relaycordntn_chap9-122-151

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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 setinstantaneous 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 Coilearthed networks 9.19

Examples of time and current grading 9.20

References 9.21

9 O v e r c u r r e n t P r o t e c t i o nf o r P h a s e a n d E a r t h F a u l t s


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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 2 3

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 protection

devices 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

9 O ve r c u r r e n t P r ot e c t ionfor P hase and Ear t h Faul ts


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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

9

OvercurrentProtectionforPhasean

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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 same

operating 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 atA on the secondary side of the transformerAfter the time delay has expired, the relay outputcontact closes to trip the circuit breaker. The relay at C

has 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 Ehave 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 discrimination

is 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 suitably

tapered 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 Cand B

= 0.24

Hence

So, a relay controlling the circuit breaker at Cand set tooperate at a fault current of 8800A would in theoryprotect the whole of the cable section between Cand BHowever, there are two important practical points thataffect this method of co-ordination:

I A=

=113 0 725 .

8800

= =11

250

2

0.485

IZ Z

AS L

=+

6350

1

Figure 9.1: Radial system with time discrimination

t1

F

DE

t1 t1

C B A


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d E

h F

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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 Cand B. However, the problem changesappreciably when there is significant impedancebetween the two circuit breakers concerned. Considerthe grading required between the circuit breakers at CandA in Figure 9.2. Assuming a fault at F4, the short-circuit current is given by:

where ZS = source impedance

= 0.485

ZL1 = cable impedance between Cand B

= 0.24

ZL2 = cable impedance between B and 4 MVAtransformer

= 0.04

ZT = transformer impedance

= 2.12

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 atA. Assuming a safety

I=11

3 2 885 .

=

0 0711

4

2

.

I

Z Z

AS L

=

+

6350

1

margin of 20% to allow for relay errors and a further10% for variations in the system impedance values, it is

reasonable 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 relay

at 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 that

the more severe faults are cleared in the longestoperating time. On the other hand, discrimination bycurrent can be applied only where there is appreciable

impedance between the two circuit breakers concerned.It is because of the limitations imposed by theindependent use of either time or current co-ordination

that the inverse time overcurrent relay characteristic hasevolved. With this characteristic, the time of operationis inversely proportional to the fault current level and the

actual characteristic is a function of both timeand 'current' settings. Figure 9.3 illustrates thecharacteristics of two relays given different current/time

settings. For a large variation in fault current betweenthe two ends of the feeder, faster operating times can be

achieved 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 characteristics

generally starts with selection of the correctcharacteristic to be used for each relay, followed bychoice of the relay current settings. Finally the grading

margins and hence time settings of the relays aredetermined. An iterative procedure is often required to

resolve 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


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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)

Time(s)

Table 9.1: Definitions of standard relay characteristics

Figure 9.4 (a): IDMT relay characteristics

(a) IEC 60255 characteristics ; TMS=1.0

OperatingTime(seconds)

Current (multiples ofI )

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 tTD

I

=

+

7

0 02394

1

0 016940 02

..

.

r

tTD

Ir=

+

7

5 95

10 18

2

..

tTD

Ir=

+

7

28 2

10 1217

2

..

tTD

Ir=

+

7

19 61

10 491

2

..

tTD

Ir=

+

7

0 0515

10 114

0 02

..

.

Relay Characteristic Equation (IEC 60255)

Standard Inverse (SI)

Very Inverse (VI)

Extremely Inverse (EI)

Long time standard earth fault t TMSIr

=

120

1

t TMSIr

=

80

12

t TMSIr

=

13 5

1

.

t TMSIr

=

0 14

10 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 an

electromechanical 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 SETINSTANTANEOUS 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 also

improves 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 the

use 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 characteristicsof standard IDMT relay

Time(seconds)

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

0.90.80.7

0.60.5

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

OperatingTime(seconds)

Current (multiples ofI )

Moderately Inverse

Time Inverse

CO 8 Inverse

ExtremelyInverse


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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 current

I2 = 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 I

I

1 2

2

100

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 supplyThe long time operating characteristic of the extremely

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Operatingtime(seconds)

0.10101

1.00

10.00

100.00

100

Current ( 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 IDMTand high-set instantaneous overcurrent relays

Time(seconds)

1

10001000.1

400/1A

R1 R2 R3Source250 MVA11kV

100/1A 50/1AFault level 13.000A Fault level 2300A Fault level 1100A

Ratio

10,000

R3

R2 R1

500A 0.125 TMS

62.5A 0.10 TMS

300A

500A


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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 present

in 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 saves

the provision of separate relay or PLC (ProgrammableLogic Controller) hardware to perform these functions.

9.9 INDEPENDENT (DEFINITE) TIME

OVERCURRENT 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 relayand fuse characteristics

1000.1

1000

1.0

10.0

100.0

10,000

200.0

Standardinverse (SI)

Current (amps)

Time(secs)

inverse (EI)

00A Fuse


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setting of at least 1.05 times the short-time rated

current of the circuit is likely to be required.

9.11 RELAY TIME GRADING MARGIN

The time interval that must be allowed between the

operation of two adjacent relays in order to achieve

correct discrimination between them is called the grading

margin. If a grading margin is not provided, or is

insufficient, more than one relay will operate for a fault,

leading to difficulties in determining the location of the

fault and unnecessary loss of supply to some consumers.

The grading margin depends on a number of factors:

i. the fault current interrupting time of the circuit

breaker

ii. relay timing errors

iii. the overshoot time of the relay

iv. CT errors

v. final margin on completion of operationFactors (ii) and (iii) above depend to a certain extent on

the relay technology used an electromechanical relay

for instance, will have a larger overshoot time than a

numerical relay.

Grading is initially carried out for the maximum fault

level at the relaying point under consideration, but a

check is also made that the required grading margin

exists for all current levels between relay pick-up current

and maximum fault level.

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1 3 0

Time(seconds)

Fault current (amps)

10

1

100100.1

000A 3500A

1000

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

RR

R4

R4A

RA

R2A

R1A

R1

T1

T2

T3

T

R

RA

R1A 300A 0.2TMSR 175A 0.3TMS

R 100A 0.37TMS

RA

set at 57.5A 0.42TMS

R1A 300A 1.8sR 175A 1.4s

R 100A 1.0s

R4A

set at 57.5A 0.6s

Figure 9.9: Comparison of definite time and standard I.D.M.T. relay


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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 continue

for 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 RelayThe 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 fixed

time, 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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d E

h F

l

Figure 9.10: Typical limits of accuracy from IEC 60255-4for an inverse definite minimum time overcurrent relay

Time(

seconds)

8

10

1

20

50

4 5 6 8 10 20 01

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


11/30

follows an I2tlaw. So, to achieve proper co-ordinationbetween two fuses in series, it is necessary to ensure thatthe total I2ttaken by the smaller fuse is not greater thanthe pre-arcing I2tvalue 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 I2tcharacteristic. Toensure satisfactory co-ordination between relay andfuse, the primary current setting of the relay should be

approximately three times the current rating of the fuseThe 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 tis 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 circuit

breaker 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 grading

calculation 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 t R CB o s2

100seconds

= + + + +t E E t t t t R CT CB o s2 100 seconds

9


dEarthFaults

1 3 2

Fault Current Relay Current Setting(A) Maximun CT Relay Time

Location Load Current Ratio Primary Multiplier Setting

Maximun Minimun (A) Per Cent Current(A)

Table 9.3: Typical relay data table

Table 9.2: Typical relay timing errors - standard IDMT relays

Relay Technology

Electro- 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


12/30


It is usual to plot all time/current characteristics to acommon voltage/MVA base on log/log scales. The plot

includes 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 paths

must be carefully considered to ensure that the finalsetting is appropriate for all conditions. Earth faults are

considered 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) time

relays presents little difficulty. The overcurrent elements

must be given settings that are lower, by a reasonablemargin, than the fault current that is likely to flow to a

fault at the remote end of the system up to which back-up protection is required, with the minimum plant inservice.

The settings must be high enough to avoid relayoperation with the maximum probable load, a suitable

margin 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 short

sections 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 such

cases, 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 varies

substantially 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 in

Section 9.20.1.

9.14 DIRECTIONAL PHASE FAULTOVERCURRENT 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.

O

P

i

f

P h

d E

h F

l

Ia

MTA

Zero torque line

VbVc

Vbc

Va

V'bc

30

30150

A phase element connected IaVbc

B phase element connected IbVca

Cphase element connected Ic Vab

Figure 9.11: Vector diagram for the 90-30 connection(phase A element)


13/30


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 30leading 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 the

form 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 with

the relay looking into the delta winding of thetransformer

It should be remembered, however, that the conditionsassumed above to establish the maximum anguladisplacement 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 purposesnon-existent.

9.14.3 Application of Directional Relays

If non-unit, non-directional relays are applied to parallefeeders having a single generating source, any faults thamight 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 R2in Figure 9.13 with their directional elements lookinginto the protected line, and giving them lower time andcurrent settings than relays R1and 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

9

OvercurrentProtectionforPhaseandEarthFaults

1 3 4

Fault

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

ero torque line

V V

Vc

V

Ia

V'bc

5

A phase element connected IaVbc

B phase element connected Ib Vca

C phase element connected IcVab


14/30


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 the

same 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 flow

from 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

O

P

i

f

P h

d E

h F

l

Figure 9.14: Grading of ring mains

2.1 2.1

6' 6

0.9

3'

1.7

0.1

5'

1

0.5

2

4'

1.3

1.7 5

0.1

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


15/30


and full discrimination may not be possible. With two

sources of supply, two solutions are possible. The first isto open the ring at one of the supply points, whichever is

more convenient, by means of a suitable high set

instantaneous overcurrent relay. The ring is then graded

as in the case of a single infeed. The second method is totreat the section of the ring between the two supply

points as a continuous bus separate from the ring and to

protect it with a unit protection system, and then proceed

to grade the ring as in the case of a single infeed. Section

9.20.4 provides a worked example of ring main grading.

9.16 EARTH FAULT PROTECTION

In the foregoing description, attention has been

principally directed towards phase fault overcurrentprotection. More sensitive protection against earth

faults can be obtained by using a relay that responds

only to the residual current of the system, since aresidual component exists only when fault current flows

to earth. The earth-fault relay is therefore completely

unaffected by load currents, whether balanced or not,and can be given a setting which is limited only by thedesign of the equipment and the presence of unbalanced

leakage or capacitance currents to earth. This is an

important consideration if settings of only a few percent

of system rating are considered, since leakage 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 limited

in magnitude by the neutral earthing impedance, or by

earth contact resistance.

The residual component is extracted by connecting the

line current transformers in parallel as shown in Figure

9.15. The simple connection shown in Figure 9.15(a) canbe extended by connecting overcurrent elements in the

individual phase leads, as illustrated in Figure 9.15(b),

and inserting the earth-fault relay between the star

points of the relay group and the current transformers.

Phase fault overcurrent relays are often provided on only

two phases since these will detect any interphase fault;

the connections to the earth-fault relay are unaffectedby this consideration. The arrangement is illustrated in

Figure 9.15(c).

The typical settings for earth-fault relays are 30%-40%of the full-load current or minimum earth-fault current

on the part of the system being protected. However,

account may have to be taken of the variation of setting

with relay burden as described in Section 9.16.1 below.If greater sensitivity than this is required, one of the

methods described in Section 9.16.3 for obtaining

sensitive 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 ratioThe CT can be assumed to maintain a sufficiently

accurate 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 foan 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

9


dEarthFaults

1 3 6

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 currenttransformers to earth-fault relays


16/30


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 a

setting 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 burden

of 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 setting

current 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

O

P

i

f

P h

d E

h F

l

Table 9.4: Calculation of effective settings

Relay Plug Coil voltage Exciting Effective SettingSetting at Setting Current Current

%% Current (A) (V) I e (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

0

Secondaryvoltag

e

Exciting current (amperes)

Effectivesetting(percent)

0 80 100

100

80

60

40

20

604020

Relay setting (per cent)


17/30


matter as the procedure adopted for phase relays inTable 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 relays

may present difficulties due to the high effective burdenthey may present to the CT.

The required sensitivity cannot normally be provided bymeans of conventional CTs. 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 settings

down 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

9


dEarthFaults

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 balancecurrent transformers


18/30


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 are

connected 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 the

primary 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. The

residual 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 polarising

quantity. 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

O

P

i

f

P h

d E

h F

l

Figure 9.18: Voltage polarised directional earth fault relay

(a) Relay connections

C

B

A

V

V V V V

V2

IO

3V

V

(b) Balanced system(zero residual volts)

(c) Unbalanced system

fault (3Vo residual volts)

>I


19/30


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 of3 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 any

discrimination, as the unbalanced voltage occurs on thewhole of the affected section of the system. Oneadvantage of this method is that no CTs are required, asvoltage is being measured. However, the requirementsfor the VTs 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 the

current of its own feeders cancelled out. Figure 9.20shows the phasor diagram.

Use of Core Balance CTs is essential. With reference toFigure 9.20, the unbalance current on the healthyfeeders lags the residual voltage by 90. The charging

currents on these feeders will be 3 times the normavalue, 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 currents

on the healthy feeders lie within the restrain regionThus, 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

9


dEarthFaults

1 4 0

I3

IH1+ H3

I +IH2

IR3

IR2

IR1

IH2

I

I2Ib2

Ia1I1

jX3

jX2

IH1

jX1

=I +IH2+IH3-IH3=IH1 IH2

IR3

Figure 9.19: Current distribution in an insulated systemwith a C phase earth fault

Figure 9.20: Phasor diagram for insulated systemwith C phase-earth fault

An RCA setting of +90 shiftsthe "center of the characteristic" to here

Vpf

Vbpf

Vf

IR3= -(IH1 IH2)

Vf

VpfIR1

I1

I1

Restrain

Operate

Vres (= -3Vo)


20/30


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 configuration

changes 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.

O

P

i

f

P h

d E

h F

l

C B

AIL

-IB

-IC

VbVc

N

Current vectors forA phase fault

ource

Petersencoil

-IC

-jXC-jX

jXL

(=IL)

Vn

L

-jXC

(=-I

Vb

jXC

Ic)

Vc

C

If

-IB

If IB- C+Vn

jXL

=O if =I+ICan

jXL

Figure 9.21: Earth fault in Petersen Coil earthed system

A

N

C B

3VO

IL

IH3

IH2

IH1

1

I1

I1

IL

IR3

Ia1

IR1

=IH1

Vres

=- VO

Vres

=- VO

a) Capacitive et inductive currents

b) Unfaulted line c) Faulted line

-IH1

IR3

=-I+I

=- -IH2

-I

Figure 9.23: C phase-earth fault in Petersen Coil earthednetwork: theoretical case no resistance present in XLor XC

IL=IF IH1 IH2-IH3+IH2

IL

IF

IH2I3

I =IF

Ib3

Ia2I2

IR3

IR2

-jXC3

-jXC2jXL

IL

IH1

Ia1I1

IR1-jXC1

Figure 9.22: Distribution of currents duringa C phase-earth fault radial distribution system


21/30


In Figure 9.23(a), it can be seen that the fault causes thehealthy phase voltages to rise by a factor of3 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 ofIa1 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 I

L-I

H1-I

H2, as

shown 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 therestrain 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 usedtwo possibilities exist for the type of protection elementthat can be applied sensitive earth fault and zerosequence wattmetric.

9.19.1 Sensitive Earth Fault ProtectionTo 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, as

compensation 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 0setting, 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


dEarthFaults

1 4 2

IL

IH3

IROFIOF

IROH

IROH

Xco

IH2 IH13XL

Faultedfeeder

Healthyfeeders

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 showingresidual 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-IH2IR3

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 currentswith resistive components

Figure 9.25: C phase-earth fault in Petersen Coil earthednetwork: practical case with resistance present in XLor XC


22/30


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

= angle between Vres and Ires

c = 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

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

O

P

i

f

P h

d E

h F

l

Active componentf residual current:

faulted feeder

Zero torque linefor O RCA

Operate

Restrain

IR1

IL

IR3 IH1-IH2

Vres=-3V

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

Utilityclient

Cable C1: 5x3x1cx630mm2XLPE

Z = 0.042 + j 0.086/km/cableL = 2km

3000/5

BusA11kV

Bus B11kV

Bus C

11kV

150/5 200/5

C3C2

4

5

3000/1

Cables C2,C3:1x3cx185mm2XLPEZ = 0.128 + j 0.093/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


23/30


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. CTs forrelays F1, F2 and 5 are existing CTs with 5Asecondaries, while the remaining CTs are new with 1Asecondaries. Relay 5 is the property of the supply utility,and is required to be set using an SI characteristic in

order 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

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= + + +

500 100

21 1 2Z Z Z Z MVA

R S C C

ZS = 500

500100%

ZC3 20 158 100 500 11

= ( )

.

ZC1 20 038 100 500

11=

( )

.

ZC10 096

5

2 0 038 = =. .

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 maximum

load 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 currentTherefore, 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 Cand 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 greatethan this value is 450A. However, Section 9.12.3 also

recommends 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 Z

MVA

S C

Fault Level

232MVA

1 kA

= + +

=

=

500 100

2 2

1 1Z Z ZMVA

S C R

.

9


dEarthFaults

1 4 4


24/30


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 Coccurs 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 Cis 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 (Figure

9.4) 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 required

Actual 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 = 15.16or,

Use 1.24 = 620A ne

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relaycordntn_chap9-122-151