Dia 5 PROT 401_r0.pdf

8/11/2019 Dia 5 PROT 401_r0.pdf

1/295

Revision Table

Editor Tech

Review

TDS

Review

Date Rev

#

Comments

CRT CRT 5/21/02 2 Tech review edits, corrected some formulas

CLS CLS 5/24/02 3 TDS review, fonts drawings and formatting changes

1Power System Basics r4

8/11/2019 Dia 5 PROT 401_r0.pdf

2/295


8/11/2019 Dia 5 PROT 401_r0.pdf

3/295

Technical papers supporting this section:

6022.pdf, Z = V/I Does Not Make a Distance Relay by J. Roberts; A. Guzman; E.O.

Schweitzer, III

General books of Power System Protection.

Revision Table

Editor Tech

Review

TDS

Review

Date Rev

#

Comments

LGP CLS 8/22/02 4 Objectives added

CLS 8/22/02 6 Rev table correction

LGP CLS 2-25-03 7 Convert to white, fix animations


8/11/2019 Dia 5 PROT 401_r0.pdf

4/295

8/11/2019 Dia 5 PROT 401_r0.pdf

5/295

This section is an introduction to the topic of transmission line protection using distance

relays. Further sections and courses will complete the wide and interesting topic of

distance protection.


8/11/2019 Dia 5 PROT 401_r0.pdf

6/295

For a perfect three-phase fault, only the positive-sequence impedance is involved in the

calculations. With the usual convention, the phase a voltage and current are equal to the

positive-sequence voltage and current.


8/11/2019 Dia 5 PROT 401_r0.pdf

7/295

8/11/2019 Dia 5 PROT 401_r0.pdf

8/295

A phase instantaneous overcurrent element is set to detect fault currents up to 80 percent

of the line length. This gives enough security margin (20 percent) to avoid non-selective

operation for faults beyond the remote bus. The relay setting is calculated for a given

value of the equivalent ZS1.


8/11/2019 Dia 5 PROT 401_r0.pdf

9/295

As the system topology behind the substation bus changes, ZS1 changes. As a result, the

relay reach will change. The only way to avoid non-selective operations for faults

beyond the remote bus is to calculate the instantaneous setting for the worst case value of

ZS1, which results in a shorter reach of the instantaneous element for all other system

configurations. It is highly probable that the system presents the worst case value for

relatively short periods of time, meaning that the relay reach will be permanently

sacrificed for a situation that occurs for short periods. This is a disadvantage of

instantaneous overcurrent relays.


8/11/2019 Dia 5 PROT 401_r0.pdf

10/295

Suppose that it is possible to design a relay that operates not when the current is larger

than a given threshold, but when the phase voltage is less than the current times a

constant, as shown in the figure.

This relay requires voltage and current information.


8/11/2019 Dia 5 PROT 401_r0.pdf

11/295

The inequality originally stated in terms of voltage and current implicitly states that the

relay will operate when the distance to the fault is less than a given limit distance, called

the distance relay reach.

Ideally, the reach of such a relay does not depend on the source impedance.


8/11/2019 Dia 5 PROT 401_r0.pdf

12/295

This relay is called impedance or under-impedance relay because the relay design is

such that the relay operates for an impedance condition. The relay measures or sees a

given impedance, equal to the ratio of the applied sinusoidal voltage and the applied

sinusoidal current.


8/11/2019 Dia 5 PROT 401_r0.pdf

13/295

The apparent impedance is a concept used to describe the impedance measured or

seen by a distance relay. It is defined as the ratio between the voltage and current

phasors applied to the relay. For the particular case that has been described, these

quantities are Va and Ia.


8/11/2019 Dia 5 PROT 401_r0.pdf

14/295

The maximum reach of the distance relay, in terms of impedance, is normally an

adjustable value of the relay. Therefore, the same relay can be used for different lines.


8/11/2019 Dia 5 PROT 401_r0.pdf

15/295

The figure shows the simplest design for an under-impedance relay. The current is passed

through a single amplifier. The magnitude of the resulting quantity is compared to the

magnitude of the voltage by a two-input magnitude comparator. The gain of the amplifier

Zr1 is the relay setting.

In the past, these devices were implemented through use of an electromechanical balance

unit. Today, in computer-based relays, the relay equation is directly implemented in the

relay routines.


8/11/2019 Dia 5 PROT 401_r0.pdf

16/295

This example shows the calculations involved in the determination of a simple impedance

relay setting.


8/11/2019 Dia 5 PROT 401_r0.pdf

17/295

The setting calculated in the former slide is in primary ohms. Because the relay is

connected to CTs and VTs, the ratios of the instrument transformer must be considered.

It is usual to find an impedance ratio ZTR = VTR/CTR to determine the secondaryimpedance measured by the relay. This ZTR is also used to determine the actual relay

setting, in secondary ohms.


8/11/2019 Dia 5 PROT 401_r0.pdf

18/295

This is the same example as before, but now the relay setting is calculated in secondary

ohms.


8/11/2019 Dia 5 PROT 401_r0.pdf

19/295

The complex plane is commonly used to represent the apparent impedance measured by

distance relays.


8/11/2019 Dia 5 PROT 401_r0.pdf

20/295

A plain impedance relay will operate for any apparent impedance whose magnitude is

less than, or equal to, the relay setting. In the complex plane, this is represented by the

region within a circle with radius equal to the relay setting. The border of the circle

represents the operation threshold of the relay.


8/11/2019 Dia 5 PROT 401_r0.pdf

21/295

The unit distance is the distance to the fault in per unit of the total lines length. This

parameter is commonly used in protective relaying.


8/11/2019 Dia 5 PROT 401_r0.pdf

22/295

If the apparent impedance of a distance relay is calculated for three-phase bolted faults

along the line, for distances varying from 0 miles to L miles, the resulting set of complex

numbers can be plotted in the complex impedance plane.


8/11/2019 Dia 5 PROT 401_r0.pdf

23/295

This set of points is a line segment as shown in the figure. The segment has the same

length and angle as the total line impedance and is called the bolted fault locus.


8/11/2019 Dia 5 PROT 401_r0.pdf

24/295

If the fault locus is superimposed with the relay operating characteristic in the same

complex plane, the resulting plot indicates the degree of protection of the relay. The case

shown in the figure represents a case in which the relay has been set to reach faults up to

~80 percent of the line.


8/11/2019 Dia 5 PROT 401_r0.pdf

25/295

During normal load conditions, the impedance seen by a distance relay has a magnitude

much larger than the length of the bolted fault locus (line). When a fault occurs, the

impedance moves instantly to a point in the complex plane located on, or very near, the

bolted fault locus. The accuracy of this statement for non-bolted faults will be shown

later.


8/11/2019 Dia 5 PROT 401_r0.pdf

26/295


8/11/2019 Dia 5 PROT 401_r0.pdf

27/295

8/11/2019 Dia 5 PROT 401_r0.pdf

28/295

There are three traditional distance elements: impedance-type, reactance-type, and mho-

type stance e ements.

The figure shows the operation equation and operating characteristic of a mho distanceelement. The characteristic is the locus of all apparent impedance values for which the

relay element is on the verge of operation. The operation zone is located inside the circle,

and the resraint zone is the region outside the circle.

The mho characteristic is a circle passing through the origin of the impedance plane. The

.

towards the first quadrant, which is where forward faults are located. For reverse faults,

the apparent impedance lies in the third quadrant and represents a restraint condition. The

fact that the circle passes through the origin is an indication of the inherent directionality

of the mho elements. However, close-in bolted faults result in a very small voltage at the

relay that may result in a loss of the voltage polarizing signal. This needs to be taken into

consideration when selecting the appropriate mho element polarizing quantity.

ere are yp ca y wo se ngs n a m o e emen : e c arac er s c ame er, M, an e

angle of this diameter with respect to the R axis, MT. The angle is equivalent to themaximum torque angle of a directional element. The mho element presents its longest

reach (greatest sensitivity) when the apparent impedance angle coincides with MT.

Normally, MT is set close to the protected line impedance angle to ensure maximumrelay sensitivity for faults and minimum sensitivity for load conditions.


8/11/2019 Dia 5 PROT 401_r0.pdf

29/295

The early electromechanical relays with a MHO characteristic used a product unit

(induction cylinder element) to achieve the torque equation: V2 V I cos(-MT) > 0.

Analog static relays used a two-input phase comparator to create the MHO characteristic.The inputs to the comparator are properly mixed from the original voltage and current to

obtain the desired behavior.


8/11/2019 Dia 5 PROT 401_r0.pdf

30/295

8/11/2019 Dia 5 PROT 401_r0.pdf

31/295

8/11/2019 Dia 5 PROT 401_r0.pdf

32/295

So far, a directional distance relay, which operates instantaneously and is set to reach less

than 100 percent of the protected line, has been described. Two important principles of

protection have been missing:

1. What happens for a fault on the protected line that is beyond the reach of the relay?

2. If the relay operates instantaneously, it cannot be used as a remote back-up for a

relay protecting a line adjacent to the remote substation.

These two roblems are overcome b addin time-dela distance rela s. This is

accomplished by using the distance relay to start a definite time timer. The output of the

timer can then be used as a tripping signal.

The figure shows how a second zone (or step) is added to each of the directional

impedance relays. A third zone, with a larger delay, can also be added.

The operation time of the second zone is usually around 0.3 seconds, and the third zone

around 0.6 seconds. However, the required time depends on the particular application.

The ohmic reach of each zone also depends on the particular power system. The figure

and the next slide show a typical reach scheme for three zones.

What about Circuit Breakers 2, 4 and 5?


8/11/2019 Dia 5 PROT 401_r0.pdf

33/295

The slide shows how the instantaneous Zone 1, and the delayed Zones 2 and 3 look in a

complex impedance plane if MHO units are used for all three zones. Note the reference to

buses A, B, and C of the previous slide, which indicate that the distance elements

correspond to the relays associate with Circuit Breaker 1, located at Substation A.


8/11/2019 Dia 5 PROT 401_r0.pdf

34/295

What about Circuit Breakers 2, 4, and 5?

The figure shows the operating time as a function of the electrical distance for six distance relays.

Here, the relays looking in both directions are shown. We show the characteristics for Relays 1,3, and 5 above the system one-line diagram. We represent the characteristics for Relays 2, 4, and

5 below the one-line diagram.

Zone 1 must underreach the remote line end to make sure that it will not operate for faults in the

adjacent lines. Zone 2 is intended to cover the end of the protected line, so it must overreach the

protected line. Zone 3 is intended to provide remote backup protection to adjacent lines, so it must

overreac t e ongest a acent ne.

We typically leave a coordination interval (including breaker tripping time) between Zones 1 and

2 and between Zones 2 and 3 of adjacent distance relays. This means that the end of Zone 2 of a

backup relay should not overlap with the begininning of Zone 2 of the primary relay. The same is

true for adjacent third zones. This is not always possible, however.

In the figure, we can see that faults located in the central section of a given line are cleared by

simultaneous and instantaneous operation of the first zones at both line ends. Should a first zone

a to operate, t e remote ac up re ay operates n secon or t r zone. n t e ot er an , au ts

close to one line end will be cleared sequentially: the nearest line end will operate in first zone,

and the remote end will operate in second zone. This sequential fault clearing is a limitation of

distance protection, because it could jeopardize system stability.

An advantage of distance protection over directional overcurrent protection is that the distance

first zone reach depends less on system operating conditions than the reach of the instantaneous

overcurrent element. In other words, distance protection provides better instantaneous line

coverage.


8/11/2019 Dia 5 PROT 401_r0.pdf

35/295

The figure is an impedance-plane representation of a line protection scheme using mho

distance relays (both directions). A longitudinal system is formed by transmission lines

AB, BC, AD, and DE. The line impedances are plotted on the complex plane, using

substation A as the origin of coordinates for convenience. The mho circles represent the

three zones of the distance schemes at both ends of line AB.


8/11/2019 Dia 5 PROT 401_r0.pdf

36/295

The figure shows several commonly used circular distance relay characteristics. For

analog relays, these characteristics can be obtained with phase and/or magnitude

comparators. In microprocessor-based relays, they are implemented using mathematical

algorithms.


8/11/2019 Dia 5 PROT 401_r0.pdf

37/295

8/11/2019 Dia 5 PROT 401_r0.pdf

38/295

Solid-state and digital relays permit creation of highly sophisticated distance

characteristics. An example is the quadrilateral characteristic. You can shape the

characteristic to meet different line protection requirements. The price for this flexibility

is setting complexity: there are four settings in a quadrilateral characteristic.

The figure shows the popular qudrilateral charateristic. Proper applciation of this

characteristic will be explained later in this course.


8/11/2019 Dia 5 PROT 401_r0.pdf

39/295


8/11/2019 Dia 5 PROT 401_r0.pdf

40/295

8/11/2019 Dia 5 PROT 401_r0.pdf

41/295

The three-phase, short-circuit case is repeated here to introduce the procedure to be used.

The line equations correspond to a symmetrical, or transposed, line. The three phases are

set to zero voltage at the fault location. The unit distance, m, is used as the distance to thefault point.


8/11/2019 Dia 5 PROT 401_r0.pdf

42/295

8/11/2019 Dia 5 PROT 401_r0.pdf

43/295

The algebraic development shows that a single distance element is enough to detect

balanced three-phase faults. The element should be connected to any phase voltage and

current to properly measure the positive-sequence impedance existing between the relay

location and the fault. This impedance is directly proportional to the distance.


8/11/2019 Dia 5 PROT 401_r0.pdf

44/295

8/11/2019 Dia 5 PROT 401_r0.pdf

45/295

The algebraic manipulation leads to the conclusion shown in the slide.

A similar development can be done for a-b and c-a faults.


8/11/2019 Dia 5 PROT 401_r0.pdf

46/295

8/11/2019 Dia 5 PROT 401_r0.pdf

47/295

8/11/2019 Dia 5 PROT 401_r0.pdf

48/295

The result of the manipulation is that, for the relay to properly measure the positive

sequence impedance between the relay location and the fault, the relay must receive:

The phase a voltage

The phase a current plus a residual current compensation factor.

The compensation factor, ko, is called the residual compensation factor, or the zero

sequence compensation factor because the residual current is three times the zero-

se uence current.

A similar result is obtained for b-to-ground and c-to-ground faults.


8/11/2019 Dia 5 PROT 401_r0.pdf

49/295

8/11/2019 Dia 5 PROT 401_r0.pdf

50/295

The table summarizes the results obtained in the former development.

There are other ways of connecting (polarizing) the distance relays. This particular way is

called the self-polarizing scheme.

In the past, six relays (or measuring units) were required for each distance relay zone to

implement a non-switching scheme like this. Today, this protection can be implemented

in a single microprocessor-based relay.


8/11/2019 Dia 5 PROT 401_r0.pdf

51/295

In summary, distance protection uses current and voltage information to make a direct, or

indirect, estimate of the distance to the fault. Phase distance elements (21) are more

sensitive than phase directional overcurrent elements (67). On the other hand, ground

distance elements (21N) are less sensitive than ground directional overcurrent elements

(67N). A widely used combination for transmission line protection uses 21 elements for

phase fault protection and 67N elements for ground fault protection.


8/11/2019 Dia 5 PROT 401_r0.pdf

52/295

Transmission line protection is complex. Problems such as infeed, fault resistance,

unequal measured impedances during faults, load encroachment, and mutual coupling

affect the apparent impedance of distance relays. Fault resistance and mutual coupling

also affect ground directional overcurrent relays. These problems may be complicated by

the evolving character of many faults.


8/11/2019 Dia 5 PROT 401_r0.pdf

53/295

All these problems may affect distance and directional overcurrent relays. Cross-country

faults, simultaneous faults, and CT saturation may also present a problem for differential

schemes.

Series-compensated lines are extremely difficult to protect. All protection principles may

have problems, because of the possibility of voltage and current inversions. If the series

compensation capacitors are carefully selected, the possibility of current inversions can

be eliminated. In this case, a differential protection scheme may be the best option.


8/11/2019 Dia 5 PROT 401_r0.pdf

54/295

Three-terminal lines and short lines also have special protection requirements. The

ringdown at subharmonic frequency resulting from compensation reactors may also

create protection problems.


8/11/2019 Dia 5 PROT 401_r0.pdf

55/295

8/11/2019 Dia 5 PROT 401_r0.pdf

56/295

The infeed effect needs to be taken into account when distance relay settings are

calculated. For example, the third zone at A (see figure) will measure ZAB + ZBC for a

fault at C without infeed. When the intermediate source is present, the impedance

estimate is greater because of the IBC/IAB factor. The third zone needs to completely cover

the adjacent line BC for all system operating conditions. Thus, the third zone reach needs

to be set considering the possible infeed. As a result, the third zone may reach far beyond

substation C when the intermediate source is out of service. This factor needs to be

considered when checking adjacent third zones for possible overlap.

Infeed effect does not affect first zones, except in three-terminal lines. In this case, the

first zone needs to be set without infeed to make sure that the zone will not overreach the

remote line end. Setting a first zone in this manner results in the presence of the

intermediate source reducing the first zone reach, thus limiting the high-speed coverage

of the protected line.

The infeed effect also needs to be considered for second zone reach settings. In three-

terminal lines, the second zone should be set with maximum infeed at the third terminal

to ensure full coverage of the protected line. On the other hand, in two-terminal lines, the

second zone should be set for minimum infeed at the remote-end substation to avoid

overlapping with the beginning of the adjacent second zone.


8/11/2019 Dia 5 PROT 401_r0.pdf

57/295

Outfeed is the result of having two paths of current flow after the relay has monitored the

current. An outfeed condition may exist when two or more adjacent lines are connected

in parallel. In three-terminal lines, outfeed may exist if there is a strong external tie

between two line terminals. The magnitude of the outfeed effect factor, I / I, is smaller

than unity, which produces a reduced impedance estimate. The result is relay overreach.

The outfeed effect also needs consideration when calculating settings for a distance relay.


8/11/2019 Dia 5 PROT 401_r0.pdf

58/295


8/11/2019 Dia 5 PROT 401_r0.pdf

59/295

8/11/2019 Dia 5 PROT 401_r0.pdf

60/295


8/11/2019 Dia 5 PROT 401_r0.pdf

61/295

Transmission line protection is complex. Problems such as infeed, fault resistance,

unequa measure mpe ances ur ng au ts, oa encroac ment, an mutua coup ng

affect the apparent impedance of distance relays. Fault resistance and mutual coupling

may also affect ground directional overcurrent relays. These problems may be

complicated by the evolving character of many faults.


8/11/2019 Dia 5 PROT 401_r0.pdf

62/295

8/11/2019 Dia 5 PROT 401_r0.pdf

63/295

Three-terminal lines and short lines also have special protection requirements. The

r ng own at su armon c requency resu t ng rom compensat on reactors may a so

create protection problems. Series-compensated lines are extremely difficult to protect.

All protection principles may have problems, because of the possibility of voltage and

current inversions. If the series-compensation capacitors are carefully selected, the

possibility of current inversions can be eliminated. In such a case, a differential

protection scheme may be the best option.

In this presentation, we will examine transmission line protection problems that exclude

CT saturation, CCVT transients, series-compensated lines, three-terminal lines, short

lines, and reactor-compensated lines.


8/11/2019 Dia 5 PROT 401_r0.pdf

64/295

Fault resistance affects all protection principles to some extent. For phase faults (three-

p ase, ne- ne) au t res stance resu ts arge y rom t e res stance o t e arc etween t e

faulted conductors. If the fault is initiated by a tree or something else in the line, its

resistance should also be considered.

Ground fault resistance includes the resistance of the arc between the conductor and the

tower, the tower and tower footing resistance, and the ground return path resistance.

Ground faults may also involve other objects such as trees.

.

transmission line faults involving trees, for example, the fault resistance may be on the

order of hundreds of ohms.

In distribution lines, an important component of ground fault resistance is the contact

resistance between the fallen conductor and ground. For a conductor falling on dry

asphalt, for example, the fault resistance could be close to infinity. The detection of fallenconductors in overhead distribution systems is a very complex protection problem.


8/11/2019 Dia 5 PROT 401_r0.pdf

65/295

Arc resistance is quite variable. A commonly accepted value for currents between 70 A

an 20,000 A s an arc vo tage rop o 440 V per p ase, n epen ent o current

magnitude.


8/11/2019 Dia 5 PROT 401_r0.pdf

66/295

This is another empirical expression for arc resistance with the arc length in meters

( nstea o eet). O serve t at t ere s a 1.4 exponent n t e current n t s express on.


8/11/2019 Dia 5 PROT 401_r0.pdf

67/295

The general effect of fault impedance is reduction in protection sensitivity. Fault

mpe ance re uces t e au t current va ues an t e vo tage sag n t e au te p ases. Fau t

impedance also increases the value of the impedance measured by distance relays. Fault

resistance limits the sensitivity of all protective relay types.


8/11/2019 Dia 5 PROT 401_r0.pdf

68/295

The figure shows the effect of fault resistance on the impedance a distance element

measures n a ra a system. T e stance e ement measures t e au t oop mpe ance,

including the fault resistance. The result is a distance estimate greater than the real

distance to the fault. This inaccurate distance estimate makes the distance element

underreach.


8/11/2019 Dia 5 PROT 401_r0.pdf

69/295

An additional problem in looped lines is the infeed effect in the fault impedance. The

re ay oes not measure t e current contr ut on to t e au t rom t e remote-en source.

As a result, RF in the impedance estimate is multiplied by an infeed effect factor IF / I.

The effect of this factor is twofold. The infeed effect increases the value of the apparent

fault resistance (the magnitude of the factor is greater than unity). The infeed effect factor

is, in general, a complex number, so the apparent fault impedance is no longer purely

resistive.


8/11/2019 Dia 5 PROT 401_r0.pdf

70/295

In this impedance plane representation, the effect of fault resistance in looped lines can be

seen. T e stance e ement s ou measure an mpe ance mZL. However, t e measure

impedance is Z. Observe that the infeed effect factor, IF / I, increases the value and

produces a phase shift in the fault resistance RF.


8/11/2019 Dia 5 PROT 401_r0.pdf

71/295

The power system model shown will be used to study the effect of RF and the power

angle, , on the apparent fault impedance. For simplicity, a homogeneous system (allsource and line impedances have the same angle) will be considered.


8/11/2019 Dia 5 PROT 401_r0.pdf

72/295

This figure shows the effect of RF and on the impedance estimate. For bolted faults, thedistance element measures the correct impedance value. An increase in the value of RFincreases the measured impedance and produces relay underreach.

In radial lines, or when = 0, the apparent impedance is purely resistive. A reactance-type characteristic would avoid relay underreach. However, for 0, even a reactanceelement may overrreach ( > 0) or underreach ( < 0). In other words, the direction of the

pre-fault power flow will determine the reactance element behavior.


8/11/2019 Dia 5 PROT 401_r0.pdf

73/295

A distance protection scheme has six basic relay elements. For the phase elements, the

ne- ne vo tages an t e erences o t e ne currents are use as nput s gna s.

Ground distance elements receive the phase voltages and the compensated line currents

as input signals. The zero-sequence current is used to compensate the line current inputs

of ground distance elements. These connections ensure that the fault-loop element(s)

correctly measure the fault-loop impedance. For example, for an ABG fault, three

distance elements correctly estimate impedance: AB, AG, and BG elements. The question

is, what impedances do the other three elements measure for this fault? These elements

need to measure im edances with values no lower than the fault-loo im edance. This

ensures that the distance elements that measure the correct impedance value will make

the tripping decision.

The simple power system shown in the figure can be used for an analytical study of the

impedances measured by the different distance elements during faults. The idea is to

derive the expressions of the measured impedance using symmetrical componenttechniques. In the figure, mZL is the impedance of the protected line section. The

ositive-se uence value of this im edance mZ is the correct value that the distance

elements measure. ZX is an impedance including mZL and the source impedance behind

the relay. The factor C expresses the infeed effect in the fault resistance.


8/11/2019 Dia 5 PROT 401_r0.pdf

74/295

This table shows the expressions of the impedances phase distance elements measure for

two types o p ase au ts (ABC an BC au ts). For ABC au ts, a t ree e ements

measure the loop impedance value, which unfortunately includes the fault impedance

term. For BC faults, only the fault-loop element BC correctly measures the impedance.

The other two elements (AB and CA) estimate higher impedances. This means that the

BC element will make the tripping decision for zone-end faults.


8/11/2019 Dia 5 PROT 401_r0.pdf

75/295

This table shows the expressions of the impedances measured by ground distance

e ements or two types o p ase au ts.

For ABC faults, all three elements measure the fault-loop impedance. In other words,ground distance elements may respond to three-phase faults unless, for example, their

operation is supervised with a zero-sequence overcurrent element. This tendency to

operate is also present for other system balanced conditions such as normal load or power

swings. For phase-to-phase faults, the ground distance elements measure impedance

values greater than the fault-loop impedance.

The effect of ground faults on ground distance elements is not presented in this analysis.

The result is the same as for the phase elements. That is, the fault-loop element correctly

measures the impedance, and the healthy phase elements estimate impedance values

greater than the fault-loop impedance.


8/11/2019 Dia 5 PROT 401_r0.pdf

76/295

Digital simulation is an excellent tool for studying the impedances that distance elements

measure ur ng au ts n comp ex power systems. T e gure s ows a power system

model that will be used for digital simulation studies.


8/11/2019 Dia 5 PROT 401_r0.pdf

77/295

The figure shows the impedances all distance elements measure for a close-in A-phase-

to-groun au t or erent RF va ues (0 to 4 o ms).

Two mho-element characteristics are shown, a self-polarized mho characteristic (crossesthrough the origin of coordinates) and a cross-polarized mho characteristic. As will be

seen in a future presentation, the effect of mho element polarization is to expand the

characteristic backwards in relation to the origin of coordinates for forward faults.

Polarization ensures mho element directionality for close-in bolted faults.

for this AG fault. It is also clear from the figure that a self-polarized mho element may

not see the fault. For a polarized mho element, the fault is well within the characteristic.

Other distance elements such as AB, CG, and CA may operate for this fault, so distance

element operation cannot be relied on to make single-pole tripping decisions. In this case,

for example, a three-pole trip would be issued instead of a single-pole trip for a single-line-to-ground fault.


8/11/2019 Dia 5 PROT 401_r0.pdf

78/295

The figure shows the effect of displacing the fault location along the protected line. The

resu t s t e appearance o au t areas n t e mpe ance p ane. T e mpe ance eac

distance element measures will lie inside the corresponding fault area. The position for

the measurement depends on fault location and fault resistance. The sides of the fault

areas marked with dots are the locii of the measured impedances for bolted (RF = 0)

faults. The straight lines parallel to those sides are the locii of the measured impedances

corresponding to the maximum RF value (4 ohms.)

The basic conclusion is the same as for the previous figure: there are several distance

elements prone to operate for a single line-to-ground fault. For single-pole tripping, the

tripping decisions of the distance elements cannot be used. A separate algorithm is

needed to determine the fault type for single-pole applications.


8/11/2019 Dia 5 PROT 401_r0.pdf

79/295

This figure shows the impedances the distance elements measure for a BCG fault at the

remote en o t e re ay reac . T e ots on eac au t ocus represent erent va ues o

fault resistance (0 to 10 ohms).

For bolted faults, three distance elements (BC, BG, and CG) see the fault exactly at the

end of the reach corresponding to each element. When the fault resistance increases, the

impedance the CG element measures moves away from the relay characteristic. On the

other hand, the BC impedance penetrates the relay characteristic. This element

overreaches, so it must be blocked from operation for this fault. For simplicity, the effect

of the fault resistance on the BC element impedance is not shown. It is clear, however,

that this impedance also leaves the operation characteristic.


8/11/2019 Dia 5 PROT 401_r0.pdf

80/295

In summary, distance elements measure different impedances for unbalanced faults.

P ase e ements can operate or c ose- n, ne-to-groun au ts, an groun e ements can

overreach for line-to-line-to-ground faults. A separate algorithm is needed to determine

the fault type. The information on the fault type can be used to decide on single-pole

tripping and to block the operation of ground distance elements for line-to-line-to-ground

faults.


8/11/2019 Dia 5 PROT 401_r0.pdf

81/295

Evolving faults present problems for all protection principles. Many faults evolve in some

way. T e au t res stance RF may vary w t t me. As a resu t, t e au t current s var a e.

Another common type of fault evolution is a change of fault type. Many faults initiate as

line-to-ground faults and evolve into line-to-line-to-ground faults and/or three-phase-to-

ground faults.

For evolving faults, it is generally difficult to detect fault inception and fault type

changes.


8/11/2019 Dia 5 PROT 401_r0.pdf

82/295

Both phase and ground distance elements measure impedance for normal load conditions.

As can be seen in the figure, the measured impedance depends on the load flow

conditions. An increase in the apparent power, S, transferred over the line reduces themagnitude of the measured impedance


8/11/2019 Dia 5 PROT 401_r0.pdf

83/295

The impedance angle depends on the direction of P and Q. For positive values of P and Q

(both P and Q flowing into the line), is between 0 and 90 and the measuredimpedance lies on the first quadrant of the impedance plane. A negative Q value brings

the impedance to the fourth quadrant.

Accordingly, a negative P value will move the measured impedance to the other two

quadrants: to the second quadrant for a positive Q value and to the third quadrant for a

negative Q value.

conditions. For positive P values (Load OUT in the figure), the impedance is in the first

or fourth quadrants. For negative P (Load IN), the impedance is in the second or third

quadrants.


8/11/2019 Dia 5 PROT 401_r0.pdf

84/295

Checks for load encroachment problems can be performed by superimposing relay and

load characteristics on the impedance plane. In the figure, it can be seen that certain load

conditions result in penetration of the impedance in the relay characteristic.

A traditional solution to avoiding distance element misoperation is to shape the relay

characteristic to exclude the load impedance regions. A drawback of this solution is that it

limits the fault resistance coverage of the distance element.

A new solution is to create a relay load element having the same shape as the load

. .

case, only a small section of the relay characteristic is lost.


8/11/2019 Dia 5 PROT 401_r0.pdf

85/295

The relay is supposed to be protecting line L1, and its location is at Bus P. The fault

occurs on line A-B.


8/11/2019 Dia 5 PROT 401_r0.pdf

86/295

The figure shows the impedance measured by a distance relay for an external fault. As

expected, the apparent impedance moves to an external point. After the fault clears, the

apparent impedance does not return instantaneously to the load equilibrium point, but

there is a post-fault slow oscillation, or swing. The characteristics of the oscillation

depend on many parameters of the power system. The case shown in the figure shows

that the oscillation does not produce any relay misoperation.


8/11/2019 Dia 5 PROT 401_r0.pdf

87/295

The figure shows a case where the post-fault power swing enters into the relay first zone

operation characteristic. This will produce an undesired operation of the relay.


8/11/2019 Dia 5 PROT 401_r0.pdf

88/295

8/11/2019 Dia 5 PROT 401_r0.pdf

89/295

Parallel lines is a very common case in transmission systems. The magnetic field

produced by a faulted line influences the behavior of the voltages and currents of a

neighboring line. This influence is called mutual coupling between lines.


8/11/2019 Dia 5 PROT 401_r0.pdf

90/295

The figure illustrates mutual coupling. For a ground fault on one of two double-circuit

lines, the zero-sequence current flowing at each line induces a voltage in the other line.

This effect modifies the voltage ground distance elements measure. If the mutually

coupled current flows in the same direction as the relay current, the measured voltage will

increase and the distance element will tend to underreach. On the other hand, if the

mutual current direction is opposite to that of the relay current, the relay element will

measure a lower voltage and tend to overreach.


8/11/2019 Dia 5 PROT 401_r0.pdf

91/295

8/11/2019 Dia 5 PROT 401_r0.pdf

92/295

These expressions show the effect of mutual coupling on the impedance ground distance

elements measure. I0M is assumed to be positive when it flows in the same direction as

Ires. The result is an increase in the apparent impedance, Z, and a relay underreach. A

negative value of I0M reduces the measured impedance, and the relay element

overreaches.


8/11/2019 Dia 5 PROT 401_r0.pdf

93/295

The figure shows the ground distance element behavior for a ground fault on a double-

circuit transmission line with both lines connected in parallel. For simplicity, it is

assumed that the system is energized at one end only.

In the lower figure, the impedances ground distance elements measure at locations A, B,

and C are shown as a function of the distance, m, to the fault from location A. For relay

elements A and C, the apparent impedances, with mutual coupling, are represented by

full lines, and dotted lines are used to represent the measured impedances without mutual

coupling. The latter case gives the correct impedance values and serves as a reference for

analysis. For relay element B, the measured impedance plot without mutual coupling

would be a straight line from ZB = ZL at m = 0, to ZB = 0 at m = 1.

The effect of mutual coupling in this case is that none of the ground distance elements

correctly measure the distance to the fault. For relay elements A and C, the mutually

coupled current flows in the same direction as the relay current. These elements measure

higher impedance values and tend to underreach. For relay element B, the mutual current

flows opposite to relay current. The result is a lower apparent impedance value and a

tendency for the relay element to underreach.


8/11/2019 Dia 5 PROT 401_r0.pdf

94/295

The mutual-coupling error may be compensated for by providing the faulted-line relay

element with information on the mutually coupled current. These equations show that an

additional compensation term, k0M I0M, is needed in the relay current of the ground

distance element. The compensation factor, k0M, equals the ratio of the zero-sequence

impedance to the positive-sequence impedance of the protected line. Several commercial

distance relays have an additional current input for the mutually coupled current.


8/11/2019 Dia 5 PROT 401_r0.pdf

95/295

A limitation of mutual coupling compensation is that it eliminates the distance

measurement errors only for the faulted-line ground elements.

In the parallel-line case that was presented before, compensation works for relays atlocations A and B and fails for the relay at C. The problem with the relay at C is that the

level of compensation needed depends on the fault location, m.

Another limitation of mutual coupling compensation is that I0M is not always available at

the relay location.


8/11/2019 Dia 5 PROT 401_r0.pdf

96/295

This figure shows cases in which the mutually-coupled current I0M is not available at the

relay location.


8/11/2019 Dia 5 PROT 401_r0.pdf

97/295

Experience shows that the first zone setting for the relay should be reduced to avoid

overreaching for severe cases of zero-sequence mutual coupling. In some cases, the first

zone may need to be reduced by 60 percent.


8/11/2019 Dia 5 PROT 401_r0.pdf

98/295


8/11/2019 Dia 5 PROT 401_r0.pdf

99/295


8/11/2019 Dia 5 PROT 401_r0.pdf

100/295

It is convenient to use an impedance plane to represent the distance element operating. - , - ,

mho-type distance elements.

The figure shows the operation equation and the operating characteristic of the mho distanceelement. The characteristic is the locus of all apparent impedance values for which the relayelement is on the verge of operation. The operation zone is located inside the circle, and therestraint zone is the region outside the circle.

The mho characteristic is a circle passing through the origin of the impedance plane. The mhoelement operates for impedances inside the circle, which is basically oriented toward the firstquadrant. This is the case for forward faults. For reverse faults, the apparent impedance lies in thethird quadrant of the impedance plane and represents a restraint condition. The fact that the circlepassed through the origin of coordinates is an indication of the inherent directionality of the mhoelements. However, close-in bolted faults produce deep voltage sags. The mho element may losethe voltage polarizing signal for close-in faults. This fact needs to be considered in selecting theappropriate mho element polarizing quantity.

There are only two settings in a mho element: the characteristic diameter, ZM, and the angle of

this diameter with respect to the R axis, MT. This is equivalent to the maximum torque angle of adirectional element: the mho element presents the highest reach (highest sensitivity) when theapparent impedance angle coincides with MT.

The value MT should be set close to the protected line impedance angle. By doing this, it ensuresmaximum relay sensitivity for faults and minimum relay sensitivity for load conditions, in which < MT.

The other two conventional distance elements lack directionaly. The impedance-typecharacteristic is a circle whose center is at the origin of coordinates. The reactance-typecharacteristic is a straight line parallel to the R axis. Impedance-type elements need an additionaldirectional element. Reactance-type elements need a directional element and a resistance elementto limit the reach on both sides of the element characteristic.


8/11/2019 Dia 5 PROT 401_r0.pdf

101/295

8/11/2019 Dia 5 PROT 401_r0.pdf

102/295


8/11/2019 Dia 5 PROT 401_r0.pdf

103/295


8/11/2019 Dia 5 PROT 401_r0.pdf

104/295


8/11/2019 Dia 5 PROT 401_r0.pdf

105/295


8/11/2019 Dia 5 PROT 401_r0.pdf

106/295


8/11/2019 Dia 5 PROT 401_r0.pdf

107/295


8/11/2019 Dia 5 PROT 401_r0.pdf

108/295


8/11/2019 Dia 5 PROT 401_r0.pdf

109/295


8/11/2019 Dia 5 PROT 401_r0.pdf

110/295

8/11/2019 Dia 5 PROT 401_r0.pdf

111/295


8/11/2019 Dia 5 PROT 401_r0.pdf

112/295

8/11/2019 Dia 5 PROT 401_r0.pdf

113/295


8/11/2019 Dia 5 PROT 401_r0.pdf

114/295


8/11/2019 Dia 5 PROT 401_r0.pdf

115/295


8/11/2019 Dia 5 PROT 401_r0.pdf

116/295


8/11/2019 Dia 5 PROT 401_r0.pdf

117/295

Technical papers supporting this section:

6030.pdf, Statistical Comparison and Evaluation of Pilot Protection Schemes, E.O.

Schweitzer III, John Kumm

AG93-06.pdf,Applying the SEL-321 Relay to Directional Comparison Blocking (DCB)

Schemes, Jeff Roberts

AG95-29.pdf,Applying the SEL-321 Relay to Permissive Overreaching Transfer Trip

POTT Schemes Armando Guzman Jeff Roberts Karl Zimmerman

AG96-19.pdf,Applying the SEL-321 Relay to Directional Comparison Unblocking

(DCUB) Schemes, Dean Hardister

6109.pdf, The Effect of Multiprinciple Line Protection on Dependability and Securityby

Jeff Roberts, Demetrios Tziouvaras, Gabriel Benmouyal, Hector J. Altuve

Revision Table

Editor Tech

Revie

w

TDS

Revie

w

Date Rev

#

Comments

CRT 1/31/0 1 Adapted from Line Pilot Protection_r9


8/11/2019 Dia 5 PROT 401_r0.pdf

118/295


8/11/2019 Dia 5 PROT 401_r0.pdf

119/295

Pilot protection (or teleprotection) is a generic name for the design of different

transmission line protection alternatives that use a communications channel. The most

important advantage of pilot protection is the provision of high-speed tripping at all

terminals for faults anywhere on the line. Without pilot protection, high-speed tripping

for all terminals will only occur for faults that are within the area where the zone 1

elements overlap. Pilot protection is typically applied to transmission lines with nominal

voltage levels of 115 kV and greater.

For comparison purposes, pilot protection can be divided into two groups, directional

comparison systems and current-only systems.

Directional comparison protection uses the channel to exchange information on the status

of directional or distance elements at both terminals. If both elements operate, there is an

internal fault. If one of the elements operates and the other restrains, the fault is outside

the protected line. The most widely used pilot protection system is directional

comparison. The main reasons for this wide acceptance are the low channel requirements

and the inherent redundancy and backup of directional comparison systems. On the other

hand, these systems experience problems associated with loss-of-potential for blown VT

fuses, ferroresonance in wound potential VTs, and transient response issues of CCVTs.

Phase-comparison and current-differential systems use current information to make a trip

decision. However, these systems require a reliable, high-capacity communications

channel. Current-only systems exhibit good performance for complex protection

problems such as series compensated lines, short lines, evolving faults, cross-country

faults, mutual induction, power swings, and series impedance unbalance. Modern digital


fiber-optic communications channels fulfill the requirements of current-only pilot

protection systems.

8/11/2019 Dia 5 PROT 401_r0.pdf

120/295

8/11/2019 Dia 5 PROT 401_r0.pdf

121/295

Some additional advantages.

Reduced duration of the voltage sag from the short circuit and resulting negative

impact on power quality.

Clearing faults quickly reduces through fault duty on power transformers,

insulator damage due to sustained arcing, etc.


8/11/2019 Dia 5 PROT 401_r0.pdf

122/295

8/11/2019 Dia 5 PROT 401_r0.pdf

123/295

Microwave systems can be either digital or analog. These are often part of a wide area

communications network for voice and data traffic as well. Analog systems generally use

audio tone sets to put the teleprotection information into a voice channel. Channel delays

for audio tone sets on analog microwave can be 8-20 milliseconds. Digital microwave

can provide channel delays in the 3-4 millisecond range.


8/11/2019 Dia 5 PROT 401_r0.pdf

124/295

Power line carrier provides a reliable point-to-point path for sending teleprotection

information. The equipment to couple the signal to the high voltage power line can be

expensive. Also, the teleprotection scheme used must be designed to work if the channel

is lost during an internal fault that short circuits the communications channel. Power line

carrier channel equipment usually comes in two types, On/Off and FSK. The type used

depends upon the needs of the teleprotection scheme.


8/11/2019 Dia 5 PROT 401_r0.pdf

125/295

Private or leased lines also provide digital and audio tone communications channels.

Although the interface equipment can be expensive, the overall installation costs can be

reduced.

On the down side, there is the ongoing lease costs of the channel. Additionally, leased

lines are often unreliable. To encourage the owner of the leased line to improve the

reliability, you must document the availability, test results, etc. and provide them to the

owner.


8/11/2019 Dia 5 PROT 401_r0.pdf

126/295

In modern systems, the relay interface to the communications channel is digital using a

proprietary protocol. As an example, SELs MIRRORED BITS Technology

communicates the status of eight bits. The advantage of these systems is that more

information can be exchanged. The exchange of more information allows for the

inclusion of control to go along with the protection. These systems also simultaneously

monitor the health and availability of the communications channel.

ON/OFF carrier sets pass one bit of information. The units either transmit a signal or they

dont.

FSK carrier sets always transmit something. Under normal conditions, they transmit a

Guard tone. When keyed, they shift the transmission frequency to a Trip tone. The sets

often include security measures, such as Trip After Guard and Guard Before Trip, to

ensure the integrity of the communications channel.


8/11/2019 Dia 5 PROT 401_r0.pdf

127/295


8/11/2019 Dia 5 PROT 401_r0.pdf

128/295

The figure shows a schematic diagram of a directional comparison system. This system

uses directional or directional-distance relay elements to distinguish internal from

external faults. For an internal fault, both relays see the fault in the forward (tripping)

direction; for an external fault, one relay sees the fault in the reverse (non-tripping)

direction.

Although the relays use current and voltage information to determine the fault direction,

the communications channel is used to exchange information about relay contact status.

In traditional systems, the relay interface to the communications channel equipment is via

contact inputs and outputs. The two-state type of information requires very low channel

throughput (about 1000 Hz bandwidth.) For these systems, the relay has no information

about the channel health.

An advantage of these tripping schemes is that channel time delay is not critical. A delay

in receiving the remote signal may delay tripping, but the delay does not affect whether

the trip or restrain decision is correct. The inherent backup provided by the directional

and/or distance elements ensures tripping (perhaps delayed) for internal faults with a

channel failure.


8/11/2019 Dia 5 PROT 401_r0.pdf

129/295

The advantages of directional comparison systems summarized in this slide. In particular,

the low channel requirements explain why more than 80 percent of transmission lines in

the United States have directional comparison protection systems.

Since only 1 bit of information is passed through the channel, a very low bandwidth is

required.

If the channel is inoperative, the fault is generally cleared in Zone 2 time.

When micro rocessor rela s are used fault locatin al orithms are used to aid in fault

locating. Current only systems do not have enough information to be able to provide any

fault location estimates.


8/11/2019 Dia 5 PROT 401_r0.pdf

130/295

Directional comparison pilot protection schemes are designed around sending one bit of

data across the teleprotection channel at very high speed. In some schemes, this one bit

tells the other end that it has permission to trip (permissive). In other schemes, the bit

represents a signal to tell the other end not to trip (block). There are many variations but

the most prevalent are the following:

Permissive Overreaching Transfer Trip (POTT)

Directional Comparison Unblocking (DCUB)

Permissive Underreaching Transfer Trip (PUTT)

Directional Comparison Blocking (DCB)


8/11/2019 Dia 5 PROT 401_r0.pdf

131/295


8/11/2019 Dia 5 PROT 401_r0.pdf

132/295

At the minimum, a POTT scheme requires a forward overreaching element at each end of

the line. This is typically provided by a Zone 2 element set to reach about 120%-150% of

the line length. If each relay sees the fault in the forward direction, then the fault can be

determined to be internal to the protected line.

Relay 3 will key permission if it sees the fault in a forward direction. Relay 4 will be

allowed to trip if it sees the fault in a forward direction AND it receives permission from

Relay 3.

.

provided by a Zone 3 element set in the reverse direction. It is important that the reach of

the reverse Zone 3 element be set for the element to always pick up for faults that can be

seen by the remote Zone 2 overreaching element.

It is important to note that in all of these schemes, an under-reaching Zone 1 element is

typically used to trip independent of the pilot protection scheme.

. ,

most common protocol.


8/11/2019 Dia 5 PROT 401_r0.pdf

133/295

The basic logic for a POTT scheme looks like this.

A trip requires pickup of Zone 2 overreaching elements AND receipt of permission

(RCVR) from the remote end.

Pickup of Zone 2 overreaching elements keys transmission of permission to trip (Key

XMTR) to the remote end.


8/11/2019 Dia 5 PROT 401_r0.pdf

134/295

A number of complications to a POTT scheme require additional logic.

If the remote terminal is open, the relay on that terminal will not see the fault and

will therefore be unable to give the local terminal permission to trip. This problemis addressed by echo key logic. The relay on the open terminal echoes the

permissive signal back to the closed terminal, allowing it to trip.

If the one terminal is a much weaker source of fault current than the other, or its

normal source is out of service, it may not have sufficient current to pick up for the

. ,

trip. This problem is addressed similarly to the open terminal echo keying logic;

but it includes 27P & 59N elements to detect the weak feed condition.


8/11/2019 Dia 5 PROT 401_r0.pdf

135/295

Additional complications to a POTT scheme that require additional logic.

If the channel fails completely, permission to trip cannot be sent. To deal with this

inability to send permission, the Zone 2 overreaching element also typically starts aZone 2 timer to allow backup tripping after a coordinating time interval to provide

backup step distance mode of operation in case of channel failure.

Current reversals during the fault can cause unfaulted lines to trip.


8/11/2019 Dia 5 PROT 401_r0.pdf

136/295

Current Reversals

In double-circuit line applications, faults near one end of the line may result in a

sequential trip operation. This sequential trip happens when the instantaneous relayelements trip the breaker nearest to the fault location (this trip is independent from the

communication tripping scheme). The breaker furthest from the fault must wait for a

permissive signal. The major problem with this sequential fault current clearance is that

it creates a current reversal in the healthy parallel line. If the protection for the healthy

line is not equipped to address this reversal, one terminal of the healthy (non-faulted) line

may trip incorrectly.

The figure shows the status at the inception of the fault. Relaying at Breaker 3 detects the

fault as being within Zones 1 and 2. The instantaneous Zone 1 element issues a trip

signal to the breaker independent of the communication-assisted tripping scheme. It is

the Zone 2 elements at Breaker 3 that issue a permissive signal to the protection at

Breaker 4. The protection at Breaker 4 detects the fault within Zone 2 but must wait for

the permissive signal from Breaker 3 before issuing a permissive trip output. In the event

that the permissive trip signal never arrives and the fault persists, Breaker 4 is tripped by

Zone 2 time-delayed protection.

The Zone 2 element at Breaker 2 also picks up at fault inception and issues a permissive

signal to the protection scheme at Breaker 1. At this time, the Zone 3 elements at Breaker

1 also pick up and identify the fault as being reverse (or out-of-section) to its location.


8/11/2019 Dia 5 PROT 401_r0.pdf

137/295

After Breaker 3 opens, the fault currents redistribute. When this redistribution occurs, the

Zone 2 element at Breaker 2 and Zone 3 element at Breaker 1 begin to drop out. If the

Zone 2 element at Breaker 1 picks up before the received permissive signal resets,

Breaker 1 trips due to this current reversal.

This scenario can easily occur when ground directional overcurrent relays are used as

they can often see an end zone fault on an adjacent line. It is less of a factor when ground

distance relays are used.

electromechanical element would be much higher than the opening springs torque

resulting in a large disparity in pickup versus dropout times. This disparity is also true

with numerical relays, but to a much lesser degree.

To address this, a reverse element (Zone 3) is used to detect when the fault is initially

seen behind the relay. A dropout delay prevents the relay from keying permission upon atransition from reverse to forward. The delay allows the remote terminal forward

e ement t me to rop out.


8/11/2019 Dia 5 PROT 401_r0.pdf

138/295


8/11/2019 Dia 5 PROT 401_r0.pdf

139/295

8/11/2019 Dia 5 PROT 401_r0.pdf

140/295

8/11/2019 Dia 5 PROT 401_r0.pdf

141/295


8/11/2019 Dia 5 PROT 401_r0.pdf

142/295

In a directional comparison blocking scheme, each line terminal has reverse looking

elements (Zone 3) and forward overreaching elements (Zone 2). The relay will send a

block signal to the remote end if it sees the fault in the reverse direction. Relay detection

of a fault in the reverse direction indicates that the fault is outside of the protected zone.

The logic allows the relay to trip if it sees the fault in the forward direction and does not

receive a blocking signal from the remote end.


8/11/2019 Dia 5 PROT 401_r0.pdf

143/295

This figure shows the fundamental logic involved. Pilot tripping occurs for an internal

fault if the local Zone 2 forward overreaching element operates and the remote Zone 3

reverse reaching element does not send a block signal within a settable time.

The channel coordination delay must allow time for the block signal to be received before

the tripping element can operate. If the block does not arrive, or is late, a DCB scheme

may overtrip. This scheme is often used with power line carrier and an ON/OFF

transmitter because the only time the signal must get through is when the fault is not on

the protected line.

One way to speed up the issuance of the blocking signal is to use non-directional carrier

start. In this case, a high-speed overcurrent element detects the fault and keys the

transmitter. Then the slower directional element will stop the signal if the fault is

forward. If the directional element detects that the fault is reverse (out of zone), the

blocking signal has already been sent. This can reduce the required carrier coordination

delay, resulting in increased security.


8/11/2019 Dia 5 PROT 401_r0.pdf

144/295

There are number of complications that need to be addressed with DCB schemes. We

have already discussed time coordination. Current reversals also must be addressed, with

logic similar to that used with the other schemes.

Loss-of-channel is a particular issue with DCB schemes. Because each terminal will trip

for lack of a block signal, these schemes will overtrip if the channel fails. This is

complicated by the typical use of an on/off type carrier set to obtain the highest possible

channel speed. An on/off carrier set is off in the normal state; it is turned on to block the

remote end.

For this reason, it is usually desirable to use an automatic carrier check back system with

on/off carrier sets. An automatic carrier check back system can be programmed to operate

several times a day. There is usually a master check back unit that keys the local

transmitter with a series of carrier pulses. The slave check back units monitor their local

receiver and recognize this code as a check back transmission instead of a fault

transmission. These units then respond by keying their local transmitter with an answer

code. If the master hears the answer on its local receiver, it knows that the channel is

viable. If it does not, it will typically alarm SCADA that the channel has failed. If an

internal fault occurs during a check back transmission, the relay will assert its carrier

stop output. The carrier sets give priority to carrier stop over carrier start. That is, if

both stop and start are asserted, the stop input takes precedence and the transmitter will

be turned off.


8/11/2019 Dia 5 PROT 401_r0.pdf

145/295


8/11/2019 Dia 5 PROT 401_r0.pdf

146/295


8/11/2019 Dia 5 PROT 401_r0.pdf

147/295

8/11/2019 Dia 5 PROT 401_r0.pdf

148/295

POTT and PUTT schemes can be less dependable because they will fail to trip high speed

during a channel failure. Conversely, DCB schemes will overtrip if the channel fails or if

the channel delay increases.

Directional comparison unblocking schemes combine the dependability of DCB schemes

with the security of POTT schemes but allow tripping during a window of time to

accommodate channel failure during a fault. DCUB schemes are attractive when the

power line is used for the communications medium.


8/11/2019 Dia 5 PROT 401_r0.pdf

149/295

DCB schemes should not be used with networked communications channels such as

SONET where the channel delay can change. For such cases, you would need a high-

speed channel such as a power line carrier On/Off channel.

POTT and DCUB schemes will not trip until the permission (or unblock) signal arrives,

so there are no concerns about channel delay for security. Channel delay does affect

ultimate tripping time.

If a fault on the power line can affect the teleprotection channel, a DCB or DCUB

.

channel include power line carrier or communications lines sharing right of way with the

protected power line.


8/11/2019 Dia 5 PROT 401_r0.pdf

150/295

8/11/2019 Dia 5 PROT 401_r0.pdf

151/295

Phase-comparison and current-differential systems only use current information. The

figure depicts a schematic diagram of current-only systems. Phase-comparison systems

compare the phase of the currents at the line terminals. For internal faults, these currents

are in phase. For external faults, the currents are approximately 180 degrees out of phase.


8/11/2019 Dia 5 PROT 401_r0.pdf

152/295


8/11/2019 Dia 5 PROT 401_r0.pdf

153/295

The system detects the current zero crossing at each line terminal and forms a square

wave signal. The local end receives the remote end square wave signal after a given

channel time delay, CD. A time delay, LD, is introduced in the local signal to compensate

for the channel time delay of the received signal. For internal faults, currents iL and iRare

in phase, the output of the AND gate lasts one-half cycle, the timer times out and issues a

trip. For external faults, iL and iRare 180 degrees out of phase, the output of the AND

gate is zero and the timer does nothing.

If LD = CD, the AND gate behaves as a coincidence detector of the positive half-cycle of

currents iL and iR. The coincidence timer issues a trip output when the coincidence time

of SL and SR is equal to, or greater than, the pickup time T. The T setting determinesthe angular width of the phase comparator characteristic. For T= one-quarter cycle, thecharacteristic is 90 wide. That is, the logic will allow tripping if the currents are out of

phase by up to 90. The dropout timer setting Tprovides a trip output latch and should

be greater than tT, where t is the fundamental frequency period.

Signals SL and SR are never exactly in phase or 180 degrees out of phase. The main

sources of phase angle error for external faults are charging current, CT saturation, and

time delay compensation errors. For internal faults, there is a phase shift because of the

non-homogeneity between the sources and the line impedance.

The system, as described, will fail to trip for an internal fault during a communications

channel failure. Alternatively, a logic inversion can be introduced in the square wave that

is sent to the remote line terminal. Likewise, the received signal is inverted before the

phase comparison. This logic enhances dependability and allows tripping when there is


no received signal, but can misoperate for an external fault during a communications

channel failure.

8/11/2019 Dia 5 PROT 401_r0.pdf

154/295

The system depicted in the previous slide is a half-wave or a single phase comparison

scheme. That system provides a comparison for the positive half-cycle only. This

introduces a half-cycle latency in the trip decision. Alternatively, a full-wave, or dual

phase comparison, system can be used. Two sets of square waves are formed at each line

terminal and compared independently. AND 1 detects the time coincidence of the

positive half-cycle square waves SL+ and SR+. AND 2 detects the time coincidence of

the negative half-cycle square waves SL- and SR-. The system can make a tripping

decision on either half-cycle, thus providing faster operating speed.

For simplicity, local and channel time delays are not shown in the figure.


8/11/2019 Dia 5 PROT 401_r0.pdf

155/295

The most widely used phase comparison system is a non-segregated scheme. The pulse

generated at each line terminal is a composite signal that combines the phase currents to

form a unique single-phase voltage. A typical composite signal, VF, is a weighted

combination of the current symmetrical components.

The high bandwidth of modern digital communications channels permits implementation

of segregated phase comparison systems. These systems fulfill an independent phase

comparison for each phase current. This is a more expensive scheme, but it provides

faulted phase identification for single-pole tripping and enhances the protection behavior

for evolving faults, cross country faults, inter-circuit faults, and series compensated lines.


8/11/2019 Dia 5 PROT 401_r0.pdf

156/295

The basic phase-comparison principle only exchanges phase information between line

terminals. This principle fails for internal faults with outfeed, such as when one current

flows in one terminal and out of the other terminal. This figure shows a possible outfeed

condition. A high-resistance internal fault, for which the load current is greater than the

fault current, is a typical case of an outfeed situation.


8/11/2019 Dia 5 PROT 401_r0.pdf

157/295


8/11/2019 Dia 5 PROT 401_r0.pdf

158/295

The percentage differential principle, originally developed for the protection of

transformers and generators, was extended to the protection of short transmission lines in

the 1930s. The traditional system uses a telephone-type pilot wire channel to exchange

analog information between the line terminals. Composite sequence networks form

voltage signals that contain magnitude and phase information on the currents at the line

terminals. Percentage differential relays at each end respond to the currents derived from

the comparison of these voltages through the pilot wire. The system operates as a

percentage differential relay at lower levels of fault current. At higher currents, the

s stem becomes a hase com arison s stem because of the effect of the saturatin

transformer included in the scheme. The transformer is intended to provide isolation

from ground potential rise in the copper conductor channel. The introduction of fiber

optic channels permitted provision of the percentage-differential characteristic for all

levels of fault current.

The figure depicts two typical percentage differential characteristics. A differential relaycompares the magnitude of an operating current with the magnitude of a restraining

current. The rela is on the ver e of o eration when the e uation definin the

characteristic is fulfilled. The operating region is the region above the operating

characteristic. A variable-percentage or dual-slope characteristic (dotted lines in the

figures) increases relay security at higher fault levels.


8/11/2019 Dia 5 PROT 401_r0.pdf

159/295

Percentage differential elements compare an operating current (also called differential

current) with a restraint current. The operating current, IOP, is the magnitude of the

phasor sum of the currents entering the protected element.

IOP is proportional to the fault current for internal faults and approaches zero for other

operating (ideal) conditions.

The slide shows the most common alternatives for obtaining the restraint current, IRT.


8/11/2019 Dia 5 PROT 401_r0.pdf

160/295

The differential current is not exactly zero for external faults. The most common causes

of false differential current in transmission line differential relays are the following:

Line charging current

Tapped load

Channel time-delay compensation errors

Current transformer saturation

Line charging current is significant in cable lines or long overhead lines.

The false differential current created by tapped loads may be the result of load current,

low-side faults, or inrush current in the tapped transformer.

The effect of line charging current and load current can be eliminated by using anegative-sequence or zero-sequence differential element.

Channel time-delay compensation errors and current transformer saturation contribute to

false differential current in all types of differential elements. To address these two

sources of error, the operating characteristic of the differential element needs to be

carefully designed.


8/11/2019 Dia 5 PROT 401_r0.pdf

161/295

Some advantages of phase-segregated current based systems are:

They do not require voltage information (this avoids problems such as loss-of-

potential for close-in faults, blown potential fuses, ferroresonance in VTs andtransients in CVTs.)

They are immune to:

Mutual induction effects

Power swings

Series impedance unbalance (open-pole conditions, unequal gap

flashing on series-compensated lines, etc.)

Current reversals in parallel-line configurations


8/11/2019 Dia 5 PROT 401_r0.pdf

162/295

Other advantages of phase-segregated current based systems are:

They perform well for evolving, inter-circuit, and cross country faults.

They are easily applied to short transmission lines

They tolerate high line loading

Depending upon the operating characteristic, current-only systems may

handle outfeed conditions during high-resistance faults and in series-

compensated and three-terminal lines.

The basic limitations of current-only systems are related to the communications channel:

they need a reliable, high-capacity channel. These limitations are rapidly disappearing

with the modern digital fiber-optic communications channels. In addition, digital

technology permits inclusion of many protection functions in a relay unit. It is nowpossible to combine a directional comparison and a current based pilot system in the

same relay. This diversity of operation principles in the same unit may enhance the

overall performance without a significant increase in cost. In applications where

reliability also demands duplicate hardware, you may install two such relay units and

obtain four separate protection functions running on two separate hardware platforms.


8/11/2019 Dia 5 PROT 401_r0.pdf

163/295

8/11/2019 Dia 5 PROT 401_r0.pdf

164/295

This figure shows a family of percentage differential relay operating characteristics for

different values of the slope, K. These characteristics correspond to the relay having a

slope characteristic that crosses the origin of coordinates. The relay restraint quantity is

the difference of the input currents. Relay characteristics are circular.

The operating region is the area out of the circle, and the restraint region is inside the

circle. Note that the

1 + j0 point corresponding to an ideal through-current condition is inside the relay

restraint region.


8/11/2019 Dia 5 PROT 401_r0.pdf

165/295

This figure depicts another family of characteristics corresponding to a relay having a

slope characteristic that crosses the origin of coordinates. The relay restraint quantity for

this case is the sum of the input current absolute values. Relay characteristics are not

circular. Note that the value of the slope, K, determines not only the size, but also the

shape of the relay characteristic.

Dual-slope differential relays may have two different types of slope characteristics. The

first slope characteristic may be a straight line crossing the origin of coordinates or may

intersect on the restraint current axis. The second slope characteristic always has an

intersect on the restraint current axis.

Thus, the dual-slope differential relay will have two different characteristics in the

current-ratio plane. The restraint current value determines the characteristic that is active

for a given power system operating condition.


8/11/2019 Dia 5 PROT 401_r0.pdf

166/295

The current-ratio plane is an excellent tool for analyzing the response of current only

protection systems for different power system conditions and to the signal corruption

resulting from the protection scheme elements. The method for analyzing relay operation

is to superimpose on the same current-ratio plane the relay characteristic and the current-

ratio trajectory resulting from the fault or abnormal condition in the power system. This

method is equivalent to the operation analysis of distance relays in the impedance plane.

For power system and protection scheme steady-state conditions, the current-ratio

trajectory reduces to a point. Under transient conditions, the trajectory will converge to a

final steady-state point in the current-ratio plane. This figure depicts current-ratio plane

regions for steady-state fault and load conditions. If we disregard all possible sources of

errors, the point representing the system condition falls along the real or a-axis. For ideal

through-current conditions (normal loads or external faults), a = 1. For internal faults

with infeed from both line ends, a > 0. For internal faults with outfeed at one terminal, a

< 0. Note that the relay characteristic should have the point a = 1 in the restraint zoneand all the fault regions in the operation zone.


8/11/2019 Dia 5 PROT 401_r0.pdf

167/295

8/11/2019 Dia 5 PROT 401_r0.pdf

168/295

Line charging current flows into the line at both line terminals and creates a false

differential current. This figure represents the current components that exist in the line for

a normal load condition.

The figure also depicts the current-ratio locus for different values of ILOAD. The trajectory

is not circular in the general case. Note that, for small load currents, the current-ratio

value lies in the right semi-plane. The only way to avoid relay misoperation is to set the

relay minimum pickup current greater than the line charging current value. For

differential elements responding to the phase currents, this sensitivity limitation affects

the relay fault resistance coverage for internal faults. The negative-sequence or zero-

sequence components of the charging current are very low when compared to the

positive-sequence or phase values. Thus, a negative-sequence or a zero-sequence

differential element can be set much more sensitive than a phase element.


8/11/2019 Dia 5 PROT 401_r0.pdf

169/295

A tapped load not included in the line differential measurement creates an operation

current component in the differential scheme. This figure shows the current distribution

in a line with a tapped load. The tapped load current, IT, may be load or fault current.

Fault currents can correspond to internal or secondary-side faults in the tapped

transformer.

When ITL = ITR, the current-ratio locus has the general aspect of that of the previous slide.

When ITL ITR, the trajectory still begins at a = 1 (for ILOAD >> IT), and ends in theright part of the real axis.

The differential relay pickup must be set greater than the load current of the tapped load.

Negative-sequence and zero-sequence differential elements can be set more sensitive than

the phase elements, because negative-sequence and zero-sequence differential elements

only respond to load unbalance.

Tapped load fault current must also be taken into account. A possible solution is todesensitize the relay to the maximum tapped load fault current. The type of fault to

cons er epen s on t e erent a e ement; t ree-p ase au t or t e p ase e ements,

phase-phase or phase-phase-ground faults for the negative-sequence elements, and phase-

phase-ground or phase-ground faults for the zero-sequence elements. If one of the tapped

transformer windings is connected in delta, a zero-sequence differential relay does not

respond to secondary-side ground faults, but the relay will still respond to internal

transformer primary winding ground faults. Another solution is to have the differential

relay time coordinated with the tapped load overcurrent protection devices. The simplest

means of accomplishing this is to use the calculated total phase or sequence current as the


input to a time-overcurrent (TOC) element. In turn, the TOC element is coordinated with

the overcurrent protection of the tapped load. It is interesting to note that by using totalline current, we in fact are turning the looped or multi-feed coordination problem into a

radial line coordination exercise.

8/11/2019 Dia 5 PROT 401_r0.pdf

170/295

Saturation of a current transformer (CT) for an external fault produces a false operating

current in a differential protection scheme. To avoid relay misoperation, it is necessary to

desensitize the relay by selecting the appropriate value of the slope, K.

The current-ratio plane can be used to visualize the effect of CT saturation and to

determine the relay slope setting.

This figure shows the secondary CT currents and the resulting differential current for a

fault with maximum dc offset. Recall that the differential current should be zero for an

.


8/11/2019 Dia 5 PROT 401_r0.pdf

171/295

This figure depicts the current-ratio trajectory corresponding to the filtered currents

shown in the previous slide. The procedure for obtaining this figure involved calculation

of the fundamental phasor values of currents, u

Documents

Dia 5 PROT 401_r0.pdf