15:25 Page 92

fit optical sensing devices as an integral part of theinsulator. Additionally, the non-linear effects andelectromagnetic interference problems in the secondarywiring of conventional VT’s and CT’s are minimised.

Optical transducers can be separated in two families:firstly the hybrid transducers, making use ofconventional electrical circuit techniques to which arecoupled various optical converter systems, and secondlythe ‘all-optical’ transducers that are based onfundamental, optical sensing principles.

6.5.1.1 Optical sensor concepts

Certain optical sensing media (glass, crystals, plastics)show a sensitivity to electric and magnetic fields andthat some properties of a probing light beam can bealtered when passing through them. One simple opticaltransducer description is given here in Figure. 6.18.

Consider the case of a beam of light passing through apair of polarising filters. If the input and outputpolarising filters have their axes rotated 45° from eachother, only half the light will come through. Thereference light input intensity is maintained constantover time. Now if these two polarising filters remainfixed and a third polarising filter is placed in betweenthem, a random rotation of this middle polariser eitherclockwise or counter-clockwise will be monitored as avarying or modulated light output intensity at the lightdetector.

When a block of optical sensing material (glass orcrystal) is immersed in a varying magnetic or electric

field, it plays the role of the ‘odd’ polariser. Changes inthe magnetic or electric field in which the optical sensoris immersed are monitored as a varying intensity of theprobing light beam at the light detector. The light outputintensity fluctuates around the zero-field level equal to50% of the reference light input. This modulation of thelight intensity due to the presence of varying fields isconverted back to time-varying currents or voltages.

A transducer uses a magneto-optic effect sensor foroptical current measuring applications. This reflects thefact that the sensor is not basically sensitive to a currentbut to the magnetic field generated by this current.Although ‘all-fibre’ approaches are feasible, mostcommercially available optical current transducers relyon a bulk-glass sensor. Most optical voltage transducers,on the other hand, rely on an electro-optic effect sensor.This reflects the fact that the sensor used is sensitive tothe imposed electric field.

6.5.1.2 Hybrid transducers

The hybrid family of non-conventional instrumenttransducers can be divided in two types: those withactive sensors and those with passive sensors. The ideabehind a transducer with an active sensor is to changethe existing output of the conventional instrumenttransformer into an optically isolated output by addingan optical conversion system (Figure 6.18). Thisconversion system may require a power supply of itsown: this is the active sensor type. The use of an opticalisolating system serves to de-couple the instrumenttransformer output secondary voltages and currents

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opticalsensingmedium

inputpolariser

outputpolariser

45° 90°

out

sensinglightdetectorin

opticalfibre

opticalfibre

light source

'Odd' polariser

0.5

1.0

0t

modulatedlight inputintensity

referencelight inputintensity

0

0.5

1.0

t

+

zero field level

Figure. 6.18: Schematic representation of the concepts behind the optical sensing of varying electric and magnetic fields

Chap6-78-97 21/06/02 15:14 Page 93

from earthed or galvanic links. Thus the only link thatremains between the control-room and the switchyard isa fibre optic cable.

Another type of hybrid non-conventional instrumenttransformer is achieved by retrofitting a passive opticalsensing medium into a conventional ‘hard-wiresecondary’ instrument transformer. This can be termedas a passive hybrid type since no power supply of anykind is needed at the secondary level.

6.5.1.3 ‘All-optical’ transducers

These instrument transformers are based entirely onoptical materials and are fully passive. The sensingfunction is achieved directly by the sensing material anda simple fibre optic cable running between the base ofthe unit and the sensor location provides thecommunication link.

The sensing element is made of an optical material that ispositioned in the electric or magnetic field to be sensed.In the case of a current measuring device the sensitiveelement is either located free in the magnetic field (Figure6.19(a)) or it can be immersed in a field-shaping magnetic‘gap’ (Figure 6.19(b)). In the case of a voltage-sensingdevice (Figure 6.20) the same alternatives exist, this timefor elements that are sensitive to electric fields. Thepossibility exists of combining both sensors within asingle housing, thus providing both a CT and VT within asingle compact housing that gives rise to space savingswithin a substation.

In all cases there is an optical fibre that channels theprobing reference light from a source into the mediumand another fibre that channels the light back to

analysing circuitry. In sharp contrast with aconventional free-standing instrument transformer, theoptical instrument transformer needs an electronicinterface module in order to function. Therefore itssensing principle (the optical material) is passive but itsoperational integrity relies on the interface that ispowered in the control room (Figure 6.21).

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'Floating'electrode

AC linevoltage

AC linevoltage

Optical fibres

Electro-opticsensor

Electro-opticsensor

Referenceelectrode

Referenceelectrode

Referenceelectrode

(a) 'Free-field' type

(b) 'Field shaping' type

Lightpath

Optical fibres

Figure 6.20: Optical voltage sensor basedon the electrical properties of optical materials

Optical fibre

AC line current

Magneticfield

Magneto-optic sensor

(a) 'Free-field' type

Optical fibre

(b) 'Field-shaping' type

Magneto-optic sensorGappedmagnetic core

AC line current

Optical fibresMagnetic field

I

I

Figure 6.19: Optical current sensor basedon the magnetic properties of optical materials

High voltagesensor assembly

Fibre optic cable

Junctionbox

AC/DC source

Opticalinterfaceunit

Figure 6.21: Novel instrument transducer conceptrequiring an electronic interface in the control room

Chap6-78-97 21/06/02 15:14 Page 94

Similar to conventional instrument transformers there are‘live tank’ and ‘dead tank’ optical transducers. Typically,current transducers take the shape of a closed loop of light-transparent material, fitted around a straight conductorcarrying the line current (Figure 6.22). In this case a bulk-glass sensor unit is depicted (Figure 6.22(a)), along with an‘all-optical’ sensor example, as shown in Figure 6.22(b).Light detectors are basically very sensitive devices and thesensing material can thus be selected in such a way as toscale-up readily for larger currents. ‘All-optical’ voltagetransducers however do not lend themselves easily forextremely high line voltages. Two concepts using a 'full-voltage' sensor are shown in Figure 6.23.

Although ‘all-optical’ instrument transformers were firstintroduced 10-15 years ago, there are still only a few inservice nowadays. Figure 6.24 shows a field installationof a combined optical CT/VT.

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Sensor #1

Sensor #2

Fibreopticcables

Fibre junction box

H2HH1AClinecurrent

Dome

Fibre opticcable conduit

Insulatorcolumn

Liquid /solid/ gaseousinternal insulation

Electro-optic sensor('all-fibre' transducer)

Electro-optic sensor(bulk-glass transducer)

AC line current

Bulk-glasssensing element

Optical fibresLight out

Light in

AC line current

Optical fibres

Light out

Light in

Fibresensing element

(a) Glass sensor approach

(b) 'All-fibre' sensor concept

I

I

II

Figure 6.22: Conceptual design of a double-sensor optical CT

Conductor

(a) 'Live tank' (b) 'Dead tank'

Figure 6.23: Optical voltage transducer concepts,using a ‘full-voltage’ sensor

Figure 6.24: Field installation of a combinedoptical CT/VT

Chap6-78-97 21/06/02 15:15 Page 95

6.5.2 Other Sensing Systems

There are a number of other sensing systems that can beused, as described below.

6.5.2.1 Zero-flux (Hall Effect) current transformer

In this case the sensing element is a semi-conductingwafer that is placed in the gap of a magneticconcentrating ring. This type of transformer is alsosensitive to d.c. currents. The transformer requires apower supply that is fed from the line or from a separatepower supply. The sensing current is typically 0.1% of thecurrent to be measured. In its simplest shape, the Halleffect voltage is directly proportional to the magnetisingcurrent to be measured. For more accurate and moresensitive applications, the sensing current is fed througha secondary, multiple-turn winding, placed around themagnetic ring in order to balance out the gap magneticfield. This zero-flux or null-flux version allows veryaccurate current measurements in both d.c. and high-frequency applications. A schematic representation ofthe sensing part is shown in Figure 6.25.

6.5.2.2 Hybrid magnetic-optical sensor

This type of transformer is mostly used in applicationssuch as series capacitive compensation of longtransmission lines, where a non-grounded measurementof current is required. In this case, several currentsensors are required on each phase in order to achievecapacitor surge protection and balance. The preferredsolution is to use small toroidally wound magnetic coretransformers connected to fibre optic isolating systems.These sensors are usually active sensors in the sense thatthe isolated systems require a power supply. This isillustrated in Figure 6.26.

6.5.2.3 Rogowski coils

The Rogowski coil is based on the principle of an air-cored current transformer with a very high loadimpedance. The secondary winding is wound on a toroid

of insulation material. In most cases the Rogowski coilwill be connected to an amplifier, in order to deliversufficient power to the connected measuring orprotection equipment and to match the input impedanceof this equipment. The Rogowski coil requiresintegration of the magnetic field and therefore has atime and phase delay whilst the integration is completed.This can be corrected for within a digital protection relay.The schematic representation of the Rogowski coil sensoris shown in Figure 6.27.

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Magnetic concentrator(gapped magnetic core)

g(gapped magnetic core)

g

Sensing current

V

i

i

Sensing element

I

Figure 6.25: Conceptual design of a Hall-effectcurrent sensing element fitted in a field-shaping gap

Opticalfibres

Electrical to opticalconverter

Air coretoroidal coil

Current carryingconductor

Figure 6.27: Schematic representationof a Rogowski coil, used for current sensing

Electrical to opticalconverter/transmitter

Current transformer

Burden

Opticalfibres

I

Figure 6.26: Design principle of a hybrid magneticcurrent transformer fitted with an optical transmitter

Chap6-78-97 21/06/02 15:15 Page 96

Introduction 3.1

Vector algebra 3.2

Manipulation of complex quantities 3.3

Circuit quantities and conventions 3.4

Impedance notation 3.5

Basic circuit laws, 3.6theorems and network reduction

References 3.7

• 3 • F u n d a m e n t a l T h e o r y

Chap3-16-29 1/07/02 8:22 Page 16


3.1 INTRODUCTION

The Protection Engineer is concerned with limiting theeffects of disturbances in a power system. Thesedisturbances, if allowed to persist, may damage plantand interrupt the supply of electric energy. They aredescribed as faults (short and open circuits) or powerswings, and result from natural hazards (for instancelightning), plant failure or human error.

To facilitate rapid removal of a disturbance from a powersystem, the system is divided into 'protection zones'.Relays monitor the system quantities (current, voltage)appearing in these zones; if a fault occurs inside a zone,the relays operate to isolate the zone from the remainderof the power system.

The operating characteristic of a relay depends on theenergizing quantities fed to it such as current or voltage,or various combinations of these two quantities, and onthe manner in which the relay is designed to respond tothis information. For example, a directional relaycharacteristic would be obtained by designing the relayto compare the phase angle between voltage and currentat the relaying point. An impedance-measuringcharacteristic, on the other hand, would be obtained bydesigning the relay to divide voltage by current. Manyother more complex relay characteristics may beobtained by supplying various combinations of currentand voltage to the relay. Relays may also be designed torespond to other system quantities such as frequency,power, etc.

In order to apply protection relays, it is usually necessaryto know the limiting values of current and voltage, andtheir relative phase displacement at the relay location,for various types of short circuit and their position in thesystem. This normally requires some system analysis forfaults occurring at various points in the system.

The main components that make up a power system aregenerating sources, transmission and distributionnetworks, and loads. Many transmission and distributioncircuits radiate from key points in the system and thesecircuits are controlled by circuit breakers. For thepurpose of analysis, the power system is treated as anetwork of circuit elements contained in branchesradiating from nodes to form closed loops or meshes.The system variables are current and voltage, and in

• 3 • Fundamental T heor y

Chap3-16-29 1/07/02 8:23 Page 17


• 3 •

Fun

dam

enta

l T

heor

y

• 1 8 •

steady state analysis, they are regarded as time varyingquantities at a single and constant frequency. Thenetwork parameters are impedance and admittance;these are assumed to be linear, bilateral (independent ofcurrent direction) and constant for a constant frequency.

3.2 VECTOR ALGEBRA

A vector represents a quantity in both magnitude anddirection. In Figure 3.1 the vector OP has a magnitude|Z| at an angle θ with the reference axis OX.

Figure 3.1

It may be resolved into two components at right anglesto each other, in this case x and y. The magnitude orscalar value of vector Z is known as the modulus |Z|, andthe angle θ is the argument, or amplitude, and is writtenas arg.

—Z. The conventional method of expressing a vector

Z—

is to write simply |Z|∠θ .

This form completely specifies a vector for graphicalrepresentation or conversion into other forms.

For vectors to be useful, they must be expressedalgebraically. In Figure 3.1, the vector

—Z is the resultant

of vectorially adding its components x and y;algebraically this vector may be written as:

—Z = x + jy …Equation 3.1

where the operator j indicates that the component y isperpendicular to component x. In electricalnomenclature, the axis OC is the 'real' or 'in-phase' axis,and the vertical axis OY is called the 'imaginary' or'quadrature' axis. 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 hasperformed its function twice, and since the vector hasreversed its sense, then:

j x j or j2 = -1

whence j = √-1

The representation of a vector quantity algebraically interms of its rectangular co-ordinates is called a 'complexquantity'. Therefore, x + jy is a complex quantity and isthe rectangular form of the vector |Z|∠θ where:

—…Equation 3.2

From Equations 3.1 and 3.2:—Z = |Z| (cosθ + jsinθ) …Equation 3.3

and since cosθ and sinθ may be expressed inexponential form by the identities:

it follows that—Z may also be written as:

—Z = |Z|e jθ …Equation 3.4

Therefore, a vector quantity may also be representedtrigonometrically and exponentially.

3.3 MANIPULATIONOF COMPLEX QUANTIT IES

Complex quantities may be represented in any of thefour co-ordinate systems given below:

a. Polar Z ∠ θ

b. Rectangular x + jy

c. Trigonometric |Z| (cosθ + jsinθ)

d. Exponential |Z|e jθ

The modulus |Z| and the argument θ are together knownas 'polar co-ordinates', and x and y are described as'cartesian co-ordinates'. Conversion between co-ordinate systems is easily achieved. As the operator jobeys the ordinary laws of algebra, complex quantities inrectangular form can be manipulated algebraically, ascan be seen by the following:

—Z1 +

—Z2 = (x1+x2) + j(y1+y2) …Equation 3.5

—Z1 -

—Z2 = (x1-x2) + j(y1-y2) …Equation 3.6

(see Figure 3.2)

cosθθ θ

= − −e ej j

2

sinθθ θ

= − −e ej

j j

2

Z x y

yx

x Z

y Z

= +( )=

=

=

−

2 2

1θ

θ

θ

tan

cos

sin

Figure 3.1: Vector OP

0

Y

X

P

|Z|y

x

q

Chap3-16-29 1/07/02 8:25 Page 18


• 3 •F

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…Equation 3.7

3.3.1 Complex variables

Some complex quantities are variable with, for example,time; when manipulating such variables in differentialequations it is expedient to write the complex quantityin exponential form.

When dealing with such functions it is important toappreciate that the quantity contains real and imaginarycomponents. If it is required to investigate only onecomponent of the complex variable, separation intocomponents must be carried out after the mathematicaloperation has taken place.

Example: Determine the rate of change of the realcomponent of a vector |Z|∠ wt with time.

|Z|∠ wt = |Z| (coswt + jsinwt)

= |Z|e jwt

The real component of the vector is |Z|coswt.

Differentiating |Z|e jwt with respect to time:

= jw|Z| (coswt + jsinwt)

Separating into real and imaginary components:

Thus, the rate of change of the real component of avector |Z|∠ wt is:

-|Z| w sinwt

ddt

Z e Z w wt jw wtjwt ( )= − +( )sin cos

ddt

Z e jw Z ejwt jwt =

Z Z Z Z

ZZ

Z

Z

1 2 1 2 1 2

1

2

1

21 2

= ∠ +

= ∠ −

θ θ

θ θ

3.3.2 Complex Numbers

A complex number may be defined as a constant thatrepresents the real and imaginary components of aphysical quantity. The impedance parameter of anelectric circuit is a complex number having real andimaginary components, which are described as resistanceand reactance respectively.

Confusion often arises between vectors and complexnumbers. A vector, as previously defined, may be acomplex number. In this context, it is simply a physicalquantity of constant magnitude acting in a constantdirection. A complex number, which, being a physicalquantity relating stimulus and response in a givenoperation, is known as a 'complex operator'. In thiscontext, it is distinguished from a vector by the fact thatit has no direction of its own.

Because complex numbers assume a passive role in anycalculation, the form taken by the variables in theproblem determines the method of representing them.

3.3.3 Mathematical Operators

Mathematical operators are complex numbers that areused to move a vector through a given angle withoutchanging the magnitude or character of the vector. Anoperator is not a physical quantity; it is dimensionless.

The symbol j, which has been compounded withquadrature components of complex quantities, is anoperator that rotates a quantity anti-clockwise through90°. Another useful operator is one which moves avector anti-clockwise through 120°, commonlyrepresented by the symbol a.

Operators are distinguished by one further feature; theyare the roots of unity. Using De Moivre's theorem, thenth root of unity is given by solving the expression:

11/n = (cos2πm + jsin2πm)1/n

where m is any integer. Hence:

where m has values 1, 2, 3, ... (n-1)

From the above expression j is found to be the 4th rootand a the 3rd root of unity, as they have four and threedistinct values respectively. Table 3.1 gives some usefulfunctions of the a operator.

1 2 21/ cos sinn

mn

j mn

= +π π

Figure 3.2: Addition of vectors

0

Y

X

y1

y2

x2x1

|Z1|

|Z2|

Chap3-16-29 1/07/02 8:25 Page 19


1=1+ j0 = e j0

1+ a + a2 = 0

Table 3.1: Properties of the a operator

3.4 C IRCUIT QUANTIT IESAND CONVENTIONS

Circuit analysis may be described as the study of theresponse of a circuit to an imposed condition, forexample a short circuit. The circuit variables are currentand voltage. Conventionally, current flow results fromthe application of a driving voltage, but there iscomplete duality between the variables and either maybe regarded as the cause of the other.

When a circuit exists, there is an interchange of energy;a circuit may be described as being made up of 'sources'and 'sinks' for energy. The parts of a circuit are describedas elements; a 'source' may be regarded as an 'active'element and a 'sink' as a 'passive' element. Some circuitelements are dissipative, that is, they are continuoussinks for energy, for example resistance. Other circuitelements may be alternately sources and sinks, forexample capacitance and inductance. The elements of acircuit are connected together to form a network havingnodes (terminals or junctions) and branches (seriesgroups of elements) that form closed loops (meshes).

In steady state a.c. circuit theory, the ability of a circuitto accept a current flow resulting from a given drivingvoltage is called the impedance of the circuit. Sincecurrent and voltage are duals the impedance parametermust also have a dual, called admittance.

3.4.1 Circuit Variables

As current and voltage are sinusoidal functions of time,varying at a single and constant frequency, they areregarded as rotating vectors and can be drawn as planvectors (that is, vectors defined by two co-ordinates) ona vector diagram.

j a a= − 2

3

a a j− =2 3

1 32− =−a j a

1 3 2− =a j a

a j ej2

43

12

32

=− − =π

a j ej

=− + =12

32

23π

For example, the instantaneous value, e, of a voltagevarying sinusoidally with time is:

e=Emsin(wt+δ) …Equation 3.8

where:

Em is the maximum amplitude of the waveform;ω=2πf, the angular velocity, δ is the argument defining the amplitude of thevoltage at a time t=0

At t=0, the actual value of the voltage is Emsinδ. So ifEm is regarded as the modulus of a vector, whose

argument is δ, then Emsinδ is the imaginary componentof the vector |Em|∠δ . Figure 3.3 illustrates this quantityas a vector and as a sinusoidal function of time.

Figure 3.3

The current resulting from applying a voltage to a circuitdepends upon the circuit impedance. If the voltage is asinusoidal function at a given frequency and theimpedance is constant the current will also varyharmonically at the same frequency, so it can be shownon the same vector diagram as the voltage vector, and isgiven by the equation

…Equation 3.9

where:

…Equation 3.10

From Equations 3.9 and 3.10 it can be seen that theangular displacement φbetween the current and voltagevectors and the current magnitude |Im|=|Em|/|Z| isdependent upon the impedance

—Z . In complex form the

impedance may be written—Z=R+jX. The 'real

component', R, is the circuit resistance, and the

Z R X

X LC

XR

= +

= −

=

−

2 2

1

1ωω

φ tan

iE

Zwtm= + −( )sin δ φ

• 3 •

Fun

dam

enta

l T

heor

y

• 2 0 •

Figure 3.3: Representationof a sinusoidal function

Y

X' X0

Y'

e

t = 0

t

|Em| Em

Chap3-16-29 1/07/02 8:25 Page 20


'imaginary component', X, is the circuit reactance. Whenthe circuit reactance is inductive (that is, wL>1/wC), thecurrent 'lags' the voltage by an angle φ, and when it iscapacitive (that is, 1/wC>wL) it 'leads' the voltage by anangle φ.

When drawing vector diagrams, one vector is chosen asthe 'reference vector' and all other vectors are drawnrelative to the reference vector in terms of magnitudeand angle. The circuit impedance |Z| is a complexoperator and is distinguished from a vector only by thefact that it has no direction of its own. A furtherconvention is that sinusoidally varying quantities aredescribed by their 'effective' or 'root mean square' (r.m.s.)values; these are usually written using the relevantsymbol without a suffix.

Thus:

…Equation 3.11

The 'root mean square' value is that value which has thesame heating effect as a direct current quantity of thatvalue in the same circuit, and this definition applies tonon-sinusoidal as well as sinusoidal quantities.

3.4.2 Sign Conventions

In describing the electrical state of a circuit, it is oftennecessary to refer to the 'potential difference' existingbetween two points in the circuit. Since wherever sucha potential difference exists, current will flow and energywill either be transferred or absorbed, it is obviouslynecessary to define a potential difference in more exactterms. For this reason, the terms voltage rise and voltagedrop are used to define more accurately the nature of thepotential difference.

Voltage rise is a rise in potential measured in thedirection of current flow between two points in a circuit.Voltage drop is the converse. A circuit element with avoltage rise across it acts as a source of energy. A circuitelement with a voltage drop across it acts as a sink ofenergy. Voltage sources are usually active circuitelements, while sinks are usually passive circuitelements. The positive direction of energy flow is fromsources to sinks.

Kirchhoff's first law states that the sum of the drivingvoltages must equal the sum of the passive voltages in aclosed loop. This is illustrated by the fundamentalequation of an electric circuit:

…Equation 3.12

where the terms on the left hand side of the equation arevoltage drops across the circuit elements. Expressed in

iR Ldidt C

idt e+ + =∫1

I I

E E

m

m

=

=

2

2

steady state terms Equation 3.12 may be written:

…Equation 3.13

and this is known as the equated-voltage equation [3.1].

It is the equation most usually adopted in electricalnetwork calculations, since it equates the drivingvoltages, which are known, to the passive voltages,which are functions of the currents to be calculated.

In describing circuits and drawing vector diagrams, forformal analysis or calculations, it is necessary to adopt anotation which defines the positive direction of assumedcurrent flow, and establishes the direction in whichpositive voltage drops and voltage rises act. Twomethods are available; one, the double suffix method, isused for symbolic analysis, the other, the single suffix ordiagrammatic method, is used for numericalcalculations.

In the double suffix method the positive direction ofcurrent flow is assumed to be from node a to node b andthe current is designated Iab . With the diagrammaticmethod, an arrow indicates the direction of current flow.

The voltage rises are positive when acting in thedirection of current flow. It can be seen from Figure 3.4that

—E1 and

—Ean are positive voltage rises and

—E2 and—

Ebn are negative voltage rises. In the diagrammaticmethod their direction of action is simply indicated by anarrow, whereas in the double suffix method,

—Ean and

—Ebn

indicate that there is a potential rise in directions na and nb.

Figure 3.4 Methods or representing a circuit

E IZ∑ ∑=

• 3 •F

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(a) Diagrammatic

(b) Double suffix

a b

n

abI

Z3

Z2Z1

E1

Zan

Zab

Ean

Zbn

Ebn

E2

E1-E2=(Z1+Z2+Z3)I

Ean-Ebn=(Zan+Zab+Zbn)Iab

I

Figure 3.4 Methods of representing a circuit

Chap3-16-29 1/07/02 8:26 Page 21


Voltage drops are also positive when acting in thedirection of current flow. From Figure 3.4(a) it can beseen that (

—Z1+

—Z2+

—Z3)

—I is the total voltage drop in the

loop in the direction of current flow, and must equate tothe total voltage rise

—E1-

—E2. In Figure 3.4(b), the voltage

drop between nodes a and b designated —Vab indicates

that point b is at a lower potential than a, and is positivewhen current flows from a to b. Conversely

—Vba is a

negative voltage drop.

Symbolically:—Vab =

—Van -

—Vbn

—Vba =

—Vbn -

—Van …Equation 3.14

where n is a common reference point.

3.4.3 Power

The product of the potential difference across and thecurrent through a branch of a circuit is a measure of therate at which energy is exchanged between that branchand the remainder of the circuit. If the potentialdifference is a positive voltage drop, the branch ispassive and absorbs energy. Conversely, if the potentialdifference is a positive voltage rise, the branch is activeand supplies energy.

The rate at which energy is exchanged is known aspower, and by convention, the power is positive whenenergy is being absorbed and negative when beingsupplied. With a.c. circuits the power alternates, so, toobtain a rate at which energy is supplied or absorbed, itis necessary to take the average power over one wholecycle.If e=Emsin(wt+δ) and i=Imsin(wt+δ-φ), then the powerequation is:

p=ei=P[1-cos2(wt+δ)]+Qsin2(wt+δ)

…Equation 3.15where:

P=|E||I|cosφ and

Q=|E||I|sinφ

From Equation 3.15 it can be seen that the quantity Pvaries from 0 to 2P and quantity Q varies from -Q to +Qin one cycle, and that the waveform is of twice theperiodic frequency of the current voltage waveform.

The average value of the power exchanged in one cycleis a constant, equal to quantity P, and as this quantity isthe product of the voltage and the component of currentwhich 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 overa cycle, suggesting that energy is stored in one half-cycleand 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 which specify the powerexchange in a given circuit, and are products of thecurrent and voltage vectors, then if

—S is the vector

product —E

—I it follows that with

—E as the reference vector

and φ as the angle between—E and

—I :

—S = 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.

3.4.4 Single-Phase and Polyphase Systems

A system is single or polyphase depending upon whetherthe sources feeding it are single or polyphase. A sourceis single or polyphase according to whether there are oneor several driving voltages associated with it. Forexample, a three-phase source is a source containingthree alternating driving voltages that are assumed toreach a maximum in phase order, A, B, C. Each phasedriving voltage is associated with a phase branch of thesystem network as shown in Figure 3.5(a).

If a polyphase system has balanced voltages, that is,equal in magnitude and reaching a maximum at equallydisplaced time intervals, and the phase branchimpedances are identical, it is called a 'balanced' system.It will become 'unbalanced' if any of the aboveconditions are not satisfied. Calculations using abalanced polyphase system are simplified, as it is onlynecessary to solve for a single phase, the solution for theremaining phases being obtained by symmetry.

The power system is normally operated as a three-phase,balanced, system. For this reason the phase voltages areequal in magnitude and can be represented by threevectors spaced 120° or 2π/3 radians apart, as shown inFigure 3.5(b).

• 3 •

Fun

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l T

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y

• 2 2 •

Figure 3.5: Three-phase systems

(a) Three-phase system

BC B'C'N N'

EanEcn Ebn

A'A

Phase branches

Direction of rotation

(b) Balanced system of vectors

120°

120°

120°

Ea

Ec=aEa Eb=a2Ea

Chap3-16-29 1/07/02 8:26 Page 22


Since the voltages are symmetrical, they may beexpressed in terms of one, that is:

—Ea =

—Ea

—Eb = a2

—Ea

—Ec = a

—Ea …Equation 3.17

where a is the vector operator e j2π/3. Further, if the phasebranch impedances are identical in a balanced system, itfollows that the resulting currents are also balanced.

3.5 IMPEDANCE NOTATION

It can be seen by inspection of any power systemdiagram that:

a. several voltage levels exist in a system

b. it is common practice to refer to plant MVA interms of per unit or percentage values

c. transmission line and cable constants are given inohms/km

Before any system calculations can take place, thesystem parameters must be referred to 'base quantities'and represented as a unified system of impedances ineither 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 MVAand the line voltage in kV. The base impedance resultingfrom the above base quantities is:

ohms …Equation 3.18

and, provided the system is balanced, the baseimpedance may be calculated using either single-phaseor three-phase quantities.

The per unit or percentage value of any impedance in thesystem is the ratio of actual to base impedance values.

Hence:

…Equation 3.19

where MVAb = base MVA

kVb = base kV

Simple transposition of the above formulae will refer theohmic value of impedance to the per unit or percentagevalues and base quantities.

Having chosen base quantities of suitable magnitude all

Z p u Z ohms MVA

kV

Z Z p u

b

b

. .

% . .

( )= ( )×( )

( )= ( )×

2

100

ZkV

MVAb =( )2

system impedances may be converted to those basequantities by using the equations given below:

…Equation 3.20

where suffix b1 denotes the value to the original base

and b2 denotes the value to new base

The choice of impedance notation depends upon thecomplexity of the system, plant impedance notation andthe nature of the system calculations envisaged.

If the system is relatively simple and contains mainlytransmission line data, given in ohms, then the ohmicmethod can be adopted with advantage. However, theper unit method of impedance notation is the mostcommon for general system studies since:

1. impedances are the same referred to either side ofa transformer if the ratio of base voltages on thetwo sides of a transformer is equal to thetransformer turns ratio

2. confusion caused by the introduction of powers of100 in percentage calculations is avoided

3. by a suitable choice of bases, the magnitudes ofthe data and results are kept within a predictablerange, and hence errors in data and computationsare easier to spot

Most power system studies are carried out usingsoftware in per unit quantities. Irrespective of themethod of calculation, the choice of base voltage, andunifying system impedances to this base, should beapproached with caution, as shown in the followingexample.

Z Z MVAMVA

Z Z kVkV

b bb

b

b bb

b

2 12

1

2 11

2

2

= ×

= ×

• 3 •F

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Figure 3.6: Selection of base voltages

11.8kV 11.8/141kV

132kVOverhead line

132/11kV

Distribution11kV

Wrong selection of base voltage

11.8kV 132kV 11kV

Right selection

11.8kV 141kV x 11=11.7kV141132

Chap3-16-29 1/07/02 8:26 Page 23


From Figure 3.6 it can be seen that the base voltages inthe three circuits are related by the turns ratios of theintervening transformers. Care is required as thenominal transformation ratios of the transformersquoted may be different from the turns ratios- e.g. a110/33kV (nominal) transformer may have a turns ratioof 110/34.5kV. Therefore, the rule for hand calculationsis: 'to refer an impedance in ohms from one circuit toanother multiply the given impedance by the square ofthe turns ratio (open circuit voltage ratio) of theintervening transformer'.

Where power system simulation software is used, thesoftware normally has calculation routines built in toadjust transformer parameters to take account ofdifferences between the nominal primary and secondaryvoltages and turns ratios. In this case, the choice of basevoltages may be more conveniently made as the nominalvoltages of each section of the power system. Thisapproach avoids confusion when per unit or percentvalues are used in calculations in translating the finalresults into volts, amps, etc.

For example, in Figure 3.7, generators G1 and G2 have asub-transient reactance of 26% on 66.6MVA rating at11kV, and transformers T1 and T2 a voltage ratio of11/145kV and an impedance of 12.5% on 75MVA.Choosing 100MVA as base MVA and 132kV as basevoltage, find the percentage impedances to new basequantities.

a. Generator reactances to new bases are:

b. Transformer reactances to new bases are:

NOTE: The base voltages of the generator and circuitsare 11kV and 145kV respectively, that is, the turnsratio of the transformer. The corresponding per unitvalues can be found by dividing by 100, and the ohmicvalue can be found by using Equation 3.19.

Figure 3.7

12 5 10075

145

13220 1

2

2. . %× ×( )( )

=

26 10066 6

11

1320 27

2

2× ×( )

( )=

.. %

3.6 BASIC CIRCUIT LAWS,THEOREMS AND NETWORK REDUCTION

Most practical power system problems are solved byusing steady state analytical methods. The assumptionsmade are that the circuit parameters are linear andbilateral and constant for constant frequency circuitvariables. In some problems, described as initial valueproblems, it is necessary to study the behaviour of acircuit in the transient state. Such problems can besolved using operational methods. Again, in otherproblems, which fortunately are few in number, theassumption of linear, bilateral circuit parameters is nolonger valid. These problems are solved using advancedmathematical techniques that are beyond the scope ofthis book.

3.6.1 Circuit Laws

In linear, bilateral circuits, three basic network lawsapply, regardless of the state of the circuit, at anyparticular instant of time. These laws are the branch,junction and mesh laws, due to Ohm and Kirchhoff, andare stated below, using steady state a.c. nomenclature.

3.6.1.1 Branch law

The current—I in a given branch of impedance

—Z is

proportional to the potential difference—V appearing

across the branch, that is,—V =

—I

—Z .

3.6.1.2 Junction law

The algebraic sum of all currents entering any junction(or node) in a network is zero, that is:

3.6.1.3 Mesh law

The algebraic sum of all the driving voltages in anyclosed path (or mesh) in a network is equal to thealgebraic sum of all the passive voltages (products of theimpedances and the currents) in the componentsbranches, that is:

Alternatively, the total change in potential around aclosed loop is zero.

3.6.2 Circuit Theorems

From the above network laws, many theorems have beenderived for the rationalisation of networks, either toreach a quick, simple, solution to a problem or torepresent a complicated circuit by an equivalent. Thesetheorems are divided into two classes: those concernedwith the general properties of networks and those

E ZI=∑∑

I =∑ 0

• 3 •

Fun

dam

enta

l T

heor

y

• 2 4 •

Figure 3.7: Section of a power system

G1

T1

T2

G2

132kVoverheadlines

Chap3-16-29 21/06/02 10:28 Page 24


concerned with network reduction.

Of the many theorems that exist, the three mostimportant are given. These are: the SuperpositionTheorem, Thévenin's Theorem and Kennelly's Star/DeltaTheorem.

3.6.2.1 Superposition Theorem(general network theorem)

The resultant current that flows in any branch of anetwork due to the simultaneous action of severaldriving voltages is equal to the algebraic sum of thecomponent currents due to each driving voltage actingalone with the remainder short-circuited.

3.6.2.2 Thévenin's Theorem(active network reduction theorem)

Any active network that may be viewed from twoterminals can be replaced by a single driving voltageacting in series with a single impedance. The drivingvoltage is the open-circuit voltage between the twoterminals and the impedance is the impedance of thenetwork viewed from the terminals with all sourcesshort-circuited.

3.6.2.3 Kennelly's Star/Delta Theorem(passive network reduction theorem)

Any three-terminal network can be replaced by a delta orstar impedance equivalent without disturbing theexternal network. The formulae relating the replacementof a delta network by the equivalent star network is asfollows (Figure 3.8):

—Zco =

—Z13

—Z23 / (

—Z12 +

—Z13 +

—Z23)

and so on.

Figure 3.8: Star/Delta network reduction

The impedance of a delta network corresponding to andreplacing any star network is:

—Z12 = —Zao +

—Zbo +—Zao

—Zbo

—————————Zco

and so on.

3.6.3 Network Reduction

The aim of network reduction is to reduce a system to asimple equivalent while retaining the identity of thatpart 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 AOBshunted by an impedance, which may be regarded as thereduction of a further network connected between A andB, and a load connected between O and N. The object ofthe reduction is to study the effect of opening a breakerat A or B during normal system operations, or of a faultat A or B. Thus the identity of nodes A and B must beretained together with the sources, but the branch ONcan be eliminated, simplifying the study. Proceeding, A,B, N, forms a star branch and can therefore be convertedto an equivalent delta.

Figure 3.9

= 51 ohms

=30.6 ohms

= 1.2 ohms (since ZNO>>> ZAOZBO)

Figure 3.10

Z Z Z Z ZZAN AO BOAO BO

NO

= + +

= + + ×0 45 18 85 0 45 18 850 75

. . . ..

Z Z Z Z ZZBN BO NOBO NO

AO

= + +

= + + ×0 75 18 85 0 75 18 850 45

. . . ..

Z Z Z Z ZZAN AO NOAO NO

BO

= + +

• 3 •F

unda

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tal

The

ory

Figure 3.8: Star-Delta network transformation

c

Zao Zbo Z12

Z23Z13

Oa b 1 2

3

(a) Star network (b) Delta network

Zco

Figure 3.9: Typical power system network

E' E''

N

0A B

1.6Ω

0.75Ω 0.45Ω

18.85Ω

2.55Ω

0.4Ω

Chap3-16-29 21/06/02 10:28 Page 25


The network is now reduced as shown in Figure 3.10.

By applying Thévenin's theorem to the active loops, thesecan be replaced by a single driving voltage in series withan impedance as shown in Figure 3.11.

Figure 3.11

The network shown in Figure 3.9 is now reduced to thatshown in Figure 3.12 with the nodes A and B retainingtheir identity. Further, the load impedance has beencompletely eliminated.

The network shown in Figure 3.12 may now be used tostudy system disturbances, for example power swingswith and without faults.

Figure 3.12

Most reduction problems follow the same pattern as theexample above. The rules to apply in practical networkreduction are:

a. decide on the nature of the disturbance ordisturbances to be studied

b. decide on the information required, for examplethe branch currents in the network for a fault at aparticular location

c. reduce all passive sections of the network notdirectly involved with the section underexamination

d. reduce all active meshes to a simple equivalent,that is, to a simple source in series with a singleimpedance

With the widespread availability of computer-basedpower system simulation software, it is now usual to usesuch software on a routine basis for network calculationswithout significant network reduction taking place.However, the network reduction techniques given aboveare still valid, as there will be occasions where suchsoftware is not immediately available and a handcalculation must be carried out.

In certain circuits, for example parallel lines on the sametowers, there is mutual coupling between branches.Correct circuit reduction must take account of thiscoupling.

Figure 3.13

Three cases are of interest. These are:

a. two branches connected together at their nodes

b. two branches connected together at one node only

c. two branches that remain unconnected

• 3 •

Fun

dam

enta

l T

heor

y

• 2 6 •

Figure 3.10: Reduction usingstar/delta transform

E'

A

51Ω 30.6Ω

0.4Ω

2.5Ω

1.2Ω1.6Ω

N

B

E''

Figure 3.12: Reduction of typicalpower system network

N

A B

1.2Ω

2.5Ω

1.55Ω

0.97E'

0.39Ω

0.99E''

Figure 3.11: Reduction of active meshes: Thévenin's Theorem

E'

A

N

(a) Reduction of left active mesh

N

A

(b) Reduction of right active mesh

E''

N

B B

N

E''31

30.630.6Ω

Ω31

0.4 x 30.6

Ω52.6

1.6 x 51

E'52.65151Ω

1.6Ω

0.4Ω

Figure 3.13: Reduction of two brancheswith mutual coupling

(a) Actual circuit

IP Q

P Q

(b) Equivalent when Zaa≠Zbb

(c) Equivalent when Zaa=Zbb

P Q

21Z= (Zaa+Zbb)

Zaa

Zbb

Z=ZaaZbb-Z2

ab

Zaa+Zbb-2Zab

Zab

Ia

Ib

I

I

Chap3-16-29 21/06/02 10:28 Page 26


Considering each case in turn:

a. consider the circuit shown in Figure 3.13(a). Theapplication of a voltage V between the terminals Pand Q gives:

V = IaZaa + IbZab

V = IaZab + IbZbb

where Ia and Ib are the currents in branches a andb, respectively and I = Ia + Ib , the total currententering at terminal P and leaving at terminal Q.

Solving for Ia and Ib :

from which

and

so that the equivalent impedance of the originalcircuit is:

…Equation 3.21

(Figure 3.13(b)), and, if the branch impedances areequal, the usual case, then:

…Equation 3.22

(Figure 3.13(c)).

b. consider the circuit in Figure 3.14(a).

Z Z Zaa ab= +( )12

Z VI

Z Z ZZ Z Z

aa bb ab

aa bb ab

= = −+ −

2

2

I I IV Z Z Z

Z Z Za baa bb ab

aa bb ab

= + =+ −( )

−22

IZ Z V

Z Z Zbaa ab

aa bb ab

=−( )

− 2

IZ Z V

Z Z Zabb ab

aa bb ab

=−( )

− 2

The assumption is made that an equivalent starnetwork can replace the network shown. Frominspection with one terminal isolated in turn and avoltage V impressed across the remaining terminalsit can be seen that:

Za+Zc=Zaa

Zb+Zc=Zbb

Za+Zb=Zaa+Zbb-2Zab

Solving these equations gives:

…Equation 3.23

-see Figure 3.14(b).

c. consider the four-terminal network given in Figure3.15(a), in which the branches 11' and 22' areelectrically separate except for a mutual link. Theequations defining the network are:

V1=Z11I1+Z12I2

V2=Z21I1+Z22I2

I1=Y11V1+Y12V2

I2=Y21V1+Y22V2

where Z12=Z21 and Y12=Y21 , if the network isassumed to be reciprocal. Further, by solving theabove equations it can be shown that:

…Equation 3.24

There are three independent coefficients, namelyZ12, Z11, Z22, so the original circuit may bereplaced by an equivalent mesh containing fourexternal terminals, each terminal being connectedto the other three by branch impedances as shownin Figure 3.15(b).

Y Z

Y Z

Y Z

Z Z Z

11 22

22 11

12 12

11 22 122

=

=

=

= −

∆

∆

∆

∆

Z Z Z

Z Z Z

Z Z

a aa ab

b bb ab

c ab

= −

= −

=

• 3 •F

unda

men

tal

The

ory

Figure 3.14: Reduction of mutually-coupled brancheswith a common terminal

A

C

B


B

C

A

(a) Actual circuit

Zaa

Zbb

Zab

Za=Zaa-Zab

Zb=Zbb-Zab

Zc=Zab

Figure 3.15 : Equivalent circuits forfour terminal network with mutual coupling

(a) Actual circuit

2

1

2'

1'

2'

1'


2

1Z11

Z22

Z11

Z22

Z12 Z12 Z12 Z12Z21

Chap3-16-29 21/06/02 10:28 Page 27


defining the equivalent mesh in Figure 3.15(b), andinserting radial branches having impedances equalto Z11 and Z22 in terminals 1 and 2, results inFigure 3.15(d).

3.7 REFERENCES

3.1 Power System Analysis. J. R. Mortlock andM. 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 •

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dam

enta

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Figure 3.15: Equivalent circuits forfour terminal network with mutual coupling

2'

1'

(d) Equivalent circuit

11

C 2

(c) Equivalent with all nodes commoned except 1

Z11 Z12

Z11

Z12

Z12

Z12

-Z12 -Z12Z12

In order to evaluate the branches of the equivalentmesh let all points of entry of the actual circuit becommoned except node 1 of circuit 1, as shown inFigure 3.15(c). Then all impressed voltages exceptV1 will be zero and:

I1 = Y11V1

I2 = Y12V1

If the same conditions are applied to the equivalentmesh, then:

I1 = V1Z11

I2 = -V1/Z12 = -V1/Z12

These relations follow from the fact that the branchconnecting nodes 1 and 1' carries current I1 andthe branches connecting nodes 1 and 2' and 1 and2 carry current I2. This must be true since branchesbetween pairs of commoned nodes can carry nocurrent.

By considering each node in turn with theremainder commoned, the following relationshipsare found:

Z11’ = 1/Y11

Z22’ = 1/Y22

Z12’ = -1/Y12

Z12 = Z1’ 2’ = -Z21’ = -Z12’

Hence:

Z11’ = Z11Z22-Z212_______________Z22

Z22’ = Z11Z22-Z212_______________Z11

Z12 = Z11Z22-Z212_______________Z12 …Equation 3.25

A similar but equally rigorous equivalent circuit isshown in Figure 3.15(d). This circuit [3.2] followsfrom the fact that the self-impedance of any circuitis independent of all other circuits. Therefore, itneed not appear in any of the mutual branches if itis lumped as a radial branch at the terminals. Soputting Z11 and Z22 equal to zero in Equation 3.25,

Chap3-16-29 21/06/02 10:28 Page 28

Introduction 7.1

Electromechanical relays 7.2

Static relays 7.3

Digital relays 7.4

Numerical relays 7.5

Additional features of numerical relays 7.6

Numerical relay issues 7.7

References 7.8

• 7 • R e l a y T e c h n o l o g y

Chap7-98-111 21/06/02 9:07 Page 98

7.1 INTRODUCTION

The last thirty years have seen enormous changes in relaytechnology. The electromechanical relay in all of itsdifferent forms has been replaced successively by static,digital and numerical relays, each change bringing withit reductions and size and improvements in functionality.At the same time, reliability levels have been maintainedor even improved and availability significantly increaseddue to techniques not available with older relay types.This represents a tremendous achievement for all thoseinvolved in relay design and manufacture.

This chapter charts the course of relay technologythrough the years. As the purpose of the book is todescribe modern protection relay practice, it is naturaltherefore to concentrate on digital and numerical relaytechnology. The vast number of electromechanical andstatic relays are still giving dependable service, butdescriptions on the technology used must necessarily besomewhat brief. For those interested in the technologyof electromechanical and static technology, moredetailed descriptions can be found in reference [7.1].

7.2 ELECTROMECHANICAL RELAYS

These relays were the earliest forms of relay used for theprotection of power systems, and they date back nearly100 years. They work on the principle of a mechanicalforce causing operation of a relay contact in response toa stimulus. The mechanical force is generated throughcurrent flow in one or more windings on a magnetic coreor cores, hence the term electromechanical relay. Theprinciple advantage of such relays is that they providegalvanic isolation between the inputs and outputs in asimple, cheap and reliable form – therefore for simpleon/off switching functions where the output contactshave to carry substantial currents, they are still used.

Electromechanical relays can be classified into severaldifferent types as follows:

a. attracted armatureb. moving coilc. inductiond. thermale. motor operatedf. mechanical

However, only attracted armature types have significant

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application at this time, all other types having beensuperseded by more modern equivalents.

7.2.1 Attracted Armature Relays

These generally consist of an iron-cored electromagnetthat attracts a hinged armature when energised. Arestoring force is provided by means of a spring orgravity so that the armature will return to its originalposition when the electromagnet is de-energised.Typical forms of an attracted armature relay are shownin Figure 7.1. Movement of the armature causes contactclosure or opening, the armature either carrying amoving contact that engages with a fixed one, or causesa rod to move that brings two contacts together. It isvery easy to mount multiple contacts in rows or stacks,and hence cause a single input to actuate a number ofoutputs. The contacts can be made quite robust andhence able to make, carry and break relatively largecurrents under quite onerous conditions (highly inductivecircuits). This is still a significant advantage of this typeof relay that ensures its continued use.

The energising quantity can be either an a.c. or a d.c.current. If an a.c. current is used, means must beprovided to prevent the chatter that would occur fromthe flux passing through zero every half cycle. Acommon solution to the problem is to split the magneticpole and provide a copper loop round one half. The fluxchange is now phase-shifted in this pole, so that at notime is the total flux equal to zero. Conversely, for relaysenergised using a d.c. current, remanent flux mayprevent the relay from releasing when the actuatingcurrent is removed. This can be avoided by preventingthe armature from contacting the electromagnet by anon-magnetic stop, or constructing the electromagnetusing a material with very low remanent flux properties.

Operating speed, power consumption and the numberand type of contacts required are a function of thedesign. The typical attracted armature relay has anoperating speed of between 100ms and 400ms, but reedrelays (whose use spanned a relatively short period in thehistory of protection relays) with light current contactscan be designed to have an operating time of as little as1msec. Operating power is typically 0.05-0.2 watts, butcould be as large as 80 watts for a relay with severalheavy-duty contacts and a high degree of resistance tomechanical shock.

Some applications require the use of a polarised relay. This

S N

Permanentmagnet

Core

Armature

Coil

Figure 7.2: Typical polarised relay

Figure 7.3: Typical attracted armature relay mounted in case

(a) D.C. relay (c) Solenoid relay

(b) Shading loop modification to pole of relay (a) for a.c. operation

(d) Reed relay

Figure 7.1: Typical attracted armature relays

Chap7-98-111 21/06/02 9:07 Page 100

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can be simply achieved by adding a permanent magnet tothe basic electromagnet. Both self-reset and bi-stableforms can be achieved. Figure 7.2 shows the basicconstruction. One possible example of use is to providevery fast operating times for a single contact, speeds of lessthan 1ms being possible. Figure 7.3 illustrates a typicalexample of an attracted armature relay.

7.3 STATIC RELAYS

The term ‘static’ implies that the relay has no movingparts. This is not strictly the case for a static relay, as theoutput contacts are still generally attracted armaturerelays. In a protection relay, the term ‘static’ refers to theabsence of moving parts to create the relaycharacteristic.

Introduction of static relays began in the early 1960’s.Their design is based on the use of analogue electronicdevices instead of coils and magnets to create the relaycharacteristic. Early versions used discrete devices suchas transistors and diodes in conjunction with resistors,capacitors, inductors, etc., but advances in electronicsenabled the use of linear and digital integrated circuitsin later versions for signal processing andimplementation of logic functions. While basic circuitsmay be common to a number of relays, the packagingwas still essentially restricted to a single protectionfunction per case, while complex functions requiredseveral cases of hardware suitably interconnected. Userprogramming was restricted to the basic functions ofadjustment of relay characteristic curves. They thereforecan be viewed in simple terms as an analogue electronicreplacement for electromechanical relays, with someadditional flexibility in settings and some saving in spacerequirements. In some cases, relay burden is reduced,making for reduced CT/VT output requirements.

A number of design problems had to be solved with staticrelays. In particular, the relays generally require areliable source of d.c. power and measures to preventdamage to vulnerable electronic circuits had to bedevised. Substation environments are particularly hostileto electronic circuits due to electrical interference ofvarious forms that are commonly found (e.g. switchingoperations and the effect of faults). While it is possibleto arrange for the d.c. supply to be generated from themeasured quantities of the relay, this has thedisadvantage of increasing the burden on the CT’s or VT’s,and there will be a minimum primary current or voltagebelow which the relay will not operate. This directlyaffects the possible sensitivity of the relay. So provisionof an independent, highly reliable and secure source ofrelay power supply was an important consideration. Toprevent maloperation or destruction of electronic devicesduring faults or switching operations, sensitive circuitryis housed in a shielded case to exclude common modeand radiated interference. The devices may also besensitive to static charge, requiring special precautionsduring handling, as damage from this cause may not beimmediately apparent, but become apparent later in theform of premature failure of the relay. Therefore, radicallydifferent relay manufacturing facilities are requiredcompared to electromechanical relays. Calibration andrepair is no longer a task performed in the field withoutspecialised equipment. Figure 7.4 shows the circuit boardfor a simple static relay and Figure 7.5 shows examples ofsimple and complex static relays.

Figure 7.4: Circuit board of static relay

Figure 7.5: Selection of static relays

Chap7-98-111 21/06/02 9:08 Page 101

7.4 DIGITAL RELAYSDigital protection relays introduced a step change intechnology. Microprocessors and microcontrollersreplaced analogue circuits used in static relays toimplement relay functions. Early examples began to beintroduced into service around 1980, and, withimprovements in processing capacity, can still be regardedas current technology for many relay applications.However, such technology will be completely supersededwithin the next five years by numerical relays.

Compared to static relays, digital relays introduce A/Dconversion of all measured analogue quantities and usea microprocessor to implement the protection algorithm.The microprocessor may use some kind of countingtechnique, or use the Discrete Fourier Transform (DFT) toimplement the algorithm. However, the typicalmicroprocessors used have limited processing capacityand memory compared to that provided in numericalrelays. The functionality tends therefore to be limitedand restricted largely to the protection function itself.Additional functionality compared to that provided by anelectromechanical or static relay is usually available,typically taking the form of a wider range of settings,and greater accuracy. A communications link to aremote computer may also be provided.

The limited power of the microprocessors used in digitalrelays restricts the number of samples of the waveformthat can be measured per cycle. This, in turn, limits thespeed of operation of the relay in certain applications.Therefore, a digital relay for a particular protectionfunction may have a longer operation time than thestatic relay equivalent. However, the extra time is notsignificant in terms of overall tripping time and possibleeffects of power system stability. Examples of digitalrelays are shown in Figure 7.6.

7.5 NUMERICAL RELAYS

The distinction between digital and numerical relay restson points of fine technical detail, and is rarely found inareas other than Protection. They can be viewed asnatural developments of digital relays as a result ofadvances in technology. Typically, they use a specialiseddigital signal processor (DSP) as the computationalhardware, together with the associated software tools.The input analogue signals are converted into a digitalrepresentation and processed according to the appropriatemathematical algorithm. Processing is carried out using aspecialised microprocessor that is optimised for signalprocessing applications, known as a digital signalprocessor or DSP for short. Digital processing of signals inreal time requires a very high power microprocessor.

In addition, the continuing reduction in the cost ofmicroprocessors and related digital devices (memory, I/O,etc.) naturally leads to an approach where a single itemof hardware is used to provide a range of functions(‘one-box solution’ approach). By using multiplemicroprocessors to provide the necessary computationalperformance, a large number of functions previouslyimplemented in separate items of hardware can now beincluded within a single item. Table 7.1 provides a list oftypical functions available, while Table 7.2 summarisesthe advantages of a modern numerical relay over thestatic equivalent of only 10-15 years ago. Figure 7.7shows typical numerical relays, and a circuit board isshown in Figure 7.8. Figure 7.9 provides an illustration ofthe savings in space possible on a HV feeder showing thespace requirement for relays with electromechanical andnumerical relay technology to provide the samefunctionality.

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• 1 0 2 •

Figure 7.6: Selection of digital relays Table 7.1: Numerical distance relay features

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

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

Chap7-98-111 21/06/02 9:08 Page 102


Because a numerical relay may implement thefunctionality that used to require several discrete relays,the relay functions (overcurrent, earth fault, etc.) arenow referred to as being ‘relay elements’, so that asingle relay (i.e. an item of hardware housed in a singlecase) may implement several functions using severalrelay elements. Each relay element will typically be asoftware routine or routines.

The argument against putting many features into onepiece of hardware centres on the issues of reliability andavailability. A failure of a numerical relay may causemany more functions to be lost, compared to applicationswhere different functions are implemented by separatehardware items. Comparison of reliability and availabilitybetween the two methods is complex as inter-dependency of elements of an application provided byseparate relay elements needs to be taken into account.

With the experience gained with static and digital relays,most hardware failure mechanisms are now well

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Table 7.2: Advantages ofnumerical protection relays over static

Several setting groups

Wider range of parameter adjustment

Remote communications built in

Internal Fault diagnosis

Power system measurements available

Distance to fault locator

Disturbance recorder

Auxiliary protection functions ( broken conductor, negative sequence, etc.)

CB monitoring (state, condition)

User-definable logic

Backup protection functions in-built

Consistency of operation times - reduced grading margin

Figure 7.7: Typical numerical relays

Chap7-98-111 21/06/02 9:08 Page 103

the design. It must work at high speed, use lowvoltage levels and yet be immune to conducted andradiated interference from the electrically noisysubstation environment. Excellent shielding of therelevant areas is therefore required. Digital inputs areoptically isolated to prevent transients beingtransmitted to the internal circuitry. Analogue inputsare isolated using precision transformers to maintainmeasurement accuracy while removing harmful

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understood and suitable precautions taken at the designstage. Software problems are minimised by rigorous useof software design techniques, extensive prototypetesting (see Chapter 21) and the ability to downloadamended software into memory (possibly using a remotetelephone link for download). Practical experienceindicates that numerical relays are at least as reliableand have at least as good a record of availability asrelays of earlier technologies.

As the technology of numerical relays has only becomeavailable in recent years, a presentation of the conceptsbehind a numerical relay is presented in the followingsections.

7.5.1 Hardware Architecture

The typical architecture of a numerical relay is shownin Figure 7.10. It consists of one or more DSPmicroprocessors, some memory, digital and analogueinput/output (I/O), and a power supply. Wheremultiple processors are provided, it is usual for one ofthem to be dedicated to executing the protection relayalgorithms, while the remainder implements anyassociated logic and handles the Human MachineInterface (HMI) interfaces. By organising the I/O on aset of plug-in printed circuit boards (PCB’s), additionalI/O up to the limits of the hardware/software can beeasily added. The internal communications bus linksthe hardware and therefore is critical component in

Figure 7.8: Circuit board for numerical relay

Figure 7.9: Space requirements of different relay technologies for same functionality

Chap7-98-111 21/06/02 9:08 Page 104

transients. Additionally, the input signals must beamplitude limited to avoid them exceeding the powersupply voltages, as otherwise the waveform will appeardistorted, as shown in Figure 7.11.

Analogue signals are converted to digital form using anA/D converter. The cheapest method is to use a singleA/D converter, preceded by a multiplexer to connecteach of the input signals in turn to the converter. Thesignals may be initially input to a number ofsimultaneous sample-and–hold circuits prior tomultiplexing, or the time relationship betweensuccessive samples must be known if the phaserelationship between signals is important. Thealternative is to provide each input with a dedicated A/Dconverter, and logic to ensure that all convertersperform the measurement simultaneously.

The frequency of sampling must be carefully considered,as the Nyquist criterion applies:

fs ≥ 2 x fh

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Figure 7.10: Relay modules and information flow

Batterybacked-up

SRAMSRAM

FlashEPROM

Front LCD panel RS232 Front comms port

Parallel test port

Main processor boardLEDs

CPU

Present valuesof all settings

CPU code & datasetting database

data

Alarm, event, fault &maintenance records

Default settings &parameters language text

software code

IRIG - B board(optional)

IRIG - B signal

Fibre opticrear commsport optional

Comms betwenmain & compressor

boards

CPU code& data

FPGA SRAM

CPU

Coprocessor board

Seria

l dat

a bu

s(s

ampl

e da

ta)

Opt

o-is

olat

edin

puts

Input boardADC

Digi

tal i

nput

s (x

8 or

x16

)

Out

put

rela

ys

Relay board

Out

put

rela

y co

ntac

ts(x

14 o

r x21

)

Timingdata

Parallel data busPower supply, rear comms,data, output relay status Digital input values

Power supplyboard

Transformerboard

Power supply (3 voltages),rear comms data Analogue input signals

Current & voltage inputs (6 to 8)Rear RS485communication port

Fieldvoltage

Watchdogcontacts

Powersupply

E2 PROM

Legend:

SRAM - Static Read Only MemoryCPU - Central Procesing UnitIRIG-B - Time Synchronisation SignalFPGA - Field Programmable Logic ArrayADC - Analog to Digital ConverterE 2PROM - Electrically Erasable Programmable Read Only MemoryEPROM - Electrically Programmable Read Only MemoryLCD - Liquid Crystal Display

where:

fs = sampling frequency

fh = highest frequency of interest

If too low a sampling frequency is chosen, aliasing of theinput signal can occur (Figure 7.12), resulting in highfrequencies appearing as part of signal in the frequencyrange of interest. Incorrect results will then be obtained.The solution is to apply an anti-aliasing filter, coupledwith an appropriate choice of sampling frequency, to theanalogue signal, so those frequency components thatcould cause aliasing are filtered out. Digital sine andcosine filters are used (Figure 7.13), with a frequencyresponse shown in Figure 7.14, to extract the real andimaginary components of the signal. Frequency trackingof the input signals is applied to adjust the samplingfrequency so that the desired number of samples/cycle isalways obtained. A modern numerical relay may sampleeach analogue input quantity at between 16 and 24samples per cycle.

Chap7-98-111 21/06/02 9:08 Page 105

All subsequent signal processing is carried out digitally insoftware, final digital outputs use relays to provideisolation or are sent via an external communications busto other devices.

7.5.2 Relay Software

The software provided is commonly organised into aseries of tasks, operating in real time. An essentialcomponent is the Real Time Operating System (RTOS),whose function is to ensure that the other tasks areexecuted as and when required, on a priority basis.

Other task software provided will naturally varyaccording to the function of the specific relay, but can begeneralised as follows:

a. system services software – this is akin to the BIOSof an ordinary PC, and controls the low-level I/Ofor the relay (i.e. drivers for the relay hardware,boot-up sequence, etc.)

b. HMI interface software – the high level softwarefor communicating with a user, via the front panelcontrols or through a data link to anothercomputer running suitable software, storage ofsetting data, etc.

c. application software – this is the software thatdefines the protection function of the relay

d. auxiliary functions – software to implement otherfeatures offered in the relay – often structured asa series of modules to reflect the options offered toa user by the manufacturer

7.5.3 Application Software

The relevant software algorithm is then applied. Firstly,the values of the quantities of interest have to bedetermined from the available information contained inthe data samples. This is conveniently done by theapplication of the Discrete Fourier Transform (DFT), and

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+Vref

Vref

Vref

Vout

-Vref

Vin

Figure 7.11: Signal distortiondue to excessive amplitude

Apparent signal

Actual signal

Sample points

Figure 7.12: Signal aliasing problem

Chap7-98-111 22/06/02 9:53 Page 106

b. timer expired – action alarm/trip

c. value returned below setting – reset timers, etc.

d. value below setting – do nothing

e. value still above setting – increment timer, etc.

Since the overall cycle time for the software is known,timers are generally implemented as counters.

7.6 ADDIT IONAL FEATURESOF NUMERICAL RELAYS

The DSP chip in a numerical relay is normally ofsufficient processing capacity that calculation of therelay protection function only occupies part of theprocessing capacity. The excess capacity is thereforeavailable to perform other functions. Of course, caremust be taken never to load the processor beyondcapacity, for if this happens, the protection algorithmwill not complete its calculation in the required time andthe protection function will be compromised.

Typical functions that may be found in a numerical relaybesides protection functions are described in this section.Note that not all functions may be found in a particularrelay. In common with earlier generations of relays,manufacturers, in accordance with their perceivedmarket segmentation, will offer different versionsoffering a different set of functions. Functionparameters will generally be available for display on thefront panel of the relay and also via an external

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(a) Sine filter

(b) Cosine filter

+ +++0 082Xs = 2

X12X3 -

2X5

2X7X2 - -X6

- -++ X482Xc = 2

X1X0 2X3 -

2X5

2X70 + +0

Figure 7.13: Digital filters

Figure 7.14: Filter frequency response

Alias of fundamental

f0 2f0 3f0 4f0 5f0 6f0 7f0 8f0 9f0

0

1

Gain

Frequency

the result is magnitude and phase information for theselected quantity. This calculation is repeated for all ofthe quantities of interest. The quantities can then becompared with the relay characteristic, and a decisionmade in terms of the following:

a. value above setting – start timers, etc.

Chap7-98-111 22/06/02 9:53 Page 107

communications port, but some by their nature may onlybe available at one output interface.

7.6.1 Measured Values Display

This is perhaps the most obvious and simple function toimplement, as it involves the least additional processortime. The values that the relay must measure to performits protection function have already been acquired andprocessed. It is therefore a simple task to display themon the front panel, and/or transmit as required to aremote computer/HMI station. Less obvious is that anumber of extra quantities may be able to be derivedfrom the measured quantities, depending on the inputsignals available. These might include:

a. sequence quantities (positive, negative, zero)

b. power, reactive power and power factor

c. energy (kWh, kvarh)

d. max. demand in a period (kW, kvar; average andpeak values)

e. harmonic quantities

f. frequency

g. temperatures/RTD status

h. motor start information (start time, total no. ofstarts/reaccelerations, total running time

i. distance to fault

The accuracy of the measured values can only be as goodas the accuracy of the transducers used (VT’s CT’s, A/Dconverter, etc.). As CT’s and VT’s for protection functionsmay have a different accuracy specification to those formetering functions, such data may not be sufficientlyaccurate for tariff purposes. However, it will besufficiently accurate for an operator to assess systemconditions and make appropriate decisions.

7.6.2 VT/CT Supervision

If suitable VT’s are used, supervision of the VT/CT suppliescan be made available. VT supervision is made morecomplicated by the different conditions under whichthere may be no VT signal – some of which indicate VTfailure and some occur because of a power system faulthaving occurred.

CT supervision is carried out more easily, the generalprinciple being the calculation of a level of negativesequence current that is inconsistent with the calculatedvalue of negative sequence voltage.

7.6.3 CB Control/State Indication /Condition Monitoring

System operators will normally require knowledge of thestate of all circuit breakers under their control. The CB

position-switch outputs can be connected to the relaydigital inputs and hence provide the indication of statevia the communications bus to a remote control centre.

Circuit breakers also require periodic maintenance oftheir operating mechanisms and contacts to ensure theywill operate when required and that the fault capacity isnot affected adversely. The requirement for maintenanceis a function of the number of trip operations, thecumulative current broken and the type of breaker. Anumerical relay can record all of these parameters andhence be configured to send an alarm when maintenanceis due. If maintenance is not carried out within definedcriteria (such as a pre-defined time or number of trips)after maintenance is required, the CB can be arranged totrip and lockout, or inhibit certain functions such asauto-reclose.

Finally, as well as tripping the CB as required under faultconditions, it can also be arranged for a digital output tobe used for CB closure, so that separate CB close controlcircuits can be eliminated.

7.6.4 Disturbance Recorder

The relay memory requires a certain minimum number ofcycles of measured data to be stored for correct signalprocessing and detection of events. The memory caneasily be expanded to allow storage of a greater timeperiod of input data, both analogue and digital, plus thestate of the relay outputs. It then has the capability to actas a disturbance recorder for the circuit being monitored,so that by freezing the memory at the instant of faultdetection or trip, a record of the disturbance is availablefor later download and analysis. It may be inconvenient todownload the record immediately, so facilities may beprovided to capture and store a number of disturbances.In industrial and small distribution networks, this may beall that is required. In transmission networks, it may benecessary to provide a single recorder to monitor a numberof circuits simultaneously, and in this case, a separatedisturbance recorder will still be required.

7.6.5 Time Synchronisation

Disturbance records and data relating to energyconsumption requires time tagging to serve any usefulpurpose. Although an internal clock will normally bepresent, this is of limited accuracy and use of this clockto provide time information may cause problems if thedisturbance record has to be correlated with similarrecords from other sources to obtain a complete pictureof an event. Many numerical relays have the facility fortime synchronisation from an external clock. Thestandard normally used is an IRIG-B signal, which may bederived from a number of sources, the latest being froma GPS satellite system.

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7.6.6 Programmable Logic

Logic functions are well suited to implementation usingmicroprocessors. The implementation of logic in a relayis not new, as functions such as intertripping and auto-reclose require a certain amount of logic. However, byproviding a substantial number of digital I/O and makingthe logic capable of being programmed using suitableoff-line software, the functionality of such schemes canbe enhanced and/or additional features provided. Forinstance, an overcurrent relay at the receiving end of atransformer feeder could use the temperature inputsprovided to monitor transformer winding temperatureand provide alarm/trip facilities to theoperator/upstream relay, eliminating the need for aseparate winding temperature relay. This is anelementary example, but other advantages are evident tothe relay manufacturer – different logic schemesrequired by different Utilities, etc., no longer needseparate relay versions or some hard-wired logic toimplement, reducing the cost of manufacture. It is alsoeasier to customise a relay for a specific application, andeliminate other devices that would otherwise berequired.

7.6.7 Provision of Setting Groups

Historically, electromechanical and static relays havebeen provided with only one group of settings to beapplied to the relay. Unfortunately, power systemschange their topology due to operational reasons on aregular basis. (e.g. supply from normal/emergencygeneration). The different configurations may requiredifferent relay settings to maintain the desired level ofnetwork protection (since, for the above example, thefault levels will be significantly different on parts of thenetwork that remain energised under both conditions).

This problem can be overcome by the provision within therelay of a number of setting groups, only one of which isin use at any one time. Changeover between groups canbe achieved from a remote command from the operator,or possibly through the programmable logic system. Thismay obviate the need for duplicate relays to be fittedwith some form of switching arrangement of the inputsand outputs depending on network configuration. Theoperator will also have the ability to remotely programthe relay with a group of settings if required.

7.6.8 Conclusions

The provision of extra facilities in numerical relays mayavoid the need for other measurement/control devices tobe fitted in a substation. A trend can therefore bediscerned in which protection relays are provided withfunctionality that in the past has been provided usingseparate equipment. The protection relay no longer

performs a basic protection function; but is becoming anintegral and major part of a substation automationscheme. The choice of a protection relay rather thansome other device is logical, as the protection relay isprobably the only device that is virtually mandatory oncircuits of any significant rating. Thus, the functionspreviously carried out by separate devices such as baycontrollers, discrete metering transducers and similardevices are now found in a protection relay. It is nowpossible to implement a substation automation schemeusing numerical relays as the principal or indeed onlyhardware provided at bay level. As the power ofmicroprocessors continues to grow and pressure onoperators to reduce costs continues, this trend willprobably continue, one obvious development being theprovision of RTU facilities in designated relays that act aslocal concentrators of information within the overallnetwork automation scheme.

7.7 NUMERICAL RELAY ISSUES

The introduction of numerical relays replaces some of theissues of previous generations of relays with new ones.Some of the new issues that must be addressed are asfollows:

a. software version controlb. relay data managementc. testing and commissioning

7.7.1 Software Version Control

Numerical relays perform their functions by means ofsoftware. The process used for software generation is nodifferent in principle to that for any other device usingreal-time software, and includes the difficulties ofdeveloping code that is error-free. Manufacturers musttherefore pay particular attention to the methodologyused for software generation and testing to ensure thatas far as possible, the code contains no errors. However,it is virtually impossible to perform internal tests thatcover all possible combinations of external effects, etc.,and therefore it must be accepted that errors may exist.In this respect, software used in relays is no different toany other software, where users accept that field usemay uncover errors that may require changes to thesoftware. Obviously, type testing can be expected toprove that the protection functions implemented by therelay are carried out properly, but it has been known forfailures of rarely used auxiliary functions to occur undersome conditions.

Where problems are discovered in software subsequentto the release of a numerical relay for sale, a new versionof the software may be considered necessary. Thisprocess then requires some form of software versioncontrol to be implemented to keep track of:

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a. the different software versions in existenceb. the differences between each versionc. the reasons for the changed. relays fitted with each of the versions

With an effective version control system, manufacturersare able to advise users in the event of reported problemsif the problem is a known software related problem andwhat remedial action is required. With the aid ofsuitable software held by a user, it may be possible todownload the new software version instead of requiringa visit from a service engineer.

7.7.2 Relay Data Management

A numerical relay usually provides many more featuresthan a relay using static or electromechanicaltechnology. To use these features, the appropriate datamust be entered into the memory of the relay. Usersmust also keep a record of all of the data, in case of dataloss within the relay, or for use in system studies, etc.The amount of data per numerical relay may be 10-50times that of an equivalent electromechanical relay, towhich must be added the possibility of user-defined logicfunctions. The task of entering the data correctly into anumerical relay becomes a much more complex task thanpreviously, which adds to the possibility of a mistakebeing made. Similarly, the amount of data that must berecorded is much larger, giving rise potentially toproblems of storage.

The problems have been addressed by the provision ofsoftware to automate the preparation and download ofrelay setting data from a portable computer connectedto a communications port of the relay. As part of theprocess, the setting data can be read back from the relayand compared with the desired settings to ensure thatthe download has been error-free. A copy of the settingdata (including user defined logic schemes where used)can also be stored on the computer, for later printoutand/or upload to the users database facilities.

More advanced software is available to perform theabove functions from an Engineering Computer in asubstation automation scheme – see Chapter 24 fordetails of such schemes).

7.7.3 Relay Testing and Commissioning

The testing of relays based on software is of necessityradically different from earlier generations of relays. Thetopic is dealt with in detail in Chapter 21, but it can bementioned here that site commissioning is usuallyrestricted to the in-built software self-check andverification that currents and voltages measured by therelay are correct. Problems revealed by such tests requirespecialist equipment to resolve, and hence field policy is

usually on a repair-by-replacement basis.

7.8 REFERENCES

7.1 Protective Relays Application Guide, 3rd edition.ALSTOM T&D Protection and Control, 1987.

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Introduction 8.1

Unit protection schemes 8.2

Teleprotection commands 8.3

Intertripping 8.4

Performance requirements 8.5

Transmission media, interference and noise 8.6

Methods of signalling 8.7

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8.1 INTRODUCTION

Unit protection schemes, formed by a number of relayslocated remotely from each other, and some distanceprotection schemes, require some form of communicationbetween each location in order to achieve a unit protectionfunction. This form of communication is known asprotection signalling. Additionally communicationsfacilities are also required when remote operation of acircuit breaker is required as a result of a local event. Thisform of communications is known as intertripping.

The communication messages involved may be quitesimple, involving instructions for the receiving device totake some defined action (trip, block, etc.), or it may bethe passing of measured data in some form from onedevice to another (as in a unit protection scheme).

Various types of communication links are available forprotection signalling, for example:

i. private pilot wires installed by the powerauthority

ii. pilot wires or channels rented from acommunications company

iii. carrier channels at high frequencies over thepower lines

iv. radio channels at very high or ultra highfrequencies

v. optical fibres

Whether or not a particular link is used depends onfactors such as the availability of an appropriatecommunication network, the distance betweenprotection relaying points, the terrain over which thepower network is constructed, as well as cost.

Protection signalling is used to implement UnitProtection schemes, provide teleprotection commands,or implement intertripping between circuit breakers.

8.2 UNIT PROTECTION SCHEMES

Phase comparison and current differential schemes usesignalling to convey information concerning the relayingquantity - phase angle of current and phase and

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magnitude of current respectively - between local andremote relaying points. Comparison of local and remotesignals provides the basis for both fault detection anddiscrimination of the schemes.

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 Chapter12 use signalling to convey a command between localand remote relaying points. Receipt of the informationis used to aid or speed up clearance of faults within aprotected zone or to prevent tripping from faults outsidea protected zone.

Teleprotection systems are often referred to by theirmode of operation, or the role of the teleprotectioncommand in the system.

8.4 INTERTRIPPING

Intertripping is the controlled tripping of a circuitbreaker so as to complete the isolation of a circuit or

piece of apparatus in sympathy with the tripping of othercircuit breakers. The main use of such schemes is toensure that protection at both ends of a faulted circuitwill operate to isolate the equipment concerned. Possiblecircumstances when it may be used are:

a. a feeder with a weak infeed at one end, insufficientto operate the protection for all faults

b. feeder protection applied to transformer –feedercircuits. Faults on the transformer windings mayoperate the transformer protection but not thefeeder protection. Similarly, some earth faults maynot be detected due to transformer connections

c. faults between the CB and feeder protection CT’s,when these are located on the feeder side of the CB.Bus-zone protection does not result in faultclearance – the fault is still fed from the remote endof the feeder, while feeder unit protection may notoperate as the fault is outside the protected zone

d. some distance protection schemes useintertripping to improve fault clearance times forsome kinds of fault – see Chapters 12/13

Intertripping schemes use signalling to convey a trip

Power transmission line

Blocking Communicationlink

VI

Data

Communicationsystems

Telecontrol

Telephone

Permissivetrip

Telemetry

Data

Communicationsystems

Telecontrol

Telephone

Telemetry

Teleprotectioncommand(receive)

Teleprotectioncommand

(send)

Protectionrelay

scheme

Protectionrelay

scheme

V ITripTrip

Intertrip

Blocking

Permissivetrip

Intertrip

Figure 8.1: Application of protection signalling and its relationship to other systems using communication(shown as a unidirectional system for simplicity)

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command to remote circuit breakers to isolate circuits.For high reliability EHV protection schemes, intertrippingmay be used to give back-up to main protections, orback-tripping in the case of breaker failure. Three typesof intertripping are commonly encountered, and aredescribed below.

8.4.1 Direct Tripping

In direct tripping applications, intertrip signals are sentdirectly to the master trip relay. Receipt of the commandcauses circuit breaker operation. The method ofcommunication must be reliable and secure because anysignal detected at the receiving end will cause a trip ofthe circuit at that end. The communications systemdesign must be such that interference on thecommunication circuit does not cause spurious trips.Should a spurious trip occur, considerable unnecessaryisolation of the primary system might result, which is atbest undesirable and at worst quite unacceptable.

8.4.2 Permissive Tripping

Permissive trip commands are always monitored by aprotection relay. The circuit breaker is tripped whenreceipt of the command coincides with operation of theprotection relay at the receiving end responding to asystem fault. Requirements for the communicationschannel are less onerous than for direct trippingschemes, since receipt of an incorrect signal mustcoincide with operation of the receiving end protectionfor a trip operation to take place. The intention of theseschemes is to speed up tripping for faults occurringwithin the protected zone.

8.4.3 Blocking Scheme

Blocking commands are initiated by a protection elementthat detects faults external to the protected zone.Detection of an external fault at the local end of aprotected circuit results in a blocking signal beingtransmitted to the remote end. At the remote end,receipt of the blocking signal prevents the remote endprotection operating if it had detected the external fault.Loss of the communications channel is less serious forthis scheme than in others as loss of the channel doesnot result in a failure to trip when required. However,the risk of a spurious trip is higher.

Figure 8.1 shows the typical applications of protectionsignalling and their relationship to other signallingsystems commonly required for control and managementof a power system. Of course, not all of the protectionsignals shown will be required in any particular scheme.

8.5 PERFORMANCE REQUIREMENTS

Overall fault clearance time is the sum of:

a. signalling time

b. protection relay operating time

c. trip relay operating time

d. circuit breaker operating time

The overall time must be less than the maximum time forwhich a fault can remain on the system for minimumplant damage, loss of stability, etc. Fast operation istherefore a pre-requisite of most signalling systems.

Typically the time allowed for the transfer of a commandis of the same order as the operating time of theassociated protection relays. Nominal operating timesrange from 5 to 40ms dependent on the mode ofoperation of the teleprotection system.

Protection signals are subjected to the noise andinterference associated with each communicationmedium. If noise reproduces the signal used to conveythe command, unwanted commands may be produced,whilst if noise occurs when a command signal is beingtransmitted, the command may be retarded or missedcompletely. Performance is expressed in terms ofsecurity and dependability. Security is assessed by theprobability of an unwanted command occurring, anddependability is assessed by the probability of missing acommand. The required degree of security anddependability is related to the mode of operation, thecharacteristics of the communication medium and theoperating standards of the particular power authority.

Typical design objectives for teleprotection systems arenot more than one incorrect trip per 500 equipmentyears and less than one failure to trip in every 1000attempts, or a delay of more than 50msec should notoccur more than once per 10 equipment years. Toachieve these objectives, special emphasis may beattached to the security and dependability of theteleprotection command for each mode of operation inthe system, as follows.

8.5.1 Performance Requirements – Intertripping

Since any unwanted command causes incorrect tripping,very high security is required at all noise levels up to themaximum that might ever be encountered.

8.5.2 Performance Requirements – Permissive Tripping

Security somewhat lower than that required forintertripping is usually satisfactory, since incorrecttripping can occur only if an unwanted commandhappens to coincide with operation of the protectionrelay for an out-of-zone fault.

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For permissive over-reach schemes, resetting after acommand should be highly dependable to avoid anychance of maloperations during current reversals.

8.5.3 Performance Requirements – Blocking Schemes

Low security is usually adequate since an unwantedcommand can never cause an incorrect trip. Highdependability is required since absence of the commandcould cause incorrect tripping if the protection relayoperates for an out-of-zone fault.

Typical performance requirements are shown in Figure 8.2.

8.6 TRANSMISSION MEDIAINTERFERENCE AND NOISE

The transmission media that provide the communicationlinks involved in protection signalling are:

a. private pilotsb. rented pilots or channelsc. power line carrierd. radioe. optical fibres

Historically, pilot wires and channels (discontinuous pilotwires with isolation transformers or repeaters along theroute between signalling points) have been the mostwidely used due to their availability, followed by PowerLine Carrier Communications (PLCC) techniques andradio. In recent years, fibre-optic systems have becomethe usual choice for new installations, primarily due totheir complete immunity from electrical interference.The use of fibre-optic cables also greatly increases thenumber of communication channels available for each

physical fibre connection and thus enables morecomprehensive monitoring of the power system to beachieved by the provision of a large number ofcommunication channels.

8.6.1 Private Pilot Wires and Channels

Pilot wires are continuous copper connections betweensignalling stations, while pilot channels arediscontinuous pilot wires with isolation transformers orrepeaters 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 aseparate wood pole route.

Distances over which signalling is required varyconsiderably. At one end of the scale, the distance may beonly a few tens of metres, where the devices concerned arelocated in the same substation. For applications on EHVlines, the distance between devices may be between 10-100km or more. For short distances, no special measuresare required against interference, but over longer distances,special send and receive relays may be required to boostsignal levels and provide immunity against inducedvoltages from power circuits, lightning strikes to groundadjacent to the route, etc. Isolation transformers may alsohave to be provided to guard against rises in substationground potential due to earth faults.

The capacity of a link can be increased if frequencydivision multiplexing techniques are used to run parallelsignalling systems, but some Utilities prefer the link to beused only for protection signalling.

Private pilot wires or channels can be attractive to anUtility running a very dense power system with shortdistances between stations.

8.6.2 Rented Pilot Wires and Channels

These are rented from national communicationauthorities and, apart from the connection from therelaying point to the nearest telephone exchange, therouting will be through cables forming part of thenational communication network.

An economic decision has to be made between the useof private or rented pilots. If private pilots are used, theowner has complete control, but bears the cost ofinstallation and maintenance. If rented pilots are used,most of these costs are eliminated, but fees must be paidto the owner of the pilots and the signal path may bechanged without warning. This may be a problem inprotection applications where signal transmission timesare critical.

The chance of voltages being induced in rented pilots issmaller than for private pilots, as the pilot route isnormally not related to the route of the power line withwhich it is associated. However, some degree of security

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0

0.020.01 10

10

10-5

10-4

10-3

10-2

0.03

0.06

0.040.05

Sec

Intertrip

Blocking

CC

Analogue Digital

DigitalAnalogue

TOPTOPT

IntertripTTT - 0.04secPUC -1.00E-03P -1.00E-01

TOPTOPT - 0.015secP

O-1.00E-01

PMCP -1.00E-01

TT - 0.015sec-2.00E-02-1.00E-01

IntertripTTT - 0.04secPP

TTPP -1.00E-01

TT - 0.015sec

P

TT - Maximum operating time

ª - UC )%PMCP

Dependability ª 100(1-PMCP )%

TOPTOPT

Figure 8.2: Typical performance requirementsfor protection signalling when the

communication link is subjected to noise

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and protection against induced voltages must be builtinto signalling systems. Electrical interference fromother signalling systems, particularly 17, 25 and 50Hzringing tones up to 150V peak, and from noise generatedwithin the equipment used in the communicationnetwork, is a common hazard. Similarly, the signallingsystem must also be proof against intermittent short andopen circuits on the pilot link, incorrect connection of 50volts d.c. across the pilot link and other similar faults.

Station earth potential rise is a significant factor to betaken into account and isolation must be provided toprotect both the personnel and equipment of thecommunication authority.

The most significant hazard to be withstood by aprotection signalling system using this medium ariseswhen a linesman inadvertently connects a lowimpedance test oscillator across the pilot link that cangenerate signalling tones. Transmissions by such anoscillator may simulate the operating code or tonesequence that, in the case of direct intertrippingschemes, would result in incorrect operation of thecircuit breaker.

Communication between relaying points may be over atwo-wire or four-wire link. Consequently the effect of aparticular human action, for example an incorrectdisconnection, may disrupt communication in onedirection or both.

The signals transmitted must be limited in both level andbandwidth to avoid interference with other signallingsystems. The owner of the pilots will impose standards

in this respect that may limit transmission capacityand/or transmission distance.

With a power system operating at, say, 132kV, whererelatively long protection signalling times are acceptable,signalling has been achieved above speech together withmetering and control signalling on an established controlnetwork. Consequently the protection signalling wasachieved at very low cost. High voltage systems (220kVand above) have demanded shorter operating times andimproved security, which has led to the renting of pilotlinks exclusively for protection signalling purposes.

8.6.3 Power Line Carrier Communications Techniques

Where long line sections are involved, or if the routeinvolves installation difficulties, the expense of providingphysical pilot connections or operational restrictionsassociated with the route length require that othermeans of providing signalling facilities are required.

Power Line Carrier Communications (PLCC) is a techniquethat involves high frequency signal transmission alongthe overhead power line. It is robust and thereforereliable, constituting a low loss transmission path that isfully controlled by the Utility.

High voltage capacitors are used, along with drainagecoils, for the purpose of injecting the signal to andextracting it from the line. Injection can be carried outby impressing the carrier signal voltage between oneconductor and earth or between any two phaseconductors. The basic units can be built up into a highpass or band pass filter as shown in Figure 8.3.

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Figure 8.3: Typical phase-to-phase coupling equipment

Seriestuningunit

To E/M VTTo E/M VT

To line To station

Line trap

Capacitor VT

Shunt filter unit

75 ohms Coaxial cableTo HF equipment

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The high voltage capacitor is tuned by a tuning coil topresent a low impedance at the signal frequency; theparallel circuit presents a high impedance at the signalfrequency while providing a path for the powerfrequency currents passed by the capacitor.

The complete arrangement is designed as a balanced orunbalanced half-section band pass filter, according towhether the transmission is phase-phase or phase-earth;the power line characteristic impedance, between 400 and600 ohms, determines the design impedance of the filter.

It is necessary to minimize the loss of signal into other partsof the power system, to allow the same frequency to beused on another line. This is done with a 'line trap' or 'wavetrap', which in its simplest form is a parallel circuit tuned topresent a very high impedance to the signal frequency. It isconnected in the phase conductor on the station side of theinjection equipment. The complete carrier couplingequipment is shown in Figure 8.4.

The single frequency line trap may be treated as anintegral part of the complete injection equipment toaccommodate two or more carrier systems. However,difficulties may arise in an overall design, as, at certainfrequencies, the actual station reactance, which isnormally capacitive, will tune with the trap, which isinductive below its resonant frequency; the result will bea low impedance across the transmission path,preventing operation at these frequencies. This situationcan be avoided by the use of an independent 'doublefrequency' or 'broad-band' trap.

The coupling filter and the carrier equipment areconnected by high frequency cable of preferredcharacteristic impedance 75 ohms. A matchingtransformer is incorporated in the line coupling filter tomatch it to the hf cable. Surge diverters are fitted toprotect the components against transient over voltages.

The attenuation of a channel is of prime importance inthe application of carrier signalling, because itdetermines the amount of transmitted energy availableat the receiving end to overcome noise and interferingvoltages. The loss of each line terminal will be 1 to 2dBthrough the coupling filter, a maximum of 3dB throughits broad-band trap and not more than 0.5dB per 100metres through the high frequency cable.

An installation of PLCC equipment including capacitorvoltage transformers and line traps, in a line-to-lineinjection arrangement, is shown in Figure 8.4.

The high frequency transmission characteristics of powercircuits are good the loss amounting to 0.02 to 0.2dB perkilometre depending upon line voltage and frequency.Line attenuation is not affected appreciably by rain, butserious increase in loss may occur when the phaseconductors are thickly coated with hoar-frost or ice.Attenuations of up to three times the fair weather valuehave been experienced. Receiving equipment commonlyincorporates automatic gain control (AGC) tocompensate for variations in attenuation of signals.

High noise levels arise from lightning strikes and systemfault inception or clearance. Although these are of shortduration, lasting only a few milliseconds at the most, theymay cause overloading of power line carrier receivingequipment. Signalling systems used for intertripping inparticular must incorporate appropriate security features toavoid maloperation. The most severe noise levels areencountered with operation of the line isolators, and thesemay last for some seconds. Although maloperation of theassociated teleprotection scheme may have littleoperational significance, since the circuit breaker at one endat least is normally already open, high security is generallyrequired to cater for noise coupled between parallel lines orpassed through line traps from adjacent lines.

Signalling for permissive intertrip applications needsspecial consideration, as this involves signalling througha power system fault. The increase in channelattenuation due to the fault varies according to the typeof fault, but most power authorities select a nominalvalue, usually between 20 and 30dB, as an applicationguide. A protection signal boost facility can be employedto cater for an increase in attenuation of this order ofmagnitude, to maintain an acceptable signal-to-noiseratio at the receiving end, so that the performance of theservice is not impaired.

Most direct intertrip applications require signalling overa healthy power system, so boosting is not normallyneeded. In fact, if a voice frequency intertrip system isoperating over a carrier bearer channel, the dynamicoperating range of the receiver must be increased toaccommodate a boosted signal. This makes it lessinherently secure in the presence of noise during aquiescent signalling condition.

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8.6.4 Radio Channels

At first consideration, the wide bandwidth associatedwith radio frequency transmissions could allow the useof modems operating at very high data rates. Protectionsignalling commands could be sent by serial codedmessages of sufficient length and complexity to givehigh security, but still achieve fast operating times. Inpractice, it is seldom economic to provide radioequipment exclusively for protection signalling, sostandard general-purpose telecommunications channelequipment is normally adopted.

Typical radio bearer equipment operates at themicrowave frequencies of 0.2 to 10GHz. Because of therelatively short range and directional nature of thetransmitter and receiver aerial systems at thesefrequencies, large bandwidths can be allocated withoutmuch chance of mutual interference with other systems.

Multiplexing techniques allow a number of channels toshare the common bearer medium and exploit the largebandwidth. In addition to voice frequency channels, widerbandwidth channels or data channels may be available,dependent on the particular system. For instance, inanalogue systems using frequency division multiplexing,normally up to 12 voice frequency channels are groupedtogether in basebands at 12-60kHz or 60-108kHz, butalternatively the baseband may be used as a 48kHz signalchannel. Modern digital systems employing pulse codemodulation and time division multiplexing usually providethe voice frequency channels by sampling at 8kHz andquantising to 8 bits; alternatively, access may be availablefor data at 64kbits/s (equivalent to one voice frequencychannel) or higher data rates.

Radio systems are well suited to the bulk transmission ofinformation between control centres and are widely usedfor this. When the route of the trunk data networkcoincides with that of transmission lines, channels canoften be allocated for protection signalling. Moregenerally, radio communication is between majorstations rather than the ends of individual lines, becauseof the need for line-of-sight operation between aerialsand other requirements of the network. Roundaboutroutes involving repeater stations and the addition ofpilot channels to interconnect the radio installation andthe relay station may be possible, but overalldependability will normally be much lower than for PLCCsystems in which the communication is direct from oneend of the line to the other.

Radio channels are not affected by increased attenuationdue to power system faults, but fading has to be takeninto account when the signal-to-noise ratio of aparticular installation is being considered.

Most of the noise in such a protection signalling systemwill be generated within the radio equipment itself.

A polluted atmosphere can cause radio beam refraction thatwill interfere with efficient signalling. The height of aerialtower should be limited, so that winds and temperaturechanges have the minimum effect on their position.

8.6.5 Optical Fibre Channels

Optical fibres are fine strands of glass, which behave aswave guides for light. This ability to transmit light overconsiderable distances can be used to provide opticalcommunication links with enormous informationcarrying capacity and an inherent immunity toelectromagnetic interference.

A practical optical cable consists of a central opticalfibre which comprises core, cladding and protectivebuffer coating surrounded by a protective plasticoversheath containing strength members which, in somecases, are enclosed by a layer of armouring.

To communicate information a beam of light ismodulated in accordance with the signal to betransmitted. This modulated beam travels along theoptical fibre and is subsequently decoded at the remoteterminal into the received signal. On/off modulation ofthe light source is normally preferred to linearmodulation since the distortion caused by non-linearitiesin the light source and detectors, as well as variations inreceived light power, are largely avoided.

The light transmitter and receiver are usually laser or LEDdevices capable of emitting and detecting narrow beamsof light at selected frequencies in the low attenuation850, 1300 and 1550 nanometre spectral windows. Thedistance over which effective communications can beestablished depends on the attenuation and dispersion ofthe communication link and this depends on the typeand quality of the fibre and the wavelength of theoptical source. Within the fibre there are many modes ofpropagation with different optical paths that causedispersion of the light signal and result in pulsebroadening. The degrading of the signal in this way canbe reduced by the use of 'graded index' fibres that causethe various modes to follow nearly equal paths. Thedistance over which signals can be transmitted issignificantly increased by the use of 'monomode' fibresthat support only one mode of propagation.

With optical fibre channels, communication at data ratesof hundreds of megahertz is achievable over a few tens ofkilometres, whilst greater distances require the use ofrepeaters. An optical fibre can be used as a dedicated linkbetween two terminal equipments, or as a multiplexedlink that carries all communication traffic such as voice,telecontrol and protection signalling. In the latter casethe available bandwidth of a link is divided by means oftime division multiplexing (T.D.M.) techniques into anumber of channels, each of 64kbits/s (equivalent to one

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voice frequency channel which typically uses an 8-bitanalogue-to-digital conversion at a sampling rate of8kHz). A number of Utilities sell surplus capacity on theirlinks to telecommunications operators. The trend ofusing rented pilot circuits is therefore being reversed,with the Utilities moving back towards ownership of thecommunication circuits that carry protection signalling.

The equipments that carry out this multiplexing at eachend of a line are known as 'Pulse Code Modulation'(P.C.M.) terminal equipments. This approach is the oneadopted by telecommunications authorities and someUtilities favour its adoption on their private systems, foreconomic considerations.

Optical fibre communications are well established in theelectrical supply industry. They are the preferred meansfor the communications link between a substation and atelephone exchange when rented circuits are used, astrials have shown that this link is particularly susceptibleto interference from power system faults if copperconductors are used. Whilst such fibres can be laid incable trenches, there is a strong trend to associate themwith the conductors themselves by producing compositecables comprising optical fibres embedded within theconductors, either earth or phase. For overhead lines useof OPGW (Optical Ground Wire) earth conductors is verycommon, while an alternative is to wrap the opticalcable helically around a phase or earth conductor. Thislatter technique can be used without restringing of theline.

8.7 S IGNALLING METHODS

Various methods are used in protection signalling; not allneed be suited to every transmission medium. Themethods to be considered briefly are:

a. D.C. voltage step or d.c. voltage reversals

b. plain tone keyed signals at high and voicefrequencies

c. frequency shift keyed signals involving two or moretones at high and voice frequencies

General purpose telecommunications equipmentoperating over power line carrier, radio or optical fibremedia incorporate frequency translating or multiplexingtechniques to provide the user with standardisedcommunication channels. They have a nominalbandwidth/channel of 4kHz and are often referred to asvoice frequency (vf) channels. Protection signallingequipments operating at voice frequencies exploit thestandardisation of the communication interface. Wherevoice frequency channels are not available or suitable,protection signalling may make use of a medium orspecialised equipment dedicated entirely to thesignalling requirements.

Figure 8.5 illustrates the communication arrangementscommonly encountered in protection signalling.

8.7.1 D.C. Voltage Signalling

A d.c. voltage step or d.c. voltage reversals may be usedto convey a signalling instruction between protectionrelaying points in a power system, but these are suitedonly to private pilot wires, where low speed signalling isacceptable, with its inherent security.

8.7.2 Plain Tone Signals

Plain high frequency signals can be used successfully forthe signalling of blocking information over a power line.A normally quiescent power line carrier equipment canbe dedicated entirely to the transfer to teleprotectionblocking commands. Phase comparison power linecarrier unit protection schemes often use suchequipment and take advantage of the very high speedand dependability of the signalling system. The specialcharacteristics of dedicated 'on/off' keyed carrier systemsare discussed later. A relatively insensitive receiver isused to discriminate against noise on an amplitude basis,and for some applications the security may besatisfactory for permissive tripping, particularly if thenormal high-speed operation of about 6ms is sacrificedby the addition of delays. The need for regular reflextesting of a normally quiescent channel usually precludesany use for intertripping.

Plain tone power line carrier signalling systems areparticularly suited to providing the blocking commandsoften associated with the protection of multi-endedfeeders, as described in Chapter 13. A blockingcommand sent from one end can be receivedsimultaneously at all the other ends using a single powerline carrier channel. Other signalling systems usuallyrequire discrete communication channels between eachof the ends or involve repeaters, leading to decreaseddependability of the blocking command.

Plain voice frequency signals can be used for blocking,permissive intertrip and direct intertrip applications forall transmission media but operation is at such a lowsignal level that security from maloperation is not verygood. Operation in the 'tone on' to 'tone off' mode givesthe best channel monitoring, but offers little security; toobtain a satisfactory performance the output must bedelayed. This results in relatively slow operation: 70milliseconds for permissive intertripping, and 180milliseconds for direct intertripping.

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8.7.3 Frequency Shift Keyed Signals

Frequency shift keyed high frequency signals can beused over a power line carrier link to give shortoperating times (15 milliseconds for blocking andpermissive intertripping, 20 milliseconds for directintertripping) for all applications of protectionsignalling. The required amount of security can beachieved by using a broadband noise detector tomonitor the actual operational signalling equipment.

Frequency shift keyed voice frequency signals can beused for all protection signalling applications over alltransmission media. Frequency modulation techniquesmake possible an improvement in performance, becauseamplitude limiting rejects the amplitude modulationcomponent of noise, leaving only the phase modulationcomponents to be detected.

The operational protection signal may consist of tonesequence codes with, say, three tones, or a multi-bitcode using two discrete tones for successive bits, or of asingle frequency shift.

Modern high-speed systems use multi-bit code or singlefrequency shift techniques. Complex codes are used to

give the required degree of security in direct intertripschemes: the short operating times needed may result inuneconomical use of the available voice frequencyspectrum, particularly if the channel is not exclusivelyemployed for protection signalling. As noise power isdirectly proportional to bandwidth, a large bandwidthcauses an increase in the noise level admitted to thedetector, making operation in the presence of noise moredifficult. So, again, it is difficult to obtain both highdependability and high security.

The signal frequency shift technique has advantageswhere fast signalling is needed for blocked distance andpermissive intertrip applications. It has little inherentsecurity, but additional circuits responsive to every typeof interference can give acceptable security. This systemdoes not require a channel capable of high transmissionrates, as the frequency changes once only; thebandwidth can therefore be narrower than in codedsystems, giving better noise rejection as well as beingadvantageous if the channel is shared with telemetryand control signalling, which will inevitably be the caseif a power line carrier bearer is employed.

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Voicefrequency

Carrierfrequency

shift

On/offkeyedcarrier

Digital

Optical

Protectionrelay

scheme

Protectionsignallingequipment

PCMprimary

multiplex

Frequencydivision

multiplex

Radiotransmitter

Opticaltransmitter

Communicationequipment

Power linecarrier

communicationchannel Power line carrier Power line carrier

Pilot wires

Pilot channel

Transmission media

Optical fibregeneral purpose

Optical fibrededicated

Radio

Figure 8.5: Communication arrangements commonly encountered in protection signalling

Chap8-112-121 21/06/02 9:03 Page 121

Introduction 9.1

Co-ordination procedure 9.2

Principles of time/current grading 9.3

Standard I.D.M.T. overcurrent relays 9.4

Combined I.D.M.T. and high set instantaneous overcurrent relays 9.5

Very Inverse overcurrent relays 9.6

Extremely Inverse overcurrent relays 9.7

Other relay characteristics 9.8

Independent (definite) time overcurrent relays 9.9

Relay current setting 9.10

Relay time grading margin 9.11

Recommended grading margins 9.12

Calculation of phase fault overcurrent relay settings 9.13

Directional phase fault overcurrent relays 9.14

Ring mains 9.15

Earth fault protection 9.16

Directional earth fault overcurrent protection 9.17

Earth fault protection on insulated networks 9.18

Earth fault protection on Petersen Coil earthed networks 9.19

Examples of time and current grading 9.20

References 9.21

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9.1 INTRODUCTION

Protection against excess current was naturally theearliest protection system to evolve. From this basicprinciple, the graded overcurrent system, a discriminativefault protection, has been developed. This should not beconfused with ‘overload’ protection, which normallymakes use of relays that operate in a time related insome degree to the thermal capability of the plant to beprotected. Overcurrent protection, on the other hand, isdirected entirely to the clearance of faults, although withthe settings usually adopted some measure of overloadprotection may be obtained.

9.2 CO-ORDINATION PROCEDURE

Correct overcurrent relay application requires knowledgeof the fault current that can flow in each part of thenetwork. Since large-scale tests are normallyimpracticable, system analysis must be used – seeChapter 4 for details. The data required for a relaysetting study are:

i. a one-line diagram of the power system involved,showing the type and rating of the protectiondevices and their associated current transformers

ii. the impedances in ohms, per cent or per unit, ofall power transformers, rotating machine andfeeder circuits

iii. the maximum and minimum values of short circuitcurrents that are expected to flow through eachprotection device

iv. the maximum load current through protectiondevices

v. the starting current requirements of motors andthe starting and locked rotor/stalling times ofinduction motors

vi. the transformer inrush, thermal withstand anddamage characteristics

vii. decrement curves showing the rate of decay ofthe fault current supplied by the generators

viii. performance curves of the current transformers

The relay settings are first determined to give theshortest operating times at maximum fault levels and

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then checked to see if operation will also be satisfactoryat the minimum fault current expected. It is alwaysadvisable to plot the curves of relays and otherprotection devices, such as fuses, that are to operate inseries, on a common scale. It is usually more convenientto use a scale corresponding to the current expected atthe lowest voltage base, or to use the predominantvoltage base. The alternatives are a common MVA baseor a separate current scale for each system voltage.

The basic rules for correct relay co-ordination can generallybe stated as follows:

a. whenever possible, use relays with the sameoperating characteristic in series with each other

b. make sure that the relay farthest from the sourcehas current settings equal to or less than the relaysbehind it, that is, that the primary current requiredto operate the relay in front is always equal to orless than the primary current required to operatethe relay behind it.

9.3 PRINCIPLES OF TIME/CURRENT GRADING

Among the various possible methods used to achievecorrect relay co-ordination are those using either time orovercurrent, or a combination of both. The common aimof all three methods is to give correct discrimination.That is to say, each one must isolate only the faultysection of the power system network, leaving the rest ofthe system undisturbed.

9.3.1 Discrimination by Time

In this method, an appropriate time setting is given toeach of the relays controlling the circuit breakers in apower system to ensure that the breaker nearest to thefault opens first. A simple radial distribution system isshown in Figure 9.1, to illustrate the principle.

Overcurrent protection is provided at B, C, D and E, thatis, at the infeed end of each section of the power system.Each protection unit comprises a definite-time delayovercurrent relay in which the operation of the currentsensitive element simply initiates the time delay element.Provided the setting of the current element is below thefault current value, this element plays no part in theachievement of discrimination. For this reason, the relay

is sometimes described as an ‘independent definite-timedelay relay’, since its operating time is for practicalpurposes independent of the level of overcurrent.

It is the time delay element, therefore, which providesthe means of discrimination. The relay at B is set at theshortest time delay possible to allow the fuse to blow fora fault at A on the secondary side of the transformer.After the time delay has expired, the relay outputcontact closes to trip the circuit breaker. The relay at Chas a time delay setting equal to t1 seconds, and similarlyfor the relays at D and E.

If a fault occurs at F, the relay at B will operate in tseconds and the subsequent operation of the circuitbreaker at B will clear the fault before the relays at C, Dand E have time to operate. The time interval t1 betweeneach relay time setting must be long enough to ensurethat the upstream relays do not operate before thecircuit breaker at the fault location has tripped andcleared the fault.

The main disadvantage of this method of discriminationis that the longest fault clearance time occurs for faultsin the section closest to the power source, where thefault level (MVA) is highest.

9.3.2 Discrimination by Current

Discrimination by current relies on the fact that the faultcurrent varies with the position of the fault because ofthe difference in impedance values between the sourceand the fault. Hence, typically, the relays controlling thevarious circuit breakers are set to operate at suitablytapered values of current such that only the relay nearestto the fault trips its breaker. Figure 9.2 illustrates themethod.

For a fault at F1, the system short-circuit current is givenby:

where Zs = source impedance

ZL1 = cable impedance between C and B

= 0.24Ω

Hence

So, a relay controlling the circuit breaker at C and set tooperate at a fault current of 8800A would in theoryprotect the whole of the cable section between C and B.However, there are two important practical points thataffect this method of co-ordination:

I A=×

=113 0 725.

8800

= =11250

2 0.485Ω

IZ Z

AS L

=+

6350

1

Figure 9.1: Radial system with time discrimination

t1F

DE

t1 t1

C B A

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a. it is not practical to distinguish between a fault atF1 and a fault at F2, since the distance betweenthese points may be only a few metres,corresponding to a change in fault current ofapproximately 0.1%

b. in practice, there would be variations in the sourcefault level, typically from 250MVA to 130MVA. Atthis lower fault level the fault current would notexceed 6800A, even for a cable fault close to C. Arelay set at 8800A would not protect any part ofthe cable section concerned

Discrimination by current is therefore not a practicalproposition for correct grading between the circuitbreakers at C and B. However, the problem changesappreciably when there is significant impedancebetween the two circuit breakers concerned. Considerthe grading required between the circuit breakers at Cand A in Figure 9.2. Assuming a fault at F4, the short-circuit current is given by:

where ZS = source impedance

= 0.485Ω

ZL1 = cable impedance between C and B

= 0.24Ω

ZL2 = cable impedance between B and 4 MVAtransformer

= 0.04Ω

ZT = transformer impedance

= 2.12Ω

Hence

= 2200 A

For this reason, a relay controlling the circuit breaker atB and set to operate at a current of 2200A plus a safetymargin would not operate for a fault at F4 and wouldthus discriminate with the relay at A. Assuming a safety

I =×11

3 2 885.

=

0 07 114

2.

IZ Z

AS L

=+

6350

1

margin of 20% to allow for relay errors and a further10% for variations in the system impedance values, it isreasonable to choose a relay setting of 1.3 x 2200A, thatis 2860A, for the relay at B. Now, assuming a fault at F3,at the end of the 11kV cable feeding the 4MVAtransformer, the short-circuit current is given by:

Thus, assuming a 250MVA source fault level:

= 8300 A

Alternatively, assuming a source fault level of 130MVA:

= 5250 A

In other words, for either value of source level, the relayat B would operate correctly for faults anywhere on the11kV cable feeding the transformer.

9.3.3 Discrimination by both Time and Current

Each of the two methods described so far has afundamental disadvantage. In the case of discriminationby time alone, the disadvantage is due to the fact thatthe more severe faults are cleared in the longestoperating time. On the other hand, discrimination bycurrent can be applied only where there is appreciableimpedance between the two circuit breakers concerned.

It is because of the limitations imposed by theindependent use of either time or current co-ordinationthat the inverse time overcurrent relay characteristic hasevolved. With this characteristic, the time of operationis inversely proportional to the fault current level and theactual characteristic is a function of both ‘time’and 'current' settings. Figure 9.3 illustrates thecharacteristics of two relays given different current/timesettings. For a large variation in fault current betweenthe two ends of the feeder, faster operating times can beachieved by the relays nearest to the source, where thefault level is the highest. The disadvantages of gradingby time or current alone are overcome.

The selection of overcurrent relay characteristicsgenerally starts with selection of the correctcharacteristic to be used for each relay, followed bychoice of the relay current settings. Finally the gradingmargins and hence time settings of the relays aredetermined. An iterative procedure is often required toresolve conflicts, and may involve use of non-optimalcharacteristics, current or time grading settings.

I =+ +( )11

3 0 93 0 214 0 04 . . .

I =+ +( )11

3 0 485 0 24 0 04 . . .

IZ Z ZS L L

=+ +( )11

3 1 2

CF1 F3F2 F4

B A

11kV250MVASource

200 metres240mm2 P.I.L.C.

Cable

200 metres240mm2 P.I.L.C.

Cable

4MVA11/3.3kV

7%

Figure 9.2: Radial system with current discrimination

Chap9 exe 21/06/02 8:51 Page 125


9.4 STANDARD I.D.M.T. OVERCURRENT RELAYS

The current/time tripping characteristics of IDMT relaysmay need to be varied according to the tripping timerequired and the characteristics of other protection devicesused in the network. For these purposes, IEC 60255 definesa number of standard characteristics as follows:

Standard Inverse (SI)Very Inverse (VI)Extremely Inverse (EI)Definite Time (DT)

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Figure 9.3: Relay characteristics for different settings

1000.10

1.00

Relay A: Current Setting = 100A, TMS = 1.0

1000 10,000

time

Relay A operatingtime

10.00

100.

1000.

Relay B: Current Setting = 125A, TMS = 1.3

Current (A)

Tim

e (s

)

Table 9.1: Definitions of standard relay characteristics

Figure 9.4 (a): IDMT relay characteristics

(a) IEC 60255 characteristics ; TMS=1.0

Ope

ratin

g Ti

me

(sec

onds

)

Current (multiples of ISI )

0.1010

1.00

10.00

100.00

1000.00

1001

Ir = (I/Is), where Is = relay setting currentTMS = Time multiplier Setting

TD = Time Dial setting

(b): North American IDMT relay characteristics

Relay Characteristic Equation (IEC 60255)

IEEE Moderately Inverse

IEEE Very Inverse

Extremely Inverse (EI)

US CO8 Inverse

US CO2 Short Time Inverse t TD

I=

−

+

70 02394

10 01694

0 02

. ..

r

t TDIr

=−

+

7

5 951

0 182

. .

t TDIr

=−

+

7

28 21

0 12172

. .

t TDIr

=−

+

7

19 611

0 4912

. .

t TDIr

=−

+

7

0 05151

0 1140 02

. ..

Relay Characteristic Equation (IEC 60255)

Standard Inverse (SI)

Very Inverse (VI)

Extremely Inverse (EI)

Long time standard earth fault t TMSI r

= ×−

1201

t TMSI r

= ×−

8012

t TMSI r

= ×−

13 51

.

t TMSI r

= ×−

0 1410 02

..

(a): Relay characteristics to IEC 60255

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The mathematical descriptions of the curves are given inTable 9.1(a), and the curves based on a common settingcurrent and time multiplier setting of 1 second areshown in Figure 9.4(a). The tripping characteristics fordifferent TMS settings using the SI curve are illustratedin Figure 9.5.

Although the curves are only shown for discrete values ofTMS, continuous adjustment may be possible in anelectromechanical relay. For other relay types, the settingsteps may be so small as to effectively provide continuousadjustment. In addition, almost all overcurrent relays arealso fitted with a high-set instantaneous element.

In most cases, use of the standard SI curve provessatisfactory, but if satisfactory grading cannot beachieved, use of the VI or EI curves may help to resolvethe problem. When digital or numeric relays are used,other characteristics may be provided, including thepossibility of user-definable curves. More details areprovided in the following sections.

Relays for power systems designed to North Americanpractice utilise ANSI/IEEE curves. Table 9.1(b) gives themathematical description of these characteristics andFigure 9.4(b) shows the curves standardised to a timedial setting of 1.0.

9.5 COMBINED I.D.M.T. AND HIGH SET INSTANTANEOUS OVERCURRENT RELAYS

A high-set instantaneous element can be used where thesource impedance is small in comparison with theprotected circuit impedance. This makes a reduction inthe tripping time at high fault levels possible. It alsoimproves the overall system grading by allowing the'discriminating curves' behind the high set instantaneouselements to be lowered.

As shown in Figure 9.6, one of the advantages of the highset instantaneous elements is to reduce the operatingtime of the circuit protection by the shaded area belowthe 'discriminating curves'. If the source impedanceremains constant, it is then possible to achieve high-speed protection over a large section of the protectedcircuit. The rapid fault clearance time achieved helps tominimise damage at the fault location. Figure 9.6 alsoillustrates a further important advantage gained by theuse of high set instantaneous elements. Grading withthe relay immediately behind the relay that has theinstantaneous elements enabled is carried out at thecurrent setting of the instantaneous elements and not at

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Figure 9.5: Typical time/current characteristics of standard IDMT relay

Tim

e (s

econ

ds)

Current (multiples of plug settings)

2

3

4

6

8

10

1

2 3 4 6 8 10 20 3010.1

0.2

0.4

0.3

0.6

0.8

1.0TMS

0.90.80.70.60.5

0.4

0.3

0.2

0.1

Figure 9.4 (b): IDMT relay characteristics

(b) North American characteristics; TD=7

0.10101

1.00

10.00

100.00

1000.00

100

Ope

ratin

g Ti

me

(sec

onds

)

Current (multiples of IS

I )

Moderately Inverse

Time Inverse

CO 8 Inverse

ExtremelyInverseInverse

Chap9 exe 21/06/02 8:51 Page 127


the maximum fault level. For example, in Figure 9.6,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 of0.2 while maintaining a grading margin between relaysof 0.4s. Similarly, relay R1 is graded with R2 at 1400Aand not at 2300A.

9.5.1 Transient Overreach

The reach of a relay is that part of the system protectedby the relay if a fault occurs. A relay that operates for afault that lies beyond the intended zone of protection issaid to overreach.When using instantaneous overcurrent elements, caremust be exercised in choosing the settings to preventthem operating for faults beyond the protected section.The initial current due to a d.c. offset in the current wavemay be greater than the relay pick-up value and cause itto operate. This may occur even though the steady stater.m.s. value of the fault current for a fault at a pointbeyond the required reach point may be less than therelay setting. This phenomenon is called transientoverreach, and is defined as:

…Equation 9.1

where:I1 = r.m.s steady-state relay pick-up currentI2 = steady state r.m.s. current which when fully

offset just causes relay pick-up

When applied to power transformers, the high setinstantaneous overcurrent elements must be set abovethe maximum through fault current than the powertransformer can supply for a fault across its LV terminals,in order to maintain discrimination with the relays onthe LV side of the transformer.

% % transient overreach = − ×I II

1 2

2100

9.6 VERY INVERSE (VI) OVERCURRENT RELAYS

Very inverse overcurrent relays are particularly suitable ifthere is a substantial reduction of fault current as thedistance from the power source increases, i.e. there is asubstantial increase in fault impedance. The VI operatingcharacteristic is such that the operating time isapproximately doubled for reduction in current from 7 to4 times the relay current setting. This permits the use ofthe same time multiplier setting for several relays in series.

Figure 9.7 provides a comparison of the SI and VI curvesfor a relay. The VI curve is much steeper and thereforethe operation increases much faster for the samereduction in current compared to the SI curve. Thisenables the requisite grading margin to be obtained witha lower TMS for the same setting current, and hence thetripping time at source can be minimised.

9.7 EXTREMELY INVERSE (EI) OVERCURRENT RELAYS

With this characteristic, the operation time isapproximately inversely proportional to the square of theapplied current. This makes it suitable for the protectionof distribution feeder circuits in which the feeder issubjected to peak currents on switching in, as would bethe case on a power circuit supplying refrigerators,pumps, water heaters and so on, which remainconnected even after a prolonged interruption of supply.The long time operating characteristic of the extremely

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Ope

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e (s

econ

ds)

0.10101

1.00

10.00

100.00

100Current ( multiples of Is )

Standard Inverse (SI)

Very Inverse (VI)

Figure 9.7: Comparison of SI and VI relay characteristics

Figure 9.6: Characteristics of combined IDMT and high-set instantaneous overcurrent relays

Tim

e (s

econ

ds)

2

3

1

100001000.1

400/1A

R1 R2 R3Source250 MVA11kV

100/1A 50/1AFault level 13.000A Fault level 2300A Fault level 1100A

Ratio

10,0000

R3

R2 RR1

500A 0.125 TMS

62.5A 0.10 TMS

300A

500A

Chap9 exe 21/06/02 8:51 Page 128


inverse relay at normal peak load values of current alsomakes this relay particularly suitable for grading withfuses. Figure 9.8 shows typical curves to illustrate this.It can be seen that use of the EI characteristic gives asatisfactory grading margin, but use of the VI or SIcharacteristics at the same settings does not. Anotherapplication of this relay is in conjunction with auto-reclosers in low voltage distribution circuits. Themajority of faults are transient in nature andunnecessary blowing and replacing of the fuses presentin final circuits of such a system can be avoided if theauto-reclosers are set to operate before the fuse blows.If the fault persists, the auto-recloser locks itself in theclosed position after one opening and the fuse blows toisolate the fault.

9.8 OTHER RELAY CHARACTERISTICS

User definable curves may be provided on some types ofdigital or numerical relays. The general principle is that theuser enters a series of current/time co-ordinates that arestored in the memory of the relay. Interpolation betweenpoints is used to provide a smooth trip characteristic. Sucha feature, if available, may be used in special cases if noneof the standard tripping characteristics is suitable.However, grading of upstream protection may becomemore 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 withadequate tripping times, and most equipment is designedwith standard protection curves in mind, the need to utilisethis form of protection is relatively rare.

Digital and numerical relays may also include pre-defined logic schemes utilising digital (relay) I/Oprovided in the relay to implement standard schemessuch as CB failure and trip circuit supervision. This savesthe provision of separate relay or PLC (ProgrammableLogic Controller) hardware to perform these functions.

9.9 INDEPENDENT (DEFINITE) TIMEOVERCURRENT RELAYS

Overcurrent relays are normally also provided withelements having independent or definite timecharacteristics. These characteristics provide a readymeans of co-ordinating several relays in series insituations in which the system fault current varies verywidely due to changes in source impedance, as there isno change in time with the variation of fault current.The time/current characteristics of this curve are shownin Figure 9.9, together with those of the standard I.D.M.T.characteristic, to indicate that lower operating times areachieved by the inverse relay at the higher values of faultcurrent, whereas the definite time relay has loweroperating times at the lower current values.

Vertical lines T1, T2, T3, and T4 indicate the reduction inoperating times achieved by the inverse relay at highfault levels.

9.10 RELAY CURRENT SETTING

An overcurrent relay has a minimum operating current,known as the current setting of the relay. The currentsetting must be chosen so that the relay does notoperate for the maximum load current in the circuitbeing protected, but does operate for a current equal orgreater to the minimum expected fault current.Although by using a current setting that is only justabove the maximum load current in the circuit a certaindegree of protection against overloads as well as faultsmay be provided, the main function of overcurrentprotection is to isolate primary system faults and not toprovide overload protection. In general, the currentsetting will be selected to be above the maximum shorttime rated current of the circuit involved. Since all relayshave hysteresis in their current settings, the setting mustbe sufficiently high to allow the relay to reset when therated current of the circuit is being carried. The amountof hysteresis in the current setting is denoted by thepick-up/drop-off ratio of a relay – the value for a modernrelay is typically 0.95. Thus, a relay minimum current

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Figure 9.8: Comparison of relay and fuse characteristics

1000.1

1000

1.0

10.0

100.0

10,000

200.0

Standardinverse (SI)

Current (amps)

Tim

e (s

ecs)

inverse (EI) Es E

200A Fuseus

v

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Chap9 exe 21/06/02 8:51 Page 129


setting of at least 1.05 times the short-time ratedcurrent of the circuit is likely to be required.

9.11 RELAY TIME GRADING MARGIN

The time interval that must be allowed between theoperation of two adjacent relays in order to achievecorrect discrimination between them is called the gradingmargin. If a grading margin is not provided, or isinsufficient, more than one relay will operate for a fault,leading to difficulties in determining the location of thefault and unnecessary loss of supply to some consumers.

The grading margin depends on a number of factors:

i. the fault current interrupting time of the circuitbreaker

ii. relay timing errors

iii. the overshoot time of the relay

iv. CT errors

v. final margin on completion of operation

Factors (ii) and (iii) above depend to a certain extent onthe relay technology used – an electromechanical relay,for instance, will have a larger overshoot time than anumerical relay.

Grading is initially carried out for the maximum faultlevel at the relaying point under consideration, but acheck is also made that the required grading marginexists for all current levels between relay pick-up currentand maximum fault level.

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Fault current (amps)

10

1

100100.1

6000A 3500A

10001

Settings of independent (definite) time relay Settings of I.D.M.T. relay with standard inverse characteristic

Fault level 2000A 1200A

10.000

Grading margin between relays: 0.4s

R1

R1A

R4

R4A

R2

R2A

R2R

3 R

4

R4A

R3A

R2A

R1A

R1

T1

T2

T3T3 T

T4T4 T

R3

R3A

R1A

300A 0.2TMSR 175A 0.3TMSR 100A 0.37TMSR4A

set at 57.5A 0.42TMS

R1A

300A 1.8sR 175A 1.4sR 100A 1.0sR4A

set at 57.5A 0.6s

Figure 9.9: Comparison of definite time and standard I.D.M.T. relay

Chap9 exe 21/06/02 8:54 Page 130


9.11.1 Circuit Breaker Interrupting Time

The circuit breaker interrupting the fault must havecompletely interrupted the current before thediscriminating relay ceases to be energised. The timetaken is dependent on the type of circuit breaker usedand the fault current to be interrupted. Manufacturersnormally provide the fault interrupting time at ratedinterrupting capacity and this value is invariably used inthe calculation of grading margin.

9.11.2 Relay Timing Error

All relays have errors in their timing compared to theideal characteristic as defined in IEC 60255. For a relayspecified to IEC 60255, a relay error index is quoted thatdetermines the maximum timing error of the relay. Thetiming error must be taken into account whendetermining the grading margin.

9.11.3 Overshoot

When the relay is de-energised, operation may continuefor a little longer until any stored energy has beendissipated. For example, an induction disc relay will havestored kinetic energy in the motion of the disc; staticrelay circuits may have energy stored in capacitors.Relay design is directed to minimising and absorbingthese energies, but some allowance is usually necessary.

The overshoot time is defined as the difference betweenthe operating time of a relay at a specified value of inputcurrent and the maximum duration of input current,which when suddenly reduced below the relay operatinglevel, is insufficient to cause relay operation.

9.11.4 CT Errors

Current transformers have phase and ratio errors due tothe exciting current required to magnetise their cores.The result is that the CT secondary current is not anidentical scaled replica of the primary current. This leadsto errors in the operation of relays, especially in the timeof operation. CT errors are not relevant whenindependent definite-time delay overcurrent relays arebeing considered.

9.11.5 Final Margin

After the above allowances have been made, thediscriminating relay must just fail to complete itsoperation. Some extra allowance, or safety margin, isrequired to ensure that relay operation does not occur.

9.11.6 Overall Accuracy

The overall limits of accuracy according to IEC 60255-4for an IDMT relay with standard inverse characteristicare shown in Figure 9.10.

9.12 RECOMMENDED GRADING INTERVALS

The following sections give the recommended overallgrading margins for between different protection devices.

9.12.1 Grading: Relay to Relay

The total interval required to cover the above itemsdepends on the operating speed of the circuit breakersand the relay performance. At one time 0.5s was anormal grading margin. With faster modern circuitbreakers and a lower relay overshoot time, 0.4s isreasonable, while under the best conditions even lowerintervals may be practical.

The use of a fixed grading margin is popular, but it maybe better to calculate the required value for each relaylocation. This more precise margin comprises a fixedtime, covering circuit breaker fault interrupting time,relay overshoot time and a safety margin, plus a variabletime that allows for relay and CT errors. Table 9.2 givestypical relay errors according to the technology used.

It should be noted that use of a fixed grading margin isonly appropriate at high fault levels that lead to shortrelay operating times. At lower fault current levels, withlonger operating times, the permitted error specified inIEC 60255 (7.5% of operating time) may exceed the fixedgrading margin, resulting in the possibility that the relayfails to grade correctly while remaining within

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Figure 9.10: Typical limits of accuracy from IEC 60255-4 for an inverse definite minimum time overcurrent relay

Tim

e (s

econ

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2

3

4

6

8

10

1

20

3

40

50

2 3 4 5 6 8 10 20 301

Time/Current characteristic allowable limit

At 2 times settingAt 5 times settingAt 10 times settingAt 20 times setting

2.5 x Declared error1.5 x Declared error1.0 x Declared error1.0 x Declared error

Chap9 exe 21/06/02 8:54 Page 131

follows an I2t law. So, to achieve proper co-ordinationbetween two fuses in series, it is necessary to ensure thatthe total I2t taken by the smaller fuse is not greater thanthe pre-arcing I2t value of the larger fuse. It has beenestablished by tests that satisfactory grading betweenthe two fuses will generally be achieved if the currentrating ratio between them is greater than two.

9.12.3 Grading: Fuse to Relay

For grading inverse time relays with fuses, the basicapproach is to ensure whenever possible that the relaybacks up the fuse and not vice versa. If the fuse isupstream of the relay, it is very difficult to maintaincorrect discrimination at high values of fault currentbecause of the fast operation of the fuse.

The relay characteristic best suited for this co-ordinationwith fuses is normally the extremely inverse (EI)characteristic as it follows a similar I2t characteristic. Toensure satisfactory co-ordination between relay andfuse, the primary current setting of the relay should beapproximately three times the current rating of the fuse.The grading margin for proper co-ordination, whenexpressed as a fixed quantity, should not be less than0.4s or, when expressed as a variable quantity, shouldhave a minimum value of:

t’ = 0.4t+0.15 seconds …Equation 9.4

where t is the nominal operating time of fuse.

Section 9.20.1 gives an example of fuse to relay grading.

9.13 CALCULATION OF PHASE FAULTOVERCURRENT RELAY SETTINGS

The correct co-ordination of overcurrent relays in a powersystem requires the calculation of the estimated relaysettings in terms of both current and time.

The resultant settings are then traditionally plotted insuitable log/log format to show pictorially that a suitablegrading margin exists between the relays at adjacentsubstations. Plotting may be done by hand, but nowadaysis more commonly achieved using suitable software.

The information required at each relaying point to allowa relay setting calculation to proceed is given in Section9.2. The principal relay data may be tabulated in a tablesimilar to that shown in Table 9.3, if only to assist inrecord keeping.


specification. This requires consideration whenconsidering the grading margin at low fault current levels.

A practical solution for determining the optimumgrading margin is to assume that the relay nearer to thefault has a maximum possible timing error of +2E, whereE is the basic timing error. To this total effective error forthe relay, a further 10% should be added for the overallcurrent transformer error.

A suitable minimum grading time interval, t’, may becalculated as follows:

…Equation 9.2

where: Er = relay timing error (IEC 60255-4)Ect = allowance for CT ratio error (%)t = operating time of relay nearer fault (s)tCB = CB interrupting time (s)to = relay overshoot time (s)ts = safety margin (s)

If, for example t=0.5s, the time interval for anelectromechanical relay tripping a conventional circuitbreaker would be 0.375s, whereas, at the lower extreme,for a static relay tripping a vacuum circuit breaker, theinterval could be as low as 0.24s.

When the overcurrent relays have independent definitetime delay characteristics, it is not necessary to includethe allowance for CT error. Hence:

…Equation 9.3

Calculation of specific grading times for each relay canoften be tedious when performing a protection gradingcalculation on a power system. Table 9.2 also givespractical grading times at high fault current levelsbetween overcurrent relays for different technologies.Where relays of different technologies are used, the timeappropriate to the technology of the downstream relayshould be used.

9.12.2 Grading: Fuse to Fuse

The operating time of a fuse is a function of both thepre-arcing and arcing time of the fusing element, which

′=

+ + +t E t t t tRCB o s

2100

seconds

′= +

+ + +t E E t t t tR CTCB o s

2100

seconds

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Fault Current Relay Current Setting(A) Maximun CT Relay Time

Location Load Current Ratio Primary Multiplier SettingMaximun Minimun (A) Per Cent Current

(A)

Table 9.3: Typical relay data table

Table 9.2: Typical relay timing errors - standard IDMT relays

Relay TechnologyElectro- Static Digital Numericalmechanical

Typical basic timing error (%) 7.5 5 5 5

Overshoot time (s) 0.05 0.03 0.02 0.02

Safety margin (s) 0.1 0.05 0.03 0.03

Typical overall grading margin - relay to relay(s) 0.4 0.35 0.3 0.3

Chap9 exe 21/06/02 8:54 Page 132


It is usual to plot all time/current characteristics to acommon voltage/MVA base on log/log scales. The plotincludes all relays in a single path, starting with the relaynearest the load and finishing with the relay nearest thesource of supply.

A separate plot is required for each independent path,and the settings of any relays that lie on multiple pathsmust be carefully considered to ensure that the finalsetting is appropriate for all conditions. Earth faults areconsidered separately from phase faults and requireseparate plots.

After relay settings have been finalised, they are enteredin a table. One such table is shown in Table 9.3. This alsoassists in record keeping and during commissioning ofthe relays at site.

9.13.1 Independent (definite) Time Relays

The selection of settings for independent (definite) timerelays presents little difficulty. The overcurrent elementsmust be given settings that are lower, by a reasonablemargin, than the fault current that is likely to flow to afault at the remote end of the system up to which back-up protection is required, with the minimum plant inservice.

The settings must be high enough to avoid relayoperation with the maximum probable load, a suitablemargin being allowed for large motor starting currents ortransformer inrush transients.

Time settings will be chosen to allow suitable gradingmargins, as discussed in Section 9.12.

9.13.2 Inverse Time Relays

When the power system consists of a series of shortsections of cable, so that the total line impedance is low,the value of fault current will be controlled principally bythe impedance of transformers or other fixed plant andwill not vary greatly with the location of the fault. In suchcases, it may be possible to grade the inverse time relaysin very much the same way as definite time relays.However, when the prospective fault current variessubstantially with the location of the fault, it is possible tomake use of this fact by employing both current and timegrading to improve the overall performance of the relay.

The procedure begins by selection of the appropriaterelay characteristics. Current settings are then chosen,with finally the time multiplier settings to giveappropriate grading margins between relays. Otherwise,the procedure is similar to that for definite time delayrelays. An example of a relay setting study is given inSection 9.20.1.

9.14 DIRECTIONAL PHASE FAULT OVERCURRENT RELAYS

When fault current can flow in both directions throughthe relay location, it may be necessary to make theresponse of the relay directional by the introduction of adirectional control facility. The facility is provided by useof additional voltage inputs to the relay.

9.14.1 Relay Connections

There are many possibilities for a suitable connection ofvoltage and current inputs. The various connections aredependent on the phase angle, at unity system powerfactor, by which the current and voltage applied to therelay are displaced. Reference [9.1] details all of theconnections that have been used. However, only very feware used in current practice and these are described below.

In a digital or numerical relay, the phase displacements arerealised by the use of software, while electromechanicaland static relays generally obtain the required phasedisplacements by suitable connection of the inputquantities to the relay. The history of the topic results inthe relay connections being defined as if they wereobtained 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 numericalrelays. Depending on the angle by which the applied voltageis shifted to produce maximum relay sensitivity (the RelayCharacteristic Angle, or RCA) two types are available.

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Ia

MTA

Zero torque line

VbVc

Vbc

Va

V'bc

30°

30°150°

A phase element connected Ia Vbc

B phase element connected Ib Vca

C phase element connected Ic Vab

Figure 9.11: Vector diagram for the 90°-30° connection (phase A element)

Chap9 exe 21/06/02 8:55 Page 133


9.14.2.1 90°-30° characteristic (30° RCA)

The A phase relay element is supplied with Ia current andVbc voltage displaced by 30° in an anti-clockwisedirection. In this case, the relay maximum sensitivity isproduced when the current lags the system phase toneutral voltage by 60°. This connection gives a correctdirectional tripping zone over the current range of 30°leading to 150° lagging; see Figure 9.11. The relaysensitivity at unity power factor is 50% of the relaymaximum sensitivity and 86.6% at zero power factorlagging. This characteristic is recommended when therelay is used for the protection of plain feeders with thezero sequence source behind the relaying point.

9.14.2.2 90°-45° characteristic (45° RCA)

The A phase relay element is supplied with current Ia andvoltage Vbc displaced by 45° in an anti-clockwisedirection. The relay maximum sensitivity is producedwhen the current lags the system phase to neutralvoltage by 45°. This connection gives a correctdirectional tripping zone over the current range of 45°leading to 135° lagging. The relay sensitivity at unitypower factor is 70.7% of the maximum torque and thesame at zero power factor lagging; see Figure 9.12.

This connection is recommended for the protection oftransformer feeders or feeders that have a zero sequencesource in front of the relay. It is essential in the case ofparallel transformers or transformer feeders, in order toensure correct relay operation for faults beyond thestar/delta transformer. This connection should also beused whenever single-phase directional relays areapplied to a circuit where a current distribution of theform 2-1-1 may arise.

For a digital or numerical relay, it is common to allowuser-selection of the RCA angle within a wide range.

Theoretically, three fault conditions can causemaloperation of the directional element:

i. a phase-phase-ground fault on a plain feeder

ii. a phase-ground fault on a transformer feeder withthe zero sequence source in front of the relay

iii. a phase-phase fault on a power transformer withthe relay looking into the delta winding of thetransformer

It should be remembered, however, that the conditionsassumed above to establish the maximum angulardisplacement between the current and voltage quantitiesat the relay are such that, in practice, the magnitude ofthe current input to the relay would be insufficient tocause the overcurrent element to operate. It can beshown analytically that the possibility of maloperationwith the 90°-45° connection is, for all practical purposes,non-existent.

9.14.3 Application of Directional Relays

If non-unit, non-directional relays are applied to parallelfeeders having a single generating source, any faults thatmight occur on any one line will, regardless of the relaysettings used, isolate both lines and completelydisconnect the power supply. With this type of systemconfiguration, it is necessary to apply directional relaysat the receiving end and to grade them with the non-directional relays at the sending end, to ensure correctdiscriminative operation of the relays during line faults.This is done by setting the directional relays R1’ and R2’in Figure 9.13 with their directional elements lookinginto the protected line, and giving them lower time andcurrent settings than relays R1 and R2. The usual practiceis to set relays R1’ and R2’ to 50% of the normal full loadof the protected circuit and 0.1TMS, but care must betaken to ensure that the continuous thermal rating ofthe relays of twice rated current is not exceeded. Anexample calculation is given in Section 9.20.3

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Source

R2R'2

R1 R'1

Load

I>

I>I>

I>

Figure 9.13: Directional relays applied to parallel feedersFigure 9.12: Vector diagram for the 90°-45° connection (phase A element)

45°

135°

MTA

Zero torque line

VcVcV VbVbV

VbcVbcV

VaVaV

IaIaI

V'bc

45°

A phase element connected Ia Vbc

B phase element connected Ib Vca

C phase element connected Ic Vab

Chap9 exe 21/06/02 8:55 Page 134


9.15 RING MAINS

A particularly common arrangement within distributionnetworks is the Ring Main. The primary reason for its useis to maintain supplies to consumers in case of faultconditions occurring on the interconnecting feeders. Atypical ring main with associated overcurrent protectionis shown in Figure 9.14. Current may flow in eitherdirection through the various relay locations, andtherefore directional overcurrent relays are applied.

In the case of a ring main fed at one point only, thesettings of the relays at the supply end and at the mid-point substation are identical. They can therefore bemade non-directional, if, in the latter case, the relays arelocated on the same feeder, that is, one at each end ofthe feeder.

It is interesting to note that when the number of feedersround the ring is an even number, the two relays with thesame operating time are at the same substation. Theywill therefore have to be directional. When the numberof feeders is an odd number, the two relays with thesame operating time are at different substations andtherefore do not need to be directional. It may also benoted that, at intermediate substations, whenever theoperating time of the relays at each substation aredifferent, the difference between their operating times isnever less than the grading margin, so the relay with thelonger operating time can be non-directional. Withmodern numerical relays, a directional facility is oftenavailable for little or no extra cost, so that it may besimpler in practice to apply directional relays at alllocations. Also, in the event of an additional feederbeing added subsequently, the relays that can be non-directional need to be re-determined and will notnecessarily be the same – giving rise to problems ofchanging a non-directional relay for a directional one. Ifa VT was not provided originally, this may be verydifficult to install at a later date.

9.15.1 Grading of Ring Mains

The usual grading procedure for relays in a ring maincircuit is to open the ring at the supply point and tograde the relays first clockwise and then anti-clockwise.That is, the relays looking in a clockwise direction aroundthe ring are arranged to operate in the sequence 1-2-3-4-5-6 and the relays looking in the anti-clockwisedirection are arranged to operate in the sequence 1’-2’-3’-4’-5’-6’, as shown in Figure 9.14.

The arrows associated with the relaying points indicatethe direction of current flow that will cause the relay tooperate. A double-headed arrow is used to indicate anon-directional relay, such as those at the supply pointwhere the power can flow only in one direction. Asingle-headed arrow is used to indicate a directional

relay, such as those at intermediate substations aroundthe ring where the power can flow in either direction.The directional relays are set in accordance with theinvariable rule, applicable to all forms of directionalprotection, that the current in the system must flowfrom the substation busbars into the protected line inorder that the relays may operate.Disconnection of the faulted line is carried out accordingto time and fault current direction. As in any parallelsystem, the fault current has two parallel paths anddivides itself in the inverse ratio of their impedances.Thus, at each substation in the ring, one set of relays willbe made inoperative because of the direction of currentflow, and the other set operative. It will also be foundthat the operating times of the relays that areinoperative are faster than those of the operative relays,with the exception of the mid-point substation, wherethe operating times of relays 3 and 3’ happen to be thesame.

The relays that are operative are graded downwardstowards the fault and the last to be affected by the faultoperates first. This applies to both paths to the fault.Consequently, the faulted line is the only one to bedisconnected from the ring and the power supply ismaintained to all the substations.

When two or more power sources feed into a ring main,time graded overcurrent protection is difficult to apply

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Figure 9.14: Grading of ring mains

2.1 2.1

6' 6

0.9

3'

1.7

0.1

5'

1

0.52

4'

1.3

1.7 50.1

1'

0.9

3

1.3

0.5

4

2'

Fault

2.1

6'

1.7

5' '4' '3

1.3 0.9

2'

0.5

'1

0.1

654

2.11.71.3

321

0.90.50.1

Ix

Iy

Chap9 exe 21/06/02 8:55 Page 135


and full discrimination may not be possible. With twosources of supply, two solutions are possible. The first isto open the ring at one of the supply points, whichever ismore convenient, by means of a suitable high setinstantaneous overcurrent relay. The ring is then gradedas in the case of a single infeed. The second method is totreat the section of the ring between the two supplypoints as a continuous bus separate from the ring and toprotect it with a unit protection system, and then proceedto grade the ring as in the case of a single infeed. Section9.20.4 provides a worked example of ring main grading.

9.16 EARTH FAULT PROTECTION

In the foregoing description, attention has beenprincipally directed towards phase fault overcurrentprotection. More sensitive protection against earthfaults can be obtained by using a relay that respondsonly to the residual current of the system, since aresidual component exists only when fault current flowsto earth. The earth-fault relay is therefore completelyunaffected by load currents, whether balanced or not,and can be given a setting which is limited only by thedesign of the equipment and the presence of unbalancedleakage or capacitance currents to earth. This is animportant consideration if settings of only a few percentof system rating are considered, since leakage currentsmay 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 onlyby far the most frequent of all faults, but may be limitedin magnitude by the neutral earthing impedance, or byearth contact resistance.

The residual component is extracted by connecting theline current transformers in parallel as shown in Figure9.15. The simple connection shown in Figure 9.15(a) canbe extended by connecting overcurrent elements in theindividual phase leads, as illustrated in Figure 9.15(b),and inserting the earth-fault relay between the starpoints of the relay group and the current transformers.

Phase fault overcurrent relays are often provided on onlytwo phases since these will detect any interphase fault;the connections to the earth-fault relay are unaffectedby this consideration. The arrangement is illustrated inFigure 9.15(c).

The typical settings for earth-fault relays are 30%-40%of the full-load current or minimum earth-fault currenton the part of the system being protected. However,account may have to be taken of the variation of settingwith relay burden as described in Section 9.16.1 below.If greater sensitivity than this is required, one of themethods described in Section 9.16.3 for obtainingsensitive earth-fault protection must be used.

9.16.1 Effective Setting of Earth-Fault Relays

The primary setting of an overcurrent relay can usuallybe taken as the relay setting multiplied by the CT ratio.The CT can be assumed to maintain a sufficientlyaccurate ratio so that, expressed as a percentage of ratedcurrent, the primary setting will be directly proportionalto the relay setting. However, this may not be true foran earth-fault relay. The performance varies accordingto the relay technology used.

9.16.1.1 Static, digital and numerical relays

When static, digital or numerical relays are used therelatively low value and limited variation of the relayburden over the relay setting range results in the abovestatement holding true. The variation of input burdenwith current should be checked to ensure that the

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A

B

C

C

B

A

C

B

A

(c)

(b)

(a)

I >

I>

I>

I> I >

I>I> I >

Figure 9.15: Residual connection of current transformers to earth-fault relays

Chap9 exe 21/06/02 8:55 Page 136


variation is sufficiently small. If not, substantial errorsmay occur, and the setting procedure will have to followthat for electromechanical relays.

9.16.1.2 Electromechanical relays

When using an electromechanical relay, the earth-faultelement generally will be similar to the phase elements.It will have a similar VA consumption at setting, but willimpose a far higher burden at nominal or rated current,because of its lower setting. For example, a relay with asetting of 20% will have an impedance of 25 times thatof a similar element with a setting of 100%. Veryfrequently, this burden will exceed the rated burden ofthe current transformers. It might be thought thatcorrespondingly larger current transformers should beused, but this is considered to be unnecessary. Thecurrent transformers that handle the phase burdens canoperate the earth fault relay and the increased errors caneasily be allowed for.

Not only is the exciting current of the energising currenttransformer proportionately high due to the large burdenof the earth-fault relay, but the voltage drop on this relayis impressed on the other current transformers of theparalleled group, whether they are carrying primarycurrent or not. The total exciting current is therefore theproduct of the magnetising loss in one CT and thenumber of current transformers in parallel. Thesummated magnetising loss can be appreciable incomparison with the operating current of the relay, andin extreme cases where the setting current is low or thecurrent transformers are of low performance, may evenexceed the output to the relay. The ‘effective settingcurrent’ in secondary terms is the sum of the relaysetting current and the total excitation loss. Strictlyspeaking, the effective setting is the vector sum of therelay setting current and the total exciting current, butthe arithmetic sum is near enough, because of thesimilarity of power factors. It is instructive to calculatethe effective setting for a range of setting values of arelay, a process that is set out in Table 9.4, with theresults illustrated in Figure 9.16.

The effect of the relatively high relay impedance and thesummation of CT excitation losses in the residual circuitis augmented still further by the fact that, at setting, theflux density in the current transformers corresponds tothe bottom bend of the excitation characteristic. Theexciting impedance under this condition is relatively low,causing the ratio error to be high. The currenttransformer actually improves in performance withincreased primary current, while the relay impedancedecreases until, with an input current several timesgreater than the primary setting, the multiple of settingcurrent in the relay is appreciably higher than themultiple of primary setting current which is applied tothe primary circuit. This causes the relay operating time

to be shorter than might be expected.

At still higher input currents, the CT performance falls offuntil finally the output current ceases to increasesubstantially. Beyond this value of input current,operation is further complicated by distortion of theoutput current waveform.

9.16.2 Time Grading of Earth-Fault Relays

The time grading of earth-fault relays can be arranged inthe same manner as for phase fault relays. Thetime/primary current characteristic for electro-mechanical relays cannot be kept proportionate to therelay characteristic with anything like the accuracy thatis possible for phase fault relays. As shown above, theratio error of the current transformers at relay settingcurrent may be very high. It is clear that time grading ofelectromechanical earth-fault relays is not such a simple

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Table 9.4: Calculation of effective settings

Relay Plug Coil voltage Exciting Effective SettingSetting at Setting Current Current

%% Current (A) (V) Ie (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

Figure 9.16: Effective setting of earth-fault relay

Current transformerexcitation characteristic

1.51.00.50

10

20

30

Seco

ndar

y vo

ltage

Exciting current (amperes)

Effe

ctiv

e se

ttin

g (p

er c

ent)

0 80 100

100

80

60

40

20

604020

Relay setting (per cent)

Chap9 exe 21/06/02 8:55 Page 137


matter as the procedure adopted for phase relays in Table 9.3. Either the above factors must be taken intoaccount with the errors calculated for each current level,making the process much more tedious, or longergrading margins must be allowed. However, for othertypes of relay, the procedure adopted for phase faultrelays can be used.

9.16.3 Sensitive Earth-Fault Protection

LV systems are not normally earthed through animpedance, due to the resulting overvoltages that mayoccur and consequential safety implications. HV systemsmay be designed to accommodate such overvoltages, butnot the majority of LV systems.

However, it is quite common to earth HV systems throughan impedance that limits the earth-fault current. Further,in some countries, the resistivity of the earth path may bevery high due to the nature of the ground itself (e.g.desert or rock). A fault to earth not involving earthconductors may result in the flow of only a small current,insufficient to operate a normal protection system. Asimilar difficulty also arises in the case of broken lineconductors, which, after falling on to hedges or drymetalled roads, remain energised because of the lowleakage current, and therefore present a danger to life.

To overcome the problem, it is necessary to provide anearth-fault protection system with a setting that isconsiderably lower than the normal line protection. Thispresents no difficulty to a modern digital or numericalrelay. However, older electromechanical or static relaysmay present difficulties due to the high effective burdenthey may present to the CT.

The required sensitivity cannot normally be provided bymeans of conventional CT’s. A core balance currenttransformer (CBCT) will normally be used. The CBCT is acurrent transformer mounted around all three phase (andneutral if present) conductors so that the CT secondarycurrent is proportional to the residual (i.e. earth) current.Such a CT can be made to have any convenient ratiosuitable for operating a sensitive earth-fault relayelement. By use of such techniques, earth fault settingsdown to 10% of the current rating of the circuit to beprotected can be obtained.

Care must be taken to position a CBCT correctly in acable circuit. If the cable sheath is earthed, the earthconnection from the cable gland/sheath junction mustbe taken through the CBCT primary to ensure that phase-sheath faults are detected. Figure 9.17 shows the correctand incorrect methods. With the incorrect method, thefault current in the sheath is not seen as an unbalancecurrent and hence relay operation does not occur.

The normal residual current that may flow during healthy

conditions limits the application of non-directional sensitiveearth-fault protection. Such residual effects can occur dueto unbalanced leakage or capacitance in the system.

9.17 DIRECTIONAL EARTH-FAULT OVERCURRENTPROTECTION

Directional earth-fault overcurrent may need to beapplied in the following situations:

i. for earth-fault protection where the overcurrentprotection is by directional relays

ii. in insulated-earth networks

iii. in Petersen coil earthed networks

iv. where the sensitivity of sensitive earth-faultprotection is insufficient – use of a directionalearth-fault relay may provide greater sensitivity

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• 1 3 8 •

Cable gland /sheathground connection

(a) Physical connections

(b) Incorrect positioning

Cable gland

Cablebox

No operation

Operation

I >

I >

I >

Figure 9.17: Positioning of core balance current transformers

Chap9 exe 21/06/02 8:57 Page 138


The relay elements previously described as phase faultelements respond to the flow of earth fault current, andit is important that their directional response be correctfor this condition. If a special earth fault element isprovided as described in Section 9.16 (which will normallybe the case), a related directional element is needed.

9.17.1 Relay Connections

The residual current is extracted as shown in Figure 9.15.Since this current may be derived from any phase, inorder to obtain a directional response it is necessary toobtain an appropriate quantity to polarise the relay. Indigital or numerical relays there are usually two choicesprovided.

9.17.1.1 Residual voltage

A suitable quantity is the residual voltage of the system.This is the vector sum of the individual phase voltages. Ifthe secondary windings of a three-phase, five limbvoltage transformer or three single-phase units areconnected in broken delta, the voltage developed acrossits terminals will be the vector sum of the phase toground voltages and hence the residual voltage of thesystem, as illustrated in Figure 9.18.

The primary star point of the VT must be earthed.However, a three-phase, three limb VT is not suitable, asthere is no path for the residual magnetic flux.

When the main voltage transformer associated with thehigh voltage system is not provided with a broken deltasecondary winding to polarise the directional earth faultrelay, it is permissible to use three single-phaseinterposing voltage transformers. Their primary windingsare connected in star and their secondary windings areconnected in broken delta. For satisfactory operation,however, it is necessary to ensure that the main voltagetransformers are of a suitable construction to reproducethe residual voltage and that the star point of theprimary winding is solidly earthed. In addition, the starpoint of the primary windings of the interposing voltagetransformers must be connected to the star point of thesecondary windings of the main voltage transformers.

The residual voltage will be zero for balanced phasevoltages. For simple earth-fault conditions, it will beequal to the depression of the faulted phase voltage. Inall cases the residual voltage is equal to three times thezero sequence voltage drop on the source impedance andis therefore displaced from the residual current by thecharacteristic angle of the source impedance. Theresidual quantities are applied to the directional elementof the earth-fault relay.

The residual current is phase offset from the residualvoltage and hence angle adjustment is required.Typically, the current will lag the polarising voltage. Themethod of system earthing also affects the RelayCharacteristic Angle (RCA), and the following settingsare usual:

i. resistance-earthed system: 0° RCA

ii. distribution system, solidly-earthed: -45° RCA

iii. transmission system, solidly-earthed: -60° RCA

The different settings for distribution and transmissionsystems arise from the different X/R ratios found in thesesystems.

9.17.1.2 Negative sequence current

The residual voltage at any point in the system may beinsufficient to polarise a directional relay, or the voltagetransformers available may not satisfy the conditions forproviding residual voltage. In these circumstances,negative sequence current can be used as the polarisingquantity. The fault direction is determined by comparisonof the negative sequence voltage with the negativesequence current. The RCA must be set based on theangle of the negative phase sequence source voltage.

9.18 EARTH-FAULT PROTECTION ON INSULATEDNETWORKS

Occasionally, a power system is run completely insulatedfrom earth. The advantage of this is that a single phase-earth fault on the system does not cause any earth fault

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Figure 9.18: Voltage polarised directional earth fault relay

(a) Relay connections

C

B

A

VaVaV

VcVcV VbVbV VcVcV VbVbV

Va2Va2V

3IOIOI

3VOVOV

VaVaV

(b) Balanced system (zero residual volts)

(c) Unbalanced system

fault (3Vo residual volts)

3

>I

Chap9 exe 21/06/02 8:57 Page 139


current to flow, and so the whole system remainsoperational. The system must be designed to withstand hightransient and steady-state overvoltages however, so its useis generally restricted to low and medium voltage systems.

It is vital that detection of a single phase-earth fault isachieved, 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 substantialcurrents to flow.

The absence of earth-fault current for a single phase-earthfault clearly presents some difficulties in fault detection.Two methods are available using modern relays.

9.18.1 Residual Voltage

When a single phase-earth fault occurs, the healthyphase voltages rise by a factor of √3 and the three phasevoltages no longer have a phasor sum of zero. Hence, aresidual voltage element can be used to detect the fault.However, the method does not provide anydiscrimination, as the unbalanced voltage occurs on thewhole of the affected section of the system. Oneadvantage of this method is that no CT’s are required, asvoltage is being measured. However, the requirementsfor the VT’s as given in Section 9.17.1.1 apply.

Grading is a problem with this method, since all relays inthe affected section will see the fault. It may be possibleto use definite-time grading, but in general, it is notpossible to provide fully discriminative protection usingthis technique.

9.18.2 Sensitive Earth Fault

This method is principally applied to MV systems, as itrelies on detection of the imbalance in the per-phasecharging currents that occurs.

Figure 9.19 illustrates the situation that occurs when asingle phase-earth fault is present. The relays on thehealthy feeders see the unbalance in charging currentsfor their own feeders. The relay in the faulted feeder seesthe charging currents in the rest of the system, with thecurrent of its’ own feeders cancelled out. Figure 9.20shows the phasor diagram.

Use of Core Balance CT’s is essential. With reference toFigure 9.20, the unbalance current on the healthyfeeders lags the residual voltage by 90°. The chargingcurrents on these feeders will be √3 times the normalvalue, as the phase-earth voltages have risen by thisamount. The magnitude of the residual current istherefore three times the steady-state charging currentper phase. As the residual currents on the healthy andfaulted feeders are in antiphase, use of a directionalearth fault relay can provide the discrimination required.

The polarising quantity used is the residual voltage. Byshifting this by 90°, the residual current seen by the relayon the faulted feeder lies within the ‘operate’ region ofthe directional characteristic, while the residual currentson the healthy feeders lie within the ‘restrain’ region.Thus, the RCA required is 90°. The relay setting has to liebetween one and three times the per-phase chargingcurrent.

This may be calculated at the design stage, butconfirmation by means of tests on-site is usual. A singlephase-earth fault is deliberately applied and theresulting currents noted, a process made easier in amodern digital or numeric relay by the measurementfacilities provided. As noted earlier, application of sucha fault for a short period does not involve any disruption

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• 1 4 0 •

Ia3Ia3I

IH1I + H3

I +IH2I

IR3I

IR2I

IR1I

IH2I

I

Ia2Ia2IIb2Ib2I

Ia1IIb1Ib1I

jXc3Xc3X

jXc2Xc2X

IH1I

jXc1Xc1X

=I +IH2I +IH3I -IH3I=IH1I IH2I

IR3I

Figure 9.19: Current distribution in an insulated system with a C phase –earth fault

Figure 9.20: Phasor diagram for insulated system with C phase-earth fault

An RCA setting of +90° shiftsthe "center of the characteristic" to here

VcpfVcpfVVbpfVbpfV

VbfVbfV

IR3I = -(IH1I IH2I )

VafVafV

VapfVapfVIR1I

Ia1Ia1I

Ib1Ib1I

Restrain

Operate

VresVresV (= -3Vo)

Chap9 exe 21/06/02 8:57 Page 140


to the network, or fault currents, but the duration shouldbe as short as possible to guard against a second suchfault occurring.

It is also possible to dispense with the directional elementif the relay can be set at a current value that lies betweenthe charging current on the feeder to be protected andthe charging current of the rest of the system.

9.19 EARTH FAULT PROTECTION ON PETERSEN COILEARTHED NETWORKS

Petersen Coil earthing is a special case of highimpedance earthing. The network is earthed via areactor, whose reactance is made nominally equal to thetotal system capacitance to earth. Under this condition,a single phase-earth fault does not result in any earthfault current in steady-state conditions. The effect istherefore similar to having an insulated system. Theeffectiveness of the method is dependent on theaccuracy of tuning of the reactance value – changes insystem capacitance (due to system configurationchanges for instance) require changes to the coilreactance. In practice, perfect matching of the coilreactance to the system capacitance is difficult toachieve, so that a small earth fault current will flow.Petersen Coil earthed systems are commonly found inareas where the system consists mainly of rural overheadlines, and are particularly beneficial in locations subjectto a high incidence of transient faults.

To understand how to correctly apply earth faultprotection to such systems, system behaviour under earthfault conditions must first be understood.

Figure 9.21 illustrates a simple network earthed througha Petersen Coil. The equations clearly show that, if thereactor is correctly tuned, no earth fault current will flow.

Figure 9.22 shows a radial distribution system earthedusing a Petersen Coil. One feeder has a phase-earth faulton phase C. Figure 9.23 shows the resulting phasordiagrams, assuming that no resistance is present.

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C B

A ILI

-IBI

-ICICI

VabVabVVacVacV

-----

N

Current vectors for A phase fault

Source

Petersencoil

-ICICI

-jX- CXCX-jX- X

jXLXLX

(=ILI )

VanVanV

L

-jX- CXCX

(=-IbIbI

VabVabV

jXC

XC

IcIcI )

VacVacV

CIfIfI

-IBI

IfIfIf IBI - C+VanVanV

jXLXLX

=O if =IBI +ICICIan

jXLXL

Figure 9.21: Earth fault in Petersen Coil earthed system

A

N

C B

3VO

VO

VIL

IH3

IH2

IH1

b1

Ia1

Ib1Ib1I

IL

IR3

Ia1

IR1

=IH1

Vres

=-3VO

V Vres

=-3VO

V

a) Capacitive et inductive currents

b) Unfaulted line c) Faulted line

-IH1

IR3

=-I +I=- -I

H2

-I

Figure 9.23: C phase-earth fault in Petersen Coil earthed network: theoretical case –no resistance present in XL or XC

ILI =IFI IH1I IH2I -IH3IH1+IH2I

ILI

IFI

IH2IIa3Ia3I

II =IFIIb3Ib3I

Ia2Ia2IIb2Ib2I

IR3

IR2I

-jX- C3XC3X

-jX- C2XC2XjXLXLX

ILIIH1IH1I

Ia1Ia1IIb1Ib1I

IR1I-jX- C1XC1X

Figure 9.22: Distribution of currents during a C phase-earth fault – radial distribution system

Chap9 exe 21/06/02 8:57 Page 141


In Figure 9.23(a), it can be seen that the fault causes thehealthy phase voltages to rise by a factor of √3 and thecharging currents lead the voltages by 90°.

Using a CBCT, the unbalance currents seen on thehealthy feeders can be seen to be a simple vectoraddition of Ia1 and Ib1, and this lies at exactly 90° laggingto the residual voltage (Figure 9.23(b)). The magnitudeof the residual current IR1 is equal to three times thesteady-state charging current per phase. On the faultedfeeder, the residual current is equal to IL-IH1-IH2, asshown in Figure 9.23(c) and more clearly by the zerosequence network of Figure 9.24.

However, in practical cases, resistance is present andFigure 9.25 shows the resulting phasor diagrams. If theresidual voltage Vres is used as the polarising voltage, theresidual current is phase shifted by an angle less than90° on the faulted feeder and greater than 90° on thehealthy feeders.

Hence a directional relay can be used, and with an RCAof 0°, the healthy feeder residual current will fall in the‘restrain’ area of the relay characteristic while thefaulted feeder residual current falls in the ‘operate’ area.

Often, a resistance is deliberately inserted in parallelwith the Petersen Coil to ensure a measurable earth faultcurrent and increase the angular difference between theresidual signals to aid relay application.

Having established that a directional relay can be used,two possibilities exist for the type of protection elementthat can be applied – sensitive earth fault and zerosequence wattmetric.

9.19.1 Sensitive Earth Fault Protection

To apply this form of protection, the relay must meet tworequirements:

a. current measurement setting capable of being setto very low values

b. an RCA of 0°, and capable of fine adjustmentaround this value

The sensitive current element is required because of thevery low current that may flow – so settings of less than0.5% of rated current may be required. However, ascompensation by the Petersen Coil may not be perfect,low levels of steady-state earth-fault current will flowand increase the residual current seen by the relay. Anoften used setting value is the per phase chargingcurrent of the circuit being protected.

Fine tuning of the RCA is also required about the 0°setting, to compensate for coil and feeder resistancesand the performance of the CT used. In practice, theseadjustments are best carried out on site throughdeliberate application of faults and recording of theresulting currents.

9.19.2 Sensitive Wattmetric Protection

It can be seen in Figure 9.25 that a small angulardifference exists between the spill current on the healthyand faulted feeders. Figure 9.26 illustrates how thisangular difference gives rise to active components ofcurrent which are in antiphase to each other.

Consequently, the active components of zero sequencepower will also lie in similar planes and a relay capableof detecting active power can make a discriminatory

• 9 •

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• 1 4 2 •

IL

IH3

IROFIOF

IROH

IROH

Xco

IH2 IH13XL

Faulted feeder

Healthy feeders

Key:IROF=residual current on faulted feederIROH=residual current on healthy feederIt can therefore be seen that:-IOF=IL-IH1-IH2-IH3IROF=IH3+IOFSo:-IROF=IL=IH1-IH2

-VO

Figure 9.24: Zero sequence network showing residual currents

A

N

C B

I'L

(I 1+IH2+IH3)'

IR1=IH1

Vres=-3VO

Vres=-3VO

-IH1-IH2

3VO

IL

IR3=IF+IH3

=IL-IH1-IH2

IR3

b) Unfaulted line

Resistive component in feederResistive componentin grounding coil

Restrain

Zero torque line for 0° RCA

c) Faulted line

Operate

Operate

Restrain

Zero torque linefor O° RCA

a) Capacitive and inductive currents with resistive components

Figure 9.25: C phase-earth fault in Petersen Coil earthed network: practical case with resistance present in XL or XC

Chap9 exe 21/06/02 8:57 Page 142


decision. If the wattmetric component of zero sequencepower is detected in the forward direction, it indicates afault on that feeder, while a power in the reversedirection indicates a fault elsewhere on the system. Thismethod of protection is more popular than the sensitiveearth fault method, and can provide greater securityagainst false operation due to spurious CBCT outputunder non-earth fault conditions.

Wattmetric power is calculated in practice using residualquantities instead of zero sequence ones. The resultingvalues are therefore nine times the zero sequencequantities as the residual values of current and voltageare each three times the corresponding zero sequencevalues. The equation used is:

…Equation 9.5

where:

Vres = residual voltage

Ires = residual current

Vo = zero sequence voltage

Io = zero sequence current

φ = angle between Vres and Ires

φc = relay characteristic angle setting

The current and RCA settings are as for a sensitive earthfault relay.

9.20 EXAMPLES OF TIME AND CURRENT GRADING

This section provides details of the time/current gradingof some example networks, to illustrate the process ofrelay setting calculations and relay grading. They arebased on the use of a modern numerical overcurrentrelay illustrated in Figure 9.27, with setting data takenfrom this relay.

V I

V I

res res c

O O c

× × −( )= × × × −( )

cos

cos

ϕ ϕ

ϕ ϕ 9

9.20.1 Relay Phase Fault Setting Example – IDMT Relays/Fuses

Consider the system shown in Figure 9.28.

The problem is to calculate appropriate relay settings forrelays 1-5 inclusive. Because the example is concernedwith grading, considerations such as bus-zone

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aults

Active componentof residual current:faulted feeder

Zero torque linefor O° RCA

Operate

RestrainIR1I

ILI

IR3I IH1I -IH2I

VresVresV =-3VOVOV

of residual current:healthy feeder

Figure 9.26: Resistive components of spill current

I>>

I>>

I>

I>

I>

I>

I

I

I

500 MVA 11kVUtility source

11kV

Max load 2800A

Utility client

Cable C1 : 5 x 3 x1c x 630mm2 XLPEZ = 0.042 + j 0.086Ω/km/cableL = 2km

3000/5

Bus A 11kV

Bus B 11kV

Bus C 11kV

150/5 200/5

C3C2

4

5

3000/1

Cables C2,C3: 1 x 3c x 185mm2XLPEZ = 0.128 + j 0.093Ω/kmL = Ikm

>

>

>I>

I>I>

I >

Max load 400A/feeder

1

500/1500/1

1000/1

3

Max load 1000A

Reactor R1 : Z=4% on 20MVA

2

Max load 190AMax load 130A Max load 90A

IS = 120%TMS = 0.25

IS = 110%TMS = 0.1

FS2160A

FS1125A

F2 F1

Figure 9.28: IDMT relay grading example

Figure 9.27: MiCOM P140

Chap9 exe 21/06/02 8:57 Page 143


protection, and CT knee-point voltage requirements, etc.,are not dealt with. All curves are plotted to an 11kVbase. The contactors in series with fuses FS1/FS2 havea maximum breaking capacity of 3kA, and relay F2 hasbeen set to ensure that the fuse operates prior to thecontactor for currents in excess of this value. CT’s forrelays F1, F2 and 5 are existing CT’s with 5Asecondaries, while the remaining CT’s are new with 1Asecondaries. Relay 5 is the property of the supply utility,and is required to be set using an SI characteristic inorder to ensure grading with upstream relays.

9.20.1.1 Impedance Calculations

All impedances must first be referred to a common base,taken as 500MVA, as follows:

Reactor R1

Cable C1

On 500MVA base,

= 15.7%

Cables C2,C3

ZC2, ZC3 = 0.158 Ω

On 500MVA base,

ZC2,

= 65.3%

Source Impedance (500MVA base)

= 100%

9.20.1.2 Fault Levels

The fault levels are calculated as follows:

(i) At bus C

For 2 feeders,

= 10.6 kA on 11kV base

For a single feeder, fault level = 178MVA

= 9.33kA

Fault Level= ×+ + +

500 10021 1 2Z Z Z Z

MVAR S C C

ZS = ×500500

100%

ZC3 2

0 158 100 500

11= × ×

( ).

ZC1 2

0 038 100 500

11= × ×

( ).

ZC10 096

52 0 038= × =. . Ω

ZR14 500

20100= × = %

(ii) At bus B

(iii) At bus A

(iv) Source

9.20.1.3 CT ratio selection

This requires consideration not only of the maximumload current, but also of the maximum secondary currentunder fault conditions.

CT secondaries are generally rated to carry a short-termcurrent equal to 100 x rated secondary current.Therefore, a check is required that none of the new CTsecondaries has a current of more than 100A whenmaximum fault current is flowing in the primary. Usingthe 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 cablefeeders, Busbar C and backup-protection to relays F1, F2and their associated fuses FS1 and FS2. The settings forRelays 1 and 2 will be identical, so calculations will onlybe performed for Relay 1. Consider first the currentsetting of the relay.

Relay 1 must be able to reset at a current of 400A – therating of the feeder. The relay has a drop-off/pick-upratio of 0.95, so the relay current setting must not be lessthan 400/0.95, or 421A. A suitable setting that is greaterthan this value is 450A. However, Section 9.12.3 alsorecommends that the current setting should be threetimes the largest fuse rating (i.e. 3 x 160A, the rating ofthe largest fuse on the outgoing circuits from Busbar C),leading to a current setting of 480A, or 96% of relayrated primary current. Note that in this application ofrelays to a distribution system, the question of maximumand minimum fault levels are probably not relevant asthe difference between maximum and minimum faultlevels will be very small. However in other applicationswhere significant differences between maximum andminimum fault levels exist, it is essential to ensure that

Fault Level 500MVA

26.3kA

=

=

Fault Level

432MVA

22.7kA

= ×+

=

=

500 100

1Z ZMVA

S C

Fault Level

232MVA

1 kA

= ×+ +

=

=

500 100

2 2

1 1Z Z ZMVA

S C R

.

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Chap9 exe 21/06/02 8:57 Page 144


the selection of a current setting that is greater than fullload current does not result in the relay failing to operateunder minimum fault current conditions. Such asituation may arise for example in a self-containedpower system with its own generation. Minimumgeneration may be represented by the presence of asingle generator and the difference between minimumfault level and maximum load level may make the choiceof relay current settings difficult.

The grading margin now has to be considered. Forsimplicity, a fixed grading margin of 0.3s between relaysis used in the calculations, in accordance with Table 9.2.Between fuse and relay, Equation 9.4 is applied, and withfuse FS2 pre-arcing time of 0.01s (from Figure 9.29), thegrading margin is 0.154s.

Consider first the IDMT overcurrent protection. Selectthe EI characteristic, as fuses exist downstream, toensure grading. The relay must discriminate with thelongest operating time between relays F1, F2 and fuseFS2 (being the largest fuse) at the maximum fault levelseen by relays 1 and 2. The maximum fault current seenby relay 1 for a fault at Busbar C occurs when only oneof cables C2, C3 is in service. This is because the wholeof the fault current then flows through the feeder that isin service. With two feeders in service, although thefault level at Busbar C is higher, each relay only sees halfof the total fault current, which is less than the faultcurrent with a single feeder in service. With EIcharacteristics used for relays F1 and F2, the operatingtime for relay F1 is 0.02s at TMS=0.1 because the faultcurrent is greater than 20 times relay setting, at whichpoint the EI characteristic becomes definite time (Figure9.4) and 0.05s for relay F2 (TMS=0.25).

Hence select relay 1 operating time =0.3+0.05=0.35s, toensure grading with relay F2 at a fault current of9.33kA.

With a primary setting of 480A, a fault current of 9.33kArepresents

9330/480 = 19.44 times setting

Thus relay 1 operating time at TMS=1.0 is 0.21s. Therequired TMS setting is given by the formula:

This value of TMS is outside the settable range of therelay (maximum setting 1.2). Therefore, changes must bemade to the relay current setting in order to bring thevalue of TMS required into the range available, providedthis does not result in the inability of the relay to operateat the minimum fault level.

By re-arrangement of the formula for the EI

∴ = = TMS 0 350 21

1 66..

.

TMS==

operation time requiredActual op. time required at TMS 1.0

characteristic:

where

t is the required operation time (s)

Isr1f = setting of relay at fault current

Hence, with t = 0.35,

Isr1f = 15.16

or,

Use 1.24 = 620A nearest available value

At a TMS of 1.0, operation time at 9330A

Hence, required TMS

for convenience, use a TMS of 1.0, slightly greater thanthe required value.

From the grading curves of Figure 9.29, it can be seenthat there are no grading problems with fuse FS1 orrelays 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 busbarprotection for Busbar B.

Again, the EI characteristic is used to ensure gradingwith relays 1 and 2. The maximum load current is1000A. Relay 3 current setting is therefore

Substituting values,

Isr3>1052A

Use a setting of 106% or 1060A, nearest availablesetting above 1052A.

Relay 3 has to grade with relays 1/2 under twoconditions:

1. for a fault just beyond relays 1 and 2 where thefault current will be the busbar fault current of12.2kA

2. for a fault at Bus C where the fault current seen by

I sr 3 0 95>

×feeder flc

CT primary current .

= =0 350 355

..

0.99

=

−

=80

9330620

1

0 3552

.

I sr1616500

1 232= = .

I Asr19330

15 16615 4= =

..

Itsr f1

80 1= +

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Chap9 exe 21/06/02 8:57 Page 145


either relay 1 or 2 will be half the total Bus C faultcurrent of 10.6kA, i.e. 5.3kA

Examining first condition 1. With a current setting of620A, a TMS of 1.0 and a fault current of 12.2kA, relay 1will operate 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 forrelay 3 and thus the time multiplier setting of relay 3should be 0.84 to give an operating time of 0.51s at11.51 times setting.

Consider now condition 2. With settings of 620A andTMS of 1.0 and a fault current of 5.3kA, relay 1 willoperate in 1.11s. Using a grading interval of 0.3s, relay 3must 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 0.33to give an operating time of 1.11s at 5 times setting. Thuscondition 1 represents the worst case and the time multipliersetting of relay 3 should be set at 0.84. In practice, a valueof 0.85 is used as the nearest available setting on the relay.

Relay 3 also has an instantaneous element. This is setsuch that it will not operate for the maximum through-fault current seen by the relay, a setting of 130% of thisvalue being satisfactory. The setting is therefore:

1.3x12.2kA

=15.86kA

This is equal to a current setting of 14.96 times thesetting of relay 3.

9.20.1.6 Relay 4

This must grade with relay 3 and relay 5. The supplyauthority requires that relay 5 use an SI characteristic toensure grading with relays further upstream, so the SIcharacteristic will be used for relay 4 also. Relay 4 mustgrade with relay 3 at Bus A maximum fault level of22.7kA. However with the use of an instantaneous highset element for relay 3, the actual grading point becomesthe point at which the high set setting of relay 3operates, i.e. 15.86kA. At this current, the operation timeof relay 3 is

Thus, relay 4 required operating time is

0.305 + 0.3 = 0.605s at a fault level of 15.86kA.

80

14 96 12

.( ) −× =0.85s 0.305s

Relay 4 current setting must be at least

= 98%.

For convenience, use a value of 100% (=3000A). Thusrelay 4 must operate in 0.605s at 15860/3000 = 5.29times setting. Thus select a time multiplier setting of0.15, giving a relay operating time of 0.62s for a normalinverse type characteristic.

At this stage, it is instructive to review the grading curves,which are shown in Figure 9.29(a). While it can be seenthat there are no grading problems between the fuses andrelays 1/2, and between relays F1/2 and relays 1/2, it isclear that relay 3 and relay 4 do not grade over the wholerange of fault current. This is a consequence of the changein characteristic for relay 4 to SI from the EI characteristicof relay 3 to ensure grading of relay 4 with relay 5. Thesolution is to increase the TMS setting of relay 4 untilcorrect grading is achieved. The alternative is to increasethe current setting, but this is undesirable unless the limitof the TMS setting is reached, because the current settingshould always be as low as possible to help ensure positiveoperation of the relay and provide overload protection.Trial and error is often used, but suitable software canspeed the task – for instance it is not difficult to constructa spreadsheet with the fuse/relay operation times andgrading margins calculated. Satisfactory grading can befound for relay 4 setting values of:

Ist4 = 1.0 or 3000A

TMS = 0.275

At 22.7kA, the operation time of relay 4 is 0.93s. Therevised grading curves are shown in Figure 9.29(b).

9.20.1.7 Relay 5

Relay 5 must grade with relay 4 at a fault current of22.7kA. At this fault current, relay 4 operates in 0.93sand thus relay 5 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 priorto relay 5. Thus 22.7kA represents 6.88 times the settingof relay 5. Relay 5 must grade with relay 4 at a faultcurrent of 22.7kA, where the required operation time is1.23s. At a TMS of 1.0, relay 5 operation time is

Therefore, the required TMS is 1.23/3.56 = 0.345, use0.35 nearest available value.

The protection grading curves that result are shown inFigure 9.30 and the setting values in Table 9.5. Gradingis now satisfactory.

0 14

6 88 13

0 02

.

..( ) −

= .56 s

28003000 0 95× .

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0.01

0.10

1.00

10.00

100.00

100 1000 10000 100000

Current (A)

Tim

e (s

ec)

Relay F1

Relay F2

Fuse FS1

Fuse FS2

Relays 1/2

Relay 3

Relay 4

(a) Initial grading curves

0.01

0.10

1.00

10.00

100.00

100 1000 10000 100000

Current (A)

Tim

e (s

ec)

Relay F1

Relay F2

Fuse FS1

Fuse FS2

Relays 1/2

Relay 3

Relay 4

(b) Revised initial grading curves

Figure 9.29: Initial relay grading curves – overcurrent relay example

Chap9 exe 21/06/02 8:59 Page 147

order to calculate fault levels. However, such impedancesare frequently not available, or known onlyapproximately and the phase fault current levels have tobe used. Note that earth fault levels can be higher thanphase fault levels if the system contains multiple earthpoints, or if earth fault levels are considered on the starside of a delta/star transformer when the star winding issolidly earthed.

On the circuit with fuse F2, low-level earth faults maynot be of sufficient magnitude to blow the fuse.

Attempting to grade the earth fault element of theupstream relay with fuse F2 will not be possible.Similarly, relays F1 and F2 have phase fault settings thatdo not provide effective protection against earth faults.The remedy would be to modify the downstreamprotection, but such considerations lie outside the scopeof this example. In general therefore, the earth faultelements of relays upstream of circuits with only phasefault protection (i.e. relays with only phase faultelements or fuses) will have to be set with a compromisethat they will detect downstream earth faults but willnot provide a discriminative trip. This illustrates thepractical point that it is rare in anything other than avery simple network to achieve satisfactory grading forall faults throughout the network.

In the example of Figure 9.27, it is likely that thedifference in fault levels between phase to phase andphase to earth faults will be very small and thus the onlyfunction of earth fault elements is to detect and isolatelow level earth faults not seen by the phase fault

Relay SettingsLoad Max

Current SettingRelay/ current Fault CT Fuse Charac-Fuse Current Ratio Rating teristic Primary Per

TMS

(A) kA Amps Cent

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

3 1000 22.7 1000/1EI 1060 106 0.85

Instant. 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

In situations where one of the relays to be graded isprovided by a third party, it is common for the settings ofthe relay to be specified and this may lead to a lack ofco-ordination between this relay and others (usuallythose downstream). Negotiation is then required to tryand achieve acceptable settings, but it is often the casethat no change to the settings of the relay provided bythe third party is allowed. A lack of co-ordinationbetween relays then has to be accepted over at least partof the range of fault currents.

9.20.2 Relay Earth-Fault Settings

The procedure for setting the earth-fault elements isidentical to that for the overcurrent elements, exceptthat zero sequence impedances must be used if availableand different from positive sequence impedances in

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Table 9.5: Relay settings for overcurrent relay example

0.01

0.10

1.00

10.00

100.00

100 1000 10000 100000

Current (A)

Tim

e (s

ec)

Relay F1

Relay F2

Fuse FS1

Fuse FS2

Relays 1/2

Relay 3

Relay 4

Relay 5

Figure 9.30: Final relay grading curves for overcurrent relay example


Chap9 exe 21/06/02 8:59 Page 148


elements. Following the guidelines of Section 9.16,relays 1/2 can use a current setting of 30% (150A) anda TMS of 0.2, using the EI characteristic. Grading ofrelays 3/4/5 follows the same procedure as described forthe phase-fault elements of these relays.

9.20.3 Protection of Parallel Feeders

Figure 9.31(a) shows two parallel transformer feedersforming part of a supply circuit. Impedances are as givenin the diagram.

The example shows that unless relays 2 and 3 are madedirectional, they will maloperate for a fault at F3. Alsoshown is how to calculate appropriate relay settings forall six relays to ensure satisfactory protection for faultsat locations F1-F4.

Figure 9.31(b) shows the impedance diagram, to100MVA, 110kV base. The fault currents for faults withvarious system configurations are shown in Table 9.6.

If relays 2 and 3 are non-directional, then, using SI relaycharacteristics for all relays, grading of the relays isdictated by the following:

a) fault at location F1, with 2 feeders in service

b) fault at location F4, with one feeder in service

The settings shown in Figure 9.32(a) can be arrived at,with the relay operation times shown in Figure 9.32(b).It is clear that for a fault at F3 with both transformerfeeders in service, relay 3 operates at the same time asrelay 2 and results in total disconnection of Bus Q andall consumers supplied solely from it. This is undesirable– the advantages of duplicated 100% rated transformershave been lost.

By making relays 2 and 3 directional as shown in Figure9.33(a), lower settings for these relays can be adopted –they can be set as low as reasonably practical butnormally a current setting of about 50% of feeder fullload current is used, with a TMS of 0.1. Grading rulescan be established as follows:

a. relay 4 is graded with relay 1 for faults at locationF1 with one transformer feeder in service

b. relay 4 is graded with relay 3 for faults at locationF3 with two transformer feeders in service

c. relay 6 grades with relay 4 for faults at F4

d. relay 6 also has to grade with relay 4 for faults atF1 with both transformer feeders in service – relay 6sees the total fault current but relay 4 only 50% ofthis current.

Normal rules about calculating current setting valuesof relays in series apply. The settings and resulting

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1

IeIeI IbIbI

I

IfIfI

I

3

Z=0.25puIZ=0.25puI

3

4 2

6Source0.01pu

Bus P

Bus Q

All impedances to100MVA, 110kV base

p100MVA, 110kV base

p

(b) Impedance diagram

I>I>I

>

I>I>I

>

>II

I>I>II>I>I

I>I>II>I>I

T1

50MVAZ=12.5%

50MVAZ=12.5%

5 3

4 2

6

If fIf I

IeIeI b

aIF4I

F3FISource

10000MVA Bus P220k

Bus Q110kV

Figure 9.31: System diagram: Parallel feeder example

Fault System Currents (A)Position Config. 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 0 26243 0 26243

Table 9.6: Fault currents for parallel feeder example

0.10

1.00

10.00

100.00

100 1000 10000 100000

Tim

e (s

ec)

Current settingRelay CT Primary TMS Characteristic

1234

6

300

300

300300300

0.61

0.70.7

1.11.11

0.4250.30.30.2 SI

SISISI

5 300 0.61 0.425 SISI

(a) Relay settings - non-directional relays

(b) Relay grading curves - non-directional relays

Current (A)

Relay 1

Relays 2/3

Relays 4/5

Relay 6

Figure 9.32: Relay grading for parallel feeder example –non-directional relays

Chap9 exe 21/06/02 8:59 Page 149


operation times are given in Figure 9.33(b) and(c)respectively.

In practice, a complete protection study would includeinstantaneous elements on the primary side of thetransformers and analysis of the situation with only onetransformer in service. These have been omitted fromthis example, as the purpose is to illustrate the principlesof parallel feeder protection in a simple fashion.

9.20.4 Grading of a Ring Main

Figure 9.34 shows a simple ring main, with a singleinfeed at Bus A and three load busbars. Settings for thedirectional relays R2-R7 and non-directional relaysR1/R8 are required. Maximum load current in the ringis 785A (maximum continuous current with onetransformer out of service), so 1000/1A CT’s are chosen.The relay considered is a MiCOM P140 series.

The first step is to establish the maximum fault currentat each relay location. Assuming a fault at Bus B (theactual location is not important), two possibleconfigurations of the ring have to be considered, firstly aclosed ring and secondly an open ring. For convenience,the ring will be considered to be open at CB1 (CB8 is theother possibility to be considered, but the conclusion willbe the same).

Figure 9.35 shows the impedance diagram for these twocases.

Three-phase fault currents I1 and I’1 can be calculated as2.13kA and 3.67kA respectively, so that the worst case iswith the ring open (this can also be seen fromconsideration of the impedance relationships, withoutthe necessity of performing the calculation).

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• 1 5 0 •

5MVAZ=7.15%

5MVAZ=7.15%

11kV fault level =200MVA11kV

C2=1.3km

CB5

CB6

CB8 CB1

R5

R6

R7 I>

R8 R1I> I>

R2I>

R3I>

R4I>I>

I>

CB4

C3=2km

C1=1km

C4=1.5km

1000/1

CB7 CB21000/1 1000/1

CB31000/1

1000/1 1000/1

1000/11000/1

3.3kV

D

1000/1

3.3kV

A3.3kV

3.3kV

B

1000/1

C

All cables are 3 x 1c x 1200mm2, AI conductor, Z = 0.09 Ω/kmVT's omitted for clarity

Figure 9.34: Ring main grading example – circuit diagram

diagram

T1

50MVAZ=12,5%

T2220/110kV

50MVAZ

5 3

4 2

1

6

IfI

IdIdI

IF4IF4F4F

IF3IF3F3F

F1 F1F1F

IF2I

F2F2F

e IbIbI

IaIaI IcIcI

Source10000MVA

Bus P220kV

Bus Q110kV

I>

I>

I>I>

I> I>

0.10

1.00

10.00

100.00

100 1000 (ii) (i) 10000

Current (A) - referred to 110kV

(i) Fault current 3888A -

faults F1, F2 - 1 feeder

(iii) Fault current 26243A -fault F4 - 1 feeder

Tim

e (s

ec)

Relay 1Relays 2/3Relays 4/5Relay 6

(c) Relay characteristics

(b) Relay settings

IFF

Relay CT Primary TMS Characteristic

123456

300

300300

300300300

0.6

0.70.6

0.420.42

1

0.275

0.4750.275

0.10.10.2 SI

SISISISISI

Current setting

(iii)

Figure 9.33: Relay grading for parallel feeder example –directional relays

(a) Ring closed

ZS+ZT

V

6.08%

ZCDI1

ZBC

D B

C

5.37% 8.26%

ZABZAD

A

4.13% 6.2%

I1=ZS

VZBC+ZCD+ZAD +ZBC+ZCD+ZAD

ZAB

1+

(b) Ring open at CB1

ZS+ZT

ZABZAD

ZCDI1

ZBC

A

D B

C

V

6.08%

4.13%

5.37% 8.26%

6.2%

I'1=V

+ZS+ZBC+ZCD+ZAD

Figure 9.35: Impedance diagrams with ring open

Chap9 exe 21/06/02 8:59 Page 150


Table 9.7 shows the fault currents at each bus for openpoints at CB1 and CB8.

For grading of the relays, consider relays looking in aclockwise direction round the ring, i.e. relays R1/R3/R5/R7.

9.20.4.1 Relay R7

Load current cannot flow from Bus D to Bus A since BusA is the only source. Hence low relay current and TMSsettings can be chosen to ensure a rapid fault clearancetime. These can be chosen arbitrarily, so long as they areabove the cable charging current and within the relaysetting characteristics. Select a relay current setting of0.8 (i.e. 800A CT primary current) and TMS of 0.05. Thisensures that the other relays will not pick up underconditions of normal load current. At a fault current of3376A, relay operating time on the SI characteristic is

= 0.24s9.20.4.2 Relay R5

This relay must grade with relay R7 at 3376A and have aminimum operation time of 0.54s. Relay R5 currentsetting must be at least 110% of relay R7 to preventunwanted pickup, so select relay R5 current setting of0.88 (i.e. 880A CT primary current).

Relay R5 operating time at TMS = 1.0

= 5.14s

Hence, relay R5 TMS = 5.14s

Use nearest settable value of TMS of 0.125.

= 0 545 14..

=( ) −

0 14

3 84 10 02

.

..

s

0 05 0 14

4 22 10 02

. .

..

×( ) −

s

Table 9.8 summarises the relay settings, while Figure9.36 illustrates the relay grading curves.

9.21 REFERENCES

9.1. Directional Element Connections for PhaseRelays. W.K Sonnemann, Transactions A.I.E.E.1950.

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(a) Clockwise grading of relays (ring open at CB8)

10000.10

1.00

Current (A)10000 100,000

10.00

100.00

Tim

e (s

ec)

(b) Anticlockwise grading of relays (ring open at CB1)

100,0001000 10000Current (A)

0.10

1.00

10.00

100.00

Tim

e (s

ec)

yRelay R5

yyRelay R7

yRelay R2

Figure 9.36: Ring main example – relay grading curves

Clockwise AnticlockwiseOpen Point CB8 Open Point CB1

Fault FaultBus Current Bus Current

kA kAD 7.124 B 3.665

C 4.259 C 5.615B 3.376 D 8.568

Table 9.7: Fault current tabulation with ring open

Relay CT Max Max CurrentBus Relay Charact- Ratio Load Fault Setting TMS

eristic Current Current (A) p.u.(A) (3.3kV base)

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

Table 9.8: Ring main example relay settings

Chap9 exe 21/06/02 8:59 Page 151

Introduction 10.1

Convention of direction 10.2

Conditions for direction comparison 10.3

Circulating current system 10.4

Balanced voltage system 10.5

Summation arrangements 10.6

Examples of electromechanicaland static unit protection systems 10.7

Digital/Numerical current differentialprotection systems 10.8

Carrier unit protection schemes 10.9

Current differential scheme– analogue techniques 10.10

Phase comparison protectionscheme considerations 10.11

Examples 10.12

References 10.13

• 1 0 • U n i t P r o t e c t i o n o f F e e d e r s

Chap10-152-169 21/06/02 8:42 Page 152


10.1 INTRODUCTION

The graded overcurrent systems described in Chapter 9,though attractively simple in principle, do not meet allthe protection requirements of a power system.Application difficulties are encountered for two reasons:firstly, satisfactory grading cannot always be arrangedfor a complex network, and secondly, the settings maylead to maximum tripping times at points in the systemthat are too long to prevent excessive disturbancesoccurring.

These problems led to the concept of 'Unit Protection',whereby sections of the power system are protectedindividually as a complete unit without reference toother sections. One form of ‘Unit Protection’ is alsoknown as ‘Differential Protection’, as the principle is tosense the difference in currents between the incomingand outgoing terminals of the unit being protected.Other forms can be based on directional comparison, ordistance teleprotection schemes, which are covered inChapter 12, or phase comparison protection, which isdiscussed later in this chapter. The configuration of thepower system may lend itself to unit protection; forinstance, a simple earth fault relay applied at the sourceend of a transformer-feeder can be regarded as unitprotection provided that the transformer windingassociated with the feeder is not earthed. In this casethe protection coverage is restricted to the feeder andtransformer winding because the transformer cannottransmit zero sequence current to an out-of-zone fault.

In most cases, however, a unit protection systeminvolves the measurement of fault currents (and possiblyvoltages) at each end of the zone, and the transmissionof information between the equipment at zoneboundaries. It should be noted that a stand-alonedistance relay, although nominally responding only tofaults within their setting zone, does not satisfy theconditions for a unit system because the zone is notclearly defined; it is defined only within the accuracylimits of the measurement. Also, to cater for someconditions, the setting of a stand-alone distance relaymay also extend outside of the protected zone to caterfor some conditions.

Merz and Price [10.1] first established the principle ofcurrent differential unit systems; their fundamentaldifferential systems have formed the basis of many

• 10 • Unit P rotect ion of Feede rs

Chap10-152-169 21/06/02 8:43 Page 153


highly developed protection arrangements for feedersand numerous other items of plant. In one arrangement,an auxiliary ‘pilot’ circuit interconnects similar currenttransformers at each end of the protected zone, asshown in Figure 10.1. Current transmitted through thezone causes secondary current to circulate round thepilot circuit without producing any current in the relay.For a fault within the protected zone the CT secondarycurrents will not balance, compared with the through-fault condition, and the difference between the currentswill flow in the relay.

An alternative arrangement is shown in Figure 10.2, inwhich the CT secondary windings are opposed forthrough-fault conditions so that no current flows in theseries connected relays. The former system is known asa ‘Circulating Current’ system, while the latter is knownas a ‘Balanced Voltage’ system.

Most systems of unit protection function through thedetermination of the relative direction of the faultcurrent. This direction can only be expressed on acomparative basis, and such a comparative measurementis the common factor of many systems, includingdirectional comparison protection and distanceteleprotection schemes with directional impedancemeasurement.

A major factor in consideration of unit protection is themethod of communication between the relays. This iscovered in detail in Chapter 8 in respect of the latestfibre-optic based digital techniques. For older ‘pilot wire’systems, only brief mention is made. For more detaileddescriptions of ‘pilot wire’ techniques, see reference[10.2] in Section 10.13.

10.2 CONVENTION OF DIRECTION

It is useful to establish a convention of direction ofcurrent flow; for this purpose, the direction measuredfrom a busbar outwards along a feeder is taken aspositive. Hence the notation of current flow shown inFigure 10.3; the section GH carries a through currentwhich is counted positive at G but negative at H, whilethe infeeds to the faulted section HJ are both positive.

Neglect of this rule has often led to anomalousarrangements of equipment or difficulty in describingthe action of a complex system. When applied, the rulewill normally lead to the use of identical equipments atthe zone boundaries, and is equally suitable for extensionto multi-ended systems. It also conforms to the standardmethods of network analysis.

10.3 CONDIT IONSFOR DIRECTION COMPARISON

The circulating current and balanced voltage systems ofFigures 10.1 and 10.2 perform full vectorial comparisonof the zone boundary currents. Such systems can betreated as analogues of the protected zone of the powersystem, in which CT secondary quantities representprimary currents and the relay operating currentcorresponds to an in-zone fault current.

These systems are simple in concept; they arenevertheless applicable to zones having any number ofboundary connections and for any pattern of terminalcurrents.

To define a current requires that both magnitude andphase be stated. Comparison in terms of both of thesequantities is performed in the Merz-Price systems, but itis not always easy to transmit all this informationover some pilot channels. Chapter 8 provides a detaileddescription of modern methods that may be used.

10.4 CIRCULATING CURRENT SYSTEM

The principle of this system is shown in outline inFigure 10.1. If the current transformers are ideal, thefunctioning of the system is straightforward. The

• 10 •

Uni

t P

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ctio

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eede

rs

• 1 5 4 •

End HEnd G

RelayIdIdI >

Figure 10.1: Circulating current system

FaultHG J

Source+ _ + +

Source

Figure 10.3: Convention of current direction

Figure 10.2: Balanced voltage system

End G

Relay G Relay H

End H

IdIdI > IdIdI >

Chap10-152-169 21/06/02 8:43 Page 154


transformers will, however, have errors arising from bothWattmetric and magnetising current losses that causedeviation from the ideal, and the interconnectionsbetween them may have unequal impedances. This cangive rise to a ‘spill’ current through the relay evenwithout a fault being present, thus limiting thesensitivity that can be obtained. Figure 10.4 illustratesthe equivalent circuit of the circulating current scheme.If a high impedance relay is used, then unless the relay islocated at point J in the circuit, a current will flowthrough the relay even with currents IPg and IPh beingidentical. If a low impedance relay is used, voltage FF ’will be very small, but the CT exciting currents will beunequal due to the unequal burdens and relay current IRwill still be non-zero.

10.4.1 Transient Instability

It is shown in Section 6.4.10 that an asymmetricalcurrent applied to a current transformer will induce aflux that is greater than the peak flux corresponding tothe steady state alternating component of the current. Itmay take the CT into saturation, with the result that thedynamic exciting impedance is reduced and the excitingcurrent greatly increased.

When the balancing current transformers of a unitprotection system differ in excitation characteristics, orhave unequal burdens, the transient flux build-ups willdiffer and an increased 'spill' current will result. There isa consequent risk of relay operation on a healthy circuitunder transient conditions, which is clearly

unacceptable. One solution is to include a stabilisingresistance in series with the relay. Details of how tocalculate the value of the stabilising resistor are usuallyincluded in the instruction manuals of all relays thatrequire one.

When a stabilising resistor is used, the relay currentsetting can be reduced to any practical value, the relaynow being a voltage-measuring device. There isobviously a lower limit, below which the relay elementdoes not have the sensitivity to pick up. Relaycalibration can in fact be in terms of voltage. For moredetails, see reference [10.2].

10.4.2 Bias

The 'spill' current in the relay arising from these varioussources of error is dependent on the magnitude of thethrough current, being negligible at low values ofthrough-fault current but sometimes reaching adisproportionately large value for more severe faults.Setting the operating threshold of the protection abovethe maximum level of spill current produces poorsensitivity. By making the differential settingapproximately proportional to the fault current, the low-level fault sensitivity is greatly improved. Figure 10.5illustrates a typical bias characteristic for a modern relaythat overcomes the problem. At low currents, the bias issmall, thus enabling the relay to be made sensitive. Athigher currents, such as would be obtained from inrush orthrough fault conditions, the bias used is higher, and thusthe spill current required to cause operation is higher. Therelay is therefore more tolerant of spill current at higherfault currents and therefore less likely to maloperate,while still being sensitive at lower current levels.

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Restrain

I1

Idiff

Is1

Is2

I2I

I3I

Percentagebias k2

Percentagebias k1

Operate

I1Ibias+ I2 I3+

2=

= I1+I2+I3

Figure 10.5: Typical bias characteristic of relay

Figure 10.4: Equivalent circuitof circulating current scheme

RelayIdIdI

RSh RSh

IPhIIPgI

iehieg

R

RR

ZehZeg

ShiSg

RLgR RLhR

(a)

H

G''

G

G '

F '

FJ

H '

H''H''H

Electro-motive forces with low impedance relayGG' 'GG'' ''

(b)

End G End H

Subscripts:p

S - CT SecondaryS

L G

hh - end H

Chap10-152-169 21/06/02 8:43 Page 155


10.5 BALANCED VOLTAGE SYSTEM

This section is included for historical reasons, mainlybecause of the number of such schemes still to be foundin service – for new installations it has been almostcompletely superseded by circulating current schemes. Itis the dual of the circulating current protection, and issummarised in Figure 10.2 as used in the ‘Translay H04’scheme.

With primary through current, the secondary e.m.f.’s ofthe current transformers are opposed, and provide nocurrent in the interconnecting pilot leads or the seriesconnected relays. An in-zone fault leads to a circulatingcurrent condition in the CT secondaries and hence torelay operation.

An immediate consequence of the arrangement is thatthe current transformers are in effect open-circuited, asno secondary current flows for any primary through-current conditions. To avoid excessive saturation of thecore and secondary waveform distortion, the core isprovided with non-magnetic gaps sufficient to absorbthe whole primary m.m.f. at the maximum current level,the flux density remaining within the linear range. Thesecondary winding therefore develops an e.m.f. and canbe regarded as a voltage source. The shunt reactance ofthe transformer is relatively low, so the device acts as atransformer loaded with a reactive shunt; hence theAmerican name of transactor. The equivalent circuit ofthe system is as shown in Figure 10.6.

The series connected relays are of relatively highimpedance; because of this the CT secondary windingresistances are not of great significance and the pilotresistance can be moderately large without significantlyaffecting the operation of the system. This is why thescheme was developed for feeder protection.

10.5.1 Stability Limit of the Voltage Balance System

Unlike normal current transformers, transactors are notsubject to errors caused by the progressive build-up of

exciting current, because the whole of the primarycurrent is expended as exciting current. In consequence,the secondary e.m.f. is an accurate measure of theprimary current within the linear range of thetransformer. Provided the transformers are designed tobe linear up to the maximum value of fault current,balance is limited only by the inherent limit of accuracyof the transformers, and as a result of capacitancebetween the pilot cores. A broken line in the equivalentcircuit shown in Figure 10.6 indicates such capacitance.Under through-fault conditions the pilots are energisedto a proportionate voltage, the charging current flowingthrough the relays. The stability ratio that can beachieved with this system is only moderate and a biastechnique is used to overcome the problem.

10.6 SUMMATION ARRANGEMENTS

Schemes have so far been discussed as though they wereapplied to single-phase systems. A polyphase systemcould be provided with independent protection for eachphase. Modern digital or numerical relayscommunicating via fibre-optic links operate on thisbasis, since the amount of data to be communicated isnot a major constraint. For older relays, use of thistechnique over pilot wires may be possible for relativelyshort distances, such as would be found with industrialand urban power distribution systems. Clearly, eachphase would require a separate set of pilot wires if theprotection was applied on a per phase basis. The cost ofproviding separate pilot-pairs and also separate relayelements per phase is generally prohibitive. Summationtechniques can be used to combine the separate phasecurrents into a single relaying quantity for comparisonover a single pair of pilot wires. For details of suchtechniques, see reference [10.2].

10.7 EXAMPLES OF ELECTROMECHANICAL AND STATIC UNIT PROTECTION SYSTEMS

As mentioned above, the basic balanced voltage principleof protection evolved to biased protection systems.Several of these have been designed, some of whichappear to be quite different from others. Thesedissimilarities are, however, superficial. A number ofthese systems that are still in common use are describedbelow.

10.7.1 ‘Translay’ Balanced VoltageElectromechanical System

A typical biased, electromechanical balanced voltagesystem, trade name ‘Translay’, still giving useful serviceon distribution systems is shown in Figure 10.7.

• 10 •

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• 1 5 6 •

Figure 10.6: Equivalent circuitfor balanced voltage system

Zeg

RSg RLgR RLhR RSh

Zeh

IdIdI >IdIdI >

Relay G

PilotParameters

End G

Relay H

End H

Chap10-152-169 21/06/02 8:43 Page 156


The electromechanical design derives its balancing voltagesfrom the transactor incorporated in the measuring relay ateach line end. The latter are based on the induction-typemeter electromagnet as shown in Figure 10.7.

The upper magnet carries a summation winding toreceive the output of the current transformers, and asecondary winding which delivers the reference e.m.f.The secondary windings of the conjugate relays areinterconnected as a balanced voltage system over thepilot channel, the lower electromagnets of both relaysbeing included in this circuit.

Through current in the power circuit produces a state ofbalance in the pilot circuit and zero current in the lowerelectromagnet coils. In this condition, no operatingtorque is produced.

An in-zone fault causing an inflow of current from eachend of the line produces circulating current in the pilotcircuit and the energisation of the lower electromagnets.These co-operate with the flux of the upperelectromagnets to produce an operating torque in thediscs of both relays. An infeed from one end only willresult in relay operation at the feeding end, but nooperation at the other, because of the absence of uppermagnet flux.

Bias is produced by a copper shading loop fitted to thepole of the upper magnet, thereby establishing a Ferrarismotor action that gives a reverse or restraining torqueproportional to the square of the upper magnet flux value.

Typical settings achievable with such a relay are:Least sensitive earth fault - 40% of ratingLeast sensitive phase-phase fault - 90% of ratingThree-phase fault - 52% of rating

10.7.2 Static Circulating CurrentUnit Protection System – ‘Translay ‘S’ ’

A typical static modular pilot wire unit protection systemoperating on the circulating current principle is shown inFigure 10.8. This uses summation transformers with aneutral section that is tapped, to provide alternativeearth fault sensitivities. Phase comparators tuned to thepower frequency are used for measurement and arestraint circuit gives a high level of stability for throughfaults and transient charging currents. High-speedoperation is obtained with moderately sized currenttransformers and where space for current transformers islimited and where the lowest possible operating time isnot essential, smaller current transformers may be used.This is made possible by a special adjustment (Kt) bywhich the operating time of the differential protectioncan be selectively increased if necessary, therebyenabling the use of current transformers having acorrespondingly decreased knee-point voltage, whilstensuring that through-fault stability is maintained togreater than 50 times the rated current.

Internal faults give simultaneous tripping of relays atboth ends of the line, providing rapid fault clearanceirrespective of whether the fault current is fed from bothline ends or from only one line end.

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Figure 10.8: Typical static circulating current feeder unit protection circuit diagram

A

C

BT1 - Summation transformer

T2 - Auxiliary transformer

RVO - Non linear resistor

Trip Trip

V

T2T T2T

T1T1

Pr Pr

TrTrT

TOTOTO

TrTrT RsRs

RoRo RVORVOV

Pilot wires

To - Operating winding

Tr - Restraining winding

Ro - Linear resistor

Pr - Pilots padding resistor

c - Phase comparator

cc

End G End H

Summationwinding

Pilot

ABC

Secondarywinding

Bias loop

y

Figure 10.7: Typical biasedelectromechanical differential protection system.

Chap10-152-169 21/06/02 8:43 Page 157


10.8 DIGITAL/NUMERICAL CURRENT DIFFERENTIAL PROTECTION SYSTEMS

A digital or numerical unit protection relay may typicallyprovide phase-segregated current differential protection.This means that the comparison of the currents at eachrelay is done on a per phase basis. For digital datacommunication between relays, it is usual that a directoptical connection is used (for short distances) or amultiplexed link. Link speeds of up to 64kbit/s (56kbit/sin N. America) are normal. Through current bias istypically applied to provide through fault stability in theevent of CT saturation. A dual slope bias technique(Figure 10.5) is used to enhance stability for throughfaults. A typical trip criterion is as follows:

For |Ibias| < Is2

|Idiff | < k1 |Ibias| + Is1

For |Ibias| < Is2

|Idiff | < k2 |Ibias| - (k2 - k1) Is2 + Is1

Once the relay at one end of the protected section hasdetermined that a trip condition exists, an intertripsignal is transmitted to the relay at the other end. Relaysthat are supplied with information on line currents at allends of the line may not need to implement intertrippingfacilities. However, it is usual to provide intertripping inany case to ensure the protection operates in the eventof any of the relays detecting a fault.

A facility for vector/ratio compensation of the measuredcurrents, so that transformer feeders can be included inthe unit protection scheme without the use ofinterposing CT’s or defining the transformer as a separatezone increases versatility. Any interposing CT’s requiredare implemented in software. Maloperation ontransformer inrush is prevented by second harmonicdetection. Care must be taken if the transformer has awide-ratio on-load tap changer, as this results in thecurrent ratio departing from nominal and may causemaloperation, depending on the sensitivity of the relays.The initial bias slope should be set taking this intoconsideration.

Tuned measurement of power frequency currentsprovides a high level of stability with capacitance inrushcurrents during line energisation. The normal steady-state capacitive charging current can be allowed for if avoltage signal can be made available and thesusceptance of the protected zone is known.

Where an earthed transformer winding or earthingtransformer 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 zerosequence current for an external earth fault. Thedifferential protection will see zero sequence differentialcurrent for an external fault and it could incorrectly

operate as a result. In older protection schemes, theproblem was eliminated by delta connection of the CTsecondary windings. For a digital or numerical relay, aselectable software zero sequence filter is typicallyemployed.

The problem remains of compensating for the timedifference between the current measurements made atthe ends of the feeder, since small differences can upsetthe stability of the scheme, even when using fast directfibre-optic links. The problem is overcome by either timesynchronisation of the measurements taken by therelays, or calculation of the propagation delay of the linkcontinuously.

10.8.1 Time Synchronisation of Relays

Fibre-optic media allow direct transmission of thesignals between relays for distances of up to several kmwithout the need for repeaters. For longer distancesrepeaters will be required. Where a dedicated fibre pairis not available, multiplexing techniques can be used. Asphase comparison techniques are used on a per phasebasis, time synchronisation of the measurements isvitally important. This requires knowledge of thetransmission delay between the relays. Four techniquesare possible for this:

a. assume a valueb. measurement during commissioning onlyc. continuous online measurementd. GPS time signal

Method (a) is not used, as the error between the assumedand actual value will be too great.

Method (b) provides reliable data if directcommunication between relays is used. As signalpropagation delays may change over a period of years,repeat measurements may be required at intervals andrelays re-programmed accordingly. There is some risk ofmaloperation due to changes in signal propagation timecausing incorrect time synchronisation betweenmeasurement intervals. The technique is less suitable ifrented fibre-optic pilots are used, since the owner mayperform circuit re-routing for operational reasonswithout warning, resulting in the propagation delaybeing outside of limits and leading to schememaloperation. Where re-routing is limited to a fewroutes, it may be possible to measure the delay on allroutes and pre-program the relays accordingly, with therelay digital inputs and ladder logic being used to detectchanges in route and select the appropriate delayaccordingly.

Method (c), continuous sensing of the signal propagationdelay, is a robust technique. One method of achievingthis is shown in Figure 10.9.

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• 1 5 8 •

Chap10-152-169 21/06/02 8:43 Page 158


Relays A and B sample signals at time TA1,TA2 …andTB1,TB2 …respectively. The times will not be coincident,even if they start coincidentally, due to slight differencesin sampling frequencies. At time TA1 relay A transmitsits data to relay B, containing a time tag and other data.Relay B receives it at time TA1+Tp1 where Tp1 is thepropagation time from relay A to relay B. Relay Brecords this time as time TB*. Relay B also sendsmessages of identical format to relay A. It transmits sucha message at time TB3, received by relay A at timeTB3+Tp2 (say time TA*), where Tp2 is the propagationtime from relay B to relay A. The message from relay Bto relay A includes the time TB3, the last received timetag from relay A (TA1) and the delay time between thearrival time of the message from A (TB*) and TB3 – callthis the delay time Td. The total elapsed time istherefore:

(TA* - TA1) = (Td + Tp1 + Tp2)

If it is assumed that Tp1 = Tp2, then the value of Tp1 andTp2 can be calculated, and hence also TB3. The relay Bmeasured data as received at relay A can then beadjusted to enable data comparison to be performed.Relay B performs similar computations in respect of thedata received from relay A (which also contains similartime information). Therefore, continuous measurementof the propagation delay is made, thus reducing thepossibility of maloperation due to this cause to aminimum. Comparison is carried out on a per-phase basis,so signal transmission and the calculations are requiredfor each phase. A variation of this technique is availablethat 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 bothrelays being capable of receiving a time signal froma GPS satellite. The propagation delay on eachcommunication channel is no longer required to beknown or calculated as both relays are synchronised to acommon time signal. For the protection scheme to meetthe required performance in respect of availability andmaloperation, the GPS signal must be capable of reliablereceipt under all atmospheric conditions. There is extrasatellite signal receiving equipment required at bothends of the line, which implies extra cost.

The minimum setting that can be achieved with suchtechniques while ensuring good stability is 20% of CTprimary current.

10.8.2 Application to Mesh Cornerand 1 1/2 Breaker Switched Substations

These substation arrangements are quite common, andthe arrangement for the latter is shown in Figure 10.10.Problems exist in protecting the feeders due to thelocation of the line CT’s, as either Bus 1 or Bus 2 or bothcan supply the feeder. Two alternatives are used toovercome the problem, and they are illustrated in theFigure. The first is to common the line CT inputs (asshown for Feeder A) and the alternative is to use a secondset of CT inputs to the relay (as shown for Feeder B).

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End A

Digital communications linkA B

End B

Current vectors

Current vectors

Measured sampling time Propagation delay timeTB3*=(TA*-Tp2) Tp1=Tp2=1/2(TA*-TA1-Td)

TB*

TA*

TA1'TA2' TB1'TB2'

Tp1

Tp2

Td

TA1*

TB*

TB3*

TB3*

TB2

TB3

TB3Td

Td

TB4

TB5

TB1

TA2

TA3

TA4

TA5

TA1

TA1

TA1

Tp1

Tp2

- sampling instants of relay A- sampling instants of relay B- propagation delay time from relay A to B- propagation delay time from relay B to A- time between the arrival of message TA1 at relay B and despatch of message TB3

- arrival time of message TB3

and relay A- arrival time of message TA1

and relay B- the measured sampling time of TB3 by relay A

Figure 10.9: Signal propagation delay measurement

Chap10-152-169 21/06/02 8:43 Page 159


In the case of a through fault as shown, the relayconnected to Feeder A theoretically sees no unbalancecurrent, and hence will be stable. However, with the linedisconnect switch open, no bias is produced in the relay,so CT’s need to be well matched and equally loaded ifmaloperation is to be avoided.

For Feeder B, the relay also theoretically sees nodifferential current, but it will see a large bias current evenwith the line disconnect switch open. This provides a highdegree of stability, in the event of transient asymmetric CTsaturation. Therefore, this technique is preferred.

Sensing of the state of the line isolator through auxiliarycontacts enables the current values transmitted to andreceived from remote relays to be set to zero when theisolator is open. Hence, stub-bus protection for theenergised part of the bus is then possible, with any faultresulting in tripping of the relevant CB.

10.9 CARRIER UNIT PROTECTION SCHEMES

In earlier sections, the pilot links between relays havebeen treated as an auxiliary wire circuit thatinterconnects relays at the boundaries of the protectedzone. In many circumstances, such as the protection oflonger line sections or where the route involvesinstallation difficulties, it is too expensive to provide anauxiliary cable circuit for this purpose, and other meansare sought.

In all cases (apart from private pilots and some shortrented pilots) power system frequencies cannot betransmitted directly on the communication medium.Instead a relaying quantity may be used to vary thehigher frequency associated with each medium (or thelight intensity for fibre-optic systems), and this processis normally referred to as modulation of a carrier wave.Demodulation or detection of the variation at a remotereceiver permits the relaying quantity to be reconstitutedfor use in conjunction with the relaying quantitiesderived locally, and forms the basis for all carrier systemsof unit protection.

Carrier systems are generally insensitive to induced

power system currents since the systems are designed tooperate at much higher frequencies, but each mediummay be subjected to noise at the carrier frequencies thatmay interfere with its correct operation. Variations ofsignal level, restrictions of the bandwidth available forrelaying and other characteristics unique to eachmedium influence the choice of the most appropriatetype of scheme. Methods and media for communicationare discussed in Chapter 8.

10.10 CURRENT DIFFERENTIAL SCHEME – ANALOGUE TECHNIQUES

The carrier channel is used in this type of scheme toconvey both the phase and magnitude of the current atone relaying point to another for comparison with thephase and magnitude of the current at that point.Transmission techniques may use either voice frequencychannels using FM modulation or A/D converters anddigital transmission. Signal propagation delays still needto be taken into consideration by introducing adeliberate delay in the locally derived signal before acomparison with the remote signal is made.

A further problem that may occur concerns the dynamicrange of the scheme. As the fault current may be up to30 times the rated current, a scheme with linearcharacteristics requires a wide dynamic range, whichimplies a wide signal transmission bandwidth. Inpractice, bandwidth is limited, so either a non-linearmodulation characteristic must be used or detection offault currents close to the setpoint will be difficult.

10.10.1 Phase Comparison Scheme

The carrier channel is used to convey the phase angle of thecurrent at one relaying point to another for comparisonwith the phase angle of the current at that point.

The principles of phase comparison are illustrated inFigure 10.11. The carrier channel transfers a logic or'on/off' signal that switches at the zero crossing pointsof the power frequency waveform. Comparison of a locallogic signal with the corresponding signal from theremote end provides the basis for the measurement ofphase shift between power system currents at the twoends and hence discrimination between internal andthrough faults.

Current flowing above the set threshold results in turn-off of the carrier signal. The protection operates if gapsin the carrier signal are greater than a set duration – thephase angle setting of the protection.

Load or through fault currents at the two ends of aprotected feeder are in antiphase (using the normal relayconvention for direction), whilst during an internal faultthe (conventional) currents tend towards the in-phase

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Figure 10.10: Breaker anda half switched substation

Bus 1

A B

Stubbusinputs

F

Bus 2B1IF

Id>Id>

B2

Chap10-152-169 21/06/02 8:46 Page 160


condition. Hence, if the phase relationship of throughfault currents is taken as a reference condition, internalfaults cause a phase shift of approximately 180° withrespect to the reference condition.

Phase comparison schemes respond to any phase shiftfrom the reference conditions, but tripping is usuallypermitted only when the phase shift exceeds an angle oftypically 30 to 90 degrees, determined by the time delaysetting of the measurement circuit, and this angle isusually referred to as the Stability Angle. Figure 10.12 isa polar diagram that illustrates the discriminationcharacteristics that result from the measurementtechniques used in phase comparison schemes.

Since the carrier channel is required to transfer only

binary information, the techniques associated withsending teleprotection commands. Blocking orpermissive trip modes of operation are possible, howeverFigure 10.11 illustrates the more usual blocking mode,since the comparator provides an output when neithersquarer is at logic '1'. A permissive trip scheme can berealised if the comparator is arranged to give an outputwhen both squarers are at logic '1'. Performance of thescheme during failure or disturbance of the carrierchannel and its ability to clear single-end-fed faultsdepends on the mode of operation, the type and functionof fault detectors or starting units, and the use of anyadditional signals or codes for channel monitoring andtransfer tripping.

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Signalling equipment andcommunication channel

Receiver

GF

E

SquarerSummation

network

ATransmitter

D'

B

H

DC

Load or through fault Internal faultIG IHIG IH HG

01

01

01

01

01

01

01

01

E=B+D'

Stability setting

D. Squarer output at end H(Received at end G viaideal carrier system as D'

C. Summation voltage at end H

E. Comparator output at end G

F. Discriminator output at end G

B. Squarer output at end G

A. Summation voltage at end G

End HEnd G

Phase comparator

Pulse lengthdiscrimination

Figure 10.11: Principles of phase comparison protection.

Chap10-152-169 21/06/02 8:46 Page 161


Signal transmission is usually performed by voicefrequency channels using frequency shift keying (FSK) orPLC techniques.

Voice frequency channels involving FSK use two discretefrequencies either side of the middle of the voice band.This arrangement is less sensitive to variations in delay orfrequency response than if the full bandwidth was used.Blocking or permissive trip modes of operation may beimplemented. In addition to the two frequencies usedfor conveying the squarer information, a third tone isoften used, either for channel monitoring or transfertripping dependent on the scheme.

For a sensitive phase comparison scheme, accuratecompensation 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 theanalogue delay circuitry usually required for currentdifferential schemes.

The principles of the Power Line Carrier channeltechnique are illustrated in Figure 10.13. The schemeoperates in the blocking mode. The 'squarer' logic is useddirectly to turn a transmitter 'on' or 'off' at one end, andthe resultant burst (or block) of carrier is coupled to andpropagates along the power line which is being protectedto a receiver at the other end. Carrier signals above athreshold are detected by the receiver, and hence producea logic signal corresponding to the block of carrier. Incontrast to Figure 10.11, the signalling system is a 2-wirerather than 4-wire arrangement, in which the localtransmission is fed directly to the local receiver alongwith any received signal. The transmitter frequencies at

both ends are nominally equal, so the receiver respondsequally to blocks of carrier from either end. Through-fault current results in transmission of blocks of carrierfrom both ends, each lasting for half a cycle, but with aphase displacement of half a cycle, so that the compositesignal is continuously above the threshold level and thedetector output logic is continuously '1'. Any phase shiftrelative to the through fault condition produces a gap inthe 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 internaland external faults, tripping being permitted only when atime delay setting is exceeded. This delay is usuallyexpressed in terms of the corresponding phase shift indegrees at system frequency ϕs in Figure 10.12.

The advantages generally associated with the use of thepower line as the communication medium apply namely,that a power line provides a robust, reliable, and low-lossinterconnection between the relaying points. In additiondedicated 'on/off' signalling is particularly suited for usein phase comparison blocking mode schemes, as signalattenuation is not a problem. This is in contrast topermissive or direct tripping schemes, where high poweroutput or boosting is required to overcome the extraattenuation due to the fault.

The noise immunity is also very good, making the schemevery reliable. Signal propagation delay is easily allowedfor in the stability angle setting, making the scheme verysensitive as well.

10.11 PHASE COMPARISION PROTECTION SCHEME CONSIDERATIONS

One type of unit protection that uses carrier techniquesfor communication between relays is phase comparisonprotection. Communication between relays commonlyuses PLCC or frequency modulated carrier modemtechniques. There are a number of considerations thatapply only to phase comparison protection systems,which are discussed in this section.

10.11.1 Lines with Shunt Capacitance

A problem can occur with the shunt capacitance currentthat flows from an energising source. Since this current isin addition to the load current that flows out of the line,and typically leads it by more than 90°, significantdifferential phase shifts between the currents at the endsof the line can occur, particularly when load current is low.

The system differential phase shift may encroach into thetripping region of the simple discriminator characteristic,regardless of how large the stability angle setting maybe. Figure 10.14 illustrates the effect and indicatestechniques that are commonly used to ensure stability.

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Discriminator stability angle setting.

θ System differential phase shift referred to through fault referenceconditionOR Through faultreference condition H

IG=-IHIG IH

G

RStabilityθ=0°

θ=270°

θ=180°-Tripping

θ=90°

(IG' IH conventional relay currents at ends of protected feeder)

O

Figure 10.12: Polar diagram for phasecomparison scheme

Chap10-152-169 21/06/02 8:46 Page 162


Operation of the discriminator can be permitted onlywhen current is above some threshold, so thatmeasurement of the large differential phase shifts whichoccur near the origin of the polar diagram is avoided. Bychoice of a suitable threshold and stability angle, a'keyhole' characteristic can be provided such that thecapacitive current characteristic falls within theresultant stability region. Fast resetting of the faultdetector is required to ensure stability following theclearance of a through fault when the currents tend tofall towards the origin of the polar diagram.

The mark-space ratio of the squarer (or modulating)waveform can be made dependent on the currentamplitude. Any decrease in the mark-space ratio willpermit a corresponding differential phase shift to occurbetween the currents before any output is given from thecomparator for measurement in the discriminator. Asquarer circuit with an offset or bias can provide a

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D. Discriminator output

C. Carrier detector output

B. Composite carrier signal at end G

1

1

0

0

10

0

1

Receiver

Transmitter

Trip

A. Squarer output at end G

Pulse lengthdiscriminator

Squarer

D

A

C

End G

Summationnetwork

B

Couplingfilter

Line trap

Line trapp

Stability setting

End H

Identicalrelay

to end G

Blocks of carrier transmitted from end G

Squarer output at end H

Blocks of carrier transmitted from end H

Load or through fault Internal fault

0

1

0

1

0

1

1

0

Trip

Figure 10.13: Principles of power line carrier phase comparison

Figure 10.14: Capacitive current in phase comparisonschemes and techniques used to avoid instability

Limits of differential phase shift due to capacitive current ICEncroachment into tripping region for discriminatorwith stability angle setting ϕs

Through FaultReference

A

Squarer ThresholdStarter Threshold

`Keyhole' characteristicMinimum starter threshold =

Characteristic of system with amplitude dependentcompensation ϕs = angular compensation for current of magnitude OA

O

sin ϕs

capacitive current

θc

where ϕs = tan-1 ICIL

OA2sin-1 for squarer threshold IC

IC

IL = load current

ICϕs IL

Chap10-152-169 21/06/02 8:46 Page 163


decreasing mark-space ratio at low currents, and with asuitable threshold level the extra phase shift θc which ispermitted can be arranged to equal or exceed the phaseshift due to capacitive current. At high current levels thecapacitive current compensation falls towards zero andthe resultant stability region on the polar diagram isusually smaller than on the keyhole characteristic, givingimprovements in sensitivity and/or dependability of thescheme. Since the stability region encompasses allthrough-fault currents, the resetting speed of any faultdetectors or starter (which may still be required for otherpurposes, such as the control of a normally quiescentscheme) is much less critical than with the keyholecharacteristic.

10.11.2 System Tripping Angles

For the protection scheme to trip correctly on internalfaults the change in differential phase shift, θ0, from thethrough-fault condition taken as reference, must exceedthe effective stability angle of the scheme. Hence:

θ0 = ϕs + θc …Equation 10.1

where

ϕs = stability angle setting

θc = capacitive current compensation

(when applicable)

The currents at the ends of a transmission line IG and IHmay be expressed in terms of magnitude and phaseshift θ with respect a common system voltage.

IG = |IG| ∠ θG

IH = |IH| ∠ θH

Using the relay convention described in Section 10.2, thereference through-fault condition is

IG = -IH

∴ IG ∠ θG = -IH ∠ θH = IH ∠ θH ± 180°

∴ |θG - θH| =180°

During internal faults, the system tripping angle θ0 is thedifferential phase shift relative to the referencecondition.

∴ θ0 =180° - |θG - θH|

Substituting θ0 in Equation 10.1, the conditions fortripping are:

180 - |θG - θH| ≥ ϕS + θc

∴ |θG - θH| ≤ 180 - (ϕS + θc) …Equation 10.2

The term (ϕs + θc) is the effective stability angle settingof the scheme. Substituting a typical value of 60° inEquation 10.2. gives the tripping condition as

|θG - θH| ≤ 120° …Equation 10.3

In the absence of pre-fault load current, the voltages atthe two ends of a line are in phase. Internal faults arefed from both ends with fault contributions whosemagnitudes and angles are determined by the position ofthe fault and the system source impedances. Althoughthe magnitudes may be markedly different, the angles(line plus source) are similar and seldom differ by morethan about 20°.

Hence |θG - θH| ≤ 20° and the requirements of Equation10.3 are very easily satisfied. The addition of arc or faultresistance makes no difference to the reasoning above, sothe scheme is inherently capable of clearing such faults.

10.11.3 Effect of Load Current

When a line is heavily loaded prior to a fault the e.m.f.'sof the sources which cause the fault current to flow maybe displaced by up to about 50°, that is, the power systemstability limit. To this the differential line and sourceangles of up to 20° mentioned above need to be added.

So |θG - θH| ≤ 70° and the requirements of Equation 10.3are still easily satisfied.

For three phase faults, or solid earth faults on phase-by-phase comparison schemes, through load current falls tozero during the fault and so need not be considered. Forall other faults, load current continues to flow in thehealthy phases and may therefore tend to increase|θG - θH| towards the through fault reference value. Forlow resistance faults the fault current usually far exceedsthe load current and so has little effect. High resistancefaults or the presence of a weak source at one end canprove more difficult, but high performance is stillpossible if the modulating quantity is chosen with careand/or fault detectors are added.

10.11.4 Modulating Quantity

Phase-by-phase comparison schemes usually use phasecurrent for modulation of the carrier. Load and faultcurrents are almost in antiphase at an end with a weaksource. Correct performance is possible only when faultcurrent exceeds load current, or

for IF < IL’ |θG - θH| ≈ 180°for IF > IL’ |θG - θH| ≈ 180° …Equation 10.4

where IF = fault current contribution from weak sourceIL = load current flowing towards weak source

To avoid any risk of failure to operate, fault detectorswith a setting greater than the maximum load currentmay be applied, but they may limit the sensitivity ofscheme. When the fault detector is not operated at oneend, fault clearance invariably involves sequentialtripping of the circuit breakers.

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Most phase comparison schemes use summationtechniques to produce a single modulating quantity,responsive to faults on any of the three phases. Phasesequence components are often used and a typicalmodulating quantity is:

IM = MI2 + NI1 …Equation 10.5

where

I1 = Positive phase sequence componentI2 = Negative phase sequence componentM,N = constants

With the exception of three phase faults all internalfaults give rise to negative phase sequence (NPS)currents, I2, which are approximately in phase at theends of the line and therefore could form an idealmodulating quantity. In order to provide a modulatingsignal during three phase faults, which give rise topositive phase sequence (PPS) currents, I1, only, apractical modulating quantity must include someresponse to I1 in addition to I2.

Typical values of the ratio M: N exceed 5:1, so that themodulating quantity is weighted heavily in favour ofNPS, and any PPS associated with load current tends tobe swamped out on all but the highest resistance faults.

For a high resistance phase-earth fault, the systemremains well balanced so that load current IL is entirelypositive sequence. The fault contribution IF providesequal parts of positive, negative and zero sequencecomponents IF /3. Assuming the fault is on 'A' phase andthe load is resistive, all sequence components are inphase at the infeed end G:

At the outfeed end load current is negative,

Now, forImH > 0,θH = 0, and |θG - θH| = 0°

and forImH < 0,θH = 180°, and |θG - θH| = 180°

Hence for correct operation ImH ≥ 0Let ImH = 0

Then

…Equation 10.6

I IMN

IFHL

E=+

=3

1

∴ =− + + I NI MI NImH L

FH FH

3 3

∴ = + +

≈

and

I NI MI NImG L

FG FG

G

3 3

0θ

The fault current in Equation 10.6 is the effective earthfault sensitivity IE of the scheme. For the typical values of

M = 6 and N = -1

Comparing this with Equation 10.4, a scheme usingsummation is potentially 1.667 times more sensitivethan one using phase current for modulation.

Even though the use of a negative value of M gives alower value of IE than if it were positive, it is usuallypreferred since the limiting condition of Im = 0 thenapplies at the load infeed end. Load and faultcomponents are additive at the outfeed end so that acorrect modulating quantity occurs there, even with thelowest fault levels. For operation of the scheme it issufficient therefore that the fault current contributionfrom the load infeed end exceeds the effective setting.

For faults on B or C phases, the NPS components aredisplaced by 120° or 240° with respect to the PPScomponents. No simple cancellation can occur, butinstead a phase displacement is introduced. For trippingto occur, Equation 10.2 must be satisfied, and to achievehigh dependability under these marginal conditions, asmall effective stability angle is essential. Figure 10.15illustrates operation near to the limits of earth faultsensitivity.

Very sensitive schemes may be implemented by usinghigh values of M_N but the scheme then becomes moresensitive to differential errors in NPS currents such asthe unbalanced components of capacitive current or spillfrom partially saturated CT's.

Techniques such as capacitive current compensation andreduction of M_N at high fault levels may be required toensure stability of the scheme.

10.11.5 Fault Detection and Starting

For a scheme using a carrier system that continuouslytransmits the modulating quantity, protecting an idealline (capacitive current=0) in an interconnectedtransmission system, measurement of current magnitudemight be unnecessary. In practice, fault detector orstarting elements are invariably provided and the schemethen becomes a permissive tripping scheme in whichboth the fault detector and the discriminator mustoperate to provide a trip output, and the fault detectormay limit the sensitivity of the scheme. Requirementsfor the fault detectors vary according to the type ofcarrier channel used, mode of operation used in the

∴ =− I IE L35

MN

=−6

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phase angle measurement, that is, blocking orpermissive, and the features used to provide tolerance tocapacitive current.

10.11.6 Normally Quiescent Power Line Carrier (Blocking Mode)

To ensure stability of through faults, it is essential thatcarrier transmission starts before any measurement ofthe width of the gap is permitted. To allow forequipment tolerances and the difference in magnitude ofthe two currents due to capacitive current, two startingelements are used, usually referred to as 'Low Set' and'High Set' respectively. Low Set controls the start-up oftransmission whilst High Set, having a setting typically1.5 to 2 times that of the Low Set element, permits thephase angle measurement to proceed.

The use of impulse starters that respond to the change incurrent level enables sensitivities of less than ratedcurrent to be achieved. Resetting of the starters occursnaturally after a swell time or at the clearance of thefault. Dwell times and resetting characteristics must

ensure that during through faults, a High Set is neveroperated when a Low Set has reset and potential raceconditions are often avoided by the transmitting of anunmodulated (and therefore blocking) carrier for a shorttime following the reset of low set; this feature is oftenreferred to as 'Marginal Guard.'

10.11.7 Scheme without CapacitiveCurrent Compensation

The 'keyhole' discrimination characteristic of depends onthe inclusion of a fault detector to ensure that nomeasurements of phase angle can occur at low currentlevels, when the capacitive current might cause largephase shifts. Resetting must be very fast to ensurestability following the shedding of through load.

10.11.8 Scheme with CapacitiveCurrent Compensation (Blocking Mode)

When the magnitude of the modulating quantity is lessthan the threshold of the squarer, transmission if itoccurred, would be a continuous blocking signal. Thismight occur at an end with a weak source, remote froma fault close to a strong source. A fault detector isrequired to permit transmission only when the currentexceeds the modulator threshold by some multiple(typically about 2 times) so that the effective stabilityangle is not excessive. For PLCC schemes, the low setelement referred to in Section 10.11.6 is usually used forthis purpose. If the fault current is insufficient tooperate the fault detector, circuit breaker tripping willnormally occur sequentially.

10.11.9 Fault Detector Operating Quantities

Most faults cause an increase in the corresponding phasecurrent(s) so measurement of current increase could formthe basis for fault detection. However, when a line isheavily loaded and has a low fault level at the outfeedend, 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 modeschemes) or no tripping (for permissive schemes).Although fault detectors can be designed to respond toany disturbance (increase or decrease of current), it ismore usual to use phase sequence components. Allunbalanced faults produce a rise in the NPS componentsfrom the zero level associated with balanced load current,whilst balanced faults produce an increase in the PPScomponents from the load level (except at ends with verylow fault level) so that the use of NPS and PPS faultdetectors make the scheme sensitive to all faults. Forschemes using summation of NPS and PPS componentsfor the modulating quantity, the use of NPS and PPS fault

• 10 •

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Assumptions for examples:Infeed of load IL at end GOutfeed of load IL at end G

System voltage reference

(a) A phase to earth fault IF = 0.9 IE

(c) B phase to earth fault IF = IE (d) C phase to earth fault IF = IE

(b) A phase to earth fault IF = 1.1 IE

NM =-6 therefore Im = 6I2 - I2 and from Equation 10.6

NILH

NILG NILG

NILGNILG

NILH NILH

ImH

θH=0

ImG

ImG

θG=180°θG=0

|θG- θH |=180°

|θG- θH |=70°

|θG- θH |=0°

θGθGθH

θH

NILH

3NIE0.9

3NIE0.9

3MIE0.9

3NIE1.1

3NIE1.1

3NIE

3NIE

3NIE

3NIE

3MIE

3MIE

3MIE

3MIE

ImHImH

ImGImG

3MIE

0.93

MIE1.1

3MIE1.1

effective earth fault sensitivity IE =- 35

ILalso IF1 =

IF3

120° 120°

Figure 10.15: Effect of load current on differentialphase shift |θg - θH| for resistive earth faultsat the effective earth fault sensitivity IE

Chap10-152-169 21/06/02 8:46 Page 166


detectors is particularly appropriate since, in addition toany reductions in hardware, the scheme may becharacterized entirely in terms of sequence components.Fault sensitivities IF for PPS and NPS impulse startersettings I1S and I2S respectively are as follows:

Three phase fault IF = I1SPhase-phase fault IF = √3I2SPhase-earth fault IF = 3I2S

10.12 EXAMPLES

This section gives examples of setting calculations forsimple unit protection schemes. It cannot and is notintended to replace a proper setting calculation for aparticular application. It is intended to illustrate theprinciples of the calculations required. The examples usethe ALSTOM MiCOM P541 Current Differential relay,which has the setting ranges given in Table 10.1 fordifferential protection. The relay also has backupdistance, high-set instantaneous, and earth-faultprotection included in the basic model to provide acomplete ‘one-box’ solution of main and backupprotection.

10.12.1 Unit Protection of a Plain Feeder

The circuit to be protected is shown in Figure 10.16. Itconsists of a plain feeder circuit formed of an overheadline 25km long. The relevant properties of the line are:Line voltage: 33kV

Z = 0.157 + j0.337Ω/km

Shunt charging current = 0.065A/km

To arrive at the correct settings, the characteristics of therelays to be applied must be considered.

The recommended settings for three of the adjustablevalues (taken from the relay manual) are:

Is2 = 2.0puk1 = 30%k2 = 150%

To provide immunity from the effects of line chargingcurrent, the setting of IS1 must be at least 2.5 times thesteady-state charging current, i.e. 4.1A or 0.01p.u., aftertaking into consideration the CT ratio of 400/1. The nearestavailable setting above this is 0.20p.u. This gives the pointson the relay characteristic as shown in Figure 10.17.The minimum operating current Idmin is related to thevalue of Is1 by the formula

Idmin = (k1IL + Is1)/(1-0.5k1)

for Ibias <Is2and

Idmin = (k2IL -(k2-k1)Is2 + Is1)/(1-0.5k2)for Ibias >Is2

where IL = load currentand hence the minimum operating current at no load is0.235p.u. or 94A.

In cases where the capacitive charging current is verylarge and hence the minimum tripping current needs tobe set to an unacceptably high value, some relays offerthe facility of subtracting the charging current from themeasured value. Use of this facility depends on having asuitable VT input and knowledge of the shuntcapacitance of the circuit.

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Figure 10.16: Typical plain feeder circuit

33kV

Digital communications link

33kV400/1400/1

25km

Steady state charging current = 0.065A/km

Id> Id>

Parameter Setting Range

Differential Current Setting, Is1 0.2 -2.0 InBias Current Threshold Setting, Is2 1-30 InLower Percentage Bias Setting, k1 0.3-1.5

Higher Precentage Bias Setting, k2 0.3-1.5

In - CT rated secondary current

Table 10.1: Relay Setting Ranges

Chap10-152-169 21/06/02 8:46 Page 167


10.12.2 Unit Protection of a Transformer Feeder

Figure 10.18 shows unit protection applied to atransformer feeder. The feeder is assumed to be a 100mlength of cable, such as might be found in someindustrial plants or where a short distance separates the33kV and 11kV substations. While 11kV cablecapacitance will exist, it can be regarded as negligible forthe purposes of this example.

The delta/star transformer connection requires phaseshift correction of CT secondary currents across thetransformer, and in this case software equivalents ofinterposing CT’s are used.

Since the LV side quantities lag the HV side quantities by30°, it is necessary to correct this phase shift by usingsoftware CT settings that produce a 30° phase shift.There are two obvious possibilities:

a. HV side: Yd1LV side: Yy0

b. HV side: Yy0LV side: Yd11

Only the second combination is satisfactory, since onlythis one provides the necessary zero-sequence currenttrap to avoid maloperation of the protection scheme forearth faults on the LV side of the transformer outside ofthe protected zone.

Ratio correction must also be applied, in order to ensurethat the relays see currents from the primary andsecondary sides of the transformer feeder that are wellbalanced under full load conditions. This is not alwaysinherently the case, due to selection of the main CTratios. For the example of Figure 10.18,

Transformer turns ratio at nominal tap

Required turns ratio according to the CT ratios used

= = 400

11250

10 32.

= =1133

0 3333 .

• 10 •

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• 1 6 8 •

I diff

I diff

I

IbiasIbiasI

00

1

2

3

4

5

6

7

8

1 2 3 4 5 6

Figure 10.17: Relay characteristic;plain feeder example

Figure 10.18: Unit protection of a transformer feeder

20 MVA33/11kV

Dyn133kV 11kV

IdIdI > IdIdI >

Digital communicationchannel

1250/1400/1

350A 1050A

0.875A 0.84A

Ratio correction: 1.14software CT: Yy0

Ratio correction: 1.19software CT: Yd11

0° -30°

Cable100m

Chap10-152-169 21/06/02 8:46 Page 168


Spill current that will arise due to the incompatibility ofthe CT ratios used with the power transformer turns ratiomay cause relay maloperation. This has to be eliminatedby using the facility in the relay for CT ratio correctionfactors. For this particular relay, the correction factorsare chosen such that the full load current seen by therelay 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, thefollowing relay settings are then suitable, and allow fortransformer efficiency and mismatch due to tap-changing:

IS1 = 20% (minimum possible)

IS1 = 20%

k1 = 30%

k2 = 150%

10.13 REFERENCES

10.1 Merz-Price Protective Gear. K. Faye-Hansen andG. Harlow. IEE Proceedings, 1911.

10.2 Protective Relays Application Guide – 3rdEdition. ALSTOM Transmission and DistributionProtection and Control, 1987.

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Introduction 11.1

Principles of distance relays 11.2

Relay performance 11.3

Relationship between relay voltageand ZS/ZL ratio 11.4

Voltage limit for accuratereach point measurement 11.5

Zones of protection 11.6

Distance relay characteristics 11.7

Distance relay implementation 11.8

Effect of source impedanceand earthing methods 11.9

Distance relay application problems 11.10

Other distance relay features 11.11

Distance relay application example 11.12

References 11.13

• 1 1 • D i s t a n c e P r o t e c t i o n

Chapt11-170-191 20/06/02 15:37 Page 170

11.1 INTRODUCTION

The problem of combining fast fault clearance withselective tripping of plant is a key aim for the protectionof power systems. To meet these requirements, high-speed protection systems for transmission and primarydistribution circuits that are suitable for use with theautomatic reclosure of circuit breakers are undercontinuous development and are very widely applied.

Distance protection, in its basic form, is a non-unitsystem of protection offering considerable economic andtechnical advantages. Unlike phase and neutralovercurrent protection, the key advantage of distanceprotection is that its fault coverage of the protectedcircuit is virtually independent of source impedancevariations.

This is illustrated in Figure 11.1, where it can be seen thatovercurrent protection cannot be applied satisfactorily.

• 11 • Distance P rotect ion


Zs=10Ω

Zs=10ΩZ1=4Ω

Z1=4Ω

F1

F2F

R1

Zs=10Ω

115kV

Relay R1(a)

115kV

>I >>>>

>>>>>I

IF1I = =7380Ax 3

√3 +√

IF2I = =6640A115x103

√3x10√

Therefore, for relay operation for line faults,Relay current setting <6640A and >7380AThis is impractical, overcurrent relay not suitableMust use Distance or Unit Protection

(b)

Figure 11.1: Advantages of distanceover overcurrent protection

Chapt11-170-191 20/06/02 15:37 Page 171

Distance protection is comparatively simple to apply andit can be fast in operation for faults located along mostof a protected circuit. It can also provide both primaryand remote back-up functions in a single scheme. It caneasily be adapted to create a unit protection schemewhen applied with a signalling channel. In this form it iseminently suitable for application 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 isproportional to its length, for distance measurement it isappropriate to use a relay capable of measuring theimpedance of a line up to a predetermined point (thereach point). Such a relay is described as a distance relayand is designed to operate only for faults occurringbetween the relay location and the selected reach point,thus giving discrimination for faults that may occur indifferent line sections.

The basic principle of distance protection involves thedivision of the voltage at the relaying point by themeasured current. The apparent impedance socalculated is compared with the reach point impedance.If the measured impedance is less than the reach pointimpedance, it is assumed that a fault exists on the linebetween the relay and the reach point.

The reach point of a relay is the point along the lineimpedance locus that is intersected by the boundarycharacteristic of the relay. Since this is dependent on theratio of voltage and current and the phase anglebetween them, it may be plotted on an R/X diagram. Theloci of power system impedances as seen by the relayduring faults, power swings and load variations may beplotted on the same diagram and in this manner theperformance of the relay in the presence of system faultsand disturbances may be studied.

11.3 RELAY PERFORMANCE

Distance relay performance is defined in terms of reachaccuracy and operating time. Reach accuracy is acomparison of the actual ohmic reach of the relay underpractical conditions with the relay setting value in ohms.Reach accuracy particularly depends on the level ofvoltage presented to the relay under fault conditions.The impedance measuring techniques employed inparticular relay designs also have an impact.

Operating times can vary with fault current, with faultposition relative to the relay setting, and with the pointon the voltage wave at which the fault occurs.Depending on the measuring techniques employed in aparticular relay design, measuring signal transient errors,such as those produced by Capacitor Voltage

Transformers or saturating CT’s, can also adversely delayrelay operation for faults close to the reach point. It isusual for electromechanical and static distance relays toclaim both maximum and minimum operating times.However, for modern digital or numerical distance relays,the variation between these is small over a wide range ofsystem operating conditions and fault positions.

11.3.1 Electromechanical/Static Distance Relays

With electromechanical and earlier static relay designs,the magnitude of input quantities particularly influencedboth reach accuracy and operating time. It wascustomary to present information on relay performanceby voltage/reach curves, as shown in Figure 11.2, andoperating time/fault position curves for various values ofsystem impedance ratios (S.I.R.’s) as shown in Figure 11.3,where:

and

ZS = system source impedance behind the relaylocation

ZL = line impedance equivalent to relay reach setting

S I R ZZ

SL

. . . =

• 11 •

Dis

tanc

e P

rote

ctio

n


105

100

9520 40 60 80 100

95

100

4020 60

105

10080

105

95

100

2010 30 40 50 60 650

0

0

Impe

danc

e re

ach

(% Z

one

1 se

ttin

g)

% relay rated voltage(a) Phase-earth faults

% relay rated voltage(b) Phase-phase faults

% relay rated voltage(c) Three-phase and three-phase-earth faults

Impe

danc

e re

ach

(% Z

one

1 se

ttin

g)Im

peda

nce

reac

h(%

Zon

e 1

sett

ing)

Figure 11.2: Typical impedance reachaccuracy characteristics for Zone 1

Chapt11-170-191 20/06/02 15:37 Page 172

Alternatively, the above information was combined in afamily of contour curves, where the fault positionexpressed as a percentage of the relay setting is plottedagainst the source to line impedance ratio, as illustratedin Figure 11.4.

11.3.2 Digital/Numerical Distance Relays

Digital/Numerical distance relays tend to have moreconsistent operating times. They are usually slightlyslower than some of the older relay designs whenoperating under the best conditions, but their maximumoperating times are also less under adverse waveformconditions or for boundary fault conditions.

11.4 RELATIONSHIP BETWEEN RELAY VOLTAGEAND ZS/ZL RATIO

A single, generic, equivalent circuit, as shown in Figure11.5(a), may represent any fault condition in a three-phase power system. The voltage V applied to theimpedance loop is the open circuit voltage of the powersystem. Point R represents the relay location; IR and VRare the current and voltage measured by the relay,respectively.

The impedances ZS and ZL are described as source andline impedances because of their position with respect tothe relay location. Source impedance ZS is a measure ofthe fault level at the relaying point. For faults involvingearth it is dependent on the method of system earthingbehind the relaying point. Line impedance ZL is ameasure of the impedance of the protected section. Thevoltage VR applied to the relay is, therefore, IRZL. For afault at the reach point, this may be alternativelyexpressed in terms of source to line impedance ratioZS/ZL by means of the following expressions:

VR=IRZLwhere:

Therefore :

or

...Equation 11.1

The above generic relationship between VR and ZS/ZL,illustrated in Figure 11.5(b), is valid for all types of shortcircuits provided a few simple rules are observed. Theseare:

i. for phase faults, V is the phase-phase sourcevoltage and ZS/ZL is the positive sequence sourceto line impedance ratio. VR is the phase-phaserelay voltage and IR is the phase-phase relaycurrent, for the faulted phases

VZ Z

VRS L

= ( ) +1

1

VZ

Z ZVR

L

S L=

+

I VZ ZR

S L=

+

• 11 •D

ista

nce

Pro

tect

ion


Ope

ratio

n tim

e (m

s)

10

(b) With system impedance ratio of 30/1

Min

Max

10 20 30 40 50 60 70 80 90 1000

20

30

40

50

Fault position (% relay setting)

(a) With system impedance ratio of 1/1

20

Ope

ratio

n tim

e (m

s)

20

Min

0

10

10 4030 50 60

50

30

40

Fault position (% relay setting)

908070 100

Max

Figure 11.3: Typical operation timecharacteristics for Zone 1 phase-phase faults

0.1

0.1

0.20.30.40.50.60.70.80.91.0

0.010 1 10 1001 1000S/ZS/ZS LZL

S/ZS/ZS LZL

(b) Zone 1 phase-phase fault: maximum operation times

Faul

t po

sitio

n (p

.u. r

elay

set

ting

Z LZ LZ)

0.1

0.01

0.30.2

0.4

0.1

0.80.70.60.5

1.00.9

101 100 1000

Faul

t po

sitio

n (p

.u. r

elay

set

ting

Z LZ)

yyyyBoundary

15ms

9ms13ms

Boundary

Figure 11.4: Typical operation-time contours

Chapt11-170-191 20/06/02 15:37 Page 173

…Equation 11.2

ii. for earth faults, V is the phase-neutral sourcevoltage and ZS/ZL is a composite ratio involvingthe positive and zero sequence impedances. VR isthe phase-neutral relay voltage and IR is the relaycurrent for the faulted phase

...Equation 11.3

whereZS = 2ZS1 + ZS0 = ZS1(2+p)

ZL = 2ZL1 + ZL0 = ZL1(2+q)

and

pZZ

qZZ

S

S

L

L

=

=

0

1

0

1

V

Z Zpq

VR

S L

l n=( ) +

+

+−

122

1

VZ Z

VRS L

p p= ( ) + −1

1

11.5 VOLTAGE LIMIT FOR ACCURATEREACH POINT MEASUREMENT

The ability of a distance relay to measure accurately fora reach point fault depends on the minimum voltage atthe relay location under this condition being above adeclared value. This voltage, which depends on the relaydesign, can also be quoted in terms of an equivalentmaximum ZS/ZL or S.I.R.

Distance relays are designed so that, provided the reachpoint voltage criterion is met, any increased measuringerrors for faults closer to the relay will not prevent relayoperation. Most modern relays are provided with healthyphase voltage polarisation and/or memory voltagepolarisation. The prime purpose of the relay polarisingvoltage is to ensure correct relay directional response forclose-up faults, in the forward or reverse direction,where the fault-loop voltage measured by the relay maybe very small.

11.6 ZONES OF PROTECTION

Careful selection of the reach settings and tripping timesfor the various zones of measurement enables correct co-ordination between distance relays on a power system.Basic distance protection will comprise instantaneousdirectional 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. Digitaland numerical distance relays may have up to five zones,some set to measure in the reverse direction. Typicalsettings for three forward-looking zones of basic distanceprotection are given in the following sub-sections. Todetermine the settings for a particular relay design or fora particular distance teleprotection scheme, involvingend-to-end signalling, the relay manufacturer’sinstructions should be referred to.

11.6.1 Zone 1 Setting

Electromechanical/static relays usually have a reachsetting of up to 80% of the protected line impedance forinstantaneous Zone 1 protection. For digital/numericaldistance relays, settings of up to 85% may be safe. Theresulting 15-20% safety margin ensures that there is norisk of the Zone 1 protection over-reaching the protectedline due to errors in the current and voltagetransformers, inaccuracies in line impedance dataprovided for setting purposes and errors of relay settingand measurement. Otherwise, there would be a loss ofdiscrimination with fast operating protection on thefollowing line section. Zone 2 of the distance protectionmust cover the remaining 15-20% of the line.

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0.1 0.2 0.3 0.5 1 2 3 4 5 10

10

0

20

30

40

50

60

70

80

90

100

System impedance ratio

(b) Variation of relay voltage with system source to line impedance ratio

2.5

5.0

10

7.5

010 20 30 40 50

VR

(%)

VR (%)

Source LineR

VS VL=VR

VR

IR

ZS ZL

ZL

ZS

ZL

ZS

V

(a) Power system configuration

(% ra

ted

volta

ge)

Volta

ge V

R

Figure 11.5: Relationship between sourceto line ratio and relay voltage

Chapt11-170-191 20/06/02 15:37 Page 174


To ensure full cover of the line with allowance for thesources of error already listed in the previous section, thereach setting of the Zone 2 protection should be at least120% of the protected line impedance. In manyapplications it is common practice to set the Zone 2reach to be equal to the protected line section +50% ofthe shortest adjacent line. Where possible, this ensuresthat the resulting maximum effective Zone 2 reach doesnot extend beyond the minimum effective Zone 1 reachof the adjacent line protection. This avoids the need tograde the Zone 2 time settings between upstream anddownstream relays. In electromechanical and staticrelays, Zone 2 protection is provided either by separateelements or by extending the reach of the Zone 1elements after a time delay that is initiated by a faultdetector. In most digital and numerical relays, the Zone2 elements are implemented in software.

Zone 2 tripping must be time-delayed to ensure gradingwith the primary relaying applied to adjacent circuits thatfall within the Zone 2 reach. Thus complete coverage ofa line section is obtained, with fast clearance of faults inthe first 80-85% of the line and somewhat slowerclearance of faults in the remaining section of the line.


Remote back-up protection for all faults on adjacentlines can be provided by a third zone of protection thatis time delayed to discriminate with Zone 2 protectionplus circuit breaker trip time for the adjacent line. Zone3 reach should be set to at least 1.2 times the impedancepresented to the relay for a fault at the remote end ofthe second line section.

On interconnected power systems, the effect of faultcurrent infeed at the remote busbars will cause theimpedance presented to the relay to be much greaterthan the actual impedance to the fault and this needs to

be taken into account when setting Zone 3. In somesystems, variations in the remote busbar infeed canprevent the application of remote back-up Zone 3protection but on radial distribution systems with singleend infeed, no difficulties should arise.

11.6.4 Settings for Reverse Reach and Other Zones

Modern digital or numerical relays may have additionalimpedance zones that can be utilised to provideadditional protection functions. For example, where thefirst three zones are set as above, Zone 4 might be usedto provide back-up protection for the local busbar, byapplying a reverse reach setting of the order of 25% ofthe Zone 1 reach. Alternatively, one of the forward-looking zones (typically Zone 3) could be set with a smallreverse offset reach from the origin of the R/X diagram,in addition to its forward reach setting. An offsetimpedance measurement characteristic is non-directional. One advantage of a non-directional zone ofimpedance measurement is that it is able to operate fora close-up, zero-impedance fault, in situations wherethere may be no healthy phase voltage signal or memoryvoltage signal available to allow operation of adirectional impedance zone. With the offset-zone timedelay bypassed, there can be provision of ‘Switch-on-to-Fault’ (SOTF) protection. This is required where there areline voltage transformers, to provide fast tripping in theevent of accidental line energisation with maintenanceearthing clamps left in position. Additional impedancezones may be deployed as part of a distance protectionscheme used in conjunction with a teleprotectionsignalling channel.

11.7 DISTANCE RELAY CHARACTERISTICS

Some numerical relays measure the absolute faultimpedance and then determine whether operation isrequired according to impedance boundaries defined onthe R/X diagram. Traditional distance relays andnumerical relays that emulate the impedance elementsof traditional relays do not measure absolute impedance.They compare the measured fault voltage with a replicavoltage derived from the fault current and the zoneimpedance setting to determine whether the fault iswithin zone or out-of-zone. Distance relay impedancecomparators or algorithms which emulate traditionalcomparators are classified according to their polarcharacteristics, the number of signal inputs they have,and the method by which signal comparisons are made.The common types compare either the relative amplitudeor phase of two input quantities to obtain operatingcharacteristics that are either straight lines or circleswhen plotted on an R/X diagram. At each stage ofdistance relay design evolution, the development of

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Zone 1 = 80-85% of protected line impedanceZone 2 (minimum) = 120% of protected lineZone 2 (maximum) < Protected line + 50% of shortest second lineZone 3F = 1.2 (protected line + longest second line)Zone 3R = 20% of protected lineX = Circuit breaker tripping timeY = Discriminating time

Time

Time

0Source Source

Z3JR Z3JF

Z1H Z1KZ2KZ3KF Z3KR

Z1L

Z2JZ1J

Y

H

HH J K

Y

X

Figure 11.6: Typical time/distance characteristicsfor three zone distance protection

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impedance operating characteristic shapes andsophistication has been governed by the technologyavailable and the acceptable cost. Since manytraditional relays are still in service and since somenumerical relays emulate the techniques of thetraditional relays, a brief review of impedancecomparators is justified.

11.7.1 Amplitude and Phase Comparison

Relay measuring elements whose functionality is basedon the comparison of two independent quantities areessentially either amplitude or phase comparators. Forthe impedance elements of a distance relay, thequantities being compared are the voltage and currentmeasured by the relay. There are numerous techniquesavailable for performing the comparison, depending onthe technology used. They vary from balanced-beam(amplitude comparison) and induction cup (phasecomparison) electromagnetic relays, through diode andoperational amplifier comparators in static-type distancerelays, to digital sequence comparators in digital relaysand to algorithms used in numerical relays.

Any type of impedance characteristic obtainable withone comparator is also obtainable with the other. Theaddition and subtraction of the signals for one type ofcomparator produces the required signals to obtain asimilar characteristic using the other type. For example,comparing V and I in an amplitude comparator results ina circular impedance characteristic centred at the originof the R/X diagram. If the sum and difference of V andI are applied to the phase comparator the result is asimilar characteristic.

11.7.2 Plain Impedance Characteristic

This characteristic takes no account of the phase anglebetween the current and the voltage applied to it; for thisreason its impedance characteristic when plotted on anR/X diagram is a circle with its centre at the origin of theco-ordinates and of radius equal to its setting in ohms.Operation occurs for all impedance values less than thesetting, that is, for all points within the circle. The relaycharacteristic, shown in Figure 11.7, is therefore non-directional, and in this form would operate for all faultsalong the vector AL and also for all faults behind thebusbars up to an impedance AM. It is to be noted that Ais the relaying point and RAB is the angle by which thefault current lags the relay voltage for a fault on the lineAB and RAC is the equivalent leading angle for a fault online AC. Vector AB represents the impedance in front ofthe relay between the relaying point A and the end of lineAB. Vector AC represents the impedance of line ACbehind the relaying point. AL represents the reach ofinstantaneous Zone 1 protection, set to cover 80% to85% of the protected line.

A relay using this characteristic has three importantdisadvantages:

i. it is non-directional; it will see faults both in frontof and behind the relaying point, and therefore

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C

Operates

A B

Line AC Line AB

X

B

R

C

M

L

A

AC

Restrains

Impedancerelayp

relay

Line AB

C

Z<Z<Z

Figure 11.7: Plain impedance relaycharacteristic

AA BIF1IIF2I

RAZ<RRADRRADR

<Z

I

C D

F

Source Source

Trip relay

X

Directionalelement RD

Impedanceelement RZ<

R

L

B

Restrains Q

A

(a) Characteristic of combined directional/impedance relay

(b) Illustration of use of directional/impedance relay: circuit diagram

(c) Logic for directional and impedance elements at A

& &

AZ<RADR : directional element at A

F

Figure 11.8: Combined directionaland impedance relays

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requires a directional element to give it correctdiscrimination

ii. it has non-uniform fault resistance coverage

iii. it is susceptible to power swings and heavyloading of a long line, because of the large areacovered by the impedance circle

Directional control is an essential discrimination qualityfor a distance relay, to make the relay non-responsive tofaults outside the protected line. This can be obtained bythe addition of a separate directional control element.The impedance characteristic of a directional controlelement is a straight line on the R/X diagram, so thecombined characteristic of the directional andimpedance relays is the semi-circle APLQ shown inFigure 11.8.

If a fault occurs at F close to C on the parallel line CD,the directional unit RD at A will restrain due to currentIF1. At the same time, the impedance unit is preventedfrom operating by the inhibiting output of unit RD. Ifthis control is not provided, the under impedanceelement could operate prior to circuit breaker C opening.Reversal of current through the relay from IF1 to IF2when C opens could then result in incorrect tripping ofthe healthy line if the directional unit RD operates beforethe impedance unit resets. This is an example of theneed to consider the proper co-ordination of multiplerelay elements to attain reliable relay performanceduring evolving fault conditions. In older relay designs,the type of problem to be addressed was commonlyreferred to as one of ‘contact race’.

11.7.3 Self-Polarised Mho Relay

The mho impedance element is generally known as suchbecause its characteristic is a straight line on anadmittance diagram. It cleverly combines thediscriminating qualities of both reach control anddirectional control, thereby eliminating the ‘contact race’problems that may be encountered with separate reachand directional control elements. This is achieved by theaddition of a polarising signal. Mho impedance elementswere particularly attractive for economic reasons whereelectromechanical relay elements were employed. As aresult, they have been widely deployed worldwide formany years and their advantages and limitations are nowwell understood. For this reason they are still emulatedin the algorithms of some modern numerical relays.

The characteristic of a mho impedance element, whenplotted on an R/X diagram, is a circle whose circumferencepasses through the origin, as illustrated in Figure 11.9(b).This demonstrates that the impedance element isinherently directional and such that it will operate only forfaults in the forward direction along line AB.

The impedance characteristic is adjusted by setting Zn,the impedance reach, along the diameter and ϕ, theangle of displacement of the diameter from the R axis.Angle ϕ is known as the Relay Characteristic Angle(RCA). The relay operates for values of fault impedanceZF within its characteristic.

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(a) Phase comparator inputs

RestrainIZn

Zn

ZFZ

V

IX

IR

(b) Mho impedance characteristic

IR

Restrain

IX

A

K

RestrainB

(c) Increased arc resistance coverage

K

A IR

B

P Q

AP Relay impedance settingjAB Protected line

Arc resistanceqLine angle

IX

jj

jj

Operate

V

V-IZn

Opperatej

qj

Figure 11.9: Mho relay characteristic

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It will be noted that the impedance reach varies withfault angle. As the line to be protected is made up ofresistance and inductance, its fault angle will bedependent upon the relative values of R and X at thesystem operating frequency. Under an arcing faultcondition, or an earth fault involving additionalresistance, such as tower footing resistance or faultthrough vegetation, the value of the resistive componentof fault impedance will increase to change theimpedance angle. Thus a relay having a characteristicangle equivalent to the line angle will under-reach underresistive fault conditions.

It is usual, therefore, to set the RCA less than the lineangle, so that it is possible to accept a small amount offault resistance without causing under-reach. However,when setting the relay, the difference between the lineangle θ and the relay characteristic angle ϕ must beknown. The resulting characteristic is shown in Figure11.9(c) where AB corresponds to the length of the line tobe protected. With ϕ set less than θ, the actual amountof line protected, AB, would be equal to the relay settingvalue AQ multiplied by cosine (θ-ϕ). Therefore therequired relay setting AQ is given by:

Due to the physical nature of an arc, there is a non-linearrelationship between arc voltage and arc current, whichresults in a non-linear resistance. Using the empiricalformula derived by A.R. van C. Warrington, [11.1] theapproximate value of arc resistance can be assessed as:

...Equation 11.4where:

Ra = arc resistance (ohms)

L = length of arc (metres)

I = arc current (A)

On long overhead lines carried on steel towers withoverhead earth wires the effect of arc resistance canusually be neglected. The effect is most significant onshort overhead lines and with fault currents below2000A (i.e. minimum plant condition), or if the protectedline is of wood-pole construction without earth wires. Inthe latter case, the earth fault resistance reduces theeffective earth-fault reach of a mho Zone 1 element tosuch an extent that the majority of faults are detected inZone 2 time. This problem can usually be overcome byusing a relay with a cross-polarised mho or a polygonalcharacteristic.

Where a power system is resistance-earthed, it should beappreciated that this does not need to be considered

RI

La = 287101 4.

AQ AB=−( )cos θ ϕ

with regard to the relay settings other than the effectthat reduced fault current may have on the value of arcresistance seen. The earthing resistance is in the sourcebehind the relay and only modifies the source angle andsource to line impedance ratio for earth faults. It wouldtherefore be taken into account only when assessingrelay performance in terms of system impedance ratio.

11.7.4 Offset Mho/Lenticular Characteristics

Under close up fault conditions, when the relay voltagefalls to zero or near-zero, a relay using a self-polarisedmho characteristic or any other form of self-polariseddirectional impedance characteristic may fail to operatewhen it is required to do so. Methods of covering thiscondition include the use of non-directional impedancecharacteristics, such as offset mho, offset lenticular, orcross-polarised and memory polarised directionalimpedance characteristics.

If current bias is employed, the mho characteristic isshifted to embrace the origin, so that the measuringelement can operate for close-up faults in both theforward and the reverse directions. The offset mho relayhas two main applications:

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(a) Busbar zone back-up using an offset mho relay

(b) Carrier starting in distance blocking schemes

Zone1

X

R

Zone1

R

X

Zone2

3Zone

Busbar zone

Zone2

Zone3

Carrier stop

Carrier start

G

K

H

J

Figure 11.10: Typical applicationsfor the offset mho relay

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11.7.4.1 Third zone and busbar back-up zone

In this application it is used in conjunction with mhomeasuring units as a fault detector and/or Zone 3measuring unit. So, with the reverse reach arranged toextend into the busbar zone, as shown in Figure 11.10(a),it will provide back-up protection for busbar faults. Thisfacility can also be provided with quadrilateralcharacteristics. A further benefit of the Zone 3application is for Switch-on-to-Fault (SOTF) protection,where the Zone 3 time delay would be bypassed for ashort period immediately following line energisation toallow rapid clearance of a fault anywhere along theprotected line.

11.7.4.2 Carrier starting unit in distance schemeswith carrier blocking

If the offset mho unit is used for starting carriersignalling, it is arranged as shown in Figure 11.10(b).Carrier is transmitted if the fault is external to theprotected line but inside the reach of the offset mhorelay, in order to prevent accelerated tripping of thesecond or third zone relay at the remote station.Transmission is prevented for internal faults by operationof the local mho measuring units, which allows high-speed fault clearance by the local and remote end circuitbreakers.

11.7.4.3 Application of lenticular characteristic

There is a danger that the offset mho relay shown inFigure 11.10(a) may operate under maximum loadtransfer conditions if Zone 3 of the relay has a largereach setting. A large Zone 3 reach may be required toprovide remote back-up protection for faults on theadjacent feeder.

To avoid this, a shaped type of characteristic may beused, where the resistive coverage is restricted. With a‘lenticular’ characteristic,the aspect ratio of the lens is adjustable, enabling

it to be set to provide the maximum fault resistancecoverage consistent with non-operation under maximumload transfer conditions.

Figure 11.11 shows how the lenticular characteristic cantolerate much higher degrees of line loading than offsetmho and plain impedance characteristics.

Reduction of load impedance from ZD3 to ZD1 willcorrespond to an equivalent increase in load current.

11.7.5 Fully Cross-Polarised Mho Characteristic

The previous section showed how the non-directionaloffset mho characteristic is inherently able to operate forclose-up zero voltage faults, where there would be nopolarising voltage to allow operation of a plain mhodirectional element. One way of ensuring correct mhoelement response for zero-voltage faults is to add apercentage of voltage from the healthy phase(s) to themain polarising voltage as a substitute phase reference.This technique is called cross-polarising, and it has theadvantage of preserving and indeed enhancing thedirectional properties of the mho characteristic. By theuse of a phase voltage memory system, that providesseveral cycles of pre-fault voltage reference during afault, the cross-polarisation technique is also effectivefor close-up three-phase faults. For this type of fault, nohealthy phase voltage reference is available.

Early memory systems were based on tuned, resonant,analogue circuits, but problems occurred when appliedto networks where the power system operatingfrequency could vary. More modern digital or numericalsystems can offer a synchronous phase reference forvariations in power system frequency before or evenduring a fault.

As described in Section 11.7.3, a disadvantage of theself-polarised, plain mho impedance characteristic, whenapplied to overhead line circuits with high impedanceangles, is that it has limited coverage of arc or faultresistance. The problem is aggravated in the case ofshort lines, since the required Zone 1 ohmic setting islow. The amount of the resistive coverage offered by themho circle is directly related to the forward reachsetting. Hence, the resulting resistive coverage may betoo small in relation to the expected values of faultresistance.

One additional benefit of applying cross-polarisation toa mho impedance element is that its resistive coveragewill be enhanced. This effect is illustrated in Figure11.12, for the case where a mho element has 100%

ab

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Impedancecharacteristic

Offset Mhocharacteristic

b

a

Offset Lenticularcharacteristic

R00

X

ZD1ZZD2Z

ZD3Z

Loadarea

Figure 11.11: Minimum load impedancepermitted with lenticular, offset mho

and impedance relays

Chapt11-170-191 20/06/02 15:40 Page 179

cross-polarisation. With cross-polarisation from thehealthy phase(s) or from a memory system, the mhoresistive expansion will occur during a balanced three-phase fault as well as for unbalanced faults. Theexpansion will not occur under load conditions, whenthere is no phase shift between the measured voltageand the polarising voltage. The degree of resistive reachenhancement depends on the ratio of source impedanceto relay reach (impedance) setting as can be deduced byreference to Figure 11.13.

It must be emphasised that the apparent extension of afully cross-polarised impedance characteristic into thenegative reactance quadrants of Figure 11.13 does notimply that there would be operation for reverse faults.With cross-polarisation, the relay characteristic expandsto encompass the origin of the impedance diagram forforward faults only. For reverse faults, the effect is toexclude the origin of the impedance diagram, therebyensuring proper directional responses for close-upforward or reverse faults.

Fully cross-polarised characteristics have now largelybeen superseded, due to the tendency of comparatorsconnected to healthy phases to operate under heavyfault conditions on another phase. This is of noconsequence in a switched distance relay, where a singlecomparator is connected to the correct fault loopimpedance by starting units before measurement begins.However, modern relays offer independent impedancemeasurement for each of the three earth-fault and threephase-fault loops. For these types of relay, maloperationof healthy phases is undesirable, especially when single-pole tripping is required for single-phase faults.

11.7.6 Partially Cross-Polarised Mho Characteristic

Where a reliable, independent method of faulted phaseselection is not provided, a modern non-switcheddistance relay may only employ a relatively smallpercentage of cross polarisation.

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Mho unit characteristic(fully cross-polarized)

ZS

N1E1

N2N

F1

IFI

F2F

ZLZ

ZL1ZZS1

Va1Va1V

Ia1Ia1I

Ia2Ia2I

Va2Va2V

ZL2ZZS2

Zn2

Zn1ZL1Z

ZS1S'1=ZL1Z +Zn2

S'2=ZL1Z +Zn1

Positive current directionfor relay

ZSource

Relay location

Mho unitcharacteristic(not cross-polarized)

-X

X

R

30°

Figure 11.13: Illustration of improvementin relay resistive coverage for fully cross-

polarised characteristic

R

X

0ZSZLZ

=25ZSZLZ

Figure 11.12: Fully cross-polarised mho relaycharacteristic with variations of ZS/ZL ratio

Shield-shapedcharacteristic with16% square-wavecross-polarisationcr X

-RR

-X

Self-polarised Mho circle

Fully cross-polarisedMho circlec

Extra resistivecoverage of shield

Conventional 16%partially cross-polarisedMho circle

Zn

(a) Comparison of polarised characteristics drawn for S.I.R. = 6

(b) Resistive expansion of shaped partially cross-polarised Mho with increasing values of S.I.R.

X

R0 1 6 12 24 60

Figure 11.14: Partially cross-polarisedcharacteristic with 'shield' shape

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The level selected must be sufficient to provide reliabledirectional control in the presence of CVT transients forclose-up faults, and also attain reliable faulted phaseselection. By employing only partial cross-polarisation,the disadvantages of the fully cross-polarisedcharacteristic are avoided, while still retaining theadvantages. Figure 11.14 shows a typical characteristicthat can be obtained using this technique.

11.7.7 Quadrilateral Characteristic

This form of polygonal impedance characteristic is shownin Figure 11.15. The characteristic is provided withforward reach and resistive reach settings that areindependently adjustable. It therefore provides betterresistive coverage than any mho-type characteristic forshort lines. This is especially true for earth faultimpedance measurement, where the arc resistances andfault resistance to earth contribute to the highest valuesof fault resistance. To avoid excessive errors in the zonereach accuracy, it is common to impose a maximumresistive reach in terms of the zone impedance reach.Recommendations in this respect can usually be found inthe appropriate relay manuals.

Quadrilateral elements with plain reactance reach linescan introduce reach error problems for resistive earthfaults where the angle of total fault current differs fromthe angle of the current measured by the relay. This willbe the case where the local and remote source voltagevectors are phase shifted with respect to each other dueto pre-fault power flow. This can be overcome byselecting an alternative to use of a phase current forpolarisation of the reactance reach line. Polygonalimpedance characteristics are highly flexible in terms offault impedance coverage for both phase and earthfaults. For this reason, most digital and numericaldistance relays now offer this form of characteristic. Afurther factor is that the additional cost implications of

implementing this characteristic using discretecomponent electromechanical or early static relaytechnology do not arise.

11.7.8 Protection against Power Swings –Use of the Ohm Characteristic

During severe power swing conditions from which asystem is unlikely to recover, stability might only beregained if the swinging sources are separated. Wheresuch scenarios are identified, power swing, or out-of-step, tripping protection can be deployed, to strategicallysplit a power system at a preferred location. Ideally, thesplit should be made so that the plant capacity andconnected loads on either side of the split are matched.

This type of disturbance cannot normally be correctlyidentified by an ordinary distance protection. Aspreviously mentioned, it is often necessary to preventdistance protection schemes from operating duringstable or unstable power swings, in order to avoidcascade tripping. To initiate system separation for aprospective unstable power swing, an out-of-steptripping scheme employing ohm impedance measuringelements can be deployed.

Ohm impedance characteristics are applied along theforward and reverse resistance axes of the R/X diagramand their operating boundaries are set to be parallel to theprotected line impedance vector, as shown in Figure 11.16.The ohm impedance elements divide the R/X impedancediagram into three zones, A, B and C. As the impedancechanges during a power swing, the point representing theimpedance moves along the swing locus, entering the threezones in turn and causing the ohm units to operate insequence. When the impedance enters the third zone thetrip sequence is completed and the circuit breaker trip coilcan be energised at a favourable angle between systemsources for arc interruption with little risk of restriking.

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Zone 3

R

RZ1RZ2RZ3

X

A

Zone 1

Zone 2

Zone 3

Zones 1&2

B

C

Figure 11.15: Quadrilateral characteristic Locus of

RG

Out-of-step tripping relaycharacteristic

X

Line impedanceH

Zone C

Zone A

Zone B

Figure 11.16: Application of out-of-steptripping relay characteristic

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Only an unstable power swing condition can cause theimpedance vector to move successively through thethree zones. Therefore, other types of systemdisturbance, such as power system fault conditions, willnot result in relay element operation.

11.7.9 Other Characteristics

The execution time for the algorithm for traditionaldistance protection using quadrilateral or similarcharacteristics may result in a relatively long operationtime, possibly up to 40ms in some relay designs. Toovercome this, some numerical distance relays also usealternative algorithms that can be executed significantlyfaster. These algorithms are based generally on detectingchanges in current and voltage that are in excess of whatis expected, often known as the ‘Delta’ algorithm.

This algorithm detects a fault by comparing themeasured values of current and voltage with the valuessampled previously. If the change between thesesamples exceeds a predefined amount (the ‘delta’), it isassumed a fault has occurred. In parallel, the distance tofault is also computed. Provided the computed distanceto fault lies within the Zone reach of the relay, a tripcommand is issued. This algorithm can be executedsignificantly faster than the conventional distancealgorithm, resulting in faster overall tripping times.Faulted phase selection can be carried out by comparingthe signs of the changes in voltage and current.

Relays that use the ‘Delta’ algorithm generally run boththis and conventional distance protection algorithms inparallel, as some types of fault (e.g. high-resistancefaults) may not fall within the fault detection criteria ofthe Delta algorithm.

11.8 DISTANCE RELAY IMPLEMENTATION

Discriminating zones of protection can be achieved usingdistance relays, provided that fault distance is a simplefunction of impedance. While this is true in principle fortransmission circuits, the impedances actually measuredby a distance relay also depend on the following factors:

1. the magnitudes of current and voltage (the relaymay not see all the current that produces the faultvoltage)

2. the fault impedance loop being measured

3. the type of fault

4. the fault resistance

5. the symmetry of line impedance

6. the circuit configuration (single, double or multi-terminal circuit)

It is impossible to eliminate all of the above factors forall possible operating conditions. However, considerablesuccess can be achieved with a suitable distance relay.This may comprise relay elements or algorithms forstarting, distance measuring and for scheme logic.

The distance measurement elements may produceimpedance characteristics selected from those describedin Section 11.7. Various distance relay formats exist,depending on the operating speed required and costconsiderations related to the relaying hardware, softwareor numerical relay processing capacity required. Themost common formats are:

a. a single measuring element for each phase isprovided, that covers all phase faults

b. a more economical arrangement is for ‘starter’elements to detect which phase or phases havesuffered a fault. The starter elements switch asingle measuring element or algorithm to measurethe most appropriate fault impedance loop. This iscommonly referred to as a switched distance relay

c. a single set of impedance measuring elements foreach impedance loop may have their reach settingsprogressively increased from one zone reachsetting to another. The increase occurs after zonetime delays that are initiated by operation ofstarter elements. This type of relay is commonlyreferred to as a reach-stepped distance relay

d. each zone may be provided with independent setsof impedance measuring elements for eachimpedance loop. This is known as a full distancescheme, capable of offering the highestperformance in terms of speed and applicationflexibility

Furthermore, protection against earth faults may requiredifferent characteristics and/or settings to those requiredfor phase faults, resulting in additional units beingrequired. A total of 18 impedance-measuring elementsor algorithms would be required in a full distance relayfor three-zone protection for all types of fault.

With electromechanical technology, each of themeasuring elements would have been a separate relayhoused in its own case, so that the distance relaycomprised a panel-mounted assembly of the requiredrelays with suitable inter-unit wiring. Figure 11.17(a)shows an example of such a relay scheme.

Digital/numerical distance relays (Figure 11.17(b)) are likelyto have all of the above functions implemented insoftware. Starter units may not be necessary. Thecomplete distance relay is housed in a single unit, makingfor significant economies in space, wiring and increaseddependability, through the increased availability that stemsfrom the provision of continuous self-supervision. When

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the additional features detailed in Section 11.11 are takeninto consideration, such equipment offers substantial userbenefits.

11.8.1 Starters for switched distance protection

Electromechanical and static distance relays do notnormally use an individual impedance-measuring elementper phase. The cost and the resulting physical scheme sizemade this arrangement impractical, except for the mostdemanding EHV transmission applications. To achieve

economy for other applications, only one measuringelement was provided, together with ‘starter’ units thatdetected which phases were faulted, in order to switch theappropriate signals to the single measuring function. Adistance relay using this technique is known as a switcheddistance relay. A number of different types of starters havebeen used, the most common being based on overcurrent,undervoltage or under-impedance measurement.

Numerical distance relays permit direct detection of thephases involved in a fault. This is called faulted phaseselection, often abbreviated to phase selection. Severaltechniques are available for faulted phase selection,which then permits the appropriate distance-measuringzone to trip. Without phase selection, the relay riskshaving over or underreach problems, or tripping three-phase when single-pole fault clearance is required.Several techniques are available for faulted phaseselection, such as:

a. superimposed current comparisons, comparing thestep change of level between pre-fault load, andfault current (the ‘Delta’ algorithm). This enablesvery fast detection of the faulted phases, withinonly a few samples of the analogue current inputs

b. change in voltage magnitude

c. change in current magnitude

Numerical phase selection is much faster thantraditional starter techniques used in electromechanicalor static distance relays. It does not impose a timepenalty as the phase selection and measuring zonealgorithms run in parallel. It is possible to build a full-scheme relay with these numerical techniques. Thephase selection algorithm provides faulted phaseselection, together with a segregated measuringalgorithm for each phase-ground and phase to phasefault loop (AN, BN, CN, AB, BC, CA), thus ensuring full-scheme operation.

However, there may be occasions where a numericalrelay that mimics earlier switched distance protectiontechniques is desired. The reasons may be economic (lesssoftware required – thus cheaper than a relay thatcontains a full-scheme implementation) and/ortechnical.

Some applications may require the numerical relaycharacteristics to match those of earlier generationsalready installed on a network, to aid selectivity. Suchrelays are available, often with refinements such asmulti-sided polygonal impedance characteristics thatassist in avoiding tripping due to heavy load conditions.

With electromechanical or static switched distancerelays, a selection of available starters often had to bemade. The choice of starter was dependent on powersystem parameters such as maximum load transfer in

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Figure 11.17 (a): Electromechanical distance relay

Figure 11.17 (b): MiCOM P440 series numerical distance relay

Chapt11-170-191 20/06/02 15:41 Page 183

relation to maximum reach required and power systemearthing arrangements.

Where overcurrent starters are used, care must be takento ensure that, with minimum generating plant inservice, the setting of the overcurrent starters is sensitiveenough to detect faults beyond the third zone.Furthermore, these starters require a high drop-off topick-up ratio, to ensure that they will drop off undermaximum load conditions after a second or third zonefault has been cleared by the first zone relay in the faultysection. Without this feature, indiscriminate trippingmay result for subsequent faults in the second or thirdzone. For satisfactory operation of the overcurrentstarters in a switched distance scheme, the followingconditions must be fulfilled:

a. the current setting of the overcurrent starters mustbe not less than 1.2 times the maximum full loadcurrent of the protected line

b. the power system minimum fault current for afault at the Zone 3 reach of the distance relay mustnot be less than 1.5 times the setting of theovercurrent starters

On multiple-earthed systems where the neutrals of allthe power transformers are solidly earthed, or in powersystems where the fault current is less than the full loadcurrent of the protected line, it is not possible to useovercurrent starters. In these circumstances under-impedance starters are typically used.

The type of under-impedance starter used is mainlydependent on the maximum expected load current andequivalent minimum load impedance in relation to therequired relay setting to cover faults in Zone 3. This isillustrated in Figure 11.11 where ZD1, ZD2, and ZD3 arerespectively the minimum load impedances permittedwhen lenticular, offset mho and impedance relays are used.

11.9 EFFECT OF SOURCE IMPEDANCEAND EARTHING METHODS

For correct operation, distance relays must be capable ofmeasuring the distance to the fault accurately. To ensurethis, it is necessary to provide the correct measuredquantities to the measurement elements. It is not alwaysthe case that use of the voltage and current for aparticular phase will give the correct result, or thatadditional compensation is required.

11.9.1 Phase Fault Impedance Measurement

Figure 11.18 shows the current and voltage relations forthe different types of fault. If ZS1 and ZL1 are the sourceand line positive sequence impedances, viewed from therelaying point, the currents and voltages at this point for

double phase faults are dependent on the sourceimpedance as well as the line impedance. Therelationships are given in Figure 11.19.

Applying the difference of the phase voltages to the relayeliminates the dependence on ZS1. For example:

V a a Z I

V a a Z I

bc L

bc L

' '

' '

= −( ) ( )= −( )

( )

21 1

21 12

for 3 - phase faults

for double - phase faults

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(c) Double phase to earth (B-C-E)

B

C

F A

F

B

C

A

(d) Double-phase (B-C)

(a) Single-phase to earth (A-E)

Ic Vc

Vb

Va

Vc

Vb

Va

Vc

Vb

Va

Va=0Ic=0Ib=0

Va=Vb=Vc=0Ia+Ib+Ic=0

Vc=0Vb=0Ia=0

Ia=0Vb=VcIb=-Ic

Ib Ia

Ic Ib Ia

Ic Ib Ia

Vc

Vb

Va

Ic Ib Ia

F

C

B

A

(b) Three-phase (A-B-C or A-B-C-E)

B

C

F A

Figure 11.18: Current and voltagerelationships for some shunt faults

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Distance measuring elements are usually calibrated interms of the positive sequence impedance. Correctmeasurement for both phase-phase and three-phasefaults is achieved by supplying each phase-phasemeasuring element with its corresponding phase-phasevoltage and difference of phase currents. Thus, for theB-C element, the current measured will be:

and the relay will measure ZL1 in each case.

11.9.2 Earth Fault Impedance Measurement

When a phase-earth fault occurs, the phase-earthvoltage at the fault location is zero. It would appear thatthe voltage drop to the fault is simply the product of thephase current and line impedance. However, the currentin the fault loop depends on the number of earthingpoints, the method of earthing and sequence impedancesof the fault loop. Unless these factors are taken intoaccount, the impedance measurement will be incorrect.

The voltage drop to the fault is the sum of the sequencevoltage drops between the relaying point and the fault.The voltage drop to the fault and current in the faultloop are:

and the residual current I’N at the relaying point is givenby:

I I I I In a b c' ' ' ' '= + + = 3 0

V I Z I Z I Z

I I I I

a L L L

a

' ' ' '

' ' ' '

= + +

= + +1 1 2 1 0 0

1 2 0

I I a a I

I I a a I

b c

b c

' ' '

' ' '

− = −( ) ( )− = −( )

( )

21

212

3 - phase faults

double - phase faults

where I’a, I’b, I’c are the phase currents at the relayingpoint. From the above expressions, the voltage at therelaying point can be expressed in terms of:

1. the phase currents at the relaying point,

2. the ratio of the transmission line zero sequence topositive sequence impedance, K, (=ZL0/ZL1),

3. the transmission line positive sequence impedanceZL1:

…Equation 11.5

The voltage appearing at the relaying point, as previouslymentioned, varies with the number of infeeds, themethod of system earthing and the position of the relayrelative to the infeed and earthing points in the system.Figure 11.20 illustrates the three possible arrangementsthat can occur in practice with a single infeed. In Figure11.20(a), the healthy phase currents are zero, so that the

V Z I I I I Ka L a a b c' ' ' ' '= + + +( ) −

11

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Faultquantity

Three-phase Double-phase(B-C)(A-B-C)

I'a I'1 0

(a2-a)I'1

(a-a2)I'1

2(ZS1+ZL1)I'1

(2a2ZL1-ZS1)I'1

(2aZL1-ZS1)I'1

a2I'1

aI'1

ZL1I'1

a2ZL1I'1

aZL1I'1

I'b

I'c

V'a

V'b

V'c

Note: I'1 = 13

(I'a+aI'b+a2I'c)

I' and V' are at relay location

Figure 11.19: Phase currents and voltagesat relaying point for 3-phase and

double-phase faults

C

B

A F 2

1

1

Relayingpoint

1

1

1 C

B

SupplyA

(b) System earthed at one point only in front of the relaying point

C

B

A1

1

1 F

1

1

Relayingpoint

2Supply

C

B

A

(c) As for (b) but with relaying point at receiving end

A

B

C

0

0

1

Relayingpoint

F

C

A

B

Supply

(a) System earthed at one point only behind the relaying point

Z= 1+ ZL1ZL0

ZL1

(K-1)3

where K=

Z= ZL1

Z=KZL1

Figure 11.20: Effect of infeed and earthingarrangements on earth fault distance

measurement

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phase currents Ia, Ib and Ic have a 1-0-0 pattern. Theimpedance seen by a relay comparing Ia and Va is:

…Equation 11.6

In Figure 11.20(b), the currents entering the fault fromthe relay branch have a 2-1-1 distribution, so:

Z=ZL1

In Figure 11.20(c), the phase currents have a 1-1-1distribution, and hence:

Z=KZL1

If there were infeeds at both ends of the line, theimpedance measured would be a superposition of anytwo of the above examples, with the relative magnitudesof the infeeds taken into account.

This analysis shows that the relay can only measure animpedance which is independent of infeed and earthing

arrangements if a proportion of the

residual current In=Ia+Ib+Ic is added to the phasecurrent Ia. This technique is known as ‘residualcompensation’.

Most distance relays compensate for the earth faultconditions by using an additional replica impedance ZN

within the measuring circuits. Whereas the phase replicaimpedance Z1 is fed with the phase current at therelaying point, ZN is fed with the full residual current.The value of ZN is adjusted so that for a fault at thereach point, the sum of the voltages developed across Z1

and ZN equals the measured phase to neutral voltage inthe faulted phase.

The required setting for ZN can be determined byconsidering an earth fault at the reach point of the relay.This is illustrated with reference to the A-N fault withsingle earthing point behind the relay as in Figure11.20(a).

Voltage supplied from the VT’s:

= I1(Z1+Z2+Z0) = I1(2Z1+Z0)

Voltage across the replica impedances:

= IaZ1+INZN

= Ia(Z1+ZN)

= 3I1(Z1+ZN)

Hence, the required setting of ZN for balance at thereach point is given by equating the above twoexpressions:

KK

N =−( )1

3

ZK

ZL= +−( )

1

1

3 1

…Equation 11.7

With the replica impedance set to , earth

fault measuring elements will measure the faultimpedance correctly, irrespective of the number ofinfeeds and earthing points on the system.

11.10 DISTANCE RELAY APPLICATION PROBLEMS

Distance relays may suffer from a number of difficultiesin their application. Many of them have been overcomein the latest numerical relays. Nevertheless, anawareness of the problems is useful where a protectionengineer has to deal with older relays that are alreadyinstalled and not due for replacement.

11.10.1 Minimum Voltage at Relay Terminals

To attain their claimed accuracy, distance relays that donot employ voltage memory techniques require aminimum voltage at the relay terminals under faultconditions. This voltage should be declared in the datasheet for the relay. With knowledge of the sequenceimpedances involved in the fault, or alternatively thefault MVA, the system voltage and the earthingarrangements, it is possible to calculate the minimumvoltage at the relay terminals for a fault at the reachpoint of the relay. It is then only necessary to check thatthe minimum voltage for accurate reach measurementcan be attained for a given application. Care should betaken that both phase and earth faults are considered.

11.10.2 Minimum Length of Line

To determine the minimum length of line that can beprotected by a distance relay, it is necessary to check firstthat any minimum voltage requirement of the relay for afault at the Zone 1 reach is within the declaredsensitivity for the relay. Secondly, the ohmic impedanceof the line (referred if necessary to VT/CT secondary sidequantities) must fall within the ohmic setting range forZone 1 reach of the relay. For very short lines andespecially for cable circuits, it may be found that thecircuit impedance is less than the minimum settingrange of the relay. In such cases, an alternative methodof protection will be required.

A suitable alternative might be current differential

Z Z0 1

3−

3 2

3

3

1 1 1 1

0 1

0 1

11

I Z Z I Z Z

ZZ Z

Z Z

ZZ

N N

N

+( ) = +( )

= −

=−( )

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protection, as the line length will probably be shortenough for the cost-effective provision of a highbandwidth communication link between the relays fittedat the ends of the protected circuit. However, the latestnumerical distance relays have a very wide range ofimpedance setting ranges and good sensitivity with lowlevels of relaying voltage, so such problems are nowrarely encountered. Application checks are still essential,though. When considering earth faults, particular caremust be taken to ensure that the appropriate earth faultloop impedance is used in the calculation.

11.10.3 Under-Reach - Effect of Remote Infeed

A distance relay is said to under-reach when theimpedance presented to it is apparently greater than theimpedance to the fault.

Percentage under-reach is defined as:

where:

ZR = intended relay reach (relay reachsetting)

ZF = effective reach

The main cause of underreaching is the effect of faultcurrent infeed at remote busbars. This is best illustratedby an example.

In Figure 11.21, the relay at A will not measure thecorrect impedance for a fault on line section ZC due tocurrent infeed IB. Consider a relay setting of ZA+ZC.

For a fault at point F, the relay is presented with animpedance:

Z ZZ

R F

R

− ×100%

So, for relay balance:

Therefore the effective reach is

...Equation 11.8

It is clear from Equation 11.8 that the relay willunderreach. It is relatively easy to compensate for thisby increasing the reach setting of the relay, but care hasto be taken. Should there be a possibility of the remoteinfeed being reduced or zero, the relay will then reachfurther than intended. For example, setting Zone 2 toreach a specific distance into an adjacent line sectionunder parallel circuit conditions may mean that Zone 2reaches beyond the Zone 1 reach of the adjacent lineprotection under single circuit operation. If IB=9IA andthe relay reach is set to see faults at F, then in theabsence of the remote infeed, the relay effective settingbecomes ZA+10ZC.

Care should also be taken that large forward reachsettings will not result in operation of healthy phaserelays for reverse earth faults, see Section 11.10.5.

11.10.4 Over-Reach

A distance relay is said to over-reach when the apparentimpedance presented to it is less than the impedance tothe fault.

Percentage over-reach is defined by the equation:

...Equation 11.9where:

ZR = relay reach setting

ZF = effective reach

An example of the over-reaching effect is when distancerelays are applied on parallel lines and one line is takenout of service and earthed at each end. This is coveredin Section 13.2.3.

11.10.5 Forward Reach Limitations

There are limitations on the maximum forward reachsetting that can be applied to a distance relay. Forexample, with reference to Figure 11.6, Zone 2 of one linesection should not reach beyond the Zone 1 coverage of

Z ZZ

F R

R

− ×100%

ZI

I IZA

A

A BC+

+

Z Z ZI I

Ix ZA C A

A B

AC+ = +

+( )× ×

ZI I

Ix ZA

A B

AC+ + × ×

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<Z

F

SourcexZC

ZC

ZA

IA

IA+IB

IB

Relaying pointRelay setting: ZA+ZC

Relay actual reach due to parallel line infeed: ZA+xZC

A

Figure 11.21: Effect on distance relaysof infeed at the remote busbar

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the next line section relay. Where there is a link betweenthe forward reach setting and the relay resistivecoverage (e.g. a Mho Zone 3 element), a relay must notoperate under maximum load conditions. Also, if therelay reach is excessive, the healthy phase-earth faultunits of some relay designs may be prone to operationfor heavy reverse faults. This problem only affected olderrelays applied to three-terminal lines that havesignificant line section length asymmetry. A number ofthe features offered with modern relays can eliminatethis problem.

11.10.6 Power Swing Blocking

Power swings are variations in power flow that occurwhen the internal voltages of generators at differentpoints of the power system slip relative to each other. Thechanges in load flows that occur as a result of faults andtheir subsequent clearance are one cause of power swings.

A power swing may cause the impedance presented to adistance relay to move away from the normal load areaand into the relay characteristic. In the case of a stablepower swing it is especially important that the distancerelay should not trip in order to allow the power systemto return to a stable conditions. For this reason, mostdistance protection schemes applied to transmissionsystems have a power swing blocking facility available.Different relays may use different principles for detectionof a power swing, but all involve recognising that themovement of the measured impedance in relation to therelay measurement characteristics is at a rate that issignificantly less than the rate of change that occursduring fault conditions. When the relay detects such acondition, operation of the relay elements can beblocked. Power swing blocking may be appliedindividually to each of the relay zones, or on an all zonesapplied/inhibited basis, depending on the particular relayused.

Various techniques are used in different relay designs toinhibit power swing blocking in the event of a faultoccurring while a power swing is in progress. This isparticularly important, for example, to allow the relay torespond to a fault that develops on a line during the deadtime of a single pole autoreclose cycle.

Some Utilities may designate certain points on thenetwork as split points, where the network should besplit in the event of an unstable power swing or pole-slipping occurring. A dedicated power swing trippingrelay may be employed for this purpose (see Section11.7.8). Alternatively, it may be possible to achievesplitting by strategically limiting the duration for whichthe operation a specific distance relay is blocked duringpower swing conditions.

11.10.7 Voltage Transformer Supervision

Fuses or sensitive miniature circuit breakers normallyprotect the secondary wiring between the voltagetransformer secondary windings and the relay terminals.

Distance relays having:

a. self-polarised offset characteristics encompassingthe zero impedance point of the R/X diagram

b. sound phase polarisation

c. voltage memory polarisation

may maloperate if one or more voltage inputs areremoved due to operation of these devices.

For these types of distance relay, supervision of the voltageinputs is recommended. The supervision may be provided byexternal means, e.g. separate voltage supervision circuits, orit may be incorporated into the distance relay itself. Ondetection of VT failure, tripping of the distance relay can beinhibited and/or an alarm is given. Modern distanceprotection relays employ voltage supervision that operatesfrom sequence voltages and currents. Zero or negativesequence voltages and corresponding zero or negativesequence currents are derived. Discrimination betweenprimary power system faults and wiring faults or loss ofsupply due to individual fuses blowing or MCB’s beingopened is obtained by blocking the distance protection onlywhen zero or negative sequence voltage is detected withoutthe presence of zero or negative sequence current. Thisarrangement will not detect the simultaneous loss of allthree voltages and additional detection is required thatoperates for loss of voltage with no change in current, or acurrent less than that corresponding to the three phasefault current under minimum fault infeed conditions. Iffast-acting miniature circuit breakers are used to protectthe VT secondary circuits, contacts from these may be usedto inhibit operation of the distance protection elements andprevent tripping.

11.11 OTHER DISTANCE RELAY FEATURES

A modern digital or numerical distance relay will oftenincorporate additional features that assist the protectionengineer in providing a comprehensive solution to theprotection requirements of a particular part of a network.

Table 11.1 provides an indication of the additional featuresthat may be provided in such a relay. The combination offeatures that are actually provided is manufacturer andrelay model dependent, but it can be seen from the Tablethat steady progression is being made towards a ‘one-box’solution that incorporates all the protection and controlrequirements for a line or cable. However, at the highesttransmission voltages, the level of dependability requiredfor rapid clearance of any protected circuit fault will stilldemand the use of two independent protection systems.

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11.12 DISTANCE RELAY APPLICATION EXAMPLE

The system diagram shown in Figure 11.22 shows asimple 230kV network. The following example shows thecalculations necessary to apply three-zone distanceprotection to the line interconnecting substations ABCand XYZ. All relevant data for this exercise are given inthe diagram. The MiCOM P441 relay with quadrilateralcharacteristics is considered in this example. Relayparameters used in the example are listed in Table 11.2.

Calculations are carried out in terms of primary systemimpedances in ohms, rather than the traditional practiceof using secondary impedances. With numerical relays,where the CT and VT ratios may be entered asparameters, the scaling between primary and secondaryohms can be performed by the relay. This simplifies theexample by allowing calculations to be carried out in

primary quantities and eliminates considerations ofVT/CT ratios.

For simplicity, it is assumed that only a conventional 3-zone distance protection is to be set and that there is noteleprotection scheme to be considered. In practice, ateleprotection scheme would normally be applied to aline at this voltage level.

11.12.1 Line Impedance

The line impedance is:

ZL = (0.089 + j0.476) x 100

= 8.9 + j47.6Ω

= 48.42 ∠79.410Ω

Use values of 48.42Ω (magnitude) and 800 (angle) asnearest settable values.

11.12.2 Residual Compensation

The relays used are calibrated in terms of the positivesequence impedance of the protected line. Since thezero sequence impedance of the line betweensubstations ABC and XYZ is different from the positivesequence impedance, the impedance seen by the relay inthe case of an earth fault, involving the passage of zerosequence current, will be different to that seen for aphase fault.

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ABC

230kV

PQR

230kV

XYZ

230kV230kV/110V

1000/1A 60km

Z<

Source Impedance: 5000MVA max

= Ω/km+ Ω/km

Figure 11.22: Example network for distancerelay setting calculation

Table 11.2: Distance relay parameters for example

Relay Parameter Parameter Unitsparameter description value

ZL1 (mag) Line positive sequence impedance (magnitude) 48.42 ΩZL1 (ang) Line positive sequence impedance (phase angle) 79.41 deg

ZLO (mag) Line zero sequence impedance (magnitude) 163.26 ΩZLO (ang) Line zero sequence impedance (phase angle) 74.87 deg

KZO (mag) Default residual compensation factor (magnitude) 0.79 -

KZO (ang) Default residual compensation factor (phase angle) -6.5 deg

Z1 (mag) Zone 1 reach impedance setting (magnitude) 38.74 ΩZ1 (ang) Zone 1 reach impedance setting (phase angle) 80 deg



R1ph Phase fault resistive reach value - Zone 1 78 ΩR2ph Phase fault resistive reach value - Zone 2 78 ΩR3ph Phase fault resistive reach value - Zone 3 78 ΩTZ1 Time delay - Zone 1 0 s

TZ2 Time delay - Zone 2 0.35 s


R1G Ground fault resistive reach value - Zone 1 104 ΩR2G Ground fault resistive reach value - Zone 2 104 ΩR3G Ground fault resistive reach value - Zone 3 104 Ω

Fault Location (Distance to fault)

Instantaneous Overcurrent Protection

Tee’d feeder protection

Alternative setting groups

CT supervision

Check synchroniser

Auto-reclose

CB state monitoring

CB condition monitoring

CB control

Measurement of voltages, currents, etc.

Event Recorder

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: Additional features in a distance relay

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Hence, the earth fault reach of the relay requires zerosequence compensation (see Section 11.9.2).

For the relay used, this adjustment is provided by theresidual (or neutral) compensation factor KZ0, set equalto:

For each of the transmission lines:

Hence,

11.12.3 Zone 1 Phase Reach

The required Zone 1 reach is 80% of the line impedance.Therefore,

Use 38.74∠80°Ω nearest settable value.


Ideally, the requirements for setting Zone 2 reach are:

1. at least 120% of the protected line

2. less than the protected line + 50% of the next line

Sometimes, the two requirements are in conflict. In thiscase, both requirements can be met. A setting of thewhole of the line between substations ABC and XYZ,plus 50% of the adjacent line section to substation PQRis used. Hence, Zone 2 reach:

Use 62.95∠80 0 Ω nearest available setting.

=∠ +

× × +

= ∠

48 42 79 41

0 5 60 0 089 0 476

62 95 79 41

. .

. . .

. .

o

o

jΩ

Ω

0 8 48 42 79 41 38 74 79 41. . . . .× ∠( ) = ∠ o o Ω

K

K

Z

Zo

0

0

0 792

6 5

=

∠ = −

.

.

Z j

Z j

Lo

Lo

1

0

0 089 0 476 0 484 7

0 426 1 576 1 632 74 87

= + ∠( )= + ∠( )

. . .

. . . .

Ω Ω

Ω Ω

9.41

KZ Z

Z

KZ Z

Z

Z

Z

00 1

1

00 1

1

3

3

=−( )

∠ = ∠−( )


Zone 3 is set to cover 120% of the sum of the linesbetween substations ABC and PQR, provided this doesnot result in any transformers at substation XYZ beingincluded. It is assumed that this constraint is met.Hence, Zone 3 reach:

Use a setting of 83.27∠80 0Ω, nearest available setting.

11.12.6 Zone Time Delay Settings

Proper co-ordination of the distance relay settings withthose of other relays is required. Independent timers areavailable for the three zones to ensure this.

For Zone 1, instantaneous tripping is normal. A timedelay is used only in cases where large d.c. offsets occurand old circuit breakers, incapable of breaking theinstantaneous d.c. component, are involved.

The Zone 2 element has to grade with the relaysprotecting the line between substations XYZ and PQRsince the Zone 2 element covers part of these lines.Assuming that this line has distance, unit orinstantaneous high-set overcurrent protection applied,the time delay required is that to cover the totalclearance time of the downstream relays. To this mustbe added the reset time for the Zone 2 element followingclearance of a fault on the adjacent line, and a suitablesafety margin. A typical time delay is 350ms, and thenormal range is 200-500ms.

The considerations for the Zone 3 element are the sameas for the Zone 2 element, except that the downstreamfault clearance time is that for the Zone 2 element of adistance relay or IDMT overcurrent protection. Assumingdistance relays are used, a typical time is 800ms. Insummary:

TZ1 = 0ms (instantaneous)

TZ2 = 250ms

TZ3 = 800ms

11.12.7 Phase Fault Resistive Reach Settings

With the use of a quadrilateral characteristic, theresistive reach settings for each zone can be setindependently of the impedance reach settings. Theresistive reach setting represents the maximum amountof additional fault resistance (in excess of the lineimpedance) for which a zone will trip, regardless of thefault within the zone.

=∠ +

× × ∠

= ∠

48 42 79 41

1 2 60 0 484 79 41

83 27 79 41

. .

. . .

. .

o

o

o

Ω

Ω

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Two constraints are imposed upon the settings, asfollows:

i. it must be greater than the maximum expectedphase-phase fault resistance (principally that of thefault arc)

ii. it must be less than the apparent resistancemeasured due to the heaviest load on the line

The minimum fault current at Substation ABC is of theorder of 1.8kA, leading to a typical arc resistance Rarcusing the van Warrington formula (Equation 11.4) of 8Ω.Using the current transformer ratio as a guide to themaximum expected load current, the minimum loadimpedance Zlmin will be 130Ω. Typically, the resistivereaches will be set to avoid the minimum loadimpedance by a 40% margin for the phase elements,leading to a maximum resistive reach setting of 78Ω.

Therefore, the resistive reach setting lies between 8Ωand 78Ω. Allowance should be made for the effects ofany remote fault infeed, by using the maximum resistivereach possible. While each zone can have its ownresistive reach setting, for this simple example they canall be set equal. This need not always be the case, itdepends on the particular distance protection schemeused and the need to include Power Swing Blocking.

Suitable settings are chosen to be 80% of the loadresistance:

R3ph = 78Ω

R2ph = 78Ω

R1ph = 78Ω

11.12.8 Earth Fault Impedance Reach Settings

By default, the residual compensation factor ascalculated in Section 11.12.2 is used to adjust the phasefault reach setting in the case of earth faults, and isapplied to all zones.

11.12.9 Earth Fault Resistive Reach Settings

The margin for avoiding the minimum load impedanceneed only be 20%. Hence the settings are:

R3G = 104Ω

R2G = 104Ω

R1G = 104Ω

This completes the setting of the relay. Table 11.2 alsoshows the settings calculated.

11.13 REFERENCES

11.1 Protective Relays – their Theory and Practice.A.R. van C. Warrington. Chapman and Hall,1962.

Chapt11-170-191 20/06/02 15:43 Page 191

Introduction 12.1

Zone 1 extension scheme 12.2

Transfer trip schemes 12.3

Blocking scheme 12.4

Directional comparison unblocking scheme 12.5

Comparison of transfer tripand blocking relaying schemes 12.6

• 1 2 • D i s t a n c e P r o t e c t i o nS c h e m e s

Chap12 exe 14/06/02 13:15 Page 192


12.1 INTRODUCTION

Conventional time-stepped distance protection isillustrated in Figure 12.1. One of the main disadvantagesof this scheme is that the instantaneous Zone 1protection at each end of the protected line cannot beset to cover the whole of the feeder length and is usuallyset to about 80%. This leaves two 'end zones', eachbeing about 20% of the protected feeder length. Faultsin these zones are cleared in Zone 1 time by theprotection at one end of the feeder and in Zone 2 time(typically 0.25 to 0.4 seconds) by the protection at theother end of the feeder.

This situation cannot be tolerated in some applications,for two main reasons:

a. faults remaining on the feeder for Zone 2 time maycause the system to become unstable

b. where high-speed auto-reclosing is used, the non-simultaneous opening of the circuit breakers atboth ends of the faulted section results in no 'deadtime' during the auto-reclose cycle for the fault tobe extinguished and for ionised gases to clear. Thisresults in the possibility that a transient fault willcause permanent lockout of the circuit breakers ateach end of the line section

• 12 • Distance P rotect ionSchemes

Figure 12.1: Conventional distance scheme

Relay Aend zone

yend zone

Relay Bend zone

yend zone

Z3B

Z2T

Z3 0

0

Z3

Z2

Z1

B

Z1B

Z2A

Z3G

Z1A

Tim

e

(a) Stepped time/distance characteristics

Trip

(b) Trip circuit (solid state logic)

0F B CA

≥1

Chap12 exe 14/06/02 13:15 Page 193


Even where instability does not occur, the increasedduration of the disturbance may give rise to powerquality problems, and may result in increased plantdamage.

Unit schemes of protection that compare the conditions atthe two ends of the feeder simultaneously positivelyidentify whether the fault is internal or external to theprotected section and provide high-speed protection forthe whole feeder length. This advantage is balanced by thefact that the unit scheme does not provide the back upprotection for adjacent feeders given by a distance scheme.

The most desirable scheme is obviously a combination ofthe best features of both arrangements, that is,instantaneous tripping over the whole feeder length plusback-up protection to adjacent feeders. This can beachieved by interconnecting the distance protectionrelays at each end of the protected feeder by acommunications channel. Communication techniquesare described in detail in Chapter 8.

The purpose of the communications channel is totransmit information about the system conditions fromone end of the protected line to the other, includingrequests to initiate or prevent tripping of the remotecircuit breaker. The former arrangement is generallyknown as a 'transfer tripping scheme' while the latter isgenerally known as a 'blocking scheme'. However, theterminology of the various schemes varies widely,according to local custom and practice.

12.2 ZONE 1 EXTENSION SCHEME (Z1X SCHEME)

This scheme is intended for use with an auto-reclosefacility, or where no communications channel isavailable, or the channel has failed. Thus it may be usedon radial distribution feeders, or on interconnected linesas a fallback when no communications channel isavailable, 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 twosettings. One is set to cover 80% of the protected linelength as in the basic distance scheme. The other, knownas 'Extended Zone 1'or ‘Z1X’, is set to overreach theprotected line, a setting of 120% of the protected linebeing common. The Zone 1 reach is normally controlledby the Z1X setting and is reset to the basic Zone 1 settingwhen a command from the auto-reclose relay is received.

On occurrence of a fault at any point within the Z1Xreach, the relay operates in Zone 1 time, trips the circuitbreaker and initiates auto-reclosure. The Zone 1 reach ofthe distance relay is also reset to the basic value of 80%,prior to the auto-reclose closing pulse being applied tothe breaker. This should also occur when the auto-reclose facility is out of service. Reversion to the Z1Xreach setting occurs only at the end of the reclaim time.For interconnected lines, the Z1X scheme is established(automatically or manually) upon loss of thecommunications channel by selection of the appropriaterelay setting (setting group in a numerical relay). If thefault is transient, the tripped circuit breakers will reclosesuccessfully, but otherwise further tripping during thereclaim time is subject to the discrimination obtainedwith normal Zone 1 and Zone 2 settings.

The disadvantage of the Zone 1 extension scheme is thatexternal faults within the Z1X reach of the relay result intripping of circuit breakers external to the faultedsection, increasing the amount of breaker maintenanceneeded and needless transient loss of supply to someconsumers. This is illustrated in Figure 12.3(a) for asingle circuit line where three circuit breakers operateand in Figure 12.3(b) for a double circuit line, where fivecircuit breakers operate.

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Figure 12.2: Zone 1 extension scheme

Z1A

Z1B

Z3B

Z2B

Z3T

Z2T O

O

CBA

Z1extA

Z1extB

Z2A

Z3A

(a) Distance/time characteristics

Trip

(b) Simplified logic

Zone 1ext

Zone 1

Zone 2

Zone 3

Auto-recloseReset Zone 1ext

≥1

≥1

&

Chap12 exe 14/06/02 13:15 Page 194


12.3 TRANSFER TRIPPING SCHEMES

A number of these schemes are available, as describedbelow. Selection of an appropriate scheme depends onthe requirements of the system being protected.

12.3.1 Direct Under-reach Transfer Tripping Scheme

The simplest way of reducing the fault clearance time atthe terminal that clears an end zone fault in Zone 2 timeis to adopt a direct transfer trip or intertrip technique, thelogic of which is shown in Figure 12.4.

A contact operated by the Zone 1 relay element isarranged to send a signal to the remote relay requesting atrip. The scheme may be called a 'direct under-reachtransfer tripping scheme’, ‘transfer trip under-reachingscheme', or ‘intertripping under-reach distance protectionscheme’, as the Zone 1 relay elements do not cover thewhole of the line.

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 ofthe circuit breaker at end B. A request to trip is also sentto the relay at end A. The receipt of a signal at Ainitiates tripping immediately because the receive relaycontact is connected directly to the trip relay. Thedisadvantage of this scheme is the possibility ofundesired tripping by accidental operation ormaloperation of signalling equipment, or interference onthe communications channel. As a result, it is notcommonly used.

12.3.2 Permissive Under-reach Transfer Tripping(PUP) Scheme

The direct under-reach transfer tripping scheme describedabove is made more secure by supervising the receivedsignal with the operation of the Zone 2 relay element beforeallowing an instantaneous trip, as shown in Figure 12.5. Thescheme is then known as a 'permissive under-reach transfertripping scheme' (sometimes abbreviated as PUP Z2scheme) or ‘permissive under-reach distance protection’, asboth relays must detect a fault before the remote end relayis permitted to trip in Zone 1 time.

• 12 •D

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Figure 12.4: Logic for direct under-reachtransfer tripping scheme

Z1

Z2

Trip

Signal receive

Z3

Signal send

Z2T

Z3T O

O

≥1

Figure 12.3: Performance of Zone 1 extensionscheme in conjunction with auto-reclose relays

(a) Fault within Zone 1 extension reach of distance relays(single circuit lines)

Z1extA

Z1extC Z1C

Z1extB2Z1extB1 Z1B2Z1B1

Z1A

Z1extA

Z1extD

Z1extP

Z1extN

Z1extMZ1extL

Z1extC

Z1D

Z1C

Z1extB Z1B

Z1P

Z1N

Z1MZ1L

Z1A

A

AB C

N M

D

P L

B C

Breakersmarked thusauto-reclose

(b) Fault within Zone 1 extension reach of distance relays(double circuit lines)

Figure 12.5: Permissive under-reachtransfer tripping scheme

Z1

Z2

Trip

Signal receive

Z3

Signal send

Z2T 0

Z3T 0

0 T

≥1

Signalsend

Signalreceive

Signalsend

Signalreceive

Sendcircuit

(f1)

Receivecircuit

(f1)

Sendcircuit

(f1)

Receivecircuit

(f1)Signalling equipment

-End ASignalling equipment

-End B

(b) Signalling arrangement

Dist

ance

rela

y

Dist

ance

rela

y

(a) Signal logic

&

Chap12 exe 14/06/02 13:15 Page 195


A variant of this scheme, found on some relays, allowstripping by Zone 3 element operation as well as Zone 2,provided the fault is in the forward direction. This issometimes called the PUP-Fwd scheme.

Time delayed resetting of the 'signal received' element isrequired to ensure that the relays at both ends of asingle-end fed faulted line of a parallel feeder circuithave time to trip when the fault is close to one end.Consider a fault F in a double circuit line, as shown inFigure 12.6. The fault is close to end A, so there isnegligible infeed from end B when the fault at F occurs.The protection at B detects a Zone 2 fault only after thebreaker at end A has tripped. It is possible for the Zone 1element at A to reset, thus removing the permissivesignal to B and causing the 'signal received' element atB to reset before the Zone 2 unit at end B operates. It istherefore necessary to delay the resetting of the 'signalreceived' element to ensure high speed tripping at end B.

The PUP schemes require only a single communicationschannel for two-way signalling between the line ends, as thechannel is keyed by the under-reaching Zone 1 elements.

When the circuit breaker at one end is open, or there isa weak infeed such that the relevant relay element doesnot operate, instantaneous clearance cannot be achievedfor end-zone faults near the 'breaker open' terminalunless special features are included, as detailed insection 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 bothZone 1 and Zone 2. In these relays, the reach of themeasuring elements is extended from Zone 1 to Zone 2by means of a range change signal immediately, insteadof after Zone 2 time. It is also called an ‘acceleratedunderreach distance protection scheme’.

The under-reaching Zone 1 unit is arranged to send asignal to the remote end of the feeder in addition totripping the local circuit breaker. The receive relaycontact is arranged to extend the reach of the measuringelement from Zone 1 to Zone 2. This accelerates thefault clearance at the remote end for faults that lie in theregion between the Zone 1 and Zone 2 reaches. Thescheme is shown in Figure 12.7. Modern distance relaysdo not employ switched measuring elements, so thescheme is likely to fall into disuse.

12.3.4 Permissive Over-Reach Transfer Tripping(POP) Scheme

In this scheme, a distance relay element set to reachbeyond the remote end of the protected line is used tosend an intertripping signal to the remote end. However,it is essential that the receive relay contact is monitoredby a directional relay contact to ensure that trippingdoes not take place unless the fault is within theprotected section; see Figure 12.8. The instantaneouscontacts of the Zone 2 unit are arranged to send thesignal, and the received signal, supervised by Zone 2operation, is used to energise the trip circuit. Thescheme is then known as a 'permissive over-reachtransfer tripping scheme' (sometimes abbreviated to‘POP’), 'directional comparison scheme', or ‘permissiveoverreach distance protection scheme’.

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Figure 12.6: PUP scheme: Single-end fedclose-up fault on double circuit line

BF

A

Open

(b) End A relay clears fault and current starts feeding from end B

(a) Fault occurs-bus bar voltage low so negligible fault current via end B

AF

B

Figure 12.7: Permissive under-reachingacceleration scheme


Z2AZ1A

Z1BZ2B

Z3B

Z3T O

OZ2T

Z1

Z3

Z2

Z3A

A B C

Trip

Signal receive

Range change signal

Signal send

≥1

≥1

(b) Signal logic

&

&

Chap12 exe 14/06/02 13:15 Page 196


Since the signalling channel is keyed by over-reaching Zone2 elements, the scheme requires duplex communicationchannels - one frequency for each direction of signalling.

If distance relays with mho characteristics are used, thescheme may be more advantageous than the permissiveunder-reaching scheme for protecting short lines,because the resistive coverage of the Zone 2 unit may begreater than that of Zone 1.

To prevent operation under current reversal conditions ina parallel feeder circuit, it is necessary to use a currentreversal guard timer to inhibit the tripping of the forwardZone 2 elements. Otherwise maloperation of the schememay occur under current reversal conditions, see Section11.9.9 for more details. It is necessary only when theZone 2 reach is set greater than 150% of the protectedline impedance.

The timer is used to block the permissive trip and signalsend circuits as shown in Figure 12.9. The timer isenergised if a signal is received and there is no operationof Zone 2 elements. An adjustable time delay on pick-up(tp) is usually set to allow instantaneous tripping to takeplace for any internal faults, taking into account apossible slower operation of Zone 2. The timer will haveoperated and blocked the ‘permissive trip’ and ‘signalsend’ circuits by the time the current reversal takes place.

The timer is de-energised if the Zone 2 elements operateor the 'signal received' element resets. The reset timedelay (td) of the timer is set to cover any overlap in timecaused by Zone 2 elements operating and the signalresetting at the remote end, when the current in thehealthy feeder reverses. Using a timer in this mannermeans that no extra time delay is added in thepermissive trip circuit for an internal fault.

The above scheme using Zone 2 relay elements is oftenreferred to as a POP Z2 scheme. An alternative existsthat uses Zone 1 elements instead of Zone 2, and this isreferred to as the POP Z1 scheme.

12.3.5 Weak Infeed Conditions

In the standard permissive over-reach scheme, as withthe permissive under-reach scheme, instantaneousclearance cannot be achieved for end-zone faults underweak infeed or breaker open conditions. To overcomethis disadvantage, two possibilities exist.

The Weak Infeed Echo feature available in someprotection relays allows the remote relay to echo the tripsignal back to the sending relay even if the appropriateremote relay element has not operated. This caters forconditions of the remote end having a weak infeed orcircuit breaker open condition, so that the relevantremote relay element does not operate. Fast clearancefor these faults is now obtained at both ends of the line.The logic is shown in Figure 12.10. A time delay (T1) isrequired in the echo circuit to prevent tripping of theremote end breaker when the local breaker is tripped bythe busbar protection or breaker fail protectionassociated with other feeders connected to the busbar.The time delay ensures that the remote end Zone 2element will reset by the time the echoed signal isreceived at that end.

• 12 •D

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Figure 12.10: Weak Infeed Echo logic circuit

Signalsend

Signalreceive

Breaker'open'

To 'POP' trip logic(Figure 12.8)

From 'POP' signalsend logic(Figure 12.8)

0T1 T2 0 ≥1& &

Figure 12.8: Permissive over-reach transfer tripping scheme

Signal receive

Z1

Z2T O

OZ3TZ3

Z2

Trip

Signal send

≥1

Signalsend

Signalreceive

Signalsend

Signalreceive

Sendcircuit

(f1)

Receivecircuit

(f2)

Sendcircuit

(f2)

f2f1

f2 f1

Receivecircuit

(f1)

Signalling equipment-End A

Signalling equipment-End B

(b) Signalling arrangement

Dist

ance

rela

y

Dist

ance

rela

y

(a) Signal logic

&

Figure 12.9: Current reversal guard logic – permissive over-reach scheme

Signal receive

Z3

Z2Trip

Signal send

Z1

Z2T O

OZ3T

tp td

≥1

&&

&

Chap12 exe 14/06/02 13:15 Page 197


Signal transmission can take place even after the remoteend breaker has tripped. This gives rise to the possibilityof continuous signal transmission due to lock-up of bothsignals. Timer T2 is used to prevent this. After this timedelay, 'signal send' is blocked.

A variation on the Weak Infeed Echo feature is to allowtripping of the remote relay under the circumstancesdescribed above, providing that an undervoltagecondition exists, due to the fault. This is known as theWeak Infeed Trip feature and ensures that both ends aretripped if the conditions are satisfied.

12.4 BLOCKING OVER-REACHING SCHEMES

The arrangements described so far have used the signallingchannel(s) to transmit a tripping instruction. If thesignalling channel fails or there is no Weak Infeed featureprovided, end-zone faults may take longer to be cleared.

Blocking over-reaching schemes use an over-reachingdistance scheme and inverse logic. Signalling is initiatedonly for external faults and signalling transmission takesplace over healthy line sections. Fast fault clearanceoccurs when no signal is received and the over-reachingZone 2 distance measuring elements looking into the lineoperate. The signalling channel is keyed by reverse-looking distance elements (Z3 in the diagram, thoughwhich zone is used depends on the particular relay used).An ideal blocking scheme is shown in Figure 12.11.

The single frequency signalling channel operates bothlocal and remote receive relays when a block signal isinitiated 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 trippingof the remote relay for Zone 2 faults external to theprotected section. To achieve this, the reverse-lookingelements and the signalling channel must operate fasterthan the forward-looking elements. In practice, this isseldom the case and to ensure discrimination, a shorttime delay is generally introduced into the blockingmode trip circuit. Either the Zone 2 or Zone 1 elementcan be used as the forward-looking element, giving riseto two variants of the scheme.

12.4.1.1 Blocking over-reaching protection scheme usingZone 2 element

This scheme (sometimes abbreviated to BOP Z2) is basedon the ideal blocking scheme of Figure 12.11, but has thesignal logic illustrated in Figure 12.12. It is also knownas a ‘directional comparison blocking scheme’ or a‘blocking over-reach distance protection scheme’.

Operation of the scheme can be understood byconsidering the faults shown at F1, F2 and F3 in Figure12.11 along with the signal logic of Figure 12.12.

A fault at F1 is seen by the Zone 1 relay elements atboth ends A and B; as a result, the fault is clearedinstantaneously at both ends of the protected line.Signalling is controlled by the Z3 elements looking awayfrom the protected section, so no transmission takesplace, thus giving fast tripping via the forward-lookingZone 1 elements.

A fault at F2 is seen by the forward-looking Zone 2elements at ends A and B and by the Zone 1 elements at

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Figure 12.11: Ideal distance protectionblocking scheme

Z3AZ2A

Z2B

Z2T O

OZ3T

Z1B

Z3B

Z1A

F1

Z1

Z2

Z3

A B CF2


(b) Simplified logic

Signalsend

Sendcircuit

(f1)

Receivecircuit

(f1)

Sendcircuit

(f1)

Receivecircuit

(f1)Signalreceive

Signalsend

SignalreceiveDi

stan

ce re

lay

Dist

ance

rela

y

(c) Signalling arrangement

F3

Signal receive

Trip

Signal send

Signalling equipment-End B

Signalling equipment-End A

≥1

&

Figure 12.12: Signal logic for BOP Z2 scheme

Trip

Z2

Z3

Z1

Z2T

td

O

O

O

O

STL

Z3T

Signal send

Channel in service

Signal receive

≥1

&

Chap12 exe 14/06/02 13:15 Page 198


end B. No signal transmission takes place, since thefault is internal and the fault is cleared in Zone 1 time atend B and after the short time lag (STL) at end A.

A fault at F3 is seen by the reverse-looking Z3 elementsat end B and the forward looking Zone 2 elements at endA. The Zone 1 relay elements at end B associated withline section B-C would normally clear the fault at F3. Toprevent the Z2 elements at end A from tripping, thereverse-looking Zone 3 elements at end B send ablocking signal to end A. If the fault is not clearedinstantaneously by the protection on line section B-C,the trip signal will be given at end B for section A-Bafter the Z3 time delay.

The setting of the reverse-looking Zone 3 elements mustbe greater than that of the Zone 2 elements at theremote end of the feeder, otherwise there is thepossibility of Zone 2 elements initiating tripping and thereverse looking Zone 3 elements failing to see anexternal fault. This would result in instantaneoustripping for an external fault. When the signallingchannel is used for a stabilising signal, as in the abovecase, transmission takes place over a healthy line sectionif power line carrier is used. The signalling channelshould then be more reliable when used in the blockingmode than in tripping mode.

It is essential that the operating times of the variousrelays be skilfully co-ordinated for all system conditions,so that sufficient time is always allowed for the receiptof a blocking signal from the remote end of the feeder.If this is not done accurately, the scheme may trip for anexternal fault or alternatively, the end zone trippingtimes may be delayed longer than is necessary.

If the signalling channel fails, the scheme must bearranged to revert to conventional basic distanceprotection. Normally, the blocking mode trip circuit issupervised by a 'channel-in-service' contact so that theblocking mode trip circuit is isolated when the channel isout of service, as shown in Figure 12.12.

In a practical application, the reverse-looking relayelements may be set with a forward offset characteristicto provide back-up protection for busbar faults after thezone time delay. It is then necessary to stop the blockingsignal being sent for internal faults. This is achieved bymaking the ‘signal send’ circuit conditional upon non-operation of the forward-looking Zone 2 elements, asshown in Figure 12.13.

Blocking schemes, like the permissive over-reachscheme, are also affected by the current reversal in thehealthy feeder due to a fault in a double circuit line. Ifcurrent reversal conditions occur, as described in section11.9.9, it may be possible for the maloperation of abreaker on the healthy line to occur. To avoid this, theresetting of the ‘signal received’ element provided in theblocking scheme is time delayed.

The timer with delayed resetting (td) is set to cover thetime difference between the maximum resetting time ofreverse-looking Zone 3 elements and the signallingchannel. So, if there is a momentary loss of the blockingsignal during the current reversal, the timer does nothave time to reset in the blocking mode trip circuit andno false tripping takes place.

12.4.1.2 Blocking over-reaching protection scheme usingZone 1 element

This is similar to the BOP Z2 scheme described above,except that an over-reaching Zone 1 element is used inthe logic, instead of the Zone 2 element. It may also beknown as the BOP Z1 scheme.

12.4.2 Weak Infeed Conditions

The protection at the strong infeed terminal will operatefor all internal faults, since a blocking signal is notreceived from the weak infeed terminal end. In the caseof external faults behind the weak infeed terminal, thereverse-looking elements at that end will see the faultcurrent fed from the strong infeed terminal and operate,initiating a block signal to the remote end. The relay atthe strong infeed end operates correctly without theneed for any additional circuits. The relay at the weakinfeed end cannot operate for internal faults, and sotripping of that breaker is possible only by means ofdirect intertripping from the strong source end.

12.5 DIRECTIONAL COMPARISONUNBLOCKING SCHEME

The permissive over-reach scheme described in Section12.3.4 can be arranged to operate on a directionalcomparison unblocking principle by providing additionalcircuitry in the signalling equipment. In this scheme(also called a ’deblocking overreach distance protection

• 12 •D

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Figure 12.13: Blocking scheme using reverse-looking relays with offset

(b) Solid state logic of send circuit

Signal send


Z3G

Z3

Z2

Z2G

G H

Z1G

Z1H

Z2H

Z3H

&

Chap12 exe 14/06/02 13:15 Page 199


scheme’), a continuous block (or guard) signal istransmitted. When the over-reaching distance elementsoperate, the frequency of the signal transmitted isshifted to an 'unblock' (trip) frequency. The receipt of theunblock frequency signal and the operation of over-reaching distance elements allow fast tripping to occurfor faults within the protected zone. In principle, thescheme is similar to the permissive over-reach scheme.

The scheme is made more dependable than the standardpermissive over-reach scheme by providing additionalcircuits in the receiver equipment. These allow trippingto take place for internal faults even if the transmittedunblock signal is short-circuited by the fault. This isachieved by allowing aided tripping for a short timeinterval, typically 100 to 150 milliseconds, after the lossof both the block and the unblock frequency signals.After this time interval, aided tripping is permitted onlyif the unblock frequency signal is received.

This arrangement gives the scheme improved security over ablocking scheme, since tripping for external faults is possibleonly if the fault occurs within the above time interval ofchannel failure. Weak Infeed terminal conditions can becatered for by the techniques detailed in Section 12.3.5.

In this way, the scheme has the dependability of ablocking scheme and the security of a permissive over-reach scheme. This scheme is generally preferred whenpower line carrier is used, except when continuoustransmission of signal is not acceptable.

12.6 COMPARISON OF TRANSFER TRIPAND BLOCKING RELAYING SCHEMES

On normal two-terminal lines the main deciding factors inthe choice of the type of scheme, apart from the reliabilityof the signalling channel previously discussed, areoperating speed and the method of operation of thesystem. Table 12.1 compares the important characteristicsof the various types of scheme.

Modern digital or numerical distance relays are providedwith a choice of several schemes in the same relay. Thusscheme selection is now largely independent of relayselection, and the user is assured that a relay is availablewith all the required features to cope with changingsystem conditions.

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Criterion Transfer tripping scheme Blocking scheme

Speed of operation Fast Not as fast

Speed with in-service testing Slower As fast

Suitable for auto-reclose Yes Yes

Security againstmaloperation due to:

Current reversal Special features required Special features required

Loss of communications Poor Good

Weak Infeed/Open CB Special features required Special features required

Table 12.1: Comparison of differentdistance protection schemes

Chap12 exe 14/06/02 13:15 Page 200

Introduction 13.1

Parallel feeders 13.2

Multi-ended feeders – unit protection 13.3

Multi-ended feeders – distance protection 13.4

Multi-ended feeders -application of distance protection schemes 13.5

Protection of series compensated lines 13.6

Examples 13.7

References 13.8

• 1 3 • P r o t e c t i o n o f C o m p l e xT r a n s m i s s i o n C i r c u i t s

Chap13 exeNEW 14/06/02 13:27 Page 202

13.1 INTRODUCTION

Chapters 10-12 have covered the basic principles ofprotection for two terminal, single circuit lines whosecircuit impedance is due solely to the conductors used.However parallel transmission circuits are ofteninstalled, either as duplicate circuits on a commonstructure, or as separate lines connecting the same twoterminal points via different routes. Also, circuits maybe multi-ended, a three-ended circuit being the mostcommon.

For economic reasons, transmission and distributionlines can be much more complicated, maybe havingthree or more terminals (multi-ended feeder), or withmore than one circuit carried on a common structure(parallel feeders), as shown in Figure 13.1. Otherpossibilities are the use of series capacitors or direct-connected shunt reactors. The protection of such linesis more complicated and requires the basic schemesdescribed in the above chapters to be modified.

The purpose of this chapter is to explain the specialrequirements of some of these situations in respect ofprotection and identify which protection schemes areparticularly appropriate for use in these situations.

13.2 PARALLEL FEEDERS

If two overhead lines are supported on the samestructures or are otherwise in close proximity over part

• 13 • P rotect ion of Comple xTra n s m i s s i o n C i r c u i t s


Source Source

Bus C

Bus A Bus B

Figure 13.1: Parallel and Multi-ended feeders

Chap13 exeNEW 14/06/02 13:27 Page 203


• 13 •

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or whole of their length, there is a mutual couplingbetween the two circuits. The positive and negativesequence coupling between the two circuits is small andis usually neglected. The zero sequence coupling can bestrong and its effect cannot be ignored.

The other situation that requires mutual effects to betaken into account is when there is an earth fault on afeeder when the parallel feeder is out of service andearthed at both ends. An earth fault in the feeder thatis in service can induce current in the earth loop of theearthed feeder, causing a misleading mutualcompensation signal.

13.2.1 Unit Protection Systems

Types of protection that use current only, for exampleunit protection systems, are not affected by the couplingbetween the feeders. Therefore, compensation for theeffects of mutual coupling is not required for the relaytripping elements.

If the relay has a distance-to-fault feature, mutualcompensation 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 distancerelays, 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 adouble circuit line with generation sources at both endsof the circuit, the current in the healthy line can reversefor a short time. Unwanted tripping of CB’s on thehealthy line can then occur if a Permissive Over-reach orBlocking distance scheme (see Chapter 12) is used.Figure 13.2 shows how the situation can arise. The CBat D clears the fault at F faster than the CB at C. BeforeCB D opens, the Zone 2 elements at A may see the faultand operate, sending a trip signal to the relay for CB B.The reverse looking element of the relay at CB B alsosees the fault and inhibits tripping of CB’s A and B.However, once CB D opens, the relay element at A startsto reset, while the forward looking elements at B pick up(due to current reversal) and initiate tripping. If thereset times of the forward-looking elements of the relayat A are longer than the operating time of the forward-looking elements at B, the relays will trip the healthyline. The solution is to incorporate a blocking time delaythat prevents the tripping of the forward-lookingelements of the relays and is initiated by the reverse-looking element. The time delay must be longer than thereset times of the relay elements at A.

13.2.2.2 Under-reach on parallel lines

If a fault occurs on a line that lies beyond the remoteterminal end of a parallel line circuit, the distance relaywill under-reach for those zones set to reach into theaffected line.

Analysis shows that under these conditions, because therelay sees only 50% (for two parallel circuits) of thetotal fault current for a fault in the adjacent line section,the relay sees the impedance of the affected section astwice the correct value. This may have to be allowed forin the settings of Zones 2 and 3 of conventionally setdistance relays.

Since the requirement for the minimum reach of Zone 2is to the end of the protected line section and the under-reach effect only occurs for faults in the following linesection(s), it is not usually necessary to adjust Zone 2impedance settings to compensate.

However, Zone 3 elements are intended to providebackup protection to adjacent line sections and hencethe under-reaching effect must be allowed for in theimpedance calculations.

13.2.2.3 Behaviour of distance relayswith earth faults on the protected feeder

When an earth fault occurs in the system, the voltageapplied to the earth fault element of the relay in onecircuit includes an induced voltage proportional to thezero sequence current in the other circuit.

Fault

A B

C DF

(b) Fault current distributionwith circuit breaker K open

A B

C

Fault

DF

Open

(a) Fault current distributionat instant of fault

Z<Z<

Z< Z<

Z<Z<Z<

Z< Z<

Figure 13.2: Fault current distributionin double-circuit line

Chap13 exeNEW 14/06/02 13:27 Page 204


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As the current distribution in the two circuits isunaffected by the presence of mutual coupling, nosimilar variation in the current applied to the relayelement takes place and, consequently, the relaymeasures the impedance to the fault incorrectly.Whether the apparent impedance to the fault is greateror less than the actual impedance depends on thedirection of the current flow in the healthy circuit. Forthe common case of two circuits, A and B, connected atthe 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 compensationfrom its own feeder, is given by:

...Equation 13.1

where:

The true impedance to the fault is nZL1 where n is theper unit fault position measured from R and ZL1 is thepositive sequence impedance of a single circuit. The'error' in measurement is determined from the fractioninside the bracket; this varies with the positive and zerosequence currents in circuit A and the zero sequencecurrent in circuit B.

M ZZ

M

L= 0

1

Z nZI I M

I I KA LB A

A A

= +( )( )+

1

0 0

1 01

2

These currents are expressed below in terms of the lineand source parameters:

ZM0 = zero sequence mutual impedancebetween the 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 inChapter 11. Using the above formulae, families of reachcurves may be constructed, of which Figure 13.4 istypical. In this figure, n’ is the effective per unit reachof a relay set to protect 80% of the line. It has beenassumed that an infinite busbar is located at each lineend, that is, Z’S1 and Z’’S1 are both zero. A family ofcurves of constant n’ has been plotted for variations inthe source zero sequence impedances Z’S0 and Z’’S0.

It can be seen from Figure 13.4 that relay R can under-reach or over-reach, according to the relative values ofthe zero sequence source to line impedance ratios; the

I I

nZ n Z

n Z n Z Z Z

In Z n Z Z

Z Z ZI

I

n Z n

B A

SO SO

SO SO L M

AS S L

S S L

A

SO

0 0

0 0

11 1 1

1 1 11

0

1

2 1

2 1

2

2 1

=

′′ − −( ) ′−( ) ′′ + −( ) ′ + +( )

=−( ) ′′ + −( ) ′ +( )

′ + ′′( )+

=

−( ) ′′ + −

(( ) ′ + +( )′ + ′′( )+ +

Z Z Z

Z Z Z ZISO L M

SO SO L M

0 0

0 002

and

R

(c) Zero Sequence network

(b) Positive sequence network

R

F1

I1

I0

F0

Relay Rlocation

n

Line B

Line A

Fault

(a) Single line diagram

IB

Z'S1,Z'SO Z''S1, Z''SO

IB1

IB0

nZM0

nZL1

ZL1

(1-n)ZL1

(1-n)ZMO

(ZLO-ZMO)

(1-n)(ZLO-ZMO)n(ZLO-ZMO)

Z'S0

Z'S1

Z''S0

Z''S1

IA1

IA0

ZL1 ZL0

ZM0IA

Figure 13.3: General parallel circuit fedfrom both ends

0.1

0.5

1

5

10

50

100

0.5 1 5 10 50

Limit of n'

=Z

xZLOZ

=ZSOyZLOZ

''

Limit of

when yx

0••

n'n'=

0.9'

n'nn''

'

n'=0.7'

n'n'

Figure 13.4: Typical reach curves illustratingthe effect of mutual coupling

Chap13 exeNEW 14/06/02 13:27 Page 205

extreme effective per unit reaches for the relay are 0.67and 1. Relay over-reach is not a problem, as thecondition being examined is a fault in the protectedfeeder, for which relay operation is desirable. It can alsobe seen from Figure 13.4 that relay R is more likely tounder-reach. However the relay located at the oppositeline end will tend to over-reach. As a result, the Zone 1characteristic of the relays at both ends of the feeder willoverlap for an earth fault anywhere in the feeder – seeSection 13.2.3.5 for more details.

Satisfactory protection can be obtained with a transfertrip, under-reach type distance scheme. Further,compensation for the effect of zero sequence mutualimpedance is not necessary unless a distance-to-faultfacility is provided. Some manufacturers compensate forthe effect of the mutual impedance in the distance relayelements, while others may restrict the application ofcompensation to the distance-to-fault function only.The latter is easy to implement in software for adigital/numerical relay but is impractical in relays usingolder technologies. Compensation is achieved byinjecting a proportion of the zero sequence currentflowing in the parallel feeder into the relay. However,some Utilities will not permit this due to the potentialhazards associated with feeding a relay protecting onecircuit from a CT located in a different circuit.

For the relay to measure the line impedance accurately,the following condition must be met:

For a solid phase to earth fault at the theoretical reachof the relay, the voltage and current in the faulty phaseat the relaying point are given by:

…Equation 13.2

The voltage and current fed into the relay are given by:

...Equation 13.3

where:

KR is the residual compensation factor

KM is the mutual compensation factor

V V

I I K I K I

R A

R A R A M B

=

= + +

0 0

V I Z I Z I Z I Z

I I I I

A A L A L A L B M

A A A A

= + + +

= + +

1 1 2 2 0 0 0 0

1 2 0

VI

ZR

RL= 1

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Thus:

13.2.3.4 Distance relay behaviourwith earth faults on the parallel feeder

Although distance relays with mutual compensationmeasure the correct distance to the fault, they may notoperate correctly if the fault occurs in the adjacentfeeder. Davison and Wright [13.1] have shown that,while distance relays without mutual compensation willnot over-reach for faults outside the protected feeder,the relays may see faults in the adjacent feeder if mutualcompensation is provided. With reference to Figure 13.3,the amount of over-reach is highest whenZ’’S1=Z’’S2=Z’’S0=∞. Under these conditions, faultsoccurring in the first 43% of feeder A will appear to thedistance relay in feeder B to be within its Zone 1 reach.The solution is to limit the mutual compensation appliedto 150% of the zero sequence compensation.

13.2.3.5 Distance relay behaviourwith single-circuit operation

If only one of the parallel feeders is in service, theprotection in the remaining feeder measures the faultimpedance correctly, except when the feeder that is notin service is earthed at both ends. In this case, the zerosequence impedance network is as shown in Figure 13.5.

Humpage and Kandil [13.2] have shown that theapparent impedance presented to the relay under theseconditions is given by:

...Equation 13.4

where:

IR is the current fed into the relay

= IA + KRIA0

Z Z I ZI ZR LA M

R L

= −10 0

2

0

K Z ZZ

K ZZ

RL L

L

MM

L

= −

=

0 1

1

0

1

Relaylocation

FO

IO

IGO

IHO ZLO

NO

nZLOZ'SO Z''SO

mZLO

(1-n)ZLO

(1-n)ZMO

Figure 13.5: Zero sequence impedance networkduring single circuit operation

Chap13 exeNEW 14/06/02 13:27 Page 206


The ratio IA0/IR varies with the system conditions,reaching a maximum when the system is earthed behindthe relay with no generation at that end. In this case,the ratio IA0/IR is equal to ZL1/ZL0 , and the apparentimpedance presented to the relay is:

It is apparent from the above formulae that the relay hasa tendency to over-reach. Care should be taken whenZone 1 settings are selected for the distance protection oflines in which this condition may be encountered. In orderto overcome this possible over-reaching effect, someUtilities reduce the reach of earth fault relays to around0.65ZL1 when lines are taken out of service. However, theprobability of having a fault on the first section of thefollowing line while one line is out of service is very small,and many Utilities do not reduce the setting under thiscondition. It should be noted that the use of mutualcompensation would not overcome the over-reachingeffect since earthing clamps are normally placed on theline side of the current transformers.

Typical values of zero sequence line impedances for HVlines in the United Kingdom are given in Table 13.1,where the maximum per unit over-reach error(ZM0/ZL0)2 is also given. It should be noted that theover-reach values quoted in this table are maxima, andwill be found only in rare cases. In most cases, there willbe generation at both ends of the feeder and the amountof over-reach will therefore be reduced. In thecalculations carried out by Humpage and Kandil, withmore realistic conditions, the maximum error found in a400kV double circuit line was 18.6%.

13.3 MULTI-ENDED FEEDERS– UNIT PROTECTION SCHEMES

A multi-ended feeder is defined as one having three ormore terminals, with either load or generation, or both,at any terminal. Those terminals with load only areusually known as ’taps’.

The simplest multi-terminal feeders are three-ended, andare generally known as tee’d feeders. This is the typemost commonly found in practice.

The protection schemes described previously for the

protection of two-ended feeders can also be used formulti-ended feeders. However, the problems involved inthe application of these schemes to multi-ended feedersare much more complex and require special attention.

The protection schemes that can be used with multi-endedfeeders are unit protection and distance schemes. Each usessome form of signalling channel, such as fibre-optic cable,power line carrier or pilot wires. The specific problems thatmay be met when applying these protections to multi-endedfeeders are discussed in the following sections.

13.3.1 A.C. Pilot Wire Protection

A.C. pilot wire relays provide a low-cost fast protection;they are insensitive to power swings and, owing to theirrelative simplicity, their reliability is excellent.

The limitations of pilot wire relays for plain feederprotection also apply. The length of feeder that can beprotected is limited by the characteristics of the pilotwires. The protection sees increasing pilot wire resistanceas tending to an open circuit and shunt capacitance as ana.c. short circuit across the pilots. The protection will havelimiting values for each of these quantities, and whenthese are exceeded, loss of sensitivity for internal faultsand maloperation for external faults may occur. For tee’dfeeders, the currents for an external earth fault will notusually be the same. The protection must be linear for anycurrent up to the maximum through-fault value. As aresult, the voltage in the pilots during fault conditionscannot be kept to low values, and pilot wires with 250Vinsulation grade are required.

13.3.2 Balanced Voltage Schemes for Tee’d Circuits

In this section two types of older balanced voltageschemes still found in many locations are described.

13.3.2.1 ‘Translay’ balanced voltage protection

This is a modification of the balanced voltage schemedescribed in Section 10.7.1. Since it is necessary tomaintain linearity in the balancing circuit, though not inthe sending element, the voltage reference is derivedfrom separate quadrature transformers, as shown inFigure 13.6. These are auxiliary units with summationwindings energized by the main current transformers inseries with the upper electromagnets of the sensingelements. The secondary windings of the quadraturecurrent transformers at all ends are interconnected bythe pilots in a series circuit that also includes the lowerelectromagnets of the relays. Secondary windings on therelay elements are not used, but these elements arefitted with bias loops in the usual way.

The plain feeder settings are increased in the tee'dscheme by 50% for one tee and 75% for two.

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Z Z ZZR L

M

L

= −

1

02

02

1

Zero sequence Zero sequence line Per unitConductor mutual impedance impedance over-reach

size ZMO ZLOerror

(ZMO/ZLO)2

Metric Line (sq.in) (sq.mm) ohms/mile ohms/km ohms/mile ohms/km

voltage equivalent

32kV 0.4 258 0.3 + j0.81 0.19+j0.5 0.41+j1.61 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 foundduring single circuit working

Chap13 exeNEW 14/06/02 13:27 Page 207

13.3.2.2 High - speed protection type DSB7

This type is of higher speed and is shown in Figure 13.7.Summation quadrature transformers are used to providethe analogue quantity, which is balanced in a series loopthrough a pilot circuit. Separate secondary windings onthe quadrature current transformers are connected tofull-wave rectifiers, the outputs of which are connectedin series in a second pilot loop, so that the electromotiveforces summate arithmetically.The measuring relay is a double-wound moving coil type,one coil being energized from the vectorial summationloop; the other receives bias from the scalar summationin the second loop proportional to the sum of thecurrents in the several line terminals, the value beingadjusted by the inclusion of an appropriate value ofresistance. Since the operating and biasing quantitiesare both derived by summation, the relays at thedifferent terminals all behave alike, either to operate orto restrain as appropriate.Special features are included to ensure stability, both inthe presence of transformer inrush current flowingthrough the feeder zone and also with a 2-1-1distribution of fault current caused by a short circuit onthe secondary side of a star-delta transformer.

13.3.3 Power Line Carrier Phase Comparison Schemes

The operating principle of these protection schemes hasalready been covered in detail in Section 10.9. Itinvolves comparing the phase angles of signals derivedfrom a combination of the sequence currents at eachend of the feeder. When the phase angle differenceexceeds a pre-set value, the ‘trip angle’, a trip signal issent to the corresponding circuit breakers. In order toprevent incorrect operation for external faults, twodifferent detectors, set at different levels, are used. Thelow-set detector starts the transmission of carrier signal,while the high-set detector is used to control the tripoutput. Without this safeguard, the scheme couldoperate incorrectly for external faults because ofoperating tolerances of the equipment and thecapacitive current of the protected feeder. Thiscondition is worse with multi-terminal feeders, since thecurrents at the feeder terminals can be very dissimilarfor an external fault. In the case of the three-terminalfeeder in Figure 13.8, if incorrect operation is to beavoided, it is necessary to make certain that the low-setdetector at end A or end B is energized when thecurrent at end C is high enough to operate the high-setdetector at that end. As only one low-set starter, at endA or end B, needs to be energized for correct operation,the most unfavourable condition will be when currentsIA and IB are equal. To maintain stability under thiscondition, the high-set to low-set setting ratio of thefault detectors needs to be twice as large as thatrequired when the scheme is applied to a plain feeder.This results in a loss of sensitivity, which may make theequipment unsuitable if the minimum fault level of thepower system is low.

A further unfavourable condition is that illustrated inFigure 13.9. If an internal fault occurs near one of theends of the feeder (end B in Figure 13.9) and there islittle or no generation at end C, the current at this endmay be flowing outwards. The protection is thenprevented from operating, since the fault currentdistribution is similar to that for an external fault; seeFigure 13.8. 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.

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ED

End A

P4P4P

End C

End B

CBA

QuadratureCT

Bias pilotsD Operating coil E Restraints coilE

Figure 13.7: Type DSB7 fast tee’d feeder protection

Figure 13.8: External fault conditions

Fault

A CT

B

IA IC

IB

Figure 13.6: Balanced voltage Tee’d feeder scheme

End A End BABC

A

AA1

A

A1

1

N

S1 S2S2S

1

C1

C1C

S1 S2S2S

S1 S2S2SC

CNN

A1

Pilots

Quadrature CT

Relay

N

AA C

S

1

Chap13 exeNEW 14/06/02 13:27 Page 208

A point that should also be considered when applyingthis scheme is the attenuation of carrier signal at the'tee' junctions. This attenuation is a function of therelative impedances of the branches of the feeder at thecarrier frequency, including the impedance of thereceiving equipment. When the impedances of thesecond and third terminals are equal, a power loss of50% takes place. In other words, the carrier signal sentfrom terminal A to terminal B is attenuated by 3dB bythe existence of the third terminal C. If the impedancesof the two branches corresponding to terminal B to C arenot equal, the attenuation may be either greater or lessthan 3dB.

13.3.4 Differential Relay using Optical Fibre SignallingCurrent differential relays can provide unit protection formulti-ended circuits without the restrictions associatedwith other forms of protection. In Section 8.6.5, thecharacteristics of optical fibre cables and their use inprotection signalling are outlined.

Their use in a three-ended system is shown in Figure13.10, where the relays at each line end aredigital/numerical relays interconnected by optical fibrelinks so that each can send information to the others. Inpractice the optical fibre links can be dedicated to theprotection system or multiplexed, in which casemultiplexing equipment, not shown in Figure 13.10, willbe used to terminate the fibres.

If IA, IB, IC are the current vector signals at line ends A,B, C, then for a healthy circuit:

IA + IB + IC = 0

The basic principles of operation of the system are thateach relay measures its local three phase currents andsends its values to the other relays. Each relay thencalculates, for each phase, a resultant differentialcurrent and also a bias current, which is used to restrainthe relay in the manner conventional for biaseddifferential unit protection.

The bias feature is necessary in this scheme because it isdesigned to operate from conventional currenttransformers that are subject to transient transformationerrors.

The two quantities are:

Figure 13.11 shows the percentage biased differentialcharacteristic used, the tripping criteria being:

and

where:

K = percentage bias setting

IS = minimum differential current setting

If the magnitudes of the differential currents indicatethat a fault has occurred, the relays trip their local circuitbreaker.

I Idiff S>

I K Idiff bias>

I I I I

I I I I

diff A B C

bias A B C

> + +

= + +( )12

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B

IB

IA ICA

T

Fault

C

Figure 13.9: Internal faultwith current flowing out at one line end

RAR

RC ICICI

RB

IBIIAI

Optical fibre signalling channels

C

A B

Figure 13.10: Current differential protectionfor tee’d feeders using optical fibre signalling

Differentialcurrent

Bias current

Trip

Restrain

Idiff

IS

Ibias

Idiff K Ibias=

Figure 13.11: Percentage biaseddifferential protection characteristic

Chap13 exeNEW 14/06/02 13:27 Page 209

The relays also continuously monitor the communicationchannel performance and carry out self-testing anddiagnostic operations. The system measures individualphase currents and so single phase tripping can be usedwhen required. Relays are provided with software to re-configure the protection between two and three terminallines, so that modification of the system from twoterminals to three terminals does not require relayreplacement. Further, loss of a single communicationslink only degrades scheme performance slightly. Therelays can recognise this and use alternatecommunications paths. Only if all communication pathsfrom a relay fail does the scheme have to revert tobackup protection.

13.4 MULTI-ENDED FEEDERS - DISTANCE RELAYS

Distance protection is widely used at present for tee'dfeeder protection. However, its application is notstraightforward, requiring careful consideration andsystematic checking of all the conditions described laterin this section.

Most of the problems found when applying distanceprotection to tee’d feeders are common to all schemes.A preliminary discussion of these problems will assist inthe assessment of the performance of the different typesof distance schemes.

13.4.1 Apparent Impedance seen by Distance Relays

The impedance seen by the distance relays is affected bythe current infeeds in the branches of the feeders.Referring to Figure 13.12, for a fault at the busbars ofthe substation B, the voltage VA at busbar A is given by:

VA = IAZLA + IBZLB

so the impedance ZA seen by the distance relay atterminal A is given by:

or

...Equation 13.5or

The apparent impedance presented to the relay has beenmodified by the term (IC /IA)ZLB. If the pre-fault load iszero, the currents IA and IC are in phase and their ratiois a real number. The apparent impedance presented to

Z Z Z II

ZA LA LBC

ALB= + +

Z Z II

ZA LAB

ALB= +

Z VI

Z II

ZAA

ALA

B

ALB= = +

the relay in this case can be expressed in terms of thesource impedances as follows:

The magnitude of the third term in this expression is afunction of the total impedances of the branches A andB and can reach a relatively high value when the faultcurrent contribution of branch C is much larger thanthat of branch A. Figure 13.13 illustrates how adistance relay with a mho characteristic located at Awith a Zone 2 element set to 120% of the protectedfeeder AB, fails to see a fault at the remote busbar B.The ’tee’ point T in this example is halfway betweensubstations A and B (ZLA = ZLB) and the fault currentsIA and IC have been assumed to be identical inmagnitude and phase angle. With these conditions, thefault appears to the relay to be located at B' instead ofat B - i.e. the relay appears to under-reach.

The under-reaching effect in tee’d feeders can be foundfor any kind of fault. For the sake of simplicity, theequations and examples mentioned so far have been for

Z Z ZZ Z

Z ZZA LA LB

SB LB

SC LCLB= + +

+( )+( )

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ZSA

ZLA ZLB

ZSBIA IB

IC

ZLC

ZSC

C

AT

B

Fault

Figure 13.12: Fault at substation B busbars

B'

B

T

AR

X

Figure 13.13: Apparent impedance presented to the relay at substation A for

a fault at substation B busbars

Chap13 exeNEW 14/06/02 13:30 Page 210

balanced faults only. For unbalanced faults, especiallythose involving earth, the equations become somewhatmore complicated, as the ratios of the sequence faultcurrent contributions at terminals A and C may not bethe same. An extreme example of this condition isfound when the third terminal is a tap with nogeneration but with the star point of the primarywinding of the transformer connected directly to earth,as shown in Figure 13.14. The corresponding sequencenetworks are illustrated in Figure 13.15.

It can be seen from Figure 13.15 that the presence of thetap has little effect in the positive and negativesequence networks. However, the zero sequenceimpedance of the branch actually shunts the zerosequence current in branch A. As a result, the distancerelay located at terminal A tends to under-reach. Onesolution to the problem is to increase the residualcurrent compensating factor in the distance relay, to

compensate for the reduction in zero sequence current.However, the solution has two possible limitations:

i. over-reach will occur when the transformer is notconnected, and hence operation for faults outsidethe protected zone may occur

ii. the inherent possibility of maloperation of theearth fault elements for earth faults behind therelay location is increased

13.4.2 Effect of Pre-fault Load

In all the previous discussions it has been assumed thatthe power transfer between terminals of the feederimmediately before the fault occurred was zero. If this isnot the case, the fault currents IA and IC in Figure 13.12may not be in phase, and the factor IC /IA in the equationfor the impedance seen by the relay at A, will be acomplex quantity with a positive or a negative phaseangle according to whether the current IC leads or lagsthe current IA. For the fault condition previouslyconsidered in Figures 13.12 and 13.13, the pre-fault loadcurrent may displace the impedance seen by the distancerelay to points such as B’1 or B’2, shown in Figure 13.16,according to the phase angle and the magnitude of thepre-fault load current. Humpage and Lewis [13.3] haveanalysed the effect of pre-fault load on the impedancesseen by distance relays for typical cases. Their resultsand conclusions point out some of the limitations ofcertain relay characteristics and schemes.

13.4.3 Effect of the Fault Current FlowingOutwards at One Terminal

Up to this point it has been assumed that the faultcurrents at terminals A and C flow into the feeder for afault at the busbar B. Under some conditions, however,the current at one of these terminals may flow outwardsinstead of inwards. A typical case is illustrated in Figure13.17; that of a parallel tapped feeder with one of theends of the parallel circuit open at terminal A.

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ZSA1 ZLA1 T1

A1

G1

B1

B2

EBEA

ZLB1

ZLJ1IA1

ZT1

ZM1

ZLC2

ZT2

ZM2

ZSH1

ZSA2 ZLA2 T2 ZLB2

IA2

ZLC0IA0

IC0

ZT0

ZSB2

A0 B0

ZSA0 ZLA0 T0 ZLB0 ZSB0

Figure 13.15: Sequence networksfor a phase A to ground fault at busbar B

in the system shown in Figure 13.14

B

T

AR

X

B'1

B'2

Figure 13.16: effects of the pre-fault load onthe apparent impedance presented to the relay

M

IAA

T

C

BZSA ZSB

ZLA ZLB

ZLC

ZT

Load

Phase Ato ground fault

Figure 13.14: Transformer tap with primarywinding solidly earthed

Chap13 exeNEW 14/06/02 13:30 Page 211

As the currents IA and IC now have different signs,the factor IC /IA becomes negative. Consequently, thedistance relay at terminal A sees an impedance smallerthan that of the protected feeder, (ZA + ZB), andtherefore has a tendency to over-reach. In some casesthe apparent impedance presented to the relay may beas low as 50% of the impedance of the protected feeder,and even lower if other lines exist between terminals Band C.

If the fault is internal to the feeder and close to thebusbars B, as shown in Figure 13.18, the current atterminal C may still flow outwards. As a result, the faultappears as an external fault to the distance relay atterminal C, which fails to operate.

13.4.4 Maloperation with Reverse Faults

Earth fault distance relays with a directionalcharacteristic tend to lose their directional properties

under reverse unbalanced fault conditions if the currentflowing through the relay is high and the relay settingrelatively large. These conditions arise principally fromearth faults. The relay setting and the reverse faultcurrent are now related, the first being a function of themaximum line length and the second depending mainlyon the impedance of the shortest feeder and the faultlevel at that terminal. For instance, referring to Figure13.19, the setting of the relay at terminal A will dependon the impedance (ZA + ZB) and the fault current infeedIC, for a fault at B, while the fault current IA for a reversefault may be quite large if the T point is near theterminals A and C.

A summary of the main problems met in the application ofdistance protection to tee'd feeders is given in Table 13.2.

13.5 MULTI-ENDED FEEDERS– APPLICATION OF DISTANCE PROTECTION SCHEMES

The schemes that have been described in Chapter 12 forthe protection of plain feeders may also be used for tee'dfeeder protection. However, the applications of some ofthese schemes are much more limited in this case.

Distance schemes can be subdivided into two maingroups; transfer trip schemes and blocking schemes. Theusual considerations when comparing these schemes aresecurity, that is, no operation for external faults, and

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A B

C

IA

IC I'C

I'B

IBT

Fault

Figure 13.18: Internal fault near busbar B with current flowing out at terminal C

AIA IB

ZBZA

ZC

IC

B

C

T

Fault

Figure 13.19: External fault behind he relay at terminal A

IABA

T

C

IB

I'B

I'CIC

ZBZA

Fault

Figure 13.17: Internal Fault at busbar Bwith current flowing out at terminal C

Case Description Relevant figure number

1 Under-reaching effect for internal faultsdue to current infeed at the T point 13.12 to 13.15

2 Effect of pre-fault load on the impedance seen' by the relay 13.16

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

Table 13.2: Main problems met in the applicationof distance protection to tee'd feeders.

Chap13 exeNEW 14/06/02 13:30 Page 212


dependability, that is, assured operation for internalfaults.

In addition, it should be borne in mind that transfer tripschemes require fault current infeed at all the terminalsto achieve high-speed protection for any fault in thefeeder. This is not the case with blocking schemes.While it is rare to find a plain feeder in high voltagesystems where there is current infeed at one end only, itis not difficult to envisage a tee’d feeder with no currentinfeed at one end, for example when the tee’d feeder isoperating as a plain feeder with the circuit breaker atone of the terminals open. Nevertheless, transfer tripschemes are also used for tee’d feeder protection, asthey offer some advantages under certain conditions.

13.5.1 Transfer Trip Under-Reach Schemes

The main requirement for transfer trip under-reachschemes is that the Zone 1 of the protection, at one endat least, shall see a fault in the feeder. In order to meetthis requirement, the Zone 1 characteristics of the relaysat different ends must overlap, either the three of themor in pairs. Cases 1, 2 and 3 in Table 13.2 should bechecked when the settings for the Zone 1 characteristicsare selected. If the conditions mentioned in case 4 arefound, direct transfer trip may be used to clear the fault;the alternative is sequentially at end C when the faultcurrent IC reverses after the circuit breaker at terminal Bhas opened; see Figure 13.18.

Transfer trip schemes may be applied to feeders thathave branches of similar length. If one or two of thebranches are very short, and this is often the case intee'd feeders, it may be difficult or impossible to makethe Zone 1 characteristics overlap. Alternative schemesare then required.

Another case for which under-reach schemes may beadvantageous is the protection of tapped feeders, mainlywhen the tap is short and is not near one of the mainterminals. Overlap of the Zone 1 characteristics is theneasily achieved, and the tap does not require protectionapplied to the terminal.

13.5.2 Transfer Trip Over-Reach Schemes

For correct operation when internal faults occur, therelays at the three ends should see a fault at any pointin the feeder. This condition is often difficult to meet,since the impedance seen by the relays for faults at oneof the remote ends of the feeder may be too large, as incase 1 in Table 13.2, increasing the possibility ofmaloperation for reverse faults, case 5 in Table 13.2. Inaddition, the relay characteristic might encroach on theload impedance.

These considerations, in addition to the signallingchannel requirements mentioned later on, make transfertrip over-reach schemes unattractive for multi-endedfeeder protection.

13.5.3 Blocking Schemes

Blocking schemes are particularly suited to the protectionof multi-ended feeders, since high-speed operation canbe obtained with no fault current infeed at one or moreterminals. The only disadvantage is when there is faultcurrent outfeed from a terminal, as shown in Figure 13.18.This is case 4 in Table 13.2. The protection units at thatterminal may see the fault as an external fault and senda blocking signal to the remote terminals. Depending onthe scheme logic either relay operation will be blocked, orclearance will be in Zone 2 time.

The setting of the directional unit should be such that nomaloperation can occur for faults in the reversedirection; case 5 in Table 13.2.

13.5.4 Signalling Channel Considerations

The minimum number of signalling channels requireddepends on the type of scheme used. With under-reachand blocking schemes, only one channel is required,whereas a permissive over-reach scheme req-uires asmany channels as there are feeder ends. The signallingchannel equipment at each terminal should include onetransmitter and (N-1) receivers, where N is the totalnumber of feeder ends. This may not be a problem iffibre-optic cables are used, but could lead to problemsotherwise.

If frequency shift channels are used to improve thereliability of the protection schemes, mainly withtransfer trip schemes, N additional frequencies arerequired for the purpose. Problems of signal attenuationand impedance matching should also be carefullyconsidered when power line carrier frequency channelsare used.

13.5.5 Directional Comparison Blocking Schemes

The principle of operation of these schemes is the sameas that of the distance blocking schemes described inthe previous section. The main advantage of directionalcomparison schemes over distance schemes is theirgreater capability to detect high-resistance earth faults.The reliability of these schemes, in terms of stability forthrough faults, is lower than that of distance blockingschemes. However, with the increasing reliability ofmodern signalling channels, directional comparisonblocking schemes seem to offer good solutions to themany and difficult problems encountered in the

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protection of multi-ended feeders. Modern relaysimplement the required features in different ways –for further information see Chapter 12 and specificrelay manuals.

13.6 PROTECTION OF SERIES COMPENSATED LINES

Figure 13.20 depicts the basic power transfer equation.It can be seen from this equation that transmitted poweris proportional to the system voltage level and load anglewhilst being inversely proportional to system impedance.Series compensated lines are used in transmissionnetworks where the required level of transmitted powercan not be met, either from a load requirement or systemstability requirement. Series compensated transmissionlines introduce a series connected capacitor, which hasthe net result of reducing the overall inductiveimpedance of the line, hence increasing the prospective,power flow. Typical levels of compensation are 35%,50% and 70%, where the percentage level dictates thecapacitor impedance compared to the transmission lineit is associated with.

The introduction of a capacitive impedance to a networkcan give rise to several relaying problems. The mostcommon of these is the situation of voltage inversion,which is shown in Figure 13.21. In this case a faultoccurs on the protected line. The overall fault impedanceis inductive and hence the fault current is inductive(shown lagging the system e.m.f. by 90 degrees in thiscase). However, the voltage measured by the relay is thatacross the capacitor and will therefore lag the faultcurrent by 90 degrees.

The net result is that the voltage measured by the relayis in anti-phase to the system e.m.f.. Whilst this view ishighly simplistic, it adequately demonstrates potentialrelay problems, in that any protection reliant uponmaking a directional decision bases its decision on aninductive system i.e. one where a forward fault isindicated by fault current lagging the measured voltage.A good example of this is a distance relay, which assumesthe transmission line is an evenly distributed inductiveimpedance. Presenting the relay with a capacitivevoltage (impedance) can lead the relay to make anincorrect directional decision.

A second problem is that of current inversion which isdemonstrated in Figure 13.22. In this case, the overallfault impedance is taken to be capacitive. The faultcurrent therefore leads the system e.m.f. by 90° whilstthe measured fault voltage remains in phase with systeme.m.f.. Again this condition can give rise to directionalstability problems for a variety of protection devices.Practically, the case of current inversion is difficult toobtain. In order to protect capacitors from high overvoltages during fault conditions some form of voltagelimiting device (usually in the form of MOV’s) is installedto bypass the capacitor at a set current level. In the caseof current inversion, the overall fault impedance has tobe capacitive and will generally be small. This leads tohigh levels of fault current, which will trigger the MOV’sand bypass the capacitors, hence leaving an inductivefault impedance and preventing the current inversion.

In general, the application of protective relays to a seriescompensated power system needs careful evaluation.The problems associated with the introduction of a seriescapacitor can be overcome by a variety of relayingtechniques so it is important to ensure the suitability ofthe chosen protection. Each particular applicationrequires careful investigation to determine the mostappropriate solution in respect of protection – there areno general guidelines that can be given.

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jXS

XS>XC

E

E

VF

IF

IF

VF

Z<

-jXC

Figure 13.21: Voltage inversionon a transmission line

Bus A Bus BEA EBZT

PT a sin d

ZT

EA EB

Figure 13.20: Power transferin a transmission line

jXS

IF

VF

jIFXS

XS< XC

Z< IFVF

E

E

-jXC

Figure 13.22: Current inversionin a transmission line

Chap13 exeNEW 14/06/02 13:30 Page 214

13.7 EXAMPLES

In this section, an example calculation illustrating thesolution to a problem mentioned in this Chapter is given.

13.7.1 Distance Relay applied to Parallel Circuits

The system diagram shown in Figure 13.23 indicates asimple 110kV network supplied from a 220kV grid throughtwo auto-transformers. The following example shows thecalculations necessary to check the suitability of threezone distance protection to the two parallel feedersinterconnecting substations A and B, Line 1 beingselected for this purpose. All relevant data for thisexercise are given in the diagram. The MiCOM P441 relaywith quadrilateral characteristics is used to provide therelay data for the example. Relay quantities used in theexample are listed in Table 13.3, and calculations arecarried out in terms of actual system impedances inohms, rather than CT secondary quantities. This simplifiesthe calculations, and enables the example to be simplifiedby excluding considerations of CT ratios. Most moderndistance relays permit settings to be specified in systemquantities rather than CT secondary quantities, but olderrelays may require the system quantities to be convertedto impedances as seen by the relay.

13.7.1.1 Residual compensation

The relays used are calibrated in terms of the positivesequence impedance of the protected line. Since the earthfault impedance of Line 1 is different from the positivesequence impedance, the impedance seen by the relay inthe case of a fault involving earth will be different to thatseen for a phase fault. Hence, the reach of the earth faultelements of the relay needs to be different.

For the relay used, this adjustment is provided by theresidual (or neutral) compensation factor Kzo, set equal to:

For Lines 1 and 2,

Hence,

K

K

ZO

ZOo

=

∠ =

0 490

7 8

.

.

Z j

Z j

L

o

LO

o

1 0 177 0 402

0 439 66 236

0 354 1 022

1 082 70 895

= +

∠( )= +

∠( )

. .

. .

. .

. .

Ω

Ω

Ω

Ω

KZ Z

Z

KZ Z

Z

ZOo

ZOo

=−( )

∠ =∠−( )

1

1

1

1

3

3

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T4T3

T5

T7T6

Line 1 Line 2

Line 3 Line 4

Grid supply at 220kVMaximum fault level7500MVAMinimum fault level2500MVA

120MVA 220/110/11kVtransformersXHL=0.15; XHT=0.35;XLT=0.25XH=0.125; XL=0.025XT=0.225 on 120MVA

110kV transmission lines: Z1=0.177+j0.40Ω/kmZO=0.354+j1.022Ω/kmLength of line: 1, 2 =50km3 =100km 4 =40km

45MVA 132/33kVtransformersXT=0.125

45MVA132/33kV

transformersXT=0.125

110kV Substation P

Voltage transformerratio 110kV/110V

Current transformerratio 600/1A

110kVSubstation Q

33kVbusbars

Figure 13.23: Example network for distancerelay setting calculation

Table 13.3: Distance relay settings

Relay Parameter Parameter UnitsParameter Description Value

ZL1 (mag) Line positive sequence impedance (magnitude) 21.95 ΩZL1 (ang) Line positive sequence impedance (phase angle) 66.236 deg

ZL0 (mag) Line zero sequence impedance (magnitude) 54.1 ΩZL0 (ang) Line zero sequence impedance (phase angle) 70.895 deg

KZ0 (mag) Default residual compensation factor (magnitude) 0.49 -

KZ0 (ang) Default residual compensation factor (phase angle) 7.8 deg

Z1 (mag) Zone 1 reach impedance setting (magnitude) 17.56 ΩZ1 (ang) Zone 1 reach impedance setting (phase angle) 66.3 deg



R1ph Phase fault resistive reach value - Zone 1 84.8 ΩR2ph Phase fault resistive reach value - Zone 2 84.8 ΩR3ph Phase fault resistive reach value - Zone 3 84.8 ΩKZ1 (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



R1G Ground fault resistive reach value - Zone 1 84.8 ΩR2G Ground fault resistive reach value - Zone 2 84.8 ΩR3G Ground fault resistive reach value - Zone 3 84.8 Ω

Chap13 exeNEW 14/06/02 13:30 Page 215

13.7.1.2 Zone impedance reach settings – phase faults

Firstly, the impedance reaches for the three relay zonesare calculated.

13.7.1.3 Zone 1 reach

Zone 1 impedance is set to 80% of the impedance of theprotected line. Hence,

Use a value of


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 Bi.e. 50% of Line 4

From the line impedances given,

(i)

(ii)

It is clear that condition (ii) governs the setting, andtherefore the initial Zone 2 reach setting is:

The effect of parallel Line 2 is to make relay 1 underreachfor faults on adjacent line sections, as discussed inSection 11.9.3. This is not a problem for the phase faultelements because Line 1 will always be protected.


The function of Zone 3 is to provide backup protectionfor uncleared faults in adjacent line sections. Thecriterion used is that the relay should be set to cover120% of the impedance between the relay location andthe end of the longest adjacent line, taking account ofany possible fault infeed from other circuits or parallelpaths. In this case, faults in Line 3 will result in the relayunder-reaching due to the parallel Lines 1 and 2, so theimpedance of Line 3 should be doubled to take this effectinto account. Therefore,

Zo

o

o

3 1 221 95 66 3

100 2 0 439 66 3

131 8 66 3

= ×∠

+ × × ∠

= ∠

.. .

. .

. .

Ω

Ω

Z o2 30 73 66 3= ∠. . Ω

2 66 236

0 5 40 0 439 66 236

1.95∠ +

× × ∠

.

. . .

o

o Ω

1 2 21 95 66 236 2 66 236. . . .× ∠ ∠ = 6.34o o Ω

1 66 37.56∠ . o Ω

Z o

o

o

1 0 8 50 0 439 66 236

0 8 21 95 66 236

17 56 66 236

= × × ∠( )= × ∠

= ∠

. . .

. . .

. .

Ω

Ω

Ω

13.7.1.6 Zone Time Delay Settings

Proper co-ordination of the distance relay settings withthose of other relays is required. Independent timers areavailable for the three zones to ensure this.

For Zone 1, instantaneous tripping is normal. A timedelay is used only in cases where large d.c. offsets occurand old circuit breakers, incapable of breaking theinstantaneous d.c. component, are involved.

The Zone 2 element has to grade with the relaysprotecting Lines 3 and 4 since the Zone 2 element coverspart of these lines. Assuming that Lines 3/4 havedistance, unit or instantaneous high-set overcurrentprotection applied, the time delay required is that tocover the total clearance time of the downstream relays.To this must be added the reset time for the Zone 2elements following clearance of a fault on an adjacentline, and a suitable safety margin. A typical time delay is250ms, and the normal range is 200-300ms.

The considerations for the Zone 3 element are the same asfor the Zone 2 element, except that the downstream faultclearance time is that for the Zone 2 element of a distancerelay or IDMT overcurrent protection. Assuming distancerelays are used, a typical time is 450ms. In summary:

TZ1 = 0ms (instantaneous)

TZ2 = 250ms

TZ3 = 450ms

13.7.1.7 Phase Fault Resistive Reach Settings

With the use of a quadrilateral characteristic, theresistive reach settings for each zone can be setindependently of the impedance reach settings. Theresistive reach setting represents the maximum amountof additional fault resistance (in excess of the lineimpedance) for which a zone will trip, regardless of thefault within the zone.

Two constraints are imposed upon the settings, asfollows:

(i) it must be greater than the maximum expectedphase-phase fault resistance (principally that ofthe fault arc)

(ii) it must be less than the apparent resistancemeasured due to the heaviest load on the line

The minimum fault current at Substation B is of theorder of 1.5kA, leading to a typical arc resistance Rarcusing the van Warrington formula (equation 11.6) of 9Ω.Using the current transformer ratio on Line 1 as a guideto the maximum expected load current, the minimumload impedance Zlmin will be 106Ω. Typically, theresistive reaches will be set to avoid the minimum loadimpedance by a 20% margin for the phase elements,leading to a maximum resistive reach setting of 84.8.Ω.

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Therefore, the resistive reach setting lies between 9Ω and84.8Ω. While each zone can have its own resistive reachsetting, for this simple example, all of the resistive reachsettings can be set equal (depending on the particulardistance protection scheme used and the need to includePower Swing Blocking, this need not always be the case).

Suitable settings are chosen to be 80% of the loadresistance:

13.7.1.8 Earth Fault Reach Settings

By default, the residual compensation factor ascalculated in section 13.7.1.1 is used to adjust the phasefault reach setting in the case of earth faults, and isapplied to all zones. However, it is also possible to applythis compensation to zones individually. Two cases inparticular require consideration, and are covered in thisexample.

13.7.1.9 Zone 1 earth fault reach

Where distance protection is applied to parallel lines (asin this example), the Zone 1 earth fault elements maysometimes over-reach and therefore operate when oneline is out of service and earthed at both ends

The solution is to reduce the earth fault reach of theZone 1 element to typically 80% of the default setting.Hence:

In practice, the setting is selected by using an alternativesetting group, selected when the parallel line is out ofservice and earthed.

13.7.1.10 Zone 2 earth fault reach

With parallel circuits, the Zone 2 element will tend tounder-reach due to the zero sequence mutual couplingbetween the lines.

Maloperation may occur, particularly for earth faultsoccurring on the remote busbar. The effect can becountered by increasing the Zone 2 earth fault reachsetting, but first it is necessary to calculate the amountof under-reach that occurs.

Underreach = ×ZIIadj

fltp

flt

K KZ ZO1 0 8

0 8 0 532

0 426

= ×

= ×

=

.

. .

.

R

R

R

ph

ph

ph

3

2

1

=

=

=

84.8

84.8

84.8

Ω

Ω

Ω

where:

since the two parallel lines are identical, and hence, forLines 1 and 2,

and hence

% Under-reach = 14.3%

This amount of under-reach is not significant and noadjustment need be made. If adjustment is required, thiscan be achieved by using the KZ2 relay setting,increasing it over the KZ0 setting by the percentageunder-reach. When this is done, care must also be takenthat the percentage over-reach during single circuitoperation is not excessive – if it is then use can be madeof the alternative setting groups provided in mostmodern distance relays to change the relay settingsaccording to the number of circuits in operation.

13.7.1 11 Ground fault resistive reach settings

The same settings can be used as for the phase faultresistive reaches. Hence,

R3G = 84.8ΩR2G = 84.8ΩR1G = 84.8Ω

This completes the setting of the relay. Table 13.3 alsoshows the settings calculated.

13.8 REFERENCES

13.1 Some factors affecting the accuracy of distancetype protective equipment under earth faultconditions. Davison, E.B. and Wright, A. Proc.IEE Vol. 110, No. 9, Sept. 1963, pp. 1678-1688.

13.2 Distance protection performance underconditions of single-circuit working in double-circuit transmission lines. Humpage, W.D. andKandil, M.S. Proc. IEE. Vol. 117. No. 4, April1970, 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.

% Under-reach Under-reachReach of protected zone

=

Under - reach 8.78 66.3

o= ∠ ×

= ∠

0 5

4 39 66 3

.

. . o Ω

Z

I

I

adj

fltp

flt

impedance of adjacent line

covered by Zone 2

fault current in parallel

line

total fault current

=

=

=

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Introduction 14.1

Application of auto-reclosing 14.2

Auto-reclosing on HV distribution networks 14.3

Factors influencing HV auto-reclose schemes 14.4

Auto-reclosing on EHV transmission lines 14.5

High speed auto-reclosing on EHV systems 14.6

Single-phase auto-reclosing 14.7

High speed auto-reclosing on linesemploying distance schemes 14.8

Delayed auto-reclosing on EHV systems 14.9

Operating features of auto-reclose schemes 14.10

Auto-close circuits 14.11

Examples of auto-reclose applications 14.12

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Chap14 -218-231 17/06/02 9:37 Page 218


14.1 INTRODUCTION

Faults on overhead lines fall into one of three categories:a. transientb. semi-permanentc. permanent

80-90% of faults on any overhead line network aretransient in nature. The remaining 10%-20% of faultsare either semi-permanent or permanent.Transient faults are commonly caused by lightning andtemporary contact with foreign objects. The immediatetripping 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 asemi-permanent fault. The cause of the fault would notbe removed by the immediate tripping of the circuit, butcould be burnt away during a time-delayed trip. HVoverhead lines in forest areas are prone to this type offault. Permanent faults, such as broken conductors, andfaults on underground cable sections, must be locatedand repaired before the supply can be restored.Use of an auto-reclose scheme to re-energise the lineafter a fault trip permits successful re-energisation ofthe line. Sufficient time must be allowed after trippingfor the fault arc to de-energise prior to reclosingotherwise the arc will re-strike. Such schemes have beenthe cause of a substantial improvement in continuity ofsupply. A further benefit, particularly to EHV systems, isthe maintenance of system stability and synchronism.A typical single-shot auto-reclose scheme is shown inFigures 14.1 and 14.2. Figure 14.1 shows a successfulreclosure in the event of a transient fault, and Figure14.2 an unsuccessful reclosure followed by lockout of thecircuit breaker if the fault is permanent.

14.2 APPLICATION OF AUTO-RECLOSING

The most important parameters of an auto-reclosescheme are:

1. dead time2. reclaim time3. single or multi-shot

These parameters are influenced by:a. type of protectionb. type of switchgearc. possible stability problemsd. effects on the various types of consumer loads

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Chap14 -218-231 17/06/02 9:37 Page 219


The weighting given to the above factors is different forHV distribution networks and EHV transmission systemsand therefore it is convenient to discuss them underseparate headings. Sections 14.3 and 14.4 cover theapplication of auto-reclosing to HV distribution networkswhile Sections 14.5-14.9 cover EHV schemes.The rapid expansion in the use of auto-reclosing has ledto the existence of a variety of different control schemes.The various features in common use are discussed inSection 14.10. The related subject of auto-closing, thatis, the automatic closing of normally open circuitbreakers, is dealt with in Section 14.11.

14.3 AUTO-RECLOSING ON HV DISTRIBUTIONNETWORKS

On HV distribution networks, auto-reclosing is applied

mainly to radial feeders where problems of systemstability do not arise, and the main advantages to bederived from its use can be summarised as follows:

a. reduction to a minimum of the interruptions ofsupply to the consumer

b. instantaneous fault clearance can be introduced, withthe accompanying benefits of shorter fault duration,less fault damage, and fewer permanent faults

As 80% of overhead line faults are transient, eliminationof loss of supply from this cause by the introduction ofauto-reclosing gives obvious benefits through:

a. improved supply continuityb. reduction of substation visits

Instantaneous tripping reduces the duration of the

• 14 •

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eclo

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• 2 2 0 •

Reclaim timeTime

Dead time Closingpulse time

Reclose initiated by protectionRelay ready to respond to further fault incidents

(after successful reclosure)

Contactsfully open

Contactsseparate

Trip coilenergised

Arcextinguished

ResetsOperates

Operatingtime

Operating time

Openingtime

Arcingtime

Dead time

Closingtime

Closing circuitenergised

Contactsmake

Contactsfully closed

Instant of fault

System disturbance time

Auto-reclose relay

Transientfault

Circuitbreaker

Protection

Figure 14.2: Operation of single-shot auto-reclose scheme on a permanent fault

Time

Dead time Closingpulse time

Reclose initiatedby protection

Dead timeOperating time

Openingtime

Closingtime

Trip coilenergised

Trip coilenergised

Contactsseparate

Arcextinguished

Contactsfully open

Closing circuitenergised

Contactsmake

Contactsfully closed

Contactsseparate

ArcExtinguished

Contacts fullyopen

Relay locks out for protectionre-operation before reclaim

time has elapsed

Arcingtime

Operatingtime

Operates ResetsReclose

on to fault Operates Resets

Auto-recloserelay

Circuitbreaker

Protection

Permanentfault

Reclaim time starts

Reclaim time resets

Figure 14.1: Single-shot auto-reclose scheme operation for a transient fault

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power arc resulting from an overhead line fault to aminimum. The chance of permanent damage occurringto the line is reduced. The application of instantaneousprotection may result in non-selective tripping of anumber of circuit breakers and an ensuing loss of supplyto a number of healthy sections. Auto-reclosing allowsthese circuit breakers to be reclosed within a fewseconds. With transient faults, the overall effect wouldbe loss of supply for a very short time but affecting alarger number of consumers. If only time-gradedprotection without auto-reclose was used, a smallernumber of consumers might be affected, but for a longertime period.

When instantaneous protection is used with auto-reclosing, the scheme is normally arranged to inhibit theinstantaneous protection after the first trip. For apermanent fault, the time-graded protection will givediscriminative tripping after reclosure, resulting in theisolation of the faulted section. Some schemes allow anumber of reclosures and time-graded trips after thefirst instantaneous trip, which may result in the burningout and clearance of semi-permanent faults. A furtherbenefit of instantaneous tripping is a reduction in circuitbreaker maintenance by reducing pre-arc heating whenclearing transient faults.

When considering feeders that are partly overhead lineand partly underground cable, any decision to installauto-reclosing would be influenced by any data knownon the frequency of transient faults. Where a significantproportion of faults are permanent, the advantages ofauto-reclosing are small, particularly since reclosing onto a faulty cable is likely to aggravate the damage.

14.4 FACTORS INFLUENCING HV AUTO-RECLOSESCHEMES

The factors that influence the choice of dead time,reclaim time, and the number of shots are now discussed.

14.4.1 Dead Time

Several factors affect the selection of system dead timeas follows:

a. system stability and synchronismb. type of loadc. CB characteristicsd. fault path de-ionisation timee. protection reset time

These factors are discussed in the following sections.

14.4.1.1 System stability and synchronism

In order to reclose without loss of synchronism after a faulton the interconnecting feeder, the dead time must be keptto the minimum permissible consistent with de-ionisation

of the fault arc. Other time delays that contribute to thetotal system disturbance time must also be kept as short aspossible. The problem arises only on distribution networkswith more than one power source, where power can be fedinto both ends of an inter-connecting line. A typicalexample is embedded generation (see Chapter 17), orwhere a small centre of population with a local dieselgenerating plant may be connected to the rest of thesupply system by a single tie-line.

The use of high-speed protection, such as unit protectionor distance schemes, with operating times of less than0.05s is essential. The circuit breakers must have veryshort operation times and then be able to reclose thecircuit after a dead time of the order of 0.3s-0.6s toallow for fault-arc de-ionisation.

It may be desirable in some cases to use synchronism checklogic, so that auto-reclosing is prevented if the phase anglehas moved outside specified limits. The matter is dealtwith more fully in Section 14.9 on EHV systems.

14.4.1.2 Type of load

On HV systems, the main problem to be considered inrelation to dead time is the effect on various types ofconsumer load.

a. industrial consumersMost industrial consumers operate mixed loadscomprising induction motors, lighting, processcontrol and static loads. Synchronous motors mayalso be used. Dead time has to be long enough toallow motor circuits to trip out on loos of supply.Once the supply is restored, restarting of drives canthen occur under direction of the process controlsystem in a safe and programmed manner, and canoften be fast enough to ensure no significant lossof production or product quality

b. domestic consumersIt is improbable that expensive processes or dangerousconditions will be involved with domestic consumersand the main consideration is that of inconvenienceand compensation for supply interruption. A deadtime of seconds or a few minutes is of littleimportance compared with the loss of cookingfacilities, central heating, light and audio/visualentertainment resulting from a longer supply failurethat could occur without auto-reclosing

14.4.1.3 Circuit breaker characteristics

The time delays imposed by the circuit breaker during atripping and reclosing operation must be taken intoconsideration, especially when assessing the possibilityof applying high speed auto-reclosing.

a. mechanism resetting time

Most circuit breakers are ‘trip free’, which means thatthe breaker can be tripped during the closing stroke.

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After tripping, a time of the order of 0.2s must beallowed for the trip-free mechanism to reset beforeapplying a closing impulse. Where high speed reclosingis required, a latch check interlock is desirable in thereclosing circuit

b. closing time

This is the time interval between the energisation of theclosing mechanism and the making of the contacts.Owing to the time constant of the solenoid and theinertia of the plunger, a solenoid closing mechanism maytake 0.3s to close. A spring-operated breaker, on theother hand, can close in less than 0.2s. Modern vacuumcircuit breakers may have a closing time of less than 0.1s

The circuit breaker mechanism imposes a minimum deadtime made up from the sum of (a) and (b) above. Figure14.3 illustrates the performance of modern HV circuitbreakers in this respect. Older circuit breakers mayrequire longer times than those shown.

14.4.1.4 De-ionisation of fault path

As mentioned above, successful high speed reclosurerequires the interruption of the fault by the circuitbreaker to be followed by a time delay long enough toallow the ionised air to disperse. This time is dependenton the system voltage, cause of fault, weather conditionsand so on, but at voltages up to 66kV, 0.1s-0.2s shouldbe adequate. On HV systems, therefore, fault de-ionisation time is of less importance than circuit breakertime delays.

14.4.1.5 Protection reset time

If time delayed protection is used, it is essential that thetiming device shall fully reset during the dead time, sothat correct time discrimination will be maintained afterreclosure on to a fault. The reset time of theelectromechanical I.D.M.T. relay is 10 seconds or more

when on maximum time setting, and dead times of atleast this value may be required.

When short dead times are required, the protectionrelays must reset almost instantaneously, a requirementthat is easily met by the use of static, digital andnumerical I.D.M.T. relays.

14.4.2 Reclaim Time

Factors affecting the setting of the reclaim time arediscussed in the following sections.

14.4.2.1 Type of protection

The reclaim time must be long enough to allow theprotection relays to operate when the circuit breaker isreclosed on to a permanent fault. The most commonforms of protection applied to HV lines are I.D.M.T. ordefinite time over-current and earth-fault relays. Themaximum operating time for the former with very lowfault levels could be up to 30 seconds, while for faultlevels of several times rating the operating time may be10 seconds or less.

In the case of definite time protection, settings of 3seconds or less are common, with 10 seconds as anabsolute maximum. It has been common practice to usereclaim times of 30 seconds on HV auto-reclose schemes.However, there is a danger with a setting of this lengththat during a thunderstorm, when the incidence oftransient faults is high, the breaker may reclosesuccessfully after one fault, and then trip and lock outfor a second fault within this time. Use of a shorterreclaim time of, say, 15 seconds may enable the secondfault to be treated as a separate incident, with a furthersuccessful reclosure.

Where fault levels are low, it may be difficult to selectI.D.M.T. time settings to give satisfactory grading with anoperating time limit of 15 seconds, and the matterbecomes a question of selecting a reclaim timecompatible with I.D.M.T. requirements.

It is common to fit sensitive earth-fault protection tosupplement the normal protection in order to detect highresistance earth faults. This protection cannot possiblybe stable on through faults, and is therefore set to havean operating time longer than that of the mainprotection. This longer time may have to be taken intoconsideration when deciding on a reclaim time. A brokenoverhead conductor in contact with dry ground or awood fence may cause this type of fault. It is rarely ifever transient and may be a danger to the public. It istherefore common practice to use a contact on thesensitive earth fault relay to block auto-reclosing andlock out the circuit breaker.

Where high-speed protection is used, reclaim times of 1second or less would be adequate. However, such short

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Figure 14.3: Typical circuit breaker trip-closeoperation times

Tripinitiation

pinitiation

p

Time (s)

Contactsseparate

Arcextinguished

Breaker fully open:closing circuit energised Breaker

fullyclosed

yclosed

Contactsmake

Oil11kV

Vacuum15kV

Oil132kV

Air380kV

SF6132kV

SF6380kV

0.06 0.038 0.03 0.035 0.04 0.020.1 0.053 0.06 0.045 0.07 0.050.08 0.023 0.2 0.235 0.03 0.010.16 0.048 0.35 0.065 0.08 0.060.24 0.28 0.55 0.3 0.11 0.070.02 0.07 0.01 0.02 0.12 0.04

t1

t1t2t3t4tt5tt6

t2t t6t4tt3tt5t

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times are rarely used in practice, to relieve the duty onthe circuit breaker.

14.4.2.2 Spring winding time

The reclaim time of motor-wound spring-closed breakersmust be at least as long as the spring winding time, toensure that the breaker is not subjected to a furtherreclosing operating with a partly wound spring.

14.4.3 Number of Shots

There are no definite rules for defining the number ofshots for any particular auto-reclose application, but anumber of factors must be taken into account.

14.4.3.1 Circuit breaker limitations

Important considerations are the ability of the circuitbreaker to perform several trip and close operations inquick succession and the effect of these operations onthe maintenance period. Maintenance periods varyaccording to the type of circuit breaker used and thefault current broken when clearing each fault. Use ofmodern numerical relays can assist, as they often have aCB condition-monitoring feature included that can bearranged to indicate to a Control Centre whenmaintenance is required. Auto-reclose may then belocked out until maintenance has been carried out.

14.4.3.2 System conditions

If statistical information on a particular system shows amoderate percentage of semi-permanent faults thatcould be burned out during 2 or 3 time-delayed trips, amulti-shot scheme may be justified. This is often thecase in forest areas. Another situation is where fused‘tees’ are used and the fault level is low, since the fusingtime may not discriminate with the main I.D.M.T. relay.The use of several shots will heat the fuse to such anextent that it would eventually blow before the mainprotection operated.

14.5 AUTO-RECLOSING ON EHV TRANSMISSION LINES

The most important consideration in the application ofauto-reclosing to EHV transmission lines is themaintenance of system stability and synchronism. Theproblems involved are dependent on whether thetransmission system is weak or strong. With a weaksystem, loss of a transmission link may lead quickly to anexcessive phase angle across the CB used for re-closure,thus preventing a successful re-closure. In a relativelystrong system, the rate of change of phase angle will beslow, so that delayed auto-reclose can be successfullyapplied.

An illustration is the interconnector between two powersystems as shown in Figure 14.4. Under healthy

conditions, the amount of synchronising powertransmitted, P, crosses the power/angle curve OAB atpoint X, showing that the phase displacement betweenthe two systems is θo. Under fault conditions, the curveOCB 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, theoperating point moves to Z, with an increased phasedisplacement, θ1, between the two systems. At this pointthe circuit breakers trip and break the connection. Thephase displacement continues to increase at a ratedependent on the inertia of the two power sources. Tomaintain synchronism, the circuit breaker must bereclosed in a time short enough to prevent the phaseangle exceeding θ2. This angle is such that the area (2)stays greater than the area (1), which is the condition formaintenance of synchronism.

This example, for a weak system, shows that thesuccessful application of auto-reclosing in such a caseneeds high-speed protection and circuit breakers, and ashort dead time. On strong systems, synchronism isunlikely to be lost by the tripping out of a single line. Forsuch systems, an alternative policy of delayed auto-reclosing may be adopted. This enables the powerswings on the system resulting from the fault to decaybefore reclosure is attempted.

The various factors to be considered when using EHVauto-reclose schemes are now dealt with. High-speedand delayed auto-reclose schemes are discussedseparately.

14.6 HIGH SPEED AUTO-RECLOSING ON EHV SYSTEMS

The first requirement for the application of high-speedauto-reclosing is knowledge of the system disturbance

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Figure 14.4: Effect of high-speed three-phaseauto-reclosing on system stability for a weak system

Input line

Phase displacement

Normal system condition

Pow

er

Fault condition1

2

A

XP

Y

C

B0 θ0 θ1 θ2

Z

Fault

Loads Loads

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time that can be tolerated without loss of systemstability. This will normally require transient stabilitystudies to be conducted for a defined set of powersystem configurations and fault conditions. Withknowledge of protection and circuit breaker operatingcharacteristics and fault arc de-ionisation times, thefeasibility of high-speed auto-reclosing can then beassessed. These factors are now discussed.

14.6.1 Protection Characteristics

The use of high-speed protection equipment, such asdistance or unit protection schemes, giving operatingtimes of less than 50ms, is essential. In conjunction withfast operating circuit breakers, high-speed protectionreduces the duration of the fault arc and thus the totalsystem disturbance time.

It is important that the circuit breakers at both ends of afault line should be tripped as rapidly as possible. Thetime that the line is still being fed from one endrepresents an effective reduction in the dead time, andmay well jeopardise the chances of a successfulreclosure. When distance protection is used, and thefault occurs near one end of the line, special measureshave to be adopted to ensure simultaneous tripping ateach end. These are described in Section 14.8.

14.6.2 De-Ionisation of Fault Arc

It is important to know the time that must be allowed forcomplete de-ionisation of the arc, to prevent the arcrestriking when the voltage is re-applied.

The de-ionisation time of an uncontrolled arc, in free airdepends on the circuit voltage, conductor spacing, faultcurrents, fault duration, wind speed and capacitivecoupling from adjacent conductors. Of these, the circuitvoltage is the most important, and as a general rule, thehigher the voltage the longer the time required for de-ionisation. Typical values are given in Table 14.1.

If single-phase tripping and auto-reclosing is used,capacitive coupling between the healthy phases and thefaulty phase tends to maintain the arc and hence extend

the dead time required. This is a particular problem onlong distance EHV transmission lines.

14.6.3 Circuit Breaker Characteristics

The high fault levels involved in EHV systems imposes avery severe duty on the circuit breakers used in high-speed auto-reclose schemes. The accepted breaker cycleof break-make-break requires the circuit breaker tointerrupt the fault current, reclose the circuit after atime delay of upwards of 0.2s and then break the faultcurrent again if the fault persists. The types of circuitbreaker commonly used on EHV systems are oil, air blastand SF6 types.

14.6.3.1 Oil circuit breakers

Oil circuit breakers are used for transmission voltages upto 300kV, and can be subdivided into the two types: ‘bulkoil’ and ‘small oil volume’. The latter is a design aimed atreducing the fire hazard associated with the largevolume of oil contained in the bulk oil breaker.

The operating mechanisms of oil circuit breakers are oftwo types, ‘fixed trip’ and ‘trip free’, of which the latteris the most common. With trip-free types, the reclosingcycle must allow time for the mechanism to reset aftertripping before applying the closing impulse.

Special means have to be adopted to obtain the shortdead times required for high-speed auto-reclosing.Various types of tripping mechanism have beendeveloped to meet this requirement.

The three types of closing mechanism fitted to oil circuitbreakers are:

i. solenoidii. springiii. pneumatic

CB’s with solenoid closing are not suitable for high-speed auto-reclose due to the long time constantinvolved. Spring, hydraulic or pneumatic closingmechanisms are universal at the upper end of the EHVrange and give the fastest closing time. Figure 14.3shows the operation times for various types of EHVcircuit breakers, including the dead time that can beattained.

14.6.3.2 Air blast circuit breakers

Air blast breakers have been developed for voltages up tothe highest at present in use on transmission lines. Theyfall into two categories:

a. pressurised head circuit breakersb. non-pressurised head circuit breakers

In pressurised head circuit breakers, compressed air ismaintained in the chamber surrounding the maincontacts. When a tripping signal is received, an auxiliary

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Line voltage (kV) Minimum de-energisation time(seconds)

66 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

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air system separates the main contacts and allowscompressed air to blast through the gap to theatmosphere, extinguishing the arc. With the contactsfully 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 arcin the de-pressurised chamber. For this reason,sequential series isolators, which isolate the maincontacts after tripping, are commonly used with air blastbreakers. Since these are comparatively slow in opening,their operation must be inhibited when auto-reclosing isrequired. A contact on the auto-reclose relay is madeavailable for this purpose.

Non-pressurised head circuit breakers are slower inoperation than the pressurised head type and are notusually applied in high-speed reclosing schemes.

14.6.3.3 SF6 circuit breakers

Most EHV circuit breaker designs now manufactured useSF6 gas as an insulating and arc-quenching medium. Thebasic design of such circuit breakers is in many wayssimilar to that of pressurised head air blast circuitbreakers, and normally retain all, or almost all, of theirvoltage withstand capability, even if the SF6 pressure levelfalls to atmospheric pressure. Sequential series isolatorsare therefore not normally used, but they are sometimesspecified to prevent damage to the circuit breaker in theevent of a lightning strike on an open ended conductor.Provision should therefore be made to inhibit sequentialseries isolation during an auto-reclose cycle.

14.6.4 Choice of Dead Time

At voltages of 220kV and above, the de-ionisation timewill probably dictate the minimum dead time, ratherthan any circuit breaker limitations. This can be deducedfrom Table 14.1. The dead time setting on a high-speedauto-reclose relay should be long enough to ensurecomplete de-ionisation of the arc. On EHV systems, anunsuccessful reclosure is more detrimental to the systemthan no reclosure at all.

14.6.5 Choice of Reclaim Time

Where EHV oil circuit breakers are concerned, thereclaim time should take account of the time needed forthe closing mechanism to reset ready for the nextreclosing operation.

14.6.6 Number of Shots

High-speed auto-reclosing on EHV systems is invariablysingle shot. Repeated reclosure attempts with high faultlevels would have serious effects on system stability, so

the circuit breakers are locked out after one unsuccessfulattempt. Also, the incidence of semi-permanent faultswhich can be cleared by repeated reclosures is less likelythan on HV systems.

14.7 SINGLE-PHASE AUTO-RECLOSING

Single phase to earth faults account for the majority ofoverhead line faults. When three-phase auto-reclosingis applied to single circuit interconnectors between twopower systems, the tripping of all three phases maycause the two systems to drift apart in phase, asdescribed in Section 14.5. No interchange ofsynchronising power can take place during the deadtime. If only the faulty phase is tripped, synchronisingpower can still be interchanged through the healthyphases. Any difference in phase between the twosystems will be correspondingly less, leading to areduction in the disturbance on the system when thecircuit breaker recloses.

For single-phase auto-reclosing each circuit breaker polemust be provided with its own closing and trippingmechanism; this is normal with EHV air blast and SF6breakers. The associated tripping and reclosing circuitryis therefore more complicated, and, except in distanceschemes, the protection may need the addition of phaseselection logic.

On the occurrence of a phase-earth fault, single-phaseauto-reclose schemes trip and reclose only thecorresponding pole of the circuit breaker. The auto-reclose function in a relay therefore has three separateelements, one for each phase. Operation of any elementenergises the corresponding dead timer, which in turninitiates a closing pulse for the appropriate pole of thecircuit 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 faultis persistent and reclosure is unsuccessful, it is usual totrip and lock out all three poles of the circuit breaker.

The above describes only one of many variants. Otherpossibilities are:

a. three-phase trip and lockout for phase-phase or 3-phase faults, or if either of the remaining phasesshould develop a fault during the dead time

b. use of a selector switch to give a choice of singleor three-phase reclosing

c. combined single and three-phase auto-reclosing;single phase to earth faults initiate single-phasetripping and reclosure, and phase-phase faultsinitiate three-phase tripping and reclosure

Modern numerical relays often incorporate the logic forall of the above schemes, for the user to select asrequired. Use can be made of any user-definable logic

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feature in a numerical relay to implement other schemesthat may be required.

The advantages of single-phase auto-reclosing are:

a. the maintenance of system integrity

b. on multiple earth systems, negligible interferencewith the transmission of load. This is because thecurrent in the faulted phase can flow throughearth via the various earthing points until the faultis cleared and the faulty phase restored

The main disadvantage is the longer de-ionisation timeresulting from capacitive coupling between the faultyand healthy lines. This leads to a longer dead time beingrequired. Maloperation of earth fault relays on doublecircuit lines owing to the flow of zero sequence currentsmay also occur. These are induced by mutual inductionbetween faulty and healthy lines (see Chapter 13 fordetails).

14.8 HIGH-SPEED AUTO-RECLOSING ON LINESEMPLOYING DISTANCE SCHEMES

The importance of rapid tripping of the circuit breakersat each end of a faulted line where high-speed auto-reclosing is employed has already been covered inSection 14.6. Simple distance protection presents somedifficulties in this respect.

Owing to the errors involved in determining the ohmicsetting of the distance relays, it is not possible to set Zone1 of a distance relay to cover 100% of the protected line– see Chapter 11 for more details. Zone 1 is set to cover80-85% of the line length, with the remainder of the linecovered by time-delayed Zone 2 protection.

Figure 14.5 illustrates this for a typical three-zonedistance scheme covering two transmission lines.

For this reason, a fault occurring in an end zone wouldbe cleared instantaneously, by the protection at one endof the feeder. However, the CB at the other end opens in0.3-0.4 seconds (Zone 2 time). High-speed auto-

reclosing applied to the circuit breakers at each end ofthe feeder could result either in no dead time or in adead time insufficient to allow de-ionisation of the faultarc. A transient fault could therefore be seen as apermanent one, resulting in the locking out of bothcircuit breakers.

Two methods are available for overcoming this difficulty.Firstly, one of the transfer-trip or blocking schemes thatinvolves the use of an intertrip signal between the twoends of the line can be used. Alternatively, a Zone 1extension scheme may be used to give instantaneoustripping over the whole line length. Further details ofthese schemes are given in Chapter 12, but a briefdescription of how they are used in conjunction with anauto-reclose scheme is given below.

14.8.1 Transfer-Trip or Blocking Schemes

This involves use of a signalling channel between the twoends of the line. Tripping occurs rapidly at both ends ofthe 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 identifywhich phase should be tripped, but this problem does notexist if a modern numerical relay is used.

Irrespective of the scheme used, it is customary toprovide an auto-reclose blocking relay to prevent thecircuit breakers auto-reclosing for faults seen by thedistance relay in Zones 2 and 3.

14.8.2 Zone 1 Extension

In this scheme, the reach of Zone 1 is normally extendedto 120% of the line length and is reset to 80% when acommand from the auto-reclose logic is received. Thisauto-reclose logic signal should occur before a closingpulse is applied to the circuit breaker and remain operateduntil the end of the reclaim time. The logic signal shouldalso be present when auto-reclose is out of service.

14.9 DELAYED AUTO-RECLOSING ON EHV SYSTEMS

On highly interconnected transmission systems, wherethe loss of a single line is unlikely to cause two sectionsof the system to drift apart significantly and losesynchronism, delayed auto-reclosing can be employed.Dead times of the order of 5s-60s are commonly used. Noproblems are presented by fault arc de-ionisation timesand circuit breaker operating characteristics, and powerswings 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

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Figure 14.5: Typical three zone distance scheme

EndZone Zone

EndZone 1(G) Zone 1(J)

MiddleZone

Zone 2 (G) Zone 2(J)

G H J K

Zone 1(H)Zone 2(H)

Zone 2(K)

Zone 1(K)

Zone 3(H)

Zone 3(K)

Zone 3(G)

Zone 3(J)

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successful are somewhat greater with delayed reclosingthan would be the case with high-speed reclosing.

14.9.1 Scheme Operation

The sequence of operations of a delayed auto-reclosescheme can be best understood by reference to Figure14.6. This shows a transmission line connecting twosubstations A and B, with the circuit beakers at A and Btripping out in the event of a line fault. Synchronism isunlikely to be lost in a system that employs delayed auto-reclose. However, the transfer of power through theremaining tie-lines on the system could result in thedevelopment of an excessive phase difference between thevoltages at points A and B. The result, if reclosure takesplace, is an unacceptable shock to the system. It istherefore usual practice to incorporate a synchronismcheck relay into the reclosing system to determinewhether auto-reclosing should take place.

After tripping on a fault, it is normal procedure to reclosethe breaker at one end first, a process known as ‘livebus/dead line charging’. Reclosing at the other and isthen under the control of a synchronism check relayelement for what is known as ‘live bus/live line reclosing’.

For example, if it were decided to charge the line initiallyfrom station A, the dead time in the auto-reclose relayat A would be set at, say, 5 seconds, while thecorresponding timer in the auto-reclose relay at B wouldbe set at, say, 15 seconds. The circuit beaker at A wouldthen reclose after 5 seconds provided that voltagemonitoring relays at A indicated that the busbars werealive and the line dead. With the line recharged, thecircuit breaker at B would then reclose with asynchronism check, after a 2 second delay imposed bythe synchronism check relay element.

If for any reason the line fails to ‘dead line charge’ fromend A, reclosure from end B would take place after 15seconds. The circuit breaker at A would then be giventhe opportunity to reclose with a synchronism check.

14.9.2 Synchronism Check Relays

The synchronism check relay element commonly providesa three-fold check:

i. phase angle differenceii. voltageiii. frequency difference

The phase angle setting is usually set to between20o–45o, and reclosure is inhibited if the phase differenceexceeds this value. The scheme waits for a reclosingopportunity with the phase angle within the set value,but locks out if reclosure does not occur within a definedperiod, typically 5s.

A voltage check is incorporated to prevent reclosureunder various circumstances. A number of differentmodes may be available. These are typicallyundervoltage 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 inconjunction with the phase angle check. In the lattercase, if a 2 second timer is employed, the logic gives anoutput only if the phase difference does not exceed thephase angle setting over a period of 2 seconds. Thislimits the frequency difference (in the case of a phaseangle setting of 20o) to a maximum of 0.11% of 50Hz,corresponding to a phase swing from +20o to -20o overthe measured 2 seconds. While a significant frequencydifference is unlikely to arise during a delayed auto-reclose sequence, the time available allows this check tobe 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 mayneed to be implemented. A numerical relay will typicallyallow any combination of these modes to beimplemented. The voltage settings for distinguishingbetween ‘live’ and ‘dead’ conditions must be carefullychosen. In addition, the locations of the VT’s must beknown and checked so that the correct voltage signalsare connected to the ‘line’ and ‘bus’ inputs.

14.10 OPERATING FEATURES OF AUTO-RECLOSESCHEMES

The extensive use of auto-reclosing has resulted in theexistence of a wide variety of different control schemes.Some of the more important variations in the featuresprovided are described below.

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&

System healthy

Protn. resetCB healthy

CB openDead time

AR inhibittime

Reclaim timer

AR lockout

CB closed

Protn. operated(local or

intertrip)

0

CB closecommand

ARin progressR

S

&

&&

1 ti

1

tR 0

td 0

Q

QRS

(b) Autoreclose logic for each CB

(a) Network diagram

A B

tR: reclaim timeti: inhibit timetd: dead time

Q

Q

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14.10.1 Initiation

Modern auto-reclosing schemes are invariably initiatedby the tripping command of a protection relay function.Some older schemes may employ a contact on the circuitbreaker. Modern digital or numerical relays oftenincorporate a comprehensive auto-reclose facility withinthe relay, thus eliminating the need for a separate auto-reclose relay and any starter relays.

14.10.2 Type of Protection

On HV distribution systems, advantage is often taken ofauto-reclosing to use instantaneous protection for thefirst trip, followed by I.D.M.T. for subsequent trips in asingle fault incident. In such cases, the auto-recloserelay must provide a means of isolating theinstantaneous relay after the first trip. In older schemes,this may be done with a normally closed contact on theauto-reclose starting element wired into the connectionbetween the instantaneous relay contact and the circuitbreaker trip coil. With digital or numerical relays within-built auto-reclose facilities, internal logic facilitieswill normally be used.

With certain supply authorities, it is the rule to fittripping relays to every circuit breaker. If auto-reclosingis required, electrically reset tripping relays must be used,and a contact must be provided either in the auto-reclose logic or by separate trip relay resetting scheme toenergise the reset coil before reclosing can take place.

14.10.3 Dead Timer

This will have a range of settings to cover the specifiedhigh-speed or delayed reclosing duty. Any interlocks thatare needed to hold up reclosing until conditions aresuitable can be connected into the dead timer circuit.Section 14.12.1 provides an example of this applied totransformer feeders.

14.10.4 Reclosing Impulse

The duration of the reclosing impulse must be related tothe requirements of the circuit breaker closingmechanism. On auto-reclose schemes using spring-closedbreakers, it is sufficient to operate a contact at the end ofthe dead time to energise the latch release coil on thespring-closing mechanism. A circuit breaker auxiliaryswitch can be used to cancel the closing pulse and resetthe auto-reclose relay. With solenoid operated breakers,it is usual to provide a closing pulse of the order of 1-2seconds, so as to hold the solenoid energised for a shorttime after the main contacts have closed. This ensuresthat the mechanism settles in the fully latched-inposition. The pneumatic or hydraulic closing mechanisms

fitted to oil, air blast and SF6 circuit breakers use a circuitbreaker auxiliary switch for terminating the closing pulseapplied by the auto-reclose relay.

14.10.5 Anti-Pumping Devices

The function of an anti-pumping device is to prevent thecircuit breaker closing and opening several times in quicksuccession. This might be caused by the application of aclosing pulse while the circuit breaker is being trippedvia the protection relays. Alternatively, it may occur ifthe circuit breaker is closed on to a fault and the closingpulse is longer than the sum of protection relay andcircuit breaker operating times. Circuit breakers withtrip free mechanisms do not require this feature.

14.10.6 Reclaim Timer

Electromechanical, static or software-based timers areused to provide the reclaim time, depending on the relaytechnology used. If electromechanical timers are used, itis convenient to employ two independently adjustabletimed contacts to obtain both the dead time and thereclaim time on one timer. With static and software-based timers, separate timer elements are generallyprovided.

14.10.7 CB Lockout

If reclosure is unsuccessful the auto-reclose relay locksout the circuit breaker. Some schemes provide a lockoutrelay with a flag, with provision of a contact for remotealarm. The circuit breaker can then only be closed byhand; this action can be arranged to reset the auto-reclose relay element automatically. Alternatively, mostmodern relays can be configured such that a lockoutcondition can be reset only by operator action.

Circuit breaker manufacturers state the maximumnumber of operations allowed before maintenance isrequired. A number of schemes provide a fault tripcounting function and give a warning when the totalapproaches the manufacturer's recommendation. Theseschemes will lock out when the total number of faulttrips has reached the maximum value allowed.

14.10.8 Manual Closing

It is undesirable to permit auto-reclosing if circuitbreaker closing is manually initiated. Auto-recloseschemes include the facility to inhibit auto-recloseinitiation for a set time following manual CB closure.The time is typically in the range of 2-5 seconds.

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14.10.9 Multi-Shot Schemes

Schemes providing up to three or four shots use timingcircuits are often included in an auto-reclose relay toprovide different, independently adjustable, dead timesfor each shot. Instantaneous protection can be used forthe first trip, since each scheme provides a signal toinhibit instantaneous tripping after a set number of tripsand selects I.D.M.T. protection for subsequent ones. Thescheme resets if reclosure is successful within the chosennumber of shots, ready to respond to further faultincidents.

14.11 AUTO-CLOSE SCHEMES

Auto-close schemes are employed to close automaticallycircuit breakers that are normally open when the supplynetwork is healthy. This may occur for a variety ofreasons, for instance the fault level may be excessive ifthe CB’s were normally closed. The circuits involved arevery similar to those used for auto-reclosing. Two typicalapplications are described in the following sections.

14.11.1 Standby Transformers

Figure 14.7 shows a busbar station fed by threetransformers, T1, T2 and T3. The loss of one transformermight cause serious overloading of the remaining two.However, connection of a further transformer toovercome this may increase the fault level to anunacceptable value.

The solution is to have a standby transformer T4permanently energised from the primary side andarranged to be switched into service if one of the otherstrips on fault.

The starting circuits for breaker CB4 monitor theoperation of transformer protection on any of thetransformers T1, T2 and T3 together with the tripping ofan associated circuit breaker CB1-CB3. In the event ofa fault, the auto-close circuit is initiated and circuitbreaker CB4 closes, after a short time delay, to switch in

the standby transformer. Some schemes employ anauto-tripping relay, so that when the faulty transformeris returned to service, the standby is automaticallydisconnected.

14.11.2 Bus Coupler or Bus Section Breaker

If all four power transformers are normally in service forthe system of Figure 14.7, and the bus sections areinterconnected by a normally-open bus section breakerinstead of the isolator, the bus section breaker should beauto-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 acceptablewith the bus-section breaker closed.Starting and auto-trip circuits are employed as in thestand-by scheme. The auto-close relay used in practiceis a variant of one of the standard auto-reclose relays.

14.12 EXAMPLES OF AUTO-RECLOSE APPLICATIONS

Auto-reclose facilities in common use for a number ofstandard substation configurations are described in thefollowing sections.

14.12.1 Double Busbar Substation

A typical double busbar station is illustrated in Figure14.8. Each of the six EHV transmission lines brought intothe station is under the control of a circuit breaker, CB1to CB6 inclusive, and each transmission line can beconnected either to the main or to the reserve busbars bymanually operated isolators.

Bus section isolators enable sections of busbar to beisolated in the event of fault, and bus coupler breaker BCpermits sections of main and reserve bars to beinterconnected.

14.12.1.1 Basic scheme – banked transformers omitted

Each line circuit breaker is provided with an auto-recloserelay that recloses the appropriate circuit breakers in the

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Figure 14.7: Standby transformer with auto-closing

T2 T3 T4

CB1 CB2 CB4withauto-closing

(Standby)

CB3

T1

Figure 14.8: Double busbar substation

CB1 CB2 CB3CB2A

L1 L3

BC

Line 1 Line 2 Line 3 Line 4 Line 5 Line 6

Bus C

EHVBusbars

Main

Reserve

T1

T2IT1

IT2

CB1AL2

CB4 CB5 CB6

L4 L6L5

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event of a line fault. For a fault on Line 1, this wouldrequire opening of CB1 and the corresponding CB at theremote end of the line. The operation of either thebusbar protection or a VT Buchholz relay is arranged tolock out the auto-reclosing sequence. In the event of apersistent fault on Line 1, the line circuit breakers tripand lock out after one attempt at reclosure.

14.12.1.2 Scheme with banked transformers

Some utilities use a variation of the basic scheme inwhich Transformers T1 and T2 are banked off Lines 1and 2, as shown in Figure 14.8. This provides someeconomy in the number of circuit breakers required. Thecorresponding transformer circuits 1 and 2 are tee'd offLines 1 and 2 respectively. The transformer secondariesare connected to a separate HV busbar system via circuitbreakers CB1A and CB2A.

Auto-reclose facilities can be extended to cover thecircuits for banked transformers where these are used.For example, a fault on line 1 would cause the trippingof circuit breakers CB1, CB1A and the remote linecircuit breaker. When Line 1 is re-energised, either byauto-reclosure of CB1 or by the remote circuit breaker,whichever is set to reclose first, transformer T1 is alsoenergised. CB1A will not reclose until the appearanceof transformer secondary voltage, as monitored by thesecondary VT; it then recloses on to the HV busbars aftera short time delay, with a synchronism check if required.

In the event of a fault on transformer T1, the local andremote line circuit breakers and breaker CB1A trip toisolate the fault. Automatic opening of the motorisedtransformer isolator IT1 follows this. The line circuitbreakers then reclose in the normal manner and circuitbreaker CB1A locks out.

A shortcoming of this scheme is that this results inhealthy transformer T1 being isolated from the system;also, isolator L1 must be opened manually before circuitbreakers CB1 and CB1A, can be closed to re-establishsupply to the HV busbars via the transformer. A variantof this scheme is designed to instruct isolator L1 to openautomatically following a persistent fault on Line 1 andprovide a second auto-reclosure of CB1 and CB1A. Thesupply to Bus C is thereby restored without manualintervention.

14.12.2 Single Switch Substation

The arrangement shown in Figure 14.9 consists basicallyof two transformer feeders interconnected by a singlecircuit breaker 120. Each transformer therefore has analternative source of supply in the event of loss of one orother of the feeders.

For example, a transient fault on Line 1 causes trippingof circuit breakers 120 and B1 followed by reclosure ofCB 120. If the reclosure is successful, Transformer T1 isre-energised and circuit breaker B1 recloses after a shorttime delay.

If the line fault is persistent, 120 trips again and themotorised line isolator 103 is automatically opened. Circuitbreaker 120 recloses again, followed by B1, so that bothtransformers T1 and T2 are then supplied from Line 2.

A transformer fault causes the automatic opening of theappropriate transformer isolator, lock-out of thetransformer secondary circuit breaker and reclosure ofcircuit breaker 120. Facilities for dead line charging orreclosure with synchronism check are provided for eachcircuit breaker.

14.12.3 Four-Switch Mesh Substation

The mesh substation illustrated in Figure 14.10 isextensively used by some utilities, either in full or part.The basic mesh has a feeder at each corner, as shown atmesh corners MC2, MC3 and MC4. One or twotransformers may also be banked at a mesh corner, asshown at MC1. Mesh corner protection is required if morethan one circuit is fed from a mesh corner, irrespective ofthe CT locations – see Chapter 15 for more details.

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Figure 14.9: Single switch substation

EHV Line 2

T1

103 120 203

213

B2

T2

EHV Line 1Bus A

Bus BB1

113

Figure 14.10: Four-switch mesh substation

Line 2 Line 3

Line 1 Line 4

113A

T1A T1B

G1A G1B

403

303

420

220

MC1 MC4

MC3

120 320mesh corner

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Considerable problems can are encountered in theapplication of auto-reclosing to the mesh substation. Forexample, circuit breakers 120 and 420 in Figure 14.10are tripped out for a variety of different types of faultassociated with mesh corner 1 (MC1), and each requiresdifferent treatment as far as auto-reclosing is concerned.Further variations occur if the faults are persistent.

Following normal practice, circuit breakers must bereclosed in sequence, so sequencing circuits arenecessary for the four mesh breakers. Closing prioritymay be in any order, but is normally 120, 220, 320, and420.

A summary of facilities is now given, based on meshcorner MC1 to show the inclusion of bankedtransformers; facilities at other corners are similar butomit the operation of equipment solely associated withthe banked transformers.

14.12.3.1 Transient fault on Line 1

Tripping of circuit breakers 120, 420, G1A and G1B isfollowed by reclosure of 120 to give dead line chargingof Line 1. Breaker 420 recloses in sequence, with asynchronism check. Breakers G1A, G1B reclose with asynchronism check if necessary.

14.12.3.2 Persistent fault on Line 1

Circuit breaker 120 trips again after the first reclosureand isolator 103 is automatically opened to isolate thefaulted line. Breakers 120, 420, G1A and G1B thenreclose in sequence as above.

14.12.3.3 Transformer fault (local transformer 1A)

Automatic opening of isolator 113A to isolate thefaulted transformer follows tripping of circuit breakers120, 420, G1A and G1B. Breakers 120, 420 and G1Bthen reclose in sequence, and breaker G1A is locked out.

14.12.3.4 Transformer fault (remote transformer)

For a remote transformer fault, an intertrip signal isreceived at the local station to trip breakers 120, 420,G1A and G1B and inhibit auto-reclosing until thefaulted transformer has been isolated at the remotestation. If the intertrip persists for 60 seconds it isassumed that the fault cannot be isolated at the remotestation. Isolator 103 is then automatically opened andcircuit breakers 120, 420, G1A and G1B are reclosed insequence.

14.12.3.5 Transient mesh corner fault

Any fault covered by the mesh corner protection zone,shown in Figure 14.10, results in tripping of circuitbreakers 120, 420, G1A and G1B. These are thenreclosed in sequence.

There may be circumstances in which reclosure onto apersistent 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 reclosureand locks out the circuit breakers.

14.12.3.6 Persistent mesh corner fault

The sequence describe in Section 14.12.3.5 is followedinitially. When CB 120 is reclosed, it will trip again dueto the fault and lock out. At this point, the logic inhibitsthe reclosure of CB’s 420, G1A and G1B and locks outthese CB’s. Line isolator 103 is automatically opened toisolate the fault from the remote station.

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Introduction 15.1Busbar faults 15.2

Protection requirements 15.3Types of protection system 15.4System protection schemes 15.5

Frame-earth protection(Howard protection) 15.6

Differential protection principles 15.7

High impedancedifferential protection 15.8Low impedance biaseddifferential protection 15.9

Numerical busbar protection 15.10References 15.11

• 1 5 • B u s b a r P r o t e c t i o n

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15.1 INTRODUCTION

The protection scheme for a power system should coverthe whole system against all probable types of fault.Unrestricted forms of line protection, such as overcurrentand distance systems, meet this requirement, althoughfaults in the busbar zone are cleared only after sometime delay. But if unit protection is applied to feedersand plant, the busbars are not inherently protected.

Busbars have often been left without specific protection,for one or more of the following reasons:

a. the busbars and switchgear have a high degree ofreliability, to the point of being regarded asintrinsically safe

b. it was feared that accidental operation of busbarprotection might cause widespread dislocation ofthe power system, which, if not quickly cleared,would cause more loss than would the veryinfrequent actual bus faults

c. it was hoped that system protection or back-upprotection would provide sufficient bus protectionif needed

It is true that the risk of a fault occurring on modernmetal-clad gear is very small, but it cannot be entirelyignored. However, the damage resulting from oneuncleared fault, because of the concentration of faultMVA, may be very extensive indeed, up to the completeloss of the station by fire. Serious damage to ordestruction of the installation would probably result inwidespread and prolonged supply interruption.

Finally, system protection will frequently not provide thecover required. Such protection may be good enough forsmall distribution substations, but not for importantstations. Even if distance protection is applied to allfeeders, the busbar will lie in the second zone of all thedistance protections, so a bus fault will be clearedrelatively slowly, and the resultant duration of thevoltage dip imposed on the rest of the system may not betolerable.

With outdoor switchgear the case is less clear since,although the likelihood of a fault is higher, the risk ofwidespread damage resulting is much less. In generalthen, busbar protection is required when the systemprotection does not cover the busbars, or when, in order

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to maintain power system stability, high-speed faultclearance is necessary. Unit busbar protection providesthis, with the further advantage that if the busbars aresectionalised, one section only need be isolated to cleara fault. The case for unit busbar protection is in factstrongest 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 significantnumber are interphase clear of earth. In fact, a largeproportion of busbar faults result from human errorrather than the failure of switchgear components.

With fully phase-segregated metalclad gear, only earthfaults are possible, and a protection scheme need haveearth fault sensitivity only. In other cases, an ability torespond 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 circuitprotection, the key position of the busbar intensifies theemphasis put on the essential requirements of speed andstability. The special features of busbar protection arediscussed below.

15.3.1 Speed

Busbar protection is primarily concerned with:

a. limitation of consequential damage

b. removal of busbar faults in less time than could beachieved by back-up line protection, with theobject of maintaining system stability

Some early busbar protection schemes used a lowimpedance differential system having a relatively longoperation time, of up to 0.5 seconds. The basis of mostmodern schemes is a differential system using either lowimpedance biased or high impedance unbiased relayscapable of operating in a time of the order of one cycleat a very moderate multiple of fault setting. To this mustbe added the operating time of the tripping relays, but anoverall tripping time of less than two cycles can beachieved. With high-speed circuit breakers, completefault clearance may be obtained in approximately 0.1seconds. When a frame-earth system is used, theoperating speed is comparable.

15.3.2 Stability

The stability of bus protection is of paramountimportance. Bearing in mind the low rate of fault

incidence, amounting to no more than an average of onefault per busbar in twenty years, it is clear that unlessthe stability of the protection is absolute, the degree ofdisturbance to which the power system is likely to besubjected may be increased by the installation of busprotection. The possibility of incorrect operation has, inthe past, led to hesitation in applying bus protection andhas also resulted in application of some very complexsystems. Increased understanding of the response ofdifferential systems to transient currents enables suchsystems to be applied with confidence in theirfundamental stability. The theory of differentialprotection is given later in Section 15.7.

Notwithstanding the complete stability of a correctlyapplied protection system, dangers exist in practice for anumber of reasons. These are:

a. interruption of the secondary circuit of a currenttransformer will produce an unbalance, whichmight cause tripping on load depending on therelative values of circuit load and effective setting.It would certainly do so during a through fault,producing substantial fault current in the circuit inquestion

b. a mechanical shock of sufficient severity maycause operation, although the likelihood of thisoccurring with modern numerical schemes isreduced

c. accidental interference with the relay, arising froma mistake during maintenance testing, may lead tooperation

In order to maintain the high order of integrity neededfor busbar protection, it is an almost invariable practiceto make tripping depend on two independentmeasurements of fault quantities. Moreover, if thetripping of all the breakers within a zone is derived fromcommon measuring relays, two separate elements mustbe operated at each stage to complete a trippingoperation. Although not current practice, in many casesthe relays are separated by about 2 metres so that noreasonable accidental mechanical interference to bothrelays simultaneously is possible.

The two measurements may be made by two similardifferential systems, or one differential system may bechecked by a frame-earth system, by earth fault relaysenergised by current transformers in the transformerneutral-earth conductors or by overcurrent relays.Alternatively, a frame-earth system may be checked byearth fault relays.

If two systems of the unit or other similar type are used,they should be energised by separate currenttransformers in the case of high impedance unbiaseddifferential schemes. The duplicate ring CT cores may bemounted on a common primary conductor but

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independence must be maintained throughout thesecondary circuit.

In the case of low impedance, biased differentialschemes that cater for unequal ratio CT's, the schemecan be energised from either one or two separate sets ofmain current transformers. The criteria of double featureoperation before tripping can be maintained by theprovision of two sets of ratio matching interposing CT'sper circuit. When multi-contact tripping relays are used,these are also duplicated, one being energised from eachdiscriminating relay; the contacts of the tripping relayare then series-connected in pairs to provide trippingoutputs.

Separate tripping relays, each controlling one breakeronly, are usually preferred. The importance of such relaysis then no more than that of normal circuit protection, sono duplication is required at this stage. Not least amongthe advantages of using individual tripping relays is thesimplification of trip circuit wiring, compared withtaking all trip circuits associated with a given bus sectionthrough a common multi-contact tripping relay.

In double busbar installations, a separate protectionsystem is applied to each section of each busbar; anoverall check system is provided, covering all sections ofboth busbars. The separate zones are arranged tooverlap the busbar section switches, so that a fault onthe section switch trips both the adjacent zones. Thishas sometimes been avoided in the past by giving thesection switch a time advantage; the section switch istripped first and the remaining breakers delayed by 0.5seconds.

Only the zone on the faulty side of the section switchwill remain operated and trip, the other zone resettingand retaining that section in service. This gain,applicable only to very infrequent section switch faults,is obtained at the expense of seriously delaying the busprotection for all other faults. This practice is thereforenot generally favoured. Some variations are dealt withlater under the more detailed scheme descriptions. Thereare many combinations possible, but the essentialprinciple is that no single accidental incident of asecondary nature shall be capable of causing anunnecessary trip of a bus section.

Security against maloperation is only achieved byincreasing the amount of equipment that is required tofunction to complete an operation; and this inevitablyincreases the statistical risk that a tripping operation dueto a fault may fail. Such a failure, leaving aside thequestion of consequential damage, may result indisruption of the power system to an extent as great, orgreater, than would be caused by an unwanted trip. Therelative risk of failure of this kind may be slight, but ithas been thought worthwhile in some instances toprovide a guard in this respect as well.

Security of both stability and operation is obtained byproviding 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.

15.4 TYPES OF PROTECTION SYSTEM

A number of busbar protection systems have beendevised:

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, while(d) and (e) are obsolete. 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 ascheme using harmonic restraint, were superseded byunbiased high impedance differential protection.

The relative simplicity of the latter, and more importantlythe relative ease with which its performance can becalculated, have ensured its success up to the presentday.

But more recently the advances in semiconductortechnology, coupled with a more pressing need to be ableto accommodate CT's of unequal ratio, have led to there-introduction of biased schemes, generally using staticrelay designs, particularly for the most extensive andonerous applications.

Frame-earth protection systems have been in use formany years, mainly associated with smaller busbarprotection schemes at distribution voltages and formetalclad busbars (e.g. SF6 insulated busbars). However,it has often been quite common for a unit protectionscheme to be used in addition, to provide two separatemeans of fault detection.

The different types of protection are described in thefollowing sections.

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Pro

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Tripcircuits

X Y

Y Z

Z X

+ _

Figure 15 .1 : Two-out-of-three pr inc ip le

Chap15-232-253 17/06/02 9:46 Page 235

15.5 SYSTEM PROTECTION SCHEMES

System protection that includes overcurrent or distancesystems will inherently give protection cover to thebusbars. Overcurrent protection will only be applied torelatively simple distribution systems, or as a back-upprotection, set to give a considerable time delay.Distance protection will provide cover for busbar faultswith its second and possibly subsequent zones. In bothcases the busbar protection obtained is slow and suitableonly for limiting the consequential damage.

The only exception is the case of a mesh-connectedsubstation, in which the current transformers are locatedat the circuit breakers. Here, the busbars are included, insections, in the individual zones of the main circuitprotection, whether this is of unit type or not. In thespecial case when the current transformers are locatedon the line side of the mesh, the circuit protection willnot cover the busbars in the instantaneous zone andseparate busbar protection, known as mesh-cornerprotection, is generally used – see Section 15.7.2.1 fordetails.

15.6 FRAME-EARTH PROTECTION(HOWARD PROTECTION)

Frame leakage protection has been extensively used inthe past in many different situations. There are severalvariations of frame leakage schemes available, providingbusbar protection schemes with different capabilities.The following sections schemes have thus been retainedfor historical and general reference purposes. Aconsiderable number of schemes are still in service andframe leakage may provide an acceptable solution inparticular circumstances. However, the need to insulatethe switchboard frame and provide cable glandinsulation and the availability of alternative schemesusing numerical relays, has contributed to a decline inuse 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 fromthe switchgear frame to earth. A current transformer ismounted on the earthing conductor and is used to energizea simple instantaneous relay as shown in Figure 15.2.

No other earth connections of any type, includingincidental connections to structural steelwork areallowed. This requirement is so that:

a. the principal earth connection and currenttransformer are not shunted, thereby raising theeffective setting. An increased effective settinggives rise to the possibility of relay maloperation.This risk is small in practice

b. earth current flowing to a fault elsewhere on thesystem cannot flow into or out of the switchgearframe via two earth connections, as this might leadto a spurious operation

The switchgear must be insulated as a whole, usually bystanding it on concrete. Care must be taken that thefoundation bolts do not touch the steel reinforcement;sufficient concrete must be cut away at each hole topermit 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 forboth the switchgear frame and the power system neutralpoint is preferred, because the fault path wouldotherwise include the two earthing electrodes in series.If either or both of these are of high resistance or haveinadequate current carrying capacity, the fault currentmay be limited to such an extent that the protectionequipment becomes inoperative. In addition, if theelectrode earthing the switchgear frame is the offender,the potential of the frame may be raised to a dangerousvalue. The use of a common earthing electrode ofadequate rating and low resistance ensures sufficientcurrent for scheme operation and limits the rise in framepotential. When the system is resistance earthed, theearthing connection from the switchgear frame is madebetween the bottom of the earthing resistor and theearthing electrode.

Figure 15.3 illustrates why a lower limit of 10 ohmsinsulation resistance between frame and earth isnecessary.

• 15 •

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Figure 15 .2 : S ingle zoneframe-earth protect ion

I >

Trip allcircuitbreaker

Frame-earthfault relay Neutral

check relay

G KJ

+

H

I >

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Under external fault conditions, the current I1 flowsthrough the frame-leakage current transformer. If theinsulation resistance is too low, sufficient current mayflow to operate the frame-leakage relay, and, as the checkfeature is unrestricted, this will also operate to completethe trip circuit. The earth resistance between the earthingelectrode and true earth is seldom greater than 1Ω, sowith 10Ω insulation resistance the current I1 is limited to10% of the total earth fault current I1 and I2. For thisreason, the recommended minimum setting for thescheme is about 30% of the minimum earth fault current.

All cable glands must be insulated, to prevent thecirculation of spurious current through the frame andearthing system by any voltages induced in the cablesheath. Preferably, the gland insulation should beprovided in two layers or stages, with an interposinglayer of metal, to facilitate the testing of the glandinsulation. 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 asystem to protect switchgear as a whole. When thebusbar is divided into sections, these can be protectedseparately, provided the frame is also sub-divided, thesections mutually insulated, and each provided with aseparate earth conductor, current transformer and relay.

Ideally, the section switch should be treated as aseparate zone, as shown in Figure 15.4, and providedwith either a separate relay or two secondaries on theframe-leakage current transformer, with an arrangementto trip both adjacent zones. The individual zone relaystrip their respective zone and the section switch.

If it is inconvenient to insulate the section switch frameon one side, this switch may be included in that zone. Itis then necessary to intertrip the other zone afterapproximately 0.5 seconds if a fault persists after thezone including the section switch has been tripped. Thisis illustrated in Figure 15.5.

• 15 •Bu

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Pro

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Figure 15 .4 : Three zone f rameearth scheme

Insulationbarriers

Triprelays

Zone HZone G

Zone Gframe leakage

relay

Zone Hframe leakage

relay

Trip K Trip L Trip M

L

L1 L2

M

M

K

I

I

>

>

K

Zone JFrame-leakagecurrenttransformer

Earthingelectroderesistance

Frameinsulationresistance to earth

Earthbar

Switchgearframe

Switchgear framebonding bar

Generator

Systemearningresistor

Outgoingfeeder

I1 I1 I2I

I1 + I2I

IFI = I1 + I2I

Figure 15 .3 : Current d ist r ibut ionfor external fault

I >

J L

K

>I

Triprelays

Trip J Trip K Trip L

Zone G

Zone G

Zone H

Zone H

Insulationbarrier

J LK1 K2K

Figure 15.5: Frame-earth scheme: bussection breaker insulated on one side only

Chap15-232-253 17/06/02 9:46 Page 237

For the above schemes to function it is necessary to havea least one infeed or earthed source of supply, and in thelatter case it is essential that this source of supply beconnected to the side of the switchboard not containingthe section switch. Further, if possible, it is preferablethat an earthed source of supply be provided on bothsides of the switchboard, in order to ensure that anyfaults that may develop between the insulating barrierand the section switch will continue to be fed with faultcurrent after the isolation of the first half of theswitchboard, and thus allow the fault to be removed. Ofthe two arrangements, the first is the one normallyrecommended, since it provides instantaneous clearanceof 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 themetal enclosures of the main and auxiliary busbars.Protection is therefore generally provided as for singlebus installations, but with the additional feature thatcircuits connected to the auxiliary bus are tripped for allfaults, as shown in Figure 15.6.

15.6.4 Frame-Earth Protection - Check System

On all but the smallest equipments, a check systemshould be provided to guard against such contingencies

as operation due to mechanical shock or mistakes madeby personnel. Faults in the low voltage auxiliary wiringmust also be prevented from causing operation bypassing current to earth through the switchgear frame.A useful check is provided by a relay energised by thesystem neutral current, or residual current. If the neutralcheck cannot be provided, the frame-earth relays shouldhave a short time delay.

When a check system is used, instantaneous relays canbe used, with a setting of 30% of the minimum earthfault current and an operating time at five times settingof 15 milliseconds or less.

Figure 15.7 shows a frame-leakage scheme for ametalclad switchgear installation similar to that shownin Figure 15.4 and incorporating a neutral current checkobtained from a suitable zero sequence current source,such as that shown in Figure 15.2.

The protection relays used for the discriminating andcheck functions are of the attracted armature type, withtwo normally open self reset contacts. The trippingcircuits cannot be complete unless both thediscriminating and check relays operate; this is becausethe discriminating and check relay contacts areconnected in series. The tripping relays are of theattracted armature type.

• 15 •

Busb

ar P

rote

ctio

n


Figure 15 .6 : F rame-earth schemefor double busbar substat ion

II >

>II

K

Lg

g1

j1

j1M1

M2M

L1

L2

j2

j2

h1

h1

Insulationbarriers

K

_

N

G H Busbarisolatorauxiliary switchesD.C. Zone bus wires

j

M

+

jj

Zone Hrelay

Zone Grelay

Zone G

Zone J

H

Trippingrelays

KOut

_GH

M

64A-1

64B-1

CSS-H

CSS-G

L6

L4

L3

L4

L3

L5

L1

L2

74-1

74-2

64B-2

64A-2 I >

74 Alarm cancellation relayCSS Control selector switch protection in/protection outL3 Busbar protection in service lampL4 Busbar protection out of service lampL5 Tripping supply healthy lampL6 Alarm and indication supply healthy lamp

64CH-2

In

CSS-H

CSS-G

In

Out

64CH-1+ Trip relays

Figure 15.7 : Typical t r ipping and alarmcircuits for a f rame-leakage scheme

Chap15-232-253 17/06/02 9:46 Page 238

It is usual to supervise the satisfactory operation of theprotection scheme with audible and visual alarms andindications for the following:

a. busbar faults

b. busbar protection in service

c. busbar protection out of service

d. tripping supply healthy

e. alarm supply healthy

To enable the protection equipment of each zone to betaken out of service independently during maintenanceperiods, isolating switches - one switch per zone - areprovided in the trip supply circuits and an alarmcancellation relay is used.

15.7 DIFFERENTIAL PROTECTION PRINCIPLES

The Merz-Price principle is applicable to a multi-terminalzone such as a busbar. The principle is a directapplication of Kirchhoff's first law. Usually, thecirculating current arrangement is used, in which thecurrent transformers and interconnections form ananalogue of the busbar and circuit connections. A relayconnected across the CT bus wires represents a faultpath in the primary system in the analogue and hence isnot energised until a fault occurs on the busbar; it thenreceives an input that, in principle at least, representsthe fault current.

The scheme may consist of a single relay connected tothe bus wires connecting all the current transformers inparallel, one set per circuit, associated with a particularzone, as shown in Figure 15.8(a). This will give earthfault protection for the busbar. This arrangement hasoften been thought to be adequate.

If the current transformers are connected as a balancedgroup for each phase together with a three-elementrelay, as shown in Figure 15.8(b), additional protectionfor phase faults can be obtained.

The phase and earth fault settings are identical, and thisscheme is recommended for its ease of application andgood performance.

15.7.1 Differential Protectionfor Sectionalised and Duplicate Busbars

Each section of a divided bus is provided with a separatecirculating current system. The zones so formed areover-lapped across the section switches, so that a faulton the latter will trip the two adjacent zones. This isillustrated in Figure 15.9.

Tripping two zones for a section switch fault can beavoided by using the time-delayed technique of Section15.6.2. However instantaneous operation is thepreferred choice.

For double bus installation, the two busbars will betreated as separate zones. The auxiliary busbar zone willoverlap the appropriate main busbar zone at the buscoupler.

Since any circuit may be transferred from one busbar tothe other by isolator switches, these and the associatedtripping circuit must also be switched to the appropriate

• 15 •Bu

sbar

Pro

tect

ion


Figure 15.8: Circulating current scheme

G H J K

Differentialrelay

Differential relay

CNN

BAA

G

IdIdI I > IdIdI >

IdIdI >

H

b) Phase and earth fault circulating current scheme usingthree-element relay

f

Zone A Zone B

Zone C

B BC

BS

Typical feeder circuits

Figure 15 .9 : Zones of protect ionfor double bus stat ion

Chap15-232-253 17/06/02 9:46 Page 239

zone by 'early make' and 'late break' auxiliary contacts.This is to ensure that when the isolators are closing, theauxiliary switches make before the main contacts of theisolator, and that when the isolators are opened, theirmain contacts part before the auxiliary switches open.The result is that the secondary circuits of the two zonesconcerned are briefly paralleled while the circuit is beingtransferred; these two zones have in any case beenunited through the circuit isolators during the transferoperation.

15.7.2 Location of Current Transformers

Ideally, the separate discriminating zones should overlapeach other and also the individual circuit protections.The overlap should occur across a circuit breaker, so thatthe latter lies in both zones. For this arrangement it isnecessary to install current transformers on both sides ofthe circuit breakers, which is economically possible withmany but not all types of switchgear. With both thecircuit and the bus protection current transformers onthe same side of the circuit breakers, the zones may beoverlapped at the current transformers, but a faultbetween the CT location and the circuit breaker will notbe completely isolated. This matter is important in allswitchgear to which these conditions apply, and isparticularly important in the case of outdoor switchgearwhere separately mounted, multi-secondary currenttransformers are generally used. The conditions areshown in Figure 15.10.

Figure 15.10(a) shows the ideal arrangement in whichboth the circuit and busbar zones are overlapped leavingno region of the primary circuit unprotected.

Figure 15.10(b) shows how mounting all currenttransformers on the circuit side of the breaker results ina small region of the primary circuit unprotected. Thisunprotected region is typically referred to as the ‘shortzone’. The fault shown will cause operation of the busbarprotection, tripping the circuit breaker, but the fault willcontinue to be fed from the circuit, if a source of poweris present. It is necessary for the bus protection tointertrip the far end of the circuit protection, if the latteris of the unit type.

With reference to Figure 15.10(b), special ‘short zone’protection can be provided to detect that the circuitbreaker has opened but that the fault current is stillflowing. Under these conditions, the protection caninitiate an intertrip to the remote end of the circuit. Thistechnique may be used, particularly when the circuitincludes a generator. In this case the intertrip proves thatthe fault is in the switchgear connections and not in thegenerator; the latter is therefore tripped electrically but notshut down on the mechanical side so as to be immediatelyready 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 substationsgives rise to additional considerations in respect of CTlocation. A single mesh corner is shown in Figure

• 15 •

Busb

ar P

rote

ctio

n


Figure 15.10: Unprotected zone withcurrent transformers mountedon one side of the circuit breaker only

protectionCircuit

-fault shown not cleared by circuit protectionb. Current transformers mounted on circuit side only of breaker

-no unprotected regiona. Current transformers mounted on both sides of breaker

Fault

Bus protection

(a) (b)

Mesh cornerprotection

Mesh corner(Note 2)

Lineprotection

Transformerprotection

(b) CT arrangements for protection - additional mesh corner protection required

Note 2: Multiple circuits may be connected to the mesh corner

Note 1: Only 1 connection to the mesh corner permitted(a) CT arrangements for protection including mesh corner

Lineprotectionrelay

Mesh corner(Note 1)

Figure 15 .11 : Mesh-corner protect ion

Chap15-232-253 17/06/02 9:48 Page 240

15.11(a). Where only one connection to the mesh ismade at a corner, CT’s located as shown will provideprotection not only to the line but the corner of the meshincluded between them. However, this arrangementcannot be used where more than one connection is madeto a mesh corner. This is because a fault on any of theconnected circuits would result in disconnection of themall, without any means of determining the faultedconnection. Protection CT’s must therefore be located oneach connection, as shown in Figure 15.11(b). This leavesthe corner of the mesh unprotected, so additional CT’sand a relay to provide mesh-corner protection are added,as also shown in Figure 15.11(b).

15.8 HIGH IMPEDANCEDIFFERENTIAL PROTECTION

This form of protection is still in common use. Theconsiderations that have to be taken into account aredetailed in the following sections.

15.8.1 Stability

The incidence of fault current with an initial unilateraltransient component causes an abnormal built-up of fluxin a current transformer, as described in Section 6.4.10.When through-fault current traverses a zone protectedby a differential system, the transient flux produced inthe current transformers is not detrimental as long as itremains within the substantially linear range of themagnetising characteristic. With fault current ofappreciable magnitude and long transient time constant,the flux density will pass into the saturated region of thecharacteristic; this will not in itself produce a spilloutput from a pair of balancing current transformersprovided that these are identical and equally burdened.A group of current transformers, though they may be ofthe same design, will not be completely identical, but amore important factor is inequality of burden. In thecase of a differential system for a busbar, an externalfault may be fed through a single circuit, the currentbeing supplied to the busbar through all other circuits.The faulted circuit is many times more heavily loadedthan the others and the corresponding currenttransformers are likely to be heavily saturated, whilethose of the other circuits are not. Severe unbalance istherefore probable, which, with a relay of normal burden,could exceed any acceptable current setting. For thisreason such systems were at one time always providedwith a time delay. This practice is, however, no longeracceptable.

It is not feasible to calculate the spill current that mayoccur, but, fortunately, this is not necessary; an alternativeapproach provides both the necessary information and thetechnique required to obtain a high performance.

An equivalent circuit, as in Figure 15.12, can represent acirculating current system.

The current transformers are replaced in the diagram byideal current transformers feeding an equivalent circuitthat represents the magnetising losses and secondarywinding resistance, and also the resistance ofthe connecting leads. These circuits can then beinterconnected as shown, with a relay connected to thejunction points to form the complete equivalent circuit.

Saturation has the effect of lowering the excitingimpedance, and is assumed to take place severely incurrent transformer H until, at the limit, the shuntimpedance becomes zero and the CT can produce nooutput. This condition is represented by a short circuit,shown in broken line, across the exciting impedance. Itshould be noted that this is not the equivalent of aphysical short circuit, since it is behind the windingresistance .

Applying the Thévenin method of solution, the voltagedeveloped across the relay will be given by:

. . .Equat ion 15 .1

The current through the relay is given by:


If RR is small, IR will approximate to IF, which isunacceptable. On the other hand, if RR is large IR isreduced. Equation 15.2 can be written, with little error,as follows:

=+( )

+ +I R R

R R Rf LH CTH

R LH CTH

IV

R R RRf

R LH CTH

=+ +

• 15 •Bu

sbar

Pro

tect

ion


Figure 15 .12 : Equivalent c i rcuitof c i rculat ing current system

IdIdI >ZEGZ

RR

RLHRRLGR RCTHRCTG

G H

ZEHZ

Chap15-232-253 17/06/02 9:48 Page 241

…Equat ion 15 .3or alternatively:

…Equat ion 15 .4

It is clear that, by increasing RR, the spill current IR can bereduced below any specified relay setting. RR is frequentlyincreased by the addition of a series-connected resistorwhich is known as the stabilising resistor.

It can also be seen from Equation 15.4 that it is only thevoltage drop in the relay circuit at setting current that isimportant. The relay can be designed as a voltagemeasuring device consuming negligible current; andprovided its setting voltage exceeds the value Vf ofEquation 15.4, the system will be stable. In fact, thesetting voltage need not exceed Vf, since the derivationof Equation 15.4 involves an extreme condition ofunbalance between the G and H current transformersthat is not completely realised. So a safety margin isbuilt-in if the voltage setting is made equal to Vf.

It is necessary to realise that the value of If to be insertedin Equation 15.4 is the complete function of the faultcurrent and the spill current IR through the relay, in thelimiting condition, will be of the same form. If the relayrequires more time to operate than the effective durationof the d.c. transient component, or has been designedwith special features to block the d.c. component, thenthis factor can be ignored and only the symmetricalvalue of the fault current need be entered in Equation15.4. If the relay setting voltage, Vs, is made equal to Vf,that is, If (RL + RCT), an inherent safety factor of theorder of two will exist.

In the case of a faster relay, capable of operating in onecycle and with no special features to block the d.c.component, it is the r.m.s. value of the first offset wavethat is significant. This value, for a fully offset waveformwith no d.c. decrement, is √

_3If. If settings are then

chosen in terms of the symmetrical component of thefault current, the √

_3 factor which has been ignored will

take up most of the basic safety factor, leaving only avery small margin.

Finally, if a truly instantaneous relay were used, therelevant 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 rewriteEquation 15.4 as:

…Equat ion 15 .5

where:

ISL = stability of scheme

VS = relay circuit voltage setting

IK V

R RSLS

L CT

= ×+

I R V I R RR R f f LH CTH= = +( )

IV

R

I R R

RRf

R

f LH CTH

R

= =+( ) RL + RCT = lead + CT winding resistance

K = factor depending on relay design(range 0.7 - 2.0)

It remains to be shown that the setting chosen issuitable.

The current transformers will have an excitation curvewhich has not so far been related to the relay settingvoltage, the latter being equal to the maximum nominalvoltage drop across the lead loop and the CT secondarywinding resistance, with the maximum secondary faultcurrent flowing through them. Under in-zone faultconditions it is necessary for the current transformers toproduce sufficient output to operate the relay. This willbe achieved provided the CT knee-point voltage exceedsthe relay setting. In order to cater for errors, it is usualto specify that the current transformers should have aknee-point e.m.f. of at least twice the necessary settingvoltage; a higher multiple is of advantage in ensuring ahigh speed of operation.

15.8.2 Effective Setting or Primary Operating Current

The minimum primary operating current is a furthercriterion of the design of a differential system. Thesecondary effective setting is the sum of the relayminimum operating current and the excitation losses inall parallel connected current transformers, whethercarrying primary current or not. This summation shouldstrictly speaking be vectorial, but is usually donearithmetically. It can be expressed as:

IR = IS +nIeS . . .Equat ion 15 .6

where:

IR = effective setting

IS = relay circuit setting current

IeS = CT excitation current at relay setting voltage

n = number of parallel - connected CT’s

Having established the relay setting voltage fromstability considerations, as shown in Section 15.8.1, andknowing the excitation characteristic of the currenttransformers, the effective setting can be computed. Thesecondary setting is converted to the primary operatingcurrent by multiplying by the turns ratio of the currenttransformers. The operating current so determinedshould be considered in terms of the conditions of theapplication.

For a phase and earth fault scheme the setting can bebased on the fault current to be expected for minimumplant and maximum system outage conditions. However,it should be remembered that:

• 15 •

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Chap15-232-253 17/06/02 9:48 Page 242

a. phase-phase faults give only 86% of the three-phase fault current

b. fault arc resistance and earth path resistancereduce fault currents somewhat

c. a reasonable margin should be allowed to ensurethat relays operate quickly and decisively

It is desirable that the primary effective setting should notexceed 30% of the prospective minimum fault current.

In the case of a scheme exclusively for earth faultprotection, the minimum earth fault current should beconsidered, taking into account any earthing impedancethat might be present as well. Furthermore, in the eventof a double phase to earth fault, regardless of the inter-phase currents, only 50% of the system e.m.f. is availablein the earth path, causing a further reduction in the earthfault current. The primary operating current musttherefore be not greater than 30% of the minimumsingle-phase earth fault current. In order to achievehigh-speed operation, it is desirable that settings shouldbe still lower, particularly in the case of the solidlyearthed power system. The transient component of thefault current in conjunction with unfavourable residualflux in the CT can cause a high degree of saturation andloss of output, possibly leading to a delay of several cyclesadditional to the natural operating time of the element.

This will not happen to any large degree if the faultcurrent is a larger multiple of setting; for example, if thefault current is five times the scheme primary operatingcurrent and the CT knee-point e.m.f. is three times therelay setting voltage, the additional delay is unlikely toexceed one cycle.

The primary operating current is sometimes designed toexceed the maximum expected circuit load in order toreduce the possibility of false operation under loadcurrent as a result of a broken CT lead. Desirable as thissafeguard may be, it will be seen that it is better not toincrease the effective current setting too much, as thiswill sacrifice some speed; the check feature in any case,maintains stability.

An overall earth fault scheme for a large distributionboard may be difficult to design because of the largenumber of current transformers paralleled together,which may lead to an excessive setting. It may beadvantageous in such a case to provide a three-elementphase and earth fault scheme, mainly to reduce thenumber of current transformers paralleled into one group.

Extra-high-voltage substations usually present no suchproblem. Using the voltage-calibrated relay, the currentconsumption can be very small.

A simplification can be achieved by providing one relayper circuit, all connected to the CT paralleling buswires.

• 15 •Bu

sbar

Pro

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E

Zone RBus wires

Zone

c1

a1

D

Bus wiresCheck zone

same as checkZone relay Zone M1 relay

Zone M1 Zone M2

same as checkZone M2 relay

cc

GFb1

BC

ABCN

M2

c1 c2

H

same as check

95 CHX-2

IdIdI > IdIdI I

+_

Zone R

M1 First main busbarM2 Second main busbarR Reserve busbar

SupervisionRelay

High ImpedanceCirculating Current

g pCirculating Current

g p

RelayMetrosil(non-linear resistor)

Stabilising Resistor

o

Figure 15 .13 : A .C . c i rcuits for h ighimpedance c i rculat ing current scheme for dupl icate busbars

Chap15-232-253 17/06/02 9:48 Page 243

This enables the trip circuits to be confined to the leastarea and reduces the risk of accidental operation.

15.8.3 Check Feature

Schemes for earth faults only can be checked by a frame-earth system, applied to the switchboard as a whole, no

subdivision being necessary. For phase fault schemes,the check will usually be a similar type of scheme appliedto the switchboard as a single overall zone.

A set of current transformers separate from those used inthe discriminating zones should be provided. No CTswitching is required and no current transformers are

• 15 •

Busb

ar P

rote

ctio

n


Figure 15.14: D.C. circuits for high impedance circulating current scheme

96In Out M1

CSS-M1

87M1-1

87M2-1

CSS-M1

L1

30 Zone indicating relay74 Alarm cancellation relay80 D.C. volts supervision relay87 High impedance circulating current relay95 Bus wires supervision relay

CSS-M2

In Out

87CH-1+

D1

87R-1

CSS-R

M2 R

D296

E96a1

c1

96F2

c2

b1G

F1

96

96

H196

96H2

D.C. Buswires80T

M2

R30

30M130

87R-2

87M2-2

87M1-287CH-2

M1X95

95M1-1

M2X95

95M2-1

95RX

95R-1

95CHX

95CH-1

30M1-1

74-1

74-2

30M2-1

30R-1

95M1X-1

95M2X-1

95RX-1

95CHX-1

L2

L1

L2

CSS-R

L2

L1CSS-M2

I80

95X Zone bus wires shorting relayCSS Control selector switchL1 Indicating lamp protection in serviceL2 Indicating lamp protection out of service

74

Chap15-232-253 17/06/02 9:48 Page 244

needed for the check zone in bus-coupler and bus-section breakers.

15.8.4 Supervision of CT Secondary Circuits

Any interruption of a CT secondary circuit up to theparalleling interconnections will cause an unbalance inthe system, equivalent to the load being carried by therelevant primary circuit. Even though this degree ofspurious output is below the effective setting thecondition cannot be ignored, since it is likely to lead toinstability under any through fault condition.

Supervision can be carried out to detect such conditionsby connecting a sensitive alarm relay across the buswires of each zone. For a phase and earth fault scheme,an internal three-phase rectifier can be used to effect asummation of the bus wire voltages on to a single alarmelement; see Figures 15.13 and 15.14.

The alarm relay is set so that operation does not occurwith the protection system healthy under normal load.Subject to this proviso, the alarm relay is made assensitive as possible; the desired effective setting is 125primary amperes or 10% of the lowest circuit rating,whichever is the greater.

Since a relay of this order of sensitivity is likely tooperate during through faults, a time delay, typically ofthree seconds, is applied to avoid unnecessary alarmsignals.

15.8.5 Arrangement of CT Connections

It is shown in Equation 15.4 how the setting voltage fora given stability level is directly related to the resistanceof the CT secondary leads. This should therefore bekept to a practical minimum. Taking into account thepractical physical laying of auxiliary cables, the CT buswires are best arranged in the form of a ring around theswitchgear site.

In a double bus installation, the CT leads should be takendirectly to the isolator selection switches. The usualrouting of cables on a double bus site is as follows:

a. current transformers to marshalling kiosk

b. marshalling kiosk to bus selection isolator auxiliaryswitches

c. interconnections between marshalling kiosks toform a closed ring

The relay for each zone is connected to one point of thering bus wire. For convenience of cabling, the main zonerelays will be connected through a multicore cablebetween the relay panel and the bus section-switchmarshalling cubicle. The reserve bar zone and the checkzone relays will be connected together by a cablerunning to the bus coupler circuit breaker marshalling

cubicle. It is possible that special circumstancesinvolving onerous conditions may over-ride thisconvenience and make connection to some other part ofthe ring desirable.

Connecting leads will usually be not less than 7/0.67mm(2.5mm2), but for large sites or in other difficultcircumstances it may be necessary to use cables of, forexample 7/1.04mm (6mm2) for the bus wire ring and theCT connections to it. The cable from the ring to the relayneed not be of the larger section.

When the reserve bar is split by bus section isolators andthe two portions are protected as separate zones, it isnecessary to common the bus wires by means of auxiliarycontacts, thereby making these two zones into one whenthe section isolators are closed.

15.8.6 Summary of Practical Details

This section provides a summary of practicalconsiderations when implementing a high-impedancebusbar protection scheme.

15.8.6.1 Designed stability level

For normal circumstances, the stability level should bedesigned to correspond to the switchgear rating; even ifthe available short-circuit power in the system is muchless than this figure, it can be expected that the systemwill 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 areasonable manufacturing tolerance. Also, they shouldpreferably be of similar design; where this is not possiblethe magnetising characteristics should be reasonablymatched.

Current transformers for use with high impedanceprotection schemes should meet the requirements ofClass PX of IEC 60044-1.

15.8.6.3 Setting voltage

The setting voltage is given by the equation

Vs > If (RL + RCT)

where:

Vs = relay circuit voltage setting

If = steady-state through fault current

RL = CT lead loop resistence

RCT = CT secondary winding resistance

• 15 •Bu

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Chap15-232-253 17/06/02 9:48 Page 245

15.8.6.4 Knee-point voltage of current transformers

This is given by the formula

VK ≥ 2Vs

15.8.6.5 Effective setting (secondary)

The effective setting of the relay is given by

IR = IS + nIeSIR

where:

IS = relay circuit current setting

IeS = CT excitation current at voltage setting

n = number of CT’s in parallel

For the primary fault setting multiply IR by the CT turnsratio.

15.8.6.6 Current transformer secondary rating

It is clear from Equations 15.4 and 15.6 that it isadvantageous to keep the secondary fault current low;this is done by making the CT turns ratio high. It iscommon practice to use current transformers with asecondary rating of 1A.

It can be shown that there is an optimum turns ratio forthe current transformers; this value depends on all theapplication parameters but is generally about 2000/1.Although a lower ratio, for instance 400/1, is oftenemployed, the use of the optimum ratio can result in aconsiderable reduction in the physical size of the currenttransformers.

15.8.6.7 Peak voltage developed by current transformers

Under in-zone fault conditions, a high impedance relayconstitutes an excessive burden to the currenttransformers, leading to the development of a highvoltage; the voltage waveform will be highly distortedbut the peak value may be many times the nominalsaturation voltage.

When the burden resistance is finite although high, anapproximate formula for the peak voltage is:


where:

VP = peak voltage developed

VK = knee-point voltage

VF = prospective voltage in absence of saturation

This formula does not hold for the open circuit conditionand is inaccurate for very high burden resistances thatapproximate to an open circuit, because simplifyingassumptions used in the derivation of the formula arenot valid for the extreme condition.

Another approach applicable to the open circuit

V V V VP K F K= −( )2 2

secondary condition is:


where:

If = fault current

Iek = exciting current at knee - point voltage

VK = knee - point voltage

Any burden connected across the secondary will reducethe voltage, but the value cannot be deduced from asimple combination of burden and exciting impedances.

These formulae are therefore to be regarded only as aguide to the possible peak voltage. With large currenttransformers, particularly those with a low secondarycurrent rating, the voltage may be very high, above asuitable insulation voltage. The voltage can be limitedwithout detriment to the scheme by connecting aceramic non-linear resistor in parallel with the relayhaving a characteristic given by:

V = CIβ

where C is a constant depending on dimensions and β isa constant in the range 0.2-0.25.

The current passed by the non-linear resistor at the relayvoltage setting depends on the value of C; in order tokeep the shunting effect to a minimum it isrecommended to use a non-linear resistor with a value ofC of 450 for relay voltages up to 175V and one with avalue of C of 900 for setting voltages up to 325V.

15.8.6.8 High impedance relay

Instantaneous attracted armature relays are used. Simplefast-operating relays would have a low safety factorconstant in the stability equation, Equation 15.5, asdiscussed in Section 15.8.1. The performance is improvedby series-tuning the relay coil, thereby making the circuitresistive in effect. Inductive reactance would tend toreduce stability, whereas the action of capacitance is toblock the unidirectional transient component of faultcurrent and so raise the stability constant.

An alternative technique used in some relays is to applythe limited spill voltage principle shown in Equation15.4. A tuned element is connected via a plug bridge toa chain of resistors; and the relay is calibrated in termsof voltage.

15.9 LOW IMPEDANCE BIASEDDIFFERENTIAL PROTECTION

The principles of low impedance differential protectionhave been described in Section 10.4, including theprinciple advantages to be gained by the use of a bias

VI

IVP

f

ekK= 2

• 15 •

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Chap15-232-253 17/06/02 9:48 Page 246

technique. Most modern busbar protection schemes usethis technique.

The principles of a check zone, zone selection, andtripping arrangements can still be applied. Currenttransformer secondary circuits are not switched directlyby isolator contacts but instead by isolator repeat relaysafter a secondary stage of current transformation. Theseswitching relays form a replica of the busbar within theprotection and provide the complete selection logic.

15.9.1 Stability

With some biased relays, the stability is not assured bythe through current bias feature alone, but is enhancedby the addition of a stabilising resistor, having a valuewhich may be calculated as follows.

The through current will increase the effective relayminimum operating current for a biased relay as follows:

IR = IS + BIF

where:

IR = effective minimum oprating current

IS = relay setting current

IF = through fault current

B = percentage restraint

As IF is generally much greater than IS, the relayeffective current, IR = BIF approximately.

From Equation 15.4, the value of stabilising resistor isgiven by:

It is interesting to note that the value of the stabilisingresistance is independent of current level, and that therewould appear to be no limit to the through faultsstability level. This has been identified [15.1] as ‘ThePrinciple of Infinite Stability’.

The stabilising resistor still constitutes a significantburden on the current transformers during internalfaults.

An alternative technique, used by the MBCZ systemdescribed in Section 15.9.6, is to block the differentialmeasurement during the portion of the cycle that acurrent transformer is saturated. If this is achieved bymomentarily short-circuiting the differential path, a verylow burden is placed on the current transformers. In thisway the differential circuit of the relay is prevented fromresponding to the spill current.

= +R RB

LH CTH

RI R R

IR

f LH CTH

R

=+( )

It must be recognised though that the use of any techniquefor inhibiting operation, to improve stability performancefor through faults, must not be allowed to diminish theability 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 currentflowing, the effective setting (IR) is raised above thebasic relay setting (IS) by whatever biasing effect isproduced by the sum of the CT magnetising currentsflowing through the bias circuit. With low impedancebiased differential schemes particularly where the busbarinstallation has relatively few circuits, these magnetisingcurrents may be negligible, depending on the value of IS.

The basic relay setting current was formerly defined asthe minimum current required solely in the differentialcircuit to cause operation – Figure 15.15(a). Thisapproach simplified analysis of performance, but wasconsidered to be unrealistic, as in practice any currentflowing in the differential circuit must flow in at leastone half of the relay bias circuit causing the practicalminimum operating current always to be higher than thenominal basic setting current. As a result, a laterdefinition, as shown in Figure 15.15(b) was developed.

Conversely, it needs to be appreciated that applying thelater definition of relay setting current, which flowsthrough at least half the bias circuit, the notional mini-mum operation current in the differential circuit aloneis somewhat less, as shown in Figure 15.15(b).Using the definition presently applicable, the effectiveminimum primary operating current

where:N = CT ratio

= +[ ]∑N I B IS eS

• 15 •Bu

sbar

Pro

tect

ion


(a) Superseded definition (b) Current definition

IopIopI IopIopI

ISI

ISI

ISI

I'S

IBIIBI

ISI

IRI = S + BIBI IRI = I + I' I'S

IBIBI

Bias Line (B%)

Bias Line (B%)

= I' B

Figure 15 .15 : Def in i t ions of re laysett ing current for b iased re lays

Chap15-232-253 17/06/02 9:48 Page 247

Unless the minimum effective operating current of ascheme has been raised deliberately to some preferredvalue, it will usually be determined by the check zone,when present, as the latter may be expected to involvethe greatest number of current transformers in parallel.A slightly more onerous condition may arise when twodiscriminating zones are coupled, transiently orotherwise, by the closing of primary isolators.

It is generally desirable to attain an effective primaryoperating current that is just greater than the maximumload current, to prevent the busbar protection fromoperating spuriously from load current should asecondary circuit wiring fault develop. This considerationis particularly important where the check feature is eithernot used or is fed from common main CT's.

15.9.3 Check Feature

For some low impedance schemes, only one set of mainCT's is required. This seems to contradict the generalprinciple of all busbar protection systems with a checkfeature that complete duplication of all equipment isrequired, but it is claimed that the spirit of the checkingprinciple is met by making operation of the protectiondependent on two different criteria such as directionaland differential measurements.

In the MBCZ scheme, described in Section 15.9.6, theprovision of auxiliary CT's as standard for ratio matchingalso provides a ready means for introducing the checkfeature duplication at the auxiliary CT's and onwards tothe relays. This may be an attractive compromise whenonly one set of main CT's is available.

15.9.4 Supervision of CT Secondary Circuits

In low impedance schemes the integrity of the CTsecondary circuits can also be monitored. A currentoperated auxiliary relay, or element of the mainprotection equipment, may be applied to detect anyunbalanced secondary currents and give an alarm after atime delay. For optimum discrimination, the currentsetting of this supervision relay must be less than that ofthe main differential protection.

In modern busbar protection schemes, the supervision ofthe secondary circuits typically forms only a part of acomprehensive supervision facility.

15.9.5 Arrangement of CT connections

It is a common modern requirement of low impedanceschemes that none of the main CT secondary circuitsshould be switched, in the previously conventional manner,to match the switching of primary circuit isolators.

The usual solution is to route all the CT secondarycircuits back to the protection panel or cubicle toauxiliary CT's. It is then the secondary circuits of theauxiliary CT’s that are switched as necessary. Soauxiliary CT's may be included for this function evenwhen the ratio matching is not in question.

In static protection equipment it is undesirable to useisolator auxiliary contacts directly for the switchingwithout some form of insulation barrier. Positiontransducers that follow the opening and closing of theisolators may provide the latter.

Alternatively, a simpler arrangement may be provided onmultiple busbar systems where the isolators switch theauxiliary current transformer secondary circuits viaauxiliary relays within the protection. These relays forma replica of the busbar and perform the necessary logic.It is therefore necessary to route all the currenttransformer secondary circuits to the relay to enablethem to be connected into this busbar replica.

Some installations have only one set of currenttransformers available per circuit. Where the facility ofa check zone is still required, this can still be achievedwith the low impedance biased protection by connectingthe auxiliary current transformers at the input of themain and check zones in series, as shown in Figure 15.16.

15.9.6 Static Low Impedance BiasedDifferential Protection - Type MBCZ

The Type MBCZ scheme conforms in general to theprinciples outlined earlier and comprises a system ofstandard modules that can be assembled to suit aparticular busbar installation. Additional modules can beadded at any time as the busbar is extended.

A separate module is used for each circuit breaker andalso one for each zone of protection. In addition to thesethere is a common alarm module and a number of powersupply units. Ratio correction facilities are providedwithin each differential module to accommodate a widerange of CT mismatch.

• 15 •

Busb

ar P

rote

ctio

n


Figure 15.16: Alternative CT connections

Mainzone

Checkzone

Checkzone

Mainzone

Chap15-232-253 17/06/02 9:54 Page 248

Figure 15.17 shows the correlation between the circuitbreakers and the protection modules for a typical doublebusbar installation. In practice the modules are mountedin a multi-tier rack or cubicle.

The modules are interconnected via a multicore cablethat is plugged into the back of the modules. There arefive main groups of buswires, allocated for:

i. protection for main busbar

ii. protection for reserve busbar

iii. protection for the transfer busbar. When thereserve busbar is also used as a transfer bar thenthis group of buswires is used

iv. auxiliary connections used by the protection tocombine modules for some of the more complexbusbar configurations

v. protection for the check zone

One extra module, not shown in this diagram, is pluggedinto the multicore bus. This is the alarm module, whichcontains 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 currentflowing to or from the busbar system via the feeders.This ensures that all zones of measurement will havesimilar fault sensitivity under all load conditions. Thebias is derived from the check zone and fixed at 20%with a characteristic generally as shown in Figure15.15(b). Thus some ratio mismatch is tolerable.

15.9.6.2 Stability with saturated current transformers

The traditional method for stabilising a differential relayis to add a resistor to the differential path. Whilst thisimproves stability it increases the burden on the currenttransformer for internal faults. The technique used inthe MBCZ scheme overcomes this problem.

The MBCZ design detects when a CT is saturated andshort-circuits the differential path for the portion of thecycle for which saturation occurs. The resultant spillcurrent does not then flow through the measuring circuitand stability is assured.

This principle allows a very low impedance differentialcircuit to be developed that will operate successfullywith relatively small CT's.

15.9.6.3 Operation for internal faults

If the CT's carrying fault current are not saturated therewill be ample current in the differential circuit to operatethe differential relay quickly for fault currents exceedingthe minimum operating level, which is adjustablebetween 20%-200% rated current.

When the only CT(s) carrying internal fault currentbecome saturated, it might be supposed that the CTsaturation detectors may completely inhibit operation byshort-circuiting the differential circuit. However, theresulting inhibit pulses remove only an insignificantportion of the differential current, so operation of therelay is therefore virtually unaffected.

• 15 •Bu

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Bus coupler 1 Feeder 1 Z1 Z3a Feeder 2 Bus section Feeder 3 Z2 Z3b Feeder 4 Bus coupler 2Checkzone

Zone 1 Zone 2

Zone 3a Zone 3b

Intermodule plug-in buswire connections

Figure 15.17: Type MBCZ busbar protection showing correlationbetween circuit breakers and protection modules

Chap15-232-253 17/06/02 9:54 Page 249

15.9.6.4 Discrepancy alarm feature

As shown in Figure 15.18, each measuring modulecontains duplicated biased differential elements and alsoa pair of supervision elements, which are a part of acomprehensive supervision facility.

This arrangement provides supervision of CT secondarycircuits for both open circuit conditions and anyimpairment of the element to operate for an internalfault, without waiting for an actual system faultcondition to show this up. For a zone to operate it isnecessary for both the differential supervision elementand the biased differential element to operate. For acircuit breaker to be tripped it requires the associatedmain zone to be operated and also the overall checkzone, as shown in Figure 15.19.

15.9.6.5 Master/follower measuring units

When two sections of a busbar are connected togetherby isolators it will result in two measuring elementsbeing connected in parallel when the isolators are closed

to operate the two busbar sections as a single bar. Thefault current will then divide between the two measuringelements in the ratio of their impedances. If both of thetwo measuring elements are of low and equal impedancethe effective minimum operating current of the schemewill be doubled.

This is avoided by using a 'master/follower' arrangement.By making the impedance of one of the measuringelements very much higher than the other it is possible toensure that one of the relays retains its original minimumoperation current. Then to ensure that both the parallel-connected zones are tripped the trip circuits of the twozones are connected in parallel. Any measuring unit canhave the role of 'master' or 'follower' as it is selectable bymeans of a switch on the front of the module.

15.9.6.6 Transfer tripping for breaker failure

Serious damage may result, and even danger to life, if acircuit breaker fails to open when called upon to do so.To reduce this risk breaker fail protection schemes weredeveloped some years ago.

These schemes are generally based on the assumptionthat if current is still flowing through the circuit breakera set time after the trip command has been issued, thenit has failed to function. The circuit breakers in the nextstage back in the system are then automatically tripped.

For a bus coupler or section breaker this would involvetripping all the infeeds to the adjacent zone, a facilitythat is included in the busbar protection scheme.

• 15 •

Busb

ar P

rote

ctio

n


Main zone

S2

S1

+ veD2

D1

Trip

S1

S2

Check zone

D2

D1

Figure 15 .19 : Busbar protect ion t r ip logic

F igure 15 .18 : B lock d iagram of measur ing unit

Enable

Diff

eren

tial

m

Bias

t

r

Enable

DifferentialBiased

DifferentialBiased

SelectionLinks

c

CurrentBuswire

Supervision

Supervision

Out of service

Trip

Protectionfault

m

t

r

TripLinksSelection

c

BuswireTrip

CT Fault

OR

r = Reserve

Alarm

t = Transfer

m = Mainc = Check

1

1

1

=1

=1

Chap15-232-253 17/06/02 9:54 Page 250

15.10 NUMERICAL BUSBAR PROTECTIONSCHEMES

The application of numerical relay technology to busbarprotection has lagged behind that of other protectionfunctions. Static technology is still usual for suchschemes, but numerical technology is now readilyavailable. The very latest developments in thetechnology are included, such as extensive use of a databus to link the various units involved, and fault toleranceagainst loss of a particular link by providing multiplecommunications paths. The development process hasbeen very rigorous, because the requirements for busbarprotection in respect of immunity to maloperation arevery high.

The philosophy adopted is one of distributed processing ofthe measured values, as shown in Figure 15.20. Feederseach have their own processing unit, which collectstogether information on the state of the feeder (currents,voltages, CB and isolator status, etc.) and communicatesit over high-speed fibre-optic data links to a central unit.For large substations, more than one central unit may beused, while in the case of small installations, all of theunits can be co-located, leading to the appearance of atraditional centralised architecture.

For simple feeders, interface units at a bay may be usedwith the data transmitted to a single centrally located peripheral unit. The central unit performs thecalculations required for the protection functions.Available protection functions are:

a. protection

b. backup overcurrent protection

c. breaker failure

d. dead zone protection

In addition, monitoring functions such as CB and isolatormonitoring, disturbance recording and transformersupervision are provided.

Because of the distributed topology used,synchronisation of the measurements taken by theperipheral units is of vital importance. A high stabilitynumerically-controlled oscillator is fitted in each of thecentral and peripheral units, with time synchronisationbetween them. In the event of loss of thesynchronisation signal, the high stability of the oscillatorin the affected feeder unit(s) enables processing of theincoming data to continue without significant errorsuntil synchronisation can be restored.

The peripheral units have responsibility for collecting therequired data, such as voltages and currents, andprocessing it into digital form for onwards transmissionto the central unit. Modelling of the CT response isincluded, to eliminate errors caused by effects such as CTsaturation. Disturbance recording for the monitoredfeeder is implemented, for later download as required.Because each peripheral unit is concerned only with anindividual feeder, the protection algorithms must residein the central unit.

The differential protection algorithm can be much moresophisticated than with earlier technology, due toimprovements in processing power. In addition tocalculating the sum of the measured currents, thealgorithm can also evaluate differences betweensuccessive current samples, since a large change above athreshold may indicate a fault – the threshold beingchosen such that normal load changes, apart from inrushconditions do not exceed the threshold. The same

• 15 •Bu

sbar

Pro

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ion


Figure 15.20: Architecture for numerical protection scheme

PersonalComputer

PU

CT

CBPU CB

CT

PU CB

CT

Feeder 1 Feeder 2

CUCentral Unit

PU

Fibre optic link

System Communication Network

PU: Peripheral UnitCU: Central Unit

CB

CT

Chap15-232-253 17/06/02 9:54 Page 251

considerations can also be applied to the phase angles ofcurrents, and incremental changes in them.

One advantage gained from the use of numericaltechnology is the ability to easily re-configure theprotection to cater for changes in configuration of thesubstation. For example, addition of an extra feederinvolves the addition of an extra peripheral unit, thefibre-optic connection to the central unit and entry viathe MMI of the new configuration into the central unit.Figure 15.21 illustrates the latest numerical technologyemployed.

15.10.1 Reliability Considerations

In considering the introduction of numerical busbarprotection schemes, users have been concerned withreliability issues such as security and availability.Conventional high impedance schemes have been one ofthe main protection schemes used for busbar protection.The basic measuring element is simple in concept andhas few components. Calculation of stability limits andother setting parameters is straightforward and schemeperformance can be predicted without the need forcostly testing. Practically, high impedance schemes haveproved to be a very reliable form of protection.

In contrast, modern numerical schemes are morecomplex with a much greater range of facilities and amuch high component count. Based on low impedancebias techniques, and with a greater range of facilities toset, setting calculations can also be more complex.

However, studies of the comparative reliability ofconventional high impedance schemes and modernnumerical schemes have shown that assessing relativereliability is not quite so simple as it might appear. Thenumerical scheme has two advantages over its oldercounterpart:

a. there is a reduction in the number of externalcomponents such as switching and other auxiliaryrelays, many of the functions of which areperformed internally within the softwarealgorithms

b. numerical schemes include sophisticatedmonitoring features which provide alarm facilitiesif the scheme is faulty. In certain cases, simulationof the scheme functions can be performed on linefrom the CT inputs through to the tripping outputsand thus scheme functions can be checked on aregular basis to ensure a full operational mode isavailable at all times

Reliability analyses using fault tree analysis methodshave examined issues of dependability (e.g. the ability tooperate when required) and security (e.g. the ability notto provide spurious/indiscriminate operation). Theseanalyses have shown that:

a. dependability of numerical schemes is better thanconventional high impedance schemes

b. security of numerical and conventional highimpedance schemes are comparable

In addition, an important feature of numerical schemesis the in-built monitoring system. This considerablyimproves the potential availability of numerical schemescompared to conventional schemes as faults within theequipment and its operational state can be detected andalarmed. With the conventional scheme, failure to re-instate the scheme correctly after maintenance may notbe detected until the scheme is required to operate. Inthis situation, its effective availability is zero until it isdetected and repaired.

15.11 REFERENCES

15.1 The Behaviour of Current Transformers subjectedto Transient Asymmetric Currents and theEffects on Associated Protective Relays. J.W.Hodgkiss. CIGRE Paper Number 329, Session15-25 June 1960.

• 15 •


Figure 15.21: Busbar protection relay using thelatest numerical technology (MiCOM P740 range)

Busb

ar P

rote

ctio

n

Chap15-232-253 17/06/02 9:54 Page 252

Introduction 16.1Winding faults 16.2

Magnetising inrush 16.3Transformer overheating 16.4

Transformer protection – overview 16.5Transformer overcurrent protection 16.6

Restricted earth fault protection 16.7Differential protection 16.8

Stabilisation of differential protectionduring magnetising inrush conditions 16.9

Combined differential andrestricted earth fault schemes 16.10

Earthing transformer protection 16.11Auto-transformer protection 16.12

Overfluxing protection 16.13Tank-earth protection 16.14

Oil and gas devices 16.15Transformer-feeder protection 16.16

Intertripping 16.17Condition monitoring of transformers 16.18

Examples of transformer protection 16.19

• 1 6 • T r a n s f o r m e r a n dT r a n s f o r m e r - f e e d e r P r o t e c t i o n

Chap16-254-279 17/06/02 9:58 Page 254

16.1 INTRODUCTION

The development of modern power systems has beenreflected in the advances in transformer design. This hasresulted in a wide range of transformers with sizesranging from a few kVA to several hundred MVA beingavailable for use in a wide variety of applications.

The considerations for a transformer protection packagevary with the application and importance of thetransformer. To reduce the effects of thermal stress andelectrodynamic forces, it is advisable to ensure that theprotection package used minimises the time fordisconnection in the event of a fault occurring within thetransformer. Small distribution transformers can beprotected satisfactorily, from both technical andeconomic considerations, by the use of fuses orovercurrent relays. This results in time-delayedprotection due to downstream co-ordinationrequirements. However, time-delayed fault clearance isunacceptable on larger power transformers used indistribution, transmission and generator applications,due to system operation/stability and cost ofrepair/length of outage considerations.

Transformer faults are generally classified into fivecategories:

a. winding and terminal faultsb. core faultsc. tank and transformer accessory faultsd. on–load tap changer faultse. abnormal operating conditionsf. sustained or uncleared external faults

For faults originating in the transformer itself, theapproximate proportion of faults due to each of thecauses listed above is shown in Figure 16.1.

• 16 • Transfor me r andTransfor me r-Feede r P rotect ion


Winding and terminal

Core

Tank and accessories

OLTC

Figure 16.1: Transformer fault statistics

Chap16-254-279 17/06/02 9:58 Page 255

16.2 WINDING FAULTS

A fault on a transformer winding is controlled inmagnitude by the following factors:

i. source impedance

ii. neutral earthing impedance

iii. transformer leakage reactance

iv. fault voltage

v. winding connection

Several distinct cases arise and are examined below.

16.2.1 Star-Connected Winding withNeutral Point Earthed through an Impedance

The winding earth fault current depends on the earthingimpedance value and is also proportional to the distanceof the fault from the neutral point, since the faultvoltage will be directly proportional to this distance.

For a fault on a transformer secondary winding, thecorresponding primary current will depend on thetransformation ratio between the primary winding andthe short-circuited secondary turns. This also varies withthe position of the fault, so that the fault current in thetransformer primary winding is proportional to thesquare of the fraction of the winding that is short-circuited. The effect is shown in Figure 16.2. Faults inthe lower third of the winding produce very little currentin the primary winding, making fault detection byprimary current measurement difficult.

16.2.2 Star-connected winding withNeutral Point Solidly Earthed

The fault current is controlled mainly by the leakagereactance of the winding, which varies in a complexmanner with the position of the fault. The variable faultpoint voltage is also an important factor, as in the caseof impedance earthing. For faults close to the neutralend of the winding, the reactance is very low, and resultsin the highest fault currents. The variation of currentwith fault position is shown in Figure 16.3.

For secondary winding faults, the primary winding faultcurrent is determined by the variable transformationratio; as the secondary fault current magnitude stayshigh throughout the winding, the primary fault current islarge for most points along the winding.

16.2.3 Delta-connected Winding

No part of a delta-connected winding operates with avoltage to earth of less than 50% of the phase voltage.The range of fault current magnitude is therefore lessthan for a star winding. The actual value of fault currentwill still depend on the method of system earthing; itshould also be remembered that the impedance of adelta winding is particularly high to fault currentsflowing to a centrally placed fault on one leg. Theimpedance can be expected to be between 25% and50%, based on the transformer rating, regardless of thenormal balanced through-current impedance. As theprefault voltage to earth at this point is half the normalphase voltage, the earth fault current may be no morethan the rated current, or even less than this value if thesource or system earthing impedance is appreciable. Thecurrent will flow to the fault from each side through thetwo half windings, and will be divided between two

• 16 •

Tran

sfor

mer

and

Tra

nsfo

rmer

-Fee

der

Pro

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ion


5

20100 4030 50 60

10

908070 100

20

15

Curr

ent

(per

uni

t)

Distance of fault from neutral (percentage of winding)

Primary current

Fault current

Figure 16.3 Earth fault currentin solidly earthed star winding

Figure 16.2 Earth fault currentin resistance-earthed star winding

20

200

10

10 4030 50 60

50

30

40

908070 100

60

90

70

80

100

p)

Fault current (I FI )F)F

FIF

IpIpI

(percentage of winding)

Perc

enta

ge o

f res

pect

ive

max

imum

sing

le-p

hase

ear

th f

ault

curr

ent

Chap16-254-279 17/06/02 9:58 Page 256

phases of the system. The individual phase currents maytherefore be relatively low, resulting in difficulties inproviding protection.

16.2.4 Phase to Phase Faults

Faults between phases within a transformer arerelatively rare; if such a fault does occur it will give riseto a substantial current comparable to the earth faultcurrents discussed in Section 16.2.2.

16.2.5 Interturn Faults

In low voltage transformers, interturn insulationbreakdown is unlikely to occur unless the mechanicalforce on the winding due to external short circuits hascaused insulation degradation, or insulating oil (if used)has become contaminated by moisture.

A high voltage transformer connected to an overheadtransmission system will be subjected to steep frontedimpulse voltages, arising from lightning strikes, faults andswitching operations. A line surge, which may be ofseveral times the rated system voltage, will concentrate onthe end turns of the winding because of the highequivalent frequency of the surge front. Part-windingresonance, involving voltages up to 20 times rated voltagemay occur. The interturn insulation of the end turns isreinforced, but cannot be increased in proportion to theinsulation to earth, which is relatively great. Partialwinding flashover is therefore more likely. The subsequentprogress 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 riseto a heavy fault current in the short-circuited loop, butthe terminal currents will be very small, because of thehigh ratio of transformation between the whole windingand the short-circuited turns.

The graph in Figure 16.4 shows the corresponding datafor a typical transformer of 3.25% impedance with theshort-circuited turns symmetrically located in the centreof the winding.

16.2.6 Core Faults

A conducting bridge across the laminated structures ofthe core can permit sufficient eddy-current to flow tocause serious overheating. The bolts that clamp the coretogether are always insulated to avoid this trouble. Ifany portion of the core insulation becomes defective, theresultant heating may reach a magnitude sufficient todamage the winding.

The additional core loss, although causing severe localheating, will not produce a noticeable change in inputcurrent and could not be detected by the normalelectrical protection; it is nevertheless highly desirablethat the condition should be detected before a majorfault has been created. In an oil-immersed transformer,core heating sufficient to cause winding insulationdamage will also cause breakdown of some of the oilwith an accompanying evolution of gas. This gas willescape to the conservator, and is used to operate amechanical relay; see Section 16.15.3.

16.2.7 Tank Faults

Loss of oil through tank leaks will ultimately produce adangerous condition, either because of a reduction inwinding insulation or because of overheating on loaddue to the loss of cooling.

Overheating may also occur due to prolongedoverloading, blocked cooling ducts due to oil sludging orfailure of the forced cooling system, if fitted.

16.2.8 Externally Applied Conditions

Sources of abnormal stress in a transformer are:

a. overload

b. system faults

c. overvoltage

d. reduced system frequency

16.2.8.1 Overload

Overload causes increased 'copper loss' and a consequenttemperature rise. Overloads can be carried for limitedperiods and recommendations for oil-immersedtransformers are given in IEC 60354.

The thermal time constant of naturally cooledtransformers lies between 2.5-5 hours. Shorter timeconstants apply in the case of force-cooled transformers.

• 16 •Tr

ansf

orm

er a

nd T

rans

form

er-F

eede

r P

rote

ctio

n


Figure 16.4 Interturn fault current/numberof turns short-circuited

20

50 10 15

40

20 25

100

80

Faul

t cu

rren

t (m

ultip

les

of ra

ted

curr

ent)

Turns short-circuited (percentage of winding)

60

Prim

ary

curr

ent

(mul

tiple

s of

rate

d cu

rren

t)

2

4

6

10

8

Primary inputcurrent

Fault current intshort circuited turns

Chap16-254-279 17/06/02 9:58 Page 257

16.2.8.2 System faults

System short circuits produce a relatively intense rate ofheating of the feeding transformers, the copper lossincreasing in proportion to the square of the per unitfault current. The typical duration of external shortcircuits that a transformer can sustain without damageif the current is limited only by the self-reactance isshown in Table 16.1. IEC 60076 provides furtherguidance on short-circuit withstand levels.

Table 16.1: Fault withstand levels

Maximum mechanical stress on windings occurs duringthe first cycle of the fault. Avoidance of damage is amatter of transformer design.

16.2.8.3 Overvoltages

Overvoltage conditions are of two kinds:

i. transient surge voltages

ii. power frequency overvoltage

Transient overvoltages arise from faults, switching, andlightning disturbances and are liable to cause interturnfaults, as described in Section 16.2.5. These overvoltagesare usually limited by shunting the high voltageterminals to earth either with a plain rod gap or by surgediverters, which comprise a stack of short gaps in serieswith a non-linear resistor. The surge diverter, in contrastto the rod gap, has the advantage of extinguishing theflow of power current after discharging a surge, in thisway avoiding subsequent isolation of the transformer.

Power frequency overvoltage causes both an increase instress on the insulation and a proportionate increase inthe working flux. The latter effect causes an increase inthe iron loss and a disproportionately large increase inmagnetising current. In addition, flux is diverted fromthe laminated core into structural steel parts. The corebolts, which normally carry little flux, may be subjectedto a large flux diverted from the highly saturated regionof core alongside. This leads to a rapid temperature risein the bolts, destroying their insulation and damagingcoil insulation if the condition continues.

16.2.8.4 Reduced system frequency

Reduction of system frequency has an effect with regardto flux density, similar to that of overvoltage.

It follows that a transformer can operate with somedegree of overvoltage with a corresponding increase in

frequency, but operation must not be continued with ahigh voltage input at a low frequency. Operation cannotbe sustained when the ratio of voltage to frequency, withthese quantities given values in per unit of their ratedvalues, exceeds unity by more than a small amount, forinstance if V/f >1.1. If a substantial rise in systemvoltage has been catered for in the design, the base of'unit voltage' should be taken as the highest voltage forwhich the transformer is designed.

16.3 MAGNETIS ING INRUSH

The phenomenon of magnetising inrush is a transientcondition that occurs primarily when a transformer isenergised. It is not a fault condition, and thereforetransformer protection must remain stable during theinrush transient.

Figure 16.5(a) shows a transformer magnetisingcharacteristic. To minimise material costs, weight andsize, transformers are generally operated near to the‘knee point’ of the magnetising characteristic.

• 16 •

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and

Tra

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-Fee

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Transformer reactance Fault current Permitted fault(%) (Multiple of rating) duration (seconds)

4 25 2

5 20 2

6 16.6 2

7 14.2 2

(d) Inrush without offset, due to yoke saturation

Zero axis

Zero axis

(c) Typical inrush current

Slow decrement

(a) Typical magnetising characteristic

Magnetising current

Normal peak flux

Flux

(b) Steady and maximum offset fluxes

Transient flux 80% residualat switching

Transient flux no residualat switching

Steady flux state

Voltage

Time

Volta

ge a

nd fl

ux

Figure 16.5: Transformer magnetising inrush

Chap16-254-279 17/06/02 9:58 Page 258

Consequently, only a small increase in core flux abovenormal operating levels will result in a high magnetisingcurrent.

Under normal steady-state conditions, the magnetisingcurrent associated with the operating flux level isrelatively small (Figure 16.5(b)). However, if atransformer winding is energised at a voltage zero, withno remanent flux, the flux level during the first voltagecycle (2 x normal flux) will result in core saturation anda high non-sinusoidal magnetising current waveform –see Figure 16.5(c). This current is referred to asmagnetising inrush current and may persist for severalcycles.

A number of factors affect the magnitude and durationof the magnetising current inrush:

a. residual flux – worst-case conditions result in the flux peak value attaining 280% of normal value

b. point on wave switching

c. number of banked transformers

d. transformer design and rating

e. system fault level

The very high flux densities quoted above are so farbeyond the normal working range that the incrementalrelative permeability of the core approximates to unityand the inductance of the winding falls to a value nearthat of the 'air-cored' inductance. The current wave,starting from zero, increases slowly at first, the fluxhaving a value just above the residual value and thepermeability of the core being moderately high. As theflux passes the normal working value and enters thehighly saturated portion of the magnetisingcharacteristic, the inductance falls and the current risesrapidly to a peak that may be 500% of the steady statemagnetising current. When the peak is passed at thenext voltage zero, the following negative half cycle ofthe voltage wave reduces the flux to the starting value,the current falling symmetrically to zero. The currentwave is therefore fully offset and is only restored to thesteady state condition by the circuit losses. The timeconstant of the transient has a range between 0.1second (for a 100kVA transformer) to 1.0 second (for alarge unit). As the magnetising characteristic is non-linear, the envelope of the transient current is not strictlyof exponential form; the magnetising current can beobserved to be still changing up to 30 minutes afterswitching on.

Although correct choice of the point on the wave for asingle–phase transformer will result in no transientinrush, mutual effects ensure that a transient inrushoccurs in all phases for three-phase transformers.

16.3.1 Harmonic Content of Inrush Waveform

The waveform of transformer magnetising currentcontains a proportion of harmonics that increases as thepeak flux density is raised to the saturating condition.The magnetising current of a transformer contains athird harmonic and progressively smaller amounts offifth and higher harmonics. If the degree of saturation isprogressively increased, not only will the harmoniccontent increase as a whole, but the relative proportionof fifth harmonic will increase and eventually exceed thethird harmonic. At a still higher level the seventh wouldovertake the fifth harmonic but this involves a degree ofsaturation that will not be experienced with powertransformers.

The energising conditions that result in an offset inrushcurrent produce a waveform that is asymmetrical. Sucha wave typically contains both even and odd harmonics.Typical inrush currents contain substantial amounts ofsecond and third harmonics and diminishing amounts ofhigher orders. As with the steady state wave, theproportion of harmonics varies with the degree ofsaturation, so that as a severe inrush transient decays,the harmonic makeup of the current passes through arange of conditions.

16.4 TRANSFORMER OVERHEATING

The rating of a transformer is based on the temperaturerise above an assumed maximum ambient temperature;under this condition no sustained overload is usuallypermissible. At a lower ambient temperature somedegree of sustained overload can be safely applied.Short-term overloads are also permissible to an extentdependent on the previous loading conditions. IEC60354 provides guidance in this respect.

The only certain statement is that the winding must notoverheat; a temperature of about 95°C is considered tobe the normal maximum working value beyond which afurther rise of 8°C-10°C, if sustained, will halve theinsulation life of the unit.

Protection against overload is therefore based onwinding temperature, which is usually measured by athermal image technique. Protection is arranged to tripthe transformer if excessive temperature is reached. Thetrip signal is usually routed via a digital input of aprotection relay on one side of the transformer, withboth alarm and trip facilities made available throughprogrammable logic in the relay. Intertripping betweenthe relays on the two sides of the transformer is usuallyapplied to ensure total disconnection of the transformer.

Winding temperature protection may be included as apart of a complete monitoring package – see Section16.18 for more details.

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16.5 TRANSFORMER PROTECTION – OVERVIEW

The problems relating to transformers described inSections 16.2-4 above require some means of protection.Table 16.2 summarises the problems and the possibleforms of protection that may be used. The followingsections provide more detail on the individual protectionmethods. It is normal for a modern relay to provide allof the required protection functions in a single package,in contrast to electromechanical types that wouldrequire several relays complete with interconnectionsand higher overall CT burdens.

16.6 TRANSFORMER OVERCURRENT PROTECTION

Fuses may adequately protect small transformers, butlarger ones require overcurrent protection using a relayand CB, as fuses do not have the required fault breakingcapacity.

16.6.1 Fuses

Fuses commonly protect small distribution transformerstypically up to ratings of 1MVA at distribution voltages.In many cases no circuit breaker is provided, making fuseprotection the only available means of automaticisolation. The fuse must have a rating well above themaximum transformer load current in order to withstandthe short duration overloads that may occur. Also, thefuses must withstand the magnetising inrush currentsdrawn when power transformers are energised. HighRupturing Capacity (HRC) fuses, although very fast inoperation with large fault currents, are extremely slowwith currents of less than three times their rated value.It follows that such fuses will do little to protect thetransformer, serving only to protect the system bydisconnecting a faulty transformer after the fault hasreached an advanced stage.

Table 16.3 shows typical ratings of fuses for use with11kV transformers.

This table should be taken only as a typical example;considerable differences exist in the time characteristicof different types of HRC fuses. Furthermore gradingwith protection on the secondary side has not beenconsidered.

16.6.2 Overcurrent relays

With the advent of ring main units incorporating SF6circuit breakers and isolators, protection of distributiontransformers can now be provided by overcurrent trips(e.g. tripping controlled by time limit fuses connectedacross the secondary windings of in-built currenttransformers) or by relays connected to currenttransformers located on the transformer primary side.Overcurrent relays are also used on larger transformersprovided with standard circuit breaker control.Improvement in protection is obtained in two ways; theexcessive delays of the HRC fuse for lower fault currentsare avoided and an earth-fault tripping element isprovided in addition to the overcurrent feature.

The time delay characteristic should be chosen todiscriminate 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 asecondary short circuit. This enables high-speedclearance of primary terminal short circuits.

16.7 RESTRICTED EARTH FAULT PROTECTION

Conventional earth fault protection using overcurrentelements fails to provide adequate protection fortransformer windings. This is particularly the case for astar-connected winding with an impedance-earthedneutral, as considered in Section 16.2.1.

The degree of protection is very much improved by theapplication of restricted earth fault protection (or REFprotection). This is a unit protection scheme for onewinding of the transformer. It can be of the high impe-dance type as shown in Figure 16.6, or of the biased low-impedance type. For the high-impedance type, the resi-dual current of three line current transformers is balan-ced against the output of a current transformer in the

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Table 16.2: Transformer faults/protection

Fault Type 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

Transformer rating Fuse

kVA Full load current (A) Rated current (A)Operating timeat 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

Chap16-254-279 17/06/02 9:58 Page 260

neutral conductor. In the biased low-impedance version,the three phase currents and the neutral current becomethe bias inputs to a differential element.The system is operative for faults within the region bet-ween current transformers, that is, for faults on the starwinding in question. The system will remain stable for allfaults outside this zone.

The gain in protection performance comes not only fromusing an instantaneous relay with a low setting, but alsobecause the whole fault current is measured, not merelythe transformed component in the HV primary winding (ifthe star winding is a secondary winding). Hence, althoughthe prospective current level decreases as fault positionsprogressively nearer the neutral end of the winding areconsidered, the square law which controls the primary linecurrent 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 evenwhen the neutral is solidly earthed. Since fault currentthen remains at a high value even to the last turn of thewinding (Figure 16.2), virtually complete cover for earthfaults is obtained. This is an improvement comparedwith the performance of systems that do not measurethe neutral conductor current.Earth fault protection applied to a delta-connected orunearthed star winding is inherently restricted, since nozero sequence components can be transmitted throughthe transformer to the other windings.Both windings of a transformer can be protected separa-tely with restricted earth fault protection, thereby provi-ding high-speed protection against earth faults for thewhole transformer with relatively simple equipment. Ahigh impedance relay is used, giving fast operation andphase fault stability.

16.8 DIFFERENTIAL PROTECTION

The restricted earth fault schemes described above inSection 16.7 depend entirely on the Kirchhoff principlethat the sum of the currents flowing into a conductingnetwork is zero. A differential system can be arranged to

cover the complete transformer; this is possible because ofthe high efficiency of transformer operation, and the closeequivalence of ampere-turns developed on the primaryand secondary windings. Figure 16.7 illustrates the prin-ciple. Current transformers on the primary and secondarysides are connected to form a circulating current system.

16.8.1 Basic Considerations forTransformer Differential Protection

In applying the principles of differential protection totransformers, a variety of considerations have to betaken into account. These include:

a. correction for possible phase shift across thetransformer windings (phase correction)

b. the effects of the variety of earthing and windingarrangements (filtering of zero sequence currents)

c. correction for possible unbalance of signals fromcurrent transformers on either side of the windings(ratio correction)

d. the effect of magnetising inrush during initialenergisation

e. the possible occurrence of overfluxing

In traditional transformer differential schemes, therequirements for phase and ratio correction were met bythe application of external interposing currenttransformers (ICT’s), as a secondary replica of the mainwinding connections, or by a delta connection of themain CT’s to provide phase correction only.Digital/numerical relays implement ratio and phasecorrection in the relay software instead, thus enablingmost combinations of transformer windingarrangements to be catered for, irrespective of thewinding connections of the primary CT’s. This avoids theadditional space and cost requirements of hardwareinterposing CT’s.

16.8.2 Line Current Transformer Primary Ratings

Line current transformers have primary ratings selectedto be approximately equal to the rated currents of the

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Figure 16.6: Restricted earth fault protectionfor a star winding

>I

High impedance relay

IdIdI >

Figure 16.7: Principle of transformerdifferential protection

Chap16-254-279 17/06/02 9:58 Page 261

transformer windings to which they are applied. Primaryratings will usually be limited to those of availablestandard ratio CT’s.

16.8.3 Phase Correction

Correct operation of transformer differential protectionrequires that the transformer primary and secondarycurrents, as measured by the relay, are in phase. If thetransformer is connected delta/star, as shown in Figure16.8, balanced three-phase through current suffers aphase change of 30°. If left uncorrected, this phasedifference would lead to the relay seeing through currentas an unbalanced fault current, and result in relayoperation. Phase correction must be implemented.

Electromechanical and static relays use appropriateCT/ICT connections to ensure that the primary andsecondary currents applied to the relay are in phase.

For digital and numerical relays, it is common to use star-connected line CT’s on all windings of the transformerand compensate for the winding phase shift in software.Depending on relay design, the only data required in suchcircumstances may be the transformer vector group

designation. Phase compensation is then performedautomatically. Caution is required if such a relay is usedto replace an existing electromechanical or static relay, asthe primary and secondary line CT’s may not have thesame winding configuration. Phase compensation andassociated relay data entry requires more detailedconsideration in such circumstances. Rarely, the availablephase compensation facilities cannot accommodate thetransformer winding connection, and in such casesinterposing CT’s must be used.

16.8.4 Filtering of Zero Sequence Currents

As described in Chapter 10.8, it is essential to providesome form of zero sequence filtering where a transformerwinding can pass zero sequence current to an externalearth fault. This is to ensure that out-of-zone earth faultsare not seen by the transformer protection as an in-zonefault. This is achieved by use of delta-connected line CT’sor interposing CT’s for older relays, and hence the windingconnection of the line and/or interposing CT’s must takethis into account, in addition to any phase compensationnecessary. For digital/numerical relays, the requiredfiltering is applied in the relay software. Table 16.4summarises the phase compensation and zero sequencefiltering requirements. An example of an incorrect choiceof ICT connection is given in Section 16.19.1.

16.8.5 Ratio Correction

Correct operation of the differential element requiresthat currents in the differential element balance underload and through fault conditions. As the primary andsecondary line CT ratios may not exactly match thetransformer rated winding currents, digital/numericalrelays are provided with ratio correction factors for eachof the CT inputs. The correction factors may be

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Figure 16.8: Differential protectionfor two-winding delta/star transformer

C

AB

IdIdI > IdIdI > IdIdI >

Table 16.4: Current transformer connections for power transformers of various vector groups

Transformer connection Transformer phase shift Clock face vector Phase compensation required HV Zero sequence filtering LV Zero sequence filtering

Yy0

0° 0 0°

Yes YesZd0 YesDz0 YesDd0Yz1 Zy1

-30° 1 30°Yes Yes

Yd1 YesDy1 YesYy6

-180° 6 180°

Yes YesZd6 YesDz6 YesDd6Yz11 Zy11

30° 11 -30°Yes Yes

Yd11 YesDy11 YesYyH YzH

(H / 12) x 360° Hour 'H' -(H / 12) x 360°

Yes YesYdH ZdH YesDzH DyH YesDdH'H': phase displacement 'clock number', according to IEC 60076-1

Chap16-254-279 17/06/02 10:00 Page 262

calculated automatically by the relay from knowledge ofthe line CT ratios and the transformer MVA rating.However, if interposing CT’s are used, ratio correctionmay not be such an easy task and may need to take intoaccount a factor of √

_3 if delta-connected CT’s or ICT’s are

involved. If the transformer is fitted with a tap changer,line CT ratios and correction factors are normally chosento achieve current balance at the mid tap of thetransformer. It is necessary to ensure that currentmismatch due to off-nominal tap operation will notcause spurious operation.

The example in Section 16.19.2 provides an illustration ofhow ratio correction factors are used, and that of Section16.9.3 shows how to set the ratio correction factors for atransformer with an unsymmetrical tap range.

16.8.6 Bias Setting

Bias is applied to transformer differential protection forthe same reasons as any unit protection scheme – toensure stability for external faults while allowingsensitive settings to pick up internal faults. The situationis slightly complicated if a tap changer is present. Withline CT/ICT ratios and correction factors set to achievecurrent balance at nominal tap, an off-nominal tap maybe seen by the differential protection as an internal fault.By selecting the minimum bias to be greater than sum ofthe maximum tap of the transformer and possible CTerrors, maloperation due to this cause is avoided. Somerelays use a bias characteristic with three sections, asshown in Figure 16.9. The first section is set higher thanthe transformer magnetising current. The second sectionis set to allow for off-nominal tap settings, while thethird has a larger bias slope beginning well above ratedcurrent to cater for heavy through-fault conditions.

16.8.7 Transformers with Multiple Windings

The unit protection principle remains valid for a systemhaving more than two connections, so a transformerwith three or more windings can still be protected by theapplication of the above principles.

When the power transformer has only one of its threewindings connected to a source of supply, with the othertwo windings feeding loads, a relay with only two sets ofCT inputs can be used, connected as shown in Figure16.10(a). The separate load currents are summated inthe CT secondary circuits, and will balance with theinfeed current on the supply side.

When more than one source of fault current infeedexists, there is a danger in the scheme of Figure 16.10(a)of current circulating between the two paralleled sets ofcurrent transformers without producing any bias. It istherefore important a relay is used with separate CTinputs for the two secondaries - Figure 16.10(b).

When the third winding consists of a delta-connectedtertiary with no connections brought out, thetransformer may be regarded as a two windingtransformer for protection purposes and protected asshown in Figure 16.10(c).

16.9 DIFFERENTIAL PROTECTION STABILISATIONDURING MAGNETISING INRUSH CONDITIONS

The magnetising inrush phenomenon described inSection 16.3 produces current input to the energisedwinding which has no equivalent on the other windings.The whole of the inrush current appears, therefore, asunbalance and the differential protection is unable to

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Figure 16.9: Typical bias characteristic

0 1 2 3 4

1

2

3

Diff

eren

tial c

urre

nt (

I d)

Setting range(0.1 - 0.5Id)

Effective bias (x In)

slope

Operate70%

Restrain slope30%

5 6

Possiblefaultinfeed

Possiblefaultinfeed

Source

Source

SourceLoads

(c) Three winding transformer with unloaded delta tertiary

(b) Three winding transformer (three power sources)

(a) Three winding transformer (one power source)

IdIdI >

IdIdI >

IdIdI >

Figure 16.10 Differential protection arrangementsfor three-winding transformers (shown singlephase for simplicity)

Chap16-254-279 17/06/02 10:00 Page 263

distinguish it from current due to an internal fault. Thebias setting is not effective and an increase in theprotection setting to a value that would avoid operationwould make the protection of little value. Methods ofdelaying, restraining or blocking of the differentialelement must therefore be used to prevent mal-operation of the protection.

16.9.1 Time Delay

Since the phenomenon is transient, stability can bemaintained by providing a small time delay. However,because this time delay also delays operation of the relayin the event of a fault occurring at switch-on, themethod is no longer used.

16.9.2 Harmonic Restraint

The inrush current, although generally resembling an in-zone fault current, differs greatly when the waveformsare compared. The difference in the waveforms can beused to distinguish between the conditions.

As stated before, the inrush current contains all harmonicorders, but these are not all equally suitable for providingbias. In practice, only the second harmonic is used.

This component is present in all inrush waveforms. It istypical of waveforms in which successive half period portionsdo not repeat with reversal of polarity but in which mirror-image symmetry can be found about certain ordinates.

The proportion of second harmonic varies somewhatwith the degree of saturation of the core, but is alwayspresent as long as the uni-directional component of fluxexists. The amount varies according to factors in thetransformer design. Normal fault currents do notcontain second or other even harmonics, nor do distortedcurrents flowing in saturated iron cored coils understeady state conditions.

The output current of a current transformer that isenergised into steady state saturation will contain oddharmonics but not even harmonics. However, should thecurrent transformer be saturated by the transientcomponent of the fault current, the resulting saturationis not symmetrical and even harmonics are introducedinto the output current. This can have the advantage ofimproving the through fault stability performance of adifferential relay. faults.

The second harmonic is therefore an attractive basis for astabilising bias against inrush effects, but care must betaken to ensure that the current transformers aresufficiently large so that the harmonics produced bytransient saturation do not delay normal operation of therelay. The differential current is passed through a filterthat extracts the second harmonic; this component is thenapplied to produce a restraining quantity sufficient to

overcome the operating tendency due to the whole of theinrush current that flows in the operating circuit. By thismeans a sensitive and high-speed system can be obtained.

16.9.3 Inrush Detection Blocking– Gap Detection Technique

Another feature that characterizes an inrush current canbe seen from Figure 16.5 where the two waveforms (c)and (d) have periods in the cycle where the current iszero. The minimum duration of this zero period istheoretically one quarter of the cycle and is easilydetected by a simple timer t1 that is set to 1_4f seconds.Figure 16.11 shows the circuit in block diagram form.Timer t1 produces an output only if the current is zero fora time exceeding 1_

4f seconds. It is reset when theinstantaneous value of the differential current exceedsthe setting reference.

As the zero in the inrush current occurs towards the endof the cycle, it is necessary to delay operation of thedifferential relay by 1_f seconds to ensure that the zerocondition can be detected if present. This is achieved byusing a second timer t2 that is held reset by an outputfrom timer t1.

When no current is flowing for a time exceeding 1_4f

seconds, timer t2 is held reset and the differential relaythat may be controlled by these timers is blocked. Whena differential current exceeding the setting of the relayflows, timer t1 is reset and timer t2 times out to give atrip signal in 1_f seconds. If the differential current ischaracteristic of transformer inrush then timer t2 will bereset on each cycle and the trip signal is blocked.

Some numerical relays may use a combination of theharmonic restraint and gap detection techniques formagnetising inrush detection.

16.10 COMBINED DIFFERENTIALAND RESTRICTED EARTH FAULT SCHEMES

The advantages to be obtained by the use of restrictedearth fault protection, discussed in Section 16.7, lead tothe system being frequently used in conjunction with anoverall differential system. The importance of this isshown in Figure 16.12 from which it will be seen that ifthe neutral of a star-connected winding is earthedthrough a resistance of one per unit, an overall differentialsystem having an effective setting of 20% will detectfaults in only 42% of the winding from the line end.

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Figure 16.11: Block diagram to show waveformgap-detecting principle

Timer 1t1= 1

4f

Inhibit Timer 2

ft2 = 1InhibitDifferential

comparatorTripDifferential

Bias

Threshold

Chap16-254-279 17/06/02 10:00 Page 264

Implementation of a combined differential/REFprotection scheme is made easy if a numerical relay withsoftware ratio/phase compensation is used. Allcompensation is made internally in the relay.

Where software ratio/phase correction is not available,either a summation transformer or auxiliary CT’s can beused. The connections are shown in Figures 16.13 and16.14 respectively.

Care must be taken in calculating the settings, but theonly significant disadvantage of the CombinedDifferential/REF scheme is that the REF element is likelyto operate for heavy internal faults as well as thedifferential elements, thus making subsequent faultanalysis somewhat confusing. However, the saving inCT’s outweighs this disadvantage.

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Figure 16.13 Combined differential and earth fault protection using summation current transformer


I

Restrictedearthfaultrelay

Differential relay

0204060801000

20

40

60

80

100

Restr

icted

earth

fault

prote

ction

Differen

tial p

rotect

ion

Percentage of winding protected

Prim

ary

oper

atin

g cu

rren

t(p

erce

ntag

e of

rate

d cu

rren

t)

Figure 16.12: Amount of winding protectedwhen transformer is resistance earthed and

ratings of transformer and resistor are equal

Restricted earthfault relay

Differential relayIdIdI > IdIdI > IdIdI >

Phase correctingauxiliary currenttransformers

>I

Figure 16.14: Combined differential and restricted earth fault protection using auxiliary CT’s

Chap16-254-279 17/06/02 10:00 Page 265

16.10.1 Application when an Earthing Transformeris connected within the Protected Zone

A delta-connected winding cannot deliver any zerosequence current to an earth fault on the connectedsystem, any current that does flow is in consequence ofan earthed neutral elsewhere on the system and willhave a 2-1-1 pattern of current distribution betweenphases. When the transformer in question represents amajor power feed, the system may be earthed at thatpoint by an earthing transformer or earthing reactor.They are frequently connected to the system, close to themain supply transformer and within the transformerprotection zone. Zero sequence current that flowsthrough the earthing transformer during system earth

faults will flow through the line current transformers onthis side, and, without an equivalent current in thebalancing current transformers, will cause unwantedoperation of the relays.

The problem can be overcome by subtracting theappropriate component of current from the main CToutput. The earthing transformer neutral current is usedfor this purpose. As this represents three times the zerosequence current flowing, ratio correction is required.This can take the form of interposing CT’s of ratio1/0.333, arranged to subtract their output from that ofthe line current transformers in each phase, as shown inFigure 16.15. The zero sequence component is cancelled,restoring balance to the differential system.

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Figure 16.15: Differential protection with in-zone earthing transformer, with restricted earth fault relay

C

A

B

Eart ingtransformer

Differential relay

Restricted earth fault relay

1/0.333


>I

C

AB

Differential relay

Earthingtransformer


Figure 16.16: Differential protection with in-zone earthing transformer; no earth fault relay

Chap16-254-279 17/06/02 10:00 Page 266

Alternatively, numerical relays may use software toperform the subtraction, having calculated the zerosequence component internally.

A high impedance relay element can be connected in theneutral lead between current transformers anddifferential relays to provide restricted earth faultprotection to the winding.

As an alternative to the above scheme, the circulatingcurrent system can be completed via a three-phasegroup of interposing transformers that are provided withtertiary windings connected in delta. This windingeffectively short-circuits the zero sequence componentand thereby removes it from the balancing quantities inthe relay circuit; see Figure 16.16.

Provided restricted earth fault protection is not required, thescheme shown in Figure 16.16 has the advantage of notrequiring a current transformer, with its associated mountingand cabling requirements, in the neutral-earth conductor.The scheme can also be connected as shown in Figure 16.17when restricted earth fault protection is needed.

16.11 EARTHING TRANSFORMER PROTECTION

Earthing transformers not protected by other means canuse the scheme shown in Figure 16.18. The delta-connected current transformers are connected to anovercurrent relay having three phase-fault elements. Thenormal action of the earthing transformer is to pass zerosequence current. The transformer equivalent currentcirculates in the delta formed by the CT secondarieswithout energising the relay. The latter may therefore beset to give fast and sensitive protection against faults inthe earthing transformer itself.

16.12 AUTOTRANSFORMER PROTECTION

Autotransformers are used to couple EHV powernetworks if the ratio of their voltages is moderate. Analternative to Differential Protection that can be appliedto autotransformers is protection based on theapplication of Kirchhoff's law to a conducting network,namely that the sum of the currents flowing into allexternal connections to the network is zero.

A circulating current system is arranged between equalratio current transformers in the two groups of lineconnections and the neutral end connections. If oneneutral current transformer is used, this and all the linecurrent transformers can be connected in parallel to asingle element relay, thus providing a scheme responsiveto earth faults only; see Figure 16.19(a).

If current transformers are fitted in each phase at theneutral end of the windings and a three-element relay is

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A

C

B

Earthing transformer

I>

Figure 16.18: Earthing transformer protection

Figure 16.17: Differential protection with in-zone earthing transformer,with alternative arrangement of restricted earth fault relay

C

A

B

Differential relay

Earthingtransformer

>I


Chap16-254-279 17/06/02 10:00 Page 267

used, a differential system can be provided, giving fullprotection against phase and earth faults; see Figure16.19(b). This provides high-speed sensitive protection.It is unaffected by ratio changes on the transformer dueto tap-changing and is immune to the effects ofmagnetising inrush current.

It does not respond to interturn faults, a deficiency that isserious in view of the high statistical risk quoted in Section16.1. Such faults, unless otherwise cleared, will be left todevelop into earth faults, by which time considerably moredamage to the transformer will have occurred.

In addition, this scheme does not respond to any fault ina tertiary winding. Unloaded delta-connected tertiarywindings are often not protected; alternatively, the deltawinding can be earthed at one point through a currenttransformer that energises an instantaneous relay. Thissystem should be separate from the main windingprotection. If the tertiary winding earthing lead isconnected to the main winding neutral above the neutralcurrent transformer in an attempt to make a combinedsystem, there may be ‘blind spots’ which the protectioncannot cover.

16.13 OVERFLUXING PROTECTION

The effects of excessive flux density are described inSection 16.2.8. Overfluxing arises principally from thefollowing system conditions:

a. high system voltage

b. low system frequency

c. geomagnetic disturbances

The latter results in low frequency earth currentscirculating through a transmission system.

Since momentary system disturbances can causetransient overfluxing that is not dangerous, time delayedtripping is required. The normal protection is an IDMT ordefinite time characteristic, initiated if a defined V/fthreshold is exceeded. Often separate alarm and tripelements are provided. The alarm function would bedefinite time-delayed and the trip function would be anIDMT characteristic. A typical characteristic is shown inFigure 16.20.

Geomagnetic disturbances may result in overfluxingwithout the V/f threshold being exceeded. Some relaysprovide a 5th harmonic detection feature, which can beused to detect such a condition, as levels of thisharmonic rise under overfluxing conditions.

16.14 TANK-EARTH PROTECTION

This is also known as Howard protection. If thetransformer tank is nominally insulated from earth (aninsulation resistance of 10 ohms being sufficient) earthfault protection can be provided by connecting a relay tothe secondary of a current transformer the primary ofwhich is connected between the tank and earth. Thisscheme is similar to the frame-earth fault busbarprotection described in Chapter 15.

16.15 OIL AND GAS DEVICES

All faults below oil in an oil-immersed transformer resultin localised heating and breakdown of the oil; some degreeof arcing will always take place in a winding fault and theresulting 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

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1

10

100

1000

Operatingtime (s)

=63=40

K=K=K 20

=1=5

1 1.1 1.2 1.3 1.4 1.5 1.6

SettingV/f

M =

t =0.8 + 0.18 x K

(M-1)2

Figure 16.20: Typical IDMT characteristicfor overfluxing protection

Figure 16.19: Protection of auto-transformerby high impedance differential relays

(a) Earth fault scheme

Highimpedancerelay

B

C

A

B

C

A

BC

A

(b) Phase and earth fault schemeN

IdIdI >

IdIdI > II > IdIdI >

Chap16-254-279 17/06/02 10:00 Page 268

arcing causes a very rapid release of large volumes of gasas well as oil vapour. The action is so violent that the gasand vapour do not have time to escape but instead buildup pressure and bodily displace the oil.

When such faults occur in transformers having oilconservators, the fault causes a blast of oil to pass up therelief pipe to the conservator. A Buchholz relay is usedto protect against such conditions. Devices respondingto abnormally high oil pressure or rate-of-rise of oilpressure are also available and may be used inconjunction with a Buchholz relay.

16.15.1 Oil Pressure Relief Devices

The simplest form of pressure relief device is the widelyused ‘frangible disc’ that is normally located at the endof an oil relief pipe protruding from the top of thetransformer tank.

The surge of oil caused by a serious fault bursts the disc,so allowing the oil to discharge rapidly. Relieving andlimiting the pressure rise avoids explosive rupture of thetank and consequent fire risk. Outdoor oil-immersedtransformers are usually mounted in a catchment pit tocollect and contain spilt oil (from whatever cause),thereby minimising the possibility of pollution.

A drawback of the frangible disc is that the oil remainingin the tank is left exposed to the atmosphere afterrupture. This is avoided in a more effective device, thesudden pressure relief valve, which opens to allowdischarge of oil if the pressure exceeds a set level, butcloses automatically as soon as the internal pressure fallsbelow this level. If the abnormal pressure is relativelyhigh, the valve can operate within a few milliseconds,and provide fast tripping when suitable contacts arefitted.

The device is commonly fitted to power transformersrated at 2MVA or higher, but may be applied todistribution transformers rated as low as 200kVA,particularly those in hazardous areas.

16.15.2 Rapid Pressure Rise Relay

This device detects rapid rise of pressure rather thanabsolute pressure and thereby can respond even quickerthan the pressure relief valve to sudden abnormally highpressures. Sensitivities as low as 0.07bar/s areattainable, but when fitted to forced-cooledtransformers the operating speed of the device may haveto be slowed deliberately to avoid spurious trippingduring circulation pump starts.

16.15.3 Buchholz Protection

Buchholz protection is normally provided on all

transformers fitted with a conservator. The Buchholzrelay is contained in a cast housing which is connectedin the pipe to the conservator, as in Figure 16.21.

A typical Buchholz relay will have two sets of contacts.One is arranged to operate for slow accumulations ofgas, the other for bulk displacement of oil in the event ofa heavy internal fault. An alarm is generated for theformer, but the latter is usually direct-wired to the CBtrip relay.

The device will therefore give an alarm for the followingfault conditions, all of which are of a low order ofurgency.

a. hot spots on the core due to short circuit oflamination insulation

b. core bolt insulation failure

c. faulty joints

d. interturn faults or other winding faults involvingonly lower power infeeds

e. loss of oil due to leakage

When a major winding fault occurs, this causes a surgeof oil, which displaces the lower float and thus causesisolation of the transformer. This action will take placefor:

i. all severe winding faults, either to earth orinterphase

ii. loss of oil if allowed to continue to a dangerousdegree

An inspection window is usually provided on either sideof the gas collection space. Visible white or yellow gasindicates that insulation has been burnt, while black orgrey gas indicates the presence of, dissociated oil. Inthese cases the gas will probably be inflammable,whereas released air will not. A vent valve is provided onthe top of the housing for the gas to be released or

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Figure 16.21: Buchholz relaymounting arrangement

76mm typical

Transformer

Conservator

5 x Internal pipediameter (min)

3 x Internal pipediameter (min)

Chap16-254-279 17/06/02 10:00 Page 269

collected for analysis. Transformers with forced oilcirculation may experience oil flow to/from theconservator on starting/stopping of the pumps. TheBuchholz relay must not operate in this circumstance.

Cleaning operations may cause aeration of the oil. Undersuch conditions, tripping of the transformer due toBuchholz operation should be inhibited for a suitable period.

Because of its universal response to faults within thetransformer, some of which are difficult to detect byother means, the Buchholz relay is invaluable, whetherregarded as a main protection or as a supplement toother protection schemes. Tests carried out by striking ahigh voltage arc in a transformer tank filled with oil,have shown that operation times of 0.05s-0.1s arepossible. Electrical protection is generally used as well,either to obtain faster operation for heavy faults, orbecause Buchholz relays have to be prevented fromtripping during oil maintenance periods. Conservatorsare fitted to oil-cooled transformers above 1000kVArating, except those to North American design practicethat use a different technique.

16.16 TRANSFORMER-FEEDER PROTECTION

A transformer-feeder comprises a transformer directlyconnected to a transmission circuit without theintervention of switchgear. Examples are shown inFigure 16.22.

The saving in switchgear so achieved is offset byincreased complication in the necessary protection. Theprimary requirement is intertripping, since the feederprotection remote from the transformer will not respondto the low current fault conditions that can be detectedby restricted earth fault and Buchholz protections.

Either unrestricted or restricted protection can beapplied; moreover, the transformer-feeder can be

protected as a single zone or be provided with separateprotections for the feeder and the transformer. In thelatter case, the separate protections can both be unittype systems. An adequate alternative is thecombination of unit transformer protection with anunrestricted system of feeder protection, plus anintertripping feature.

16.16.1 Non-Unit Schemes

The following sections describe how non-unit schemesare applied to protect transformer-feeders againstvarious types of fault.

16.16.1.1 Feeder phase and earth faults

High-speed protection against phase and earth faultscan be provided by distance relays located at the end ofthe feeder remote from the transformer. The transformerconstitutes an appreciable lumped impedance. It istherefore possible to set a distance relay zone to coverthe whole feeder and reach part way into thetransformer impedance. With a normal tolerance onsetting thus allowed for, it is possible for fast Zone 1protection to cover the whole of the feeder withcertainty without risk of over-reaching to a fault on thelow voltage side.

Although the distance zone is described as being set ’halfway into the transformer’, it must not be thought thathalf the transformer winding will be protected. Theeffects of auto-transformer action and variations in theeffective impedance of the winding with fault positionprevent this, making the amount of winding beyond theterminals which is protected very small. The value of thesystem is confined to the feeder, which, as stated above,receives high-speed protection throughout.

16.16.1.2 Feeder phase faults

A distance scheme is not, for all practical purposes,affected by varying fault levels on the high voltagebusbars and is therefore the best scheme to apply if thefault level may vary widely. In cases where the fault levelis reasonably constant, similar protection can beobtained using high set instantaneous overcurrent relays.These should have a low transient over-reach, defined as:

where: IS = setting current

IF = steady - state r.m.s. value of fault currentwhich when fully offset just operates therelay

The instantaneous overcurrent relays must be setwithout risk of them operating for faults on the remoteside of the transformer.

I II

S F

F

− × 100%

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HV LV

HV LV

HV LV

HVLV

Figure 16.22: Typical transformer-feeder circuits.

Chap16-254-279 17/06/02 10:01 Page 270

Referring to Figure 16.23, the required setting to ensurethat the relay will not operate for a fully offset fault IF2is given by:

IS = 1.2 (1 + t) IF2

where IF2 is the fault current under maximum sourceconditions, that is, when ZS is minimum, and the factorof 1.2 covers possible errors in the system impedancedetails used for calculation of IF2 , together with relayand CT errors.As it is desirable for the instantaneous overcurrentprotection to clear all phase faults anywhere within thefeeder under varying system operating conditions, it isnecessary to have a relay setting less than IF1 in order toensure fast and reliable operation.

Let the setting ratio resulting from setting IS be

Therefore,rIF1 = 1.2(1 + t)IF2

Hence,

r tZ Z

Z Z Z

r tZ Zx Z Z

t

x

S L

S L T

S L

S L

= +( ) ++ +

= +( ) ++( ) +( )

=+( )

+

1 2 1

1 2 11

1 2 1

1

.

.

.

rII

S

F

=1

where:

It can be seen that for a given transformer size, the mostsensitive protection for the line will be obtained by usingrelays with the lowest transient overreach. It should benoted that where r is greater than 1, the protection willnot cover the whole line. Also, any increase in sourceimpedance above the minimum value will increase theeffective setting ratios above those shown. Theinstantaneous protection is usually applied with a timedelayed overcurrent element having a lower currentsetting. In this way, instantaneous protection is providedfor the feeder, with the time-delayed element coveringfaults on the transformer.

When the power can flow in the transformer-feeder ineither direction, overcurrent relays will be required atboth ends. In the case of parallel transformer-feeders, itis essential that the overcurrent relays on the lowvoltage side be directional, operating only for faultcurrent fed into the transformer-feeder, as described inSection 9.14.3.

16.16.1.3 Earth faults

Instantaneous restricted earth fault protection isnormally provided. When the high voltage winding isdelta connected, a relay in the residual circuit of the linecurrent transformers gives earth fault protection which

xZ

Z ZT

S L

=+

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Figure 16.23: Over-reach considerations in the application of transformer-feeder protection

ZS ZLZT

IF1 IF2

Transientover-reach (%)

0.25

1.0

0.5

2.0

8.0

4.0

Setting ratio r =

1.01 1.20 1.44 1.92

0.84

0.42

0.63

0.14

0.25

0.50

0.30

0.17

1.00

0.75

0.60

0.36

0.20

1.20

0.90

0.80

0.48

0.27

1.60

1.20

Is = Relay setting = 1.2(1 + t)IF2

IS

IF2

t = Transient over-reach (p.u.)

5 25 50 100

I>>

x = ZT

ZS + ZL

~

Chap16-254-279 17/06/02 10:01 Page 271

is fundamentally limited to the feeder and the associateddelta-connected transformer winding. The latter isunable to transmit any zero sequence current to athrough earth fault.

When the feeder is associated with an earthed star-connected winding, normal restricted earth faultprotection as described in Section 16.7 is not applicablebecause of the remoteness of the transformer neutral.

Restricted protection can be applied using a directionalearth fault relay. A simple sensitive and high-speeddirectional element can be used, but attention must bepaid to the transient stability of the element.Alternatively, a directional IDMT relay may be used, thetime multiplier being set low. The slight inverse timedelay in operation will ensure that unwanted transientoperation is avoided.

When the supply source is on the high voltage star side,an alternative scheme that does not require a voltagetransformer can be used. The scheme is shown in Figure16.24. For the circuit breaker to trip, both relays A andB must operate, which will occur for earth faults on thefeeder or transformer winding.

External earth faults cause the transformer to deliver zerosequence current only, which will circulate in the closeddelta connection of the secondary windings of the threeauxiliary current transformers. No output is available torelay B. Through phase faults will operate relay B, butnot the residual relay A. Relay B must have a setting

above the maximum load. As the earthing of the neutralat a receiving point is likely to be solid and the earth faultcurrent will therefore be comparable with the phase faultcurrent, high settings are not a serious limitation.

Earth fault protection of the low voltage winding will beprovided by a restricted earth fault system using eitherthree or four current transformers, according to whetherthe winding is delta or star-connected, as described inSection 16.7.

16.16.1.4 In-zone capacitance

The feeder portion of the transformer-feeder will have anappreciable capacitance between each conductor andearth. During an external earth fault the neutral will bedisplaced, and the resulting zero sequence component ofvoltage will produce a corresponding component of zerosequence capacitance current. In the limiting case of fullneutral displacement, this zero sequence current will beequal in value to the normal positive sequence current.

The resulting residual current is equal to three times thezero sequence current and hence to three times thenormal line charging current. The value of thiscomponent of in-zone current should be considered whenestablishing the effective setting of earth fault relays.

16.16.2 Unit Schemes

The basic differences between the requirements of feeder

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A

B

C

I > >I >I

I >

Relay B

Relay A

A

+

Tripcircuit

B

B

B

Figure 16.24: Instantaneous protection of transformer-feeder

Chap16-254-279 17/06/02 10:02 Page 272

and transformer protections lie in the limitation imposedon the transfer of earth fault current by the transformerand the need for high sensitivity in the transformerprotection, suggesting that the two components of atransformer-feeder should be protected separately. Thisinvolves mounting current transformers adjacent to, oron, the high voltage terminals of the transformer.Separate current transformers are desirable for thefeeder and transformer protections so that these can bearranged in two separate overlapping zones. The use ofcommon current transformers is possible, but mayinvolve the use of auxiliary current transformers, orspecial winding and connection arrangements of therelays. Intertripping of the remote circuit breaker fromthe transformer protection will be necessary, but this canbe done using the communication facilities of the feederprotection relays.

Although technically superior, the use of separateprotection systems is seldom justifiable when comparedwith an overall system or a combination of non-unitfeeder protection and a unit transformer system.

An overall unit system must take into account the factthat zero sequence current on one side of a transformermay not be reproduced in any form on the other side.This represents little difficulty to a modern numericalrelay using software phase/zero sequence compensationand digital communications to transmit full informationon the phase and earth currents from one relay to theother. However, it does represent a more difficultproblem for relays using older technology. The linecurrent transformers can be connected to a summationtransformer with unequal taps, as shown in Figure16.25(a). This arrangement produces an output for phasefaults and also some response for A and B phase-earthfaults. However, the resulting settings will be similar tothose for phase faults and no protection will be given forC phase-earth faults.

An alternative technique is shown in Figure 16.25(b).

The B phase is taken through a separate winding onanother transformer or relay electromagnet, to provideanother balancing system. The two transformers areinterconnected with their counterparts at the other endof the feeder-transformer by four pilot wires. Operationwith three pilot cores is possible but four are preferable,involving little increase in pilot cost.

16.17 INTERTRIPPING

In order to ensure that both the high and low voltagecircuit breakers operate for faults within the transformerand feeder, it is necessary to operate both circuitbreakers from protection normally associated with one.The technique for doing this is known as intertripping.

The necessity for intertripping on transformer-feedersarises from the fact that certain types of fault produceinsufficient current to operate the protection associatedwith one of the circuit breakers. These faults are:

a. faults in the transformer that operate the Buchholzrelay and trip the local low voltage circuit breaker,while failing to produce enough fault current tooperate the protection associated with the remotehigh voltage circuit breaker

b. earth faults on the star winding of the transformer,which, because of the position of the fault in thewinding, again produce insufficient current forrelay operation at the remote circuit breaker

c. earth faults on the feeder or high voltage delta-connected winding which trip the high voltagecircuit breaker only, leaving the transformerenergised form the low voltage side and with twohigh voltage phases at near line-to-line voltageabove earth. Intermittent arcing may follow andthere is a possibility of transient overvoltageoccurring and causing a further breakdown ofinsulation

Several methods are available for intertripping; these arediscussed in Chapter 8.

16.17.1 Neutral Displacement

An alternative to intertripping is to detect the conditionby measuring the residual voltage on the feeder. Anearth fault occurring on the feeder connected to anunearthed transformer winding should be cleared by thefeeder circuit, but if there is also a source of supply onthe secondary side of the transformer, the feeder may bestill live. The feeder will then be a local unearthedsystem, and, if the earth fault continues in an arcingcondition, dangerous overvoltages may occur.

A voltage relay is energised from the broken-deltaconnected secondary winding of a voltage transformeron the high voltage line, and receives an inputproportional to the zero sequence voltage of the line,that is, to any displacement of the neutral point; seeFigure 16.26.

The relay normally receives zero voltage, but, in thepresence of an earth fault, the broken-delta voltage willrise to three times the phase voltage. Earth faultselsewhere in the system may also result in displacementof the neutral and hence discrimination is achieved usingdefinite or inverse time characteristics.

16.18 CONDITION MONITORING OF TRANSFORMERS

It is possible to provide transformers with measuringdevices to detect early signs of degradation in various

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Figure 16.25: Methods of protection for transformer-feeders using electromechanical static technology

(b) Balanced voltage system

A

B

C

Relay electromagnets(bias inherent)

Pilots

(a) Circulating current system

E

D D

E

A

B

C

Differential relays

Feeder

D Bias winding

E Operating winding

Chap16-254-279 17/06/02 10:02 Page 274

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ABC

Ursd>

Voltagetransformer

Residual voltage relay

Figure 16.26: Neutral displacement detectionusing voltage transformer.

components and provide warning to the operator inorder to avoid a lengthy and expensive outage due tofailure. The technique, which can be applied to otherplant as well as transformers, is called conditionmonitoring, as the intent is to provide the operator withregular information on the condition of the transformer.By reviewing the trends in the information provided, the

operator can make a better judgement as to thefrequency of maintenance, and detect early signs ofdeterioration that, if ignored, would lead to an internalfault occurring. Such techniques are an enhancement to,but are not a replacement for, the protection applied toa transformer.

The extent to which condition monitoring is applied totransformers on a system will depend on many factors,amongst which will be the policy of the asset owner, thesuitability of the design (existing transformers mayrequire modifications involving a period out of service –this may be costly and not justified), the importance ofthe asset to system operation, and the general record ofreliability. Therefore, it should not be expected that alltransformers would be, or need to be, so fitted.

A typical condition monitoring system for an oil-immersed transformer is capable of monitoring thecondition of various transformer components as shownin Table 16.5. There can be some overlap with themeasurements available from a digital/numerical relay.By the use of software to store and perform trendanalysis of the measured data, the operator can bepresented with information on the state of health of thetransformer, and alarms raised when measured valuesexceed appropriate limits. This will normally provide the

Monitored Equipment Measured Quantity Health Information

Table 16.5: Condition monitoring for transformers

Bushings

Tank

Tap changer

Coolers

Conservator

Voltage

Partial discharge measurement(wideband voltage)

Load current

Oil pressure

Oil temperature

Gas-in-oil content

Buchholz gas contentMoisture-in-oil content

PositionDrive power consumption

Total switched load currentOLTC oil temperature

Oil temperature differenceCooling air temperatureAmbient temperature

Pump statusOil level

Insulation quality

LoadingPermissible overload rating

Hot-spot temperatureInsulation quality

Hot-spot temperaturePermissible overload rating

Oil qualityWinding insulation condition

Oil qualityWinding insulation condition

Frequency of use of each tap positionOLTC health

OLTC contact wearOLTC health

Cooler efficiency

Cooling plant healthTank integrity

Chap16-254-279 17/06/02 10:02 Page 275

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operator with early warning of degradation within one ormore components of the transformer, enablingmaintenance to be scheduled to correct the problemprior to failure occurring. The maintenance canobviously be planned to suit system conditions, providedthe rate of degradation is not excessive.

As asset owners become more conscious of the costs ofan unplanned outage, and electric supply networks areutilised closer to capacity for long periods of time, theusefulness of this technique can be expected to grow.

16.19 EXAMPLES OF TRANSFORMER PROTECTION

This section provides three examples of the applicationof modern relays to transformer protection. The latestMiCOM P630 series relay provides advanced software tosimplify the calculations, so an earlier ALSTOM typeKBCH relay is used to illustrate the complexity of therequired calculations.

16.19.1 Provision of Zero-Sequence Filtering

Figure 16.27 shows a delta-star transformer to beprotected using a unit protection scheme. With a mainwinding connection of Dyn11, suitable choices of primaryand secondary CT winding arrangements, and softwarephase compensation are to be made. With the KBCHrelay, phase compensation is selected by the user in theform of software-implemented ICT’s.

With the Dyn11 connection, the secondary voltages andcurrents are displaced by +30° from the primary.Therefore, the combination of primary, secondary andphase correction must provide a phase shift of –30° ofthe secondary quantities relative to the primary.

For simplicity, the CT’s on the primary and secondarywindings of the transformer are connected in star. Therequired phase shift can be achieved either by use of ICTconnections on the primary side having a phase shift of

+30° or on the secondary side having a phase shift of–30°. There is a wide combination of primary andsecondary ICT winding arrangements that can providethis, such as Yd10 (+60°) on the primary and Yd3 (-90°)on the secondary. Another possibility is Yd11 (+30°) onthe primary and Yy0 (0°) on the secondary. It is usual tochoose the simplest arrangements possible, andtherefore the latter of the above two possibilities mightbe selected.

However, the distribution of current in the primary andsecondary windings of the transformer due to anexternal earth fault on the secondary side of thetransformer must now be considered. The transformerhas an earth connection on the secondary winding, so itcan deliver zero sequence current to the fault. Use ofstar connected main CT’s and Yy0 connected ICT’sprovides a path for the zero sequence current to reachthe protection relay. On the primary side of thetransformer, the delta connected main primary windingcauses zero-sequence current to circulate round thedelta and hence will not be seen by the primary sidemain CT’s. The protection relay will therefore not see anyzero-sequence current on the primary side, and hencedetects the secondary side zero sequence currentincorrectly as an in-zone fault.

The solution is to provide the ICT’s on the secondary sideof the transformer with a delta winding, so that thezero-sequence current circulates round the delta and isnot seen by the relay. Therefore, a rule can be developedthat a transformer winding with a connection to earthmust have a delta-connected main or ICT for unitprotection to operate correctly.

Selection of Yy0 connection for the primary side ICT’sand Yd1 (–30°o) for the secondary side ICT’s provides the

Figure 16.27: Transformer zero sequence filtering example

Primary ICT's Unit protection relay Secondary ICT's

Secondary CT'sPrimary CT's Dyn 11

IdIdI >

Primary ICT'sYy0

Unit ProtectionRelay

Secondary ICT'sYd1

R=1000 A Rstab

600/1

Id>

Primary CT'sYy0, 250/1

Secondary CT'sYy0, 600/1

FLC = 175A FLC = 525A

10MVA33/11kVZ=10%Dyn11

Figure 16.28: Transformer unit protection example

Chap16-254-279 17/06/02 10:02 Page 276

required phase shift and the zero-sequence trap on thesecondary side.

16.19.2 Unit Protection of a Delta-Star Transformer

Figure 16.28 shows a delta-star transformer to whichunit protection is to be applied, including restricted earthfault protection to the star winding.

Referring to the figure, the ICT’s have already beencorrectly selected, and are conveniently applied insoftware. It therefore remains to calculate suitable ratiocompensation (it is assumed that the transformer has notaps), transformer differential protection settings andrestricted earth fault settings.

16.19.2.1 Ratio compensation

Transformer HV full load current on secondary of mainCT’s is:

175/250 = 0.7Ratio compensation = 1/0.7

= 1.428Select nearest value = 1.43LV secondary current = 525/600

= 0.875Ratio compensation = 1/0.875

= 1.14

16.9.2.2 Transformer unit protection settings

A current setting of 20% of the rated relay current isrecommended. This equates to 35A primary current. TheKBCH relay has a dual slope bias characteristic with fixedbias slope settings of 20% up to rated current and 80%above that level. The corresponding characteristic isshown in Figure 16.29.

16.9.2.3 Restricted earth fault protection

The KBCH relay implements high-impedance RestrictedEarth Fault (REF) protection. Operation is required for a

primary earth fault current of 25% rated earth faultcurrent (i.e. 250A). The prime task in calculating settingsis to calculate the value of the stabilising resistor Rstaband stability factor K.

A stabilising resistor is required to ensure through faultstability when one of the secondary CT’s saturates whilethe others do not. The requirements can be expressed as:

VS = ISRstab and

VS > KIf (Rct + 2Rl + RB )

where:

VS = stability voltage setting

VK = CT knee point voltage

K = relay stability factor

IS = relay current setting

Rct = CT winding resistance

Rl = CT secondary lead resistance

RB = resistance of any other components inthe relay circuit

Rstab = stabilising resistor

For this example:

VK = 97V

Rct = 3.7Ω

Rl = 0.057Ω

For the relay used, the various factors are related by thegraph of Figure 16.30.

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0

100

200

300

400

500

600

0 200 400 600 800differential currentEffective bias (A)

Diff

eren

tial c

urre

nt (A

)

Operate

Restrain

Figure 16.29: Transformer unitprotection characteristic

10

20

30

40

50

70

60

1 2 3 4 6 7 8 9 10

0.90 1

0.80.70.6

0.5

0.4

0.3

0.2

0.1

Ove

rall

oper

atio

ntim

e -

mill

isec

onds

K Fa

ctor

Overall op time

K Factor

Unstable

Stable

VKVKV VSVSV

Figure 16.30: REF operating characteristicfor KBCH relay

Chap16-254-279 17/06/02 10:02 Page 277

and substituting values, VP = 544V. Thus a Metrosil isnot required.

16.9.3 Unit Protection for On-Load TapChanging Transformer

The previous example deals with a transformer having notaps. In practice, most transformers have a range of tapsto cater for different loading conditions. While mosttransformers have an off-load tap-changer, transformersused for voltage control in a network are fitted with anon-load tap-changer. The protection settings must thentake the variation of tap-change position into account toavoid the possibility of spurious trips at extreme tappositions. For this example, the same transformer as inSection 16.19.2 will be used, but with an on-loadtapping range of +5% to -15%. The tap-changer islocated on the primary winding, while the tap-stepusually does not matter.

The stages involved in the calculation are as follows:

a. determine ratio correction at mid-tap and resultingsecondary currents

b. determine HV currents at tap extremities with ratiocorrection

c. determine the differential current at the tapextremities

d. determine bias current at tap extremities

e. check for sufficient margin between differentialand operating currents

16.19.3.1 Ratio correction

In accordance with Section 16.8.4, the mid-tap positionis used to calculate the ratio correction factors. The midtap position is –5%, and at this tap position:

Primary voltage to give rated secondary voltage:

= 33 x 0.95 = 31.35kV

andRated Primary Current = 184A

Transformer HV full load current on secondary of mainCT’s is:

184/250 = 0.737

Ratio compensation = 1/0.737

= 1.357

Select nearest value = 1.36

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.

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Starting with the desired operating time, the VK/VS ratioand K factor can be found.

An operating of 40ms (2 cycles at 50Hz) is usuallyacceptable, and hence, from Figure 16.30,

VK/VS = 4

K = 0.5

The maximum earth fault current is limited by theearthing resistor to 1000A (primary). The maximumphase fault current can be estimated by assuming thesource impedance to be zero, so it is limited only bytransformer impedance to 5250A, or 10A secondary aftertaking account of the ratio compensation. Hence thestability voltage can be calculated as

VS = 0.5 x 10( 3.7 + 2 x 0.057) = 19.07V

Hence,

Calculated VK = 4 x 19.07 = 76.28V

However,

Actual VK = 91V and

VK/VS = 4.77

Thus from Figure 16.30, with K = 0.5, the protection isunstable.

By adopting an iterative procedure for values of VK/VSand K, a final acceptable result of VK/VS = 4.55, K = 0.6,is obtained. This results in an operating time of 40ms.

The required earth fault setting current Iop is 250A. Thechosen E/F CT has an exciting current Ie of 1%, andhence using the equation:

Iop = CT ratio x (IS + nIe)

where:

n = no of CT’s in parallel (=4)

IS = 0.377, use 0.38 nearest settable value.

The stabilising resistance Rstab can be calculated as60.21Ω.

The relay can only withstand a maximum of 3kV peakunder fault conditions. A check is required to see if thisvoltage is exceeded – if it is, a non-linear resistor, knownas a Metrosil, must be connected across the relay andstabilising resistor. The peak voltage is estimated usingthe formula:

where:VF = If (Rct + 2Rl + Rstab )

and

If = fault current in secondary of CT circuit

V V V VP K F K= −( )2 2

Chap16-254-279 17/06/02 10:02 Page 278

16.19.3.5 Margin between differentialand operating currents

The operating current of the relay is given by the formula

Iop = IS + 0.2Ibias

Hence, at the +5% tap, with IS = 0.2

Iopt1 = 0.2 + (0.2 x 0.952)

= 0.3904A

At the –15% tap,

Iop = IS + 0.2 +(Ibias - 1) x 0.8

(since the bias >1.0)

Iopt2 = 0.2 + 0.2 +(1.059 - 1) x 0.8

= 0.4472A

For satisfactory operation of the relay, the operatingcurrent should be no greater than 90% of the differentialcurrent at the tap extremities.

For the +5% tap, the differential current is 24% of theoperating current, and at the –15% tap, the differentialcurrent is 27% of the operating current. Therefore, asetting of IS is satisfactory.

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16.19.3.2 HV currents at tap extremities

At the +5% tap, the HV full-load current will be:

=166.6A primary

Hence, the secondary current with ratio correction:

At the -15% tap, the HV full-load current on the primaryof the CT’s:

Hence, the secondary current with ratio correction:

16.19.3.3 Determine differential current at tap extremities

The full load current seen by the relay, after ratiocorrection is 0.875 x 1.14 = 0.998A.

At the +5% tap, the differential current

Idifft2 = 0.998 - 0.906 = 0.092A

At the –15% tap,

Idifft2 = 1.12 - 0.998 = 0.122A

16.19.3.4 Determine bias currents at tap extremities

The bias current is given by the formula:

where:IRHV = relay HV current

IRLV = relay LV current

Hence,

and

I biast 20 998 1 12

2=

+( )

=

. .

1.059A

I biast10 998 0 906

2=

+( )

=

. .

0.952A

II I

biasRHV RLV=

+( )2

= ×

=

205 8 1 36250

1 12

. .

. A

=× ×

=

1033 0 85 3

205 8

.

. A

= ×166 6 1 36250

. .

= 0.906A

1033 1 05 3× ×.

Chap16-254-279 17/06/02 10:02 Page 279

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Network Protection And Automation Guide