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Tutorial on Application and Setting of Ground Distance Elements on Transmission Lines Draft 5.0PREPARED BY THEPower System Relaying and Control CommitteeLine Protection SubcommitteeWorking Group D30

IEEE Power & Energy Society

January 2020TECHNICAL REPORT

PES-TR??

© IEEE 2020 The Institute of Electrical and Electronics Engineers, Inc.No part of this publication may be reproduced in any form, in an electronic retrieval system or otherwise, without the prior written permission of the publisher.

TR-?? — Title of the Report

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Working Group for Tutorial on Application and Setting of Ground Distance Elements on Transmission Lines

Chair: Karl Zimmerman

Members and Contributors

Jorg BlumscheinWes BrownDon Burkart

Randy CrellinMohammad Dadash Zadeh

Alla DeronjaJay Gosalia

Nathan GulczynskiMahfooz Hilaly

Craig HoltKevin JonesMeyer Kao

Will KnapekGary Kobet

Mike KockottHilmon LadnerJoshua Lamb

Van LeDaniel Lebeau

Heather MalsonAaron MartinJoe Mooney

Anthony NewmanJoshua Park

Claudine PascalVijay Shanmugasunda

Christopher WalkerTed WarrenJack Wilson

Zhiying Zhang

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ACKNOWLEDGMENTS (Optional)

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KEYWORDS

Distance, protection, relays

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CONTENTS

1. INTRODUCTION..........................................................................................................1

2. EASE OF USE.............................................................................................................1

2.1 Template.............................................................................................................1

2.2 Maintaining the Integrity of the Specifications.....................................................1

3. TECHNICAL REPORT PREPARATION......................................................................1

3.1 Abbreviations and Acronyms..............................................................................2

3.2 Units....................................................................................................................2

3.3 Equations............................................................................................................2

3.4 Footnotes............................................................................................................3

3.5 Some Common Mistakes....................................................................................3

4. USING THE TEMPLATE..............................................................................................3

4.1 Identify the Headings...........................................................................................4

4.1.1 Members and Contributors...........................................................................4

4.2 Figures and Tables..............................................................................................4

4.2.1 Figures.........................................................................................................4

4.2.2 Tables...........................................................................................................4

4.2.3 Positioning Figures and Tables....................................................................5

5. REFERENCES.............................................................................................................5

APPENDIX A SAMPLE HEADING..................................................................................8

A.1 Sample Heading..................................................................................................8

A.1.1 Sample Heading...........................................................................................8

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1. INTRODUCTION (Heading 1)The use of ground distance elements in transmission line protection schemes has become increasingly common as microprocessor-based relays have become the predominant technology. These modern relays typically include ground distance elements as a standard feature, so activation of these elements can be accomplished with a few configuration settings and no additional hardware or wiring in most cases.

In legacy electromechanical devices, phase distance relaying was widely used and the inclusion of ground distance relays was less common. Directional ground overcurrent relays were more often applied for ground fault protection on networked transmission lines. This led to a more thorough understanding of the phase distance technology, while experience with the unique characteristics and challenges associated with ground distance relaying has lagged.

This paper discusses the design, operational characteristics, and various types of ground distance elements and provides an overview of common applications and general settings practices. Additionally, typical application challenges for the ground distance element are presented and practical solutions are offered.

2. Ground Distance Element Design of Mho ElementsThere are basically two types of characteristics used in distance relays. Mho and quadrilateral characteristics are the two major types, and all other characteristics are modifications of these basic characteristics.

As we all know, the distance relay provides impedance-based protection so it needs voltage and current input. Voltage input is provided via voltage transformers (VTs) and current input is provided via current transformers (CTs). In addition, distance relays model the impedance of the line inside the distance protection. The operation of a distance relay can be represented in the most simplistic way as a balance scale, as shown in Figure 1.

Figure 1. Simple representation of distance relay operation1


Figure 1 illustrates the basic principle of operation: Voltage and current are balanced during the normal operation of the system where the protection is applied. Voltage can be viewed as a restraining quantity, while current is an operating quantity. During normal operation (e.g., 69 V and 5 A), both are balanced. When a fault occurs, the voltage reduces (for example, 10 V), and current increases (for example, 30 A), which disturbs the balance. The current is an operative force that closes the trip contact and trips the breaker, isolating the fault.

To apply this concept to the power system, consider the protection as a “black box” applied on the line it protects, as shown in Figure 2.

Figure 2. Example line with distance protection relay

In the above figure, the protection is protecting Line AB and the reach of the relay at Station A is set as ZR. One thing to remember here is that the reach of the relay ZR is a vector, which means it has magnitude and angle. ZR represents the impedance of the line being protected by the distance protection. Typically, the reach is highly inductive because the resistance of the line is smaller compared with the impedance of the line (e.g., 80 to 85 degrees).

Figure 3 shows the reach impedance and mho characteristic of the distance relay. The mho characteristic for the distance relay is a circle with a diameter equal to the reach of the relay. If the impedance measured by the relay falls inside the mho characteristic, a fault condition is determined. If the impedance falls outside the characteristics, no fault condition exists. Once the relay senses the fault condition, it produces a trip signal. The angle of the reach is called the characteristic angle, or maximum torque angle, in electromechanical distance relays (e.g., KD or CEY relays).

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Figure 3. mho characteristic of relay with reach ZR.

The basic block diagram of mho distance relay is as follows.

Figure 4. Basic block diagram of mho relay.

Current input from the CT is passed through impedance ZR, which converts the current from the CT into the voltage and creates the vector IZR. Inverted vector IZR and voltage input from the VT are summed together to create the vector V – IZR. This vector and voltage vector V are then provided to a phase comparator, where the angle between vector V and vector V – IZR is compared. If the angle between these two vectors is 90 degrees or more, a trip output is issued. If the angle between these two vectors is less than 90 degrees, no trip output is issued.

As we compare the two vectors V – IZR and V for 90 degrees as a balance point for trip or no trip status, the locus of these balance points is a circle with IZR as a diameter.

Figure 5 shows vectors for internal and external faults.

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Figure 5. Vectors for internal (left) and external faults (right).

Now, let us establish some terms that will be useful as we move further in this tutorial. A mho relay compares the angle between two vectors. One is V – IZR and the other is V. We designate one of the vectors as a base vector where the other is compared. So, consider V the base vector and call it the polarizing voltage or Vpol. In Figure 5, Vpol is V. Thus, for an A Phase element, Vpol is Va and V – IZR is Va – IaZR.

When a relay has a polarizing voltage that is the same as the phase voltage, we call it a phase comparator relay or a self-polarized relay. The first versions of mho relays were all self-polarized.

Self-polarized relays have some limitations. When there is a zero-voltage fault, such as a fault directly in front of the relay location, the fault voltage V is almost zero, so Vpol = 0. Now, out of the two quantities Vpol and V – IZR, we do not have Vpol, so the self-polarized relay cannot decide on a trip or no trip status. So the self-polarized relay has a limitation in that it cannot protect the line against a zero-voltage fault.

Engineers soon worked out an alternative. They decided that if the prefault voltage is “memorized,” then relays can use the prefault voltage as the Vpol. This way, the relay will always have Vpol available. Using healthy phase voltage as a polarizing voltage is the other alternative. The diagram in Figure 6 shows how the healthy phase voltage can be used to provide the Vpol for a phase-to-ground fault.

Figure 6. Voltages for A-G fault.

Using –(VB + VC) provides the polarizing voltage Vpol for any phase-to-ground fault. Also, using the memory voltage or the prefault voltage of Phase A results in the same effect. Using memory voltage or prefault voltage is a very good way to make sure polarizing voltage is available all the time.

It is important to know the effect of using memory voltage or healthy phase voltage on the mho characteristic. Now, we determine the different vectors for a mho characteristic. When the relay uses healthy phase or memory polarization, the relay now has one more

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vector, which is Vpol, in addition to self-voltage V. To begin deciding how to draw the prefault voltage (Vpol) on an R-X diagram, we consider the scenario in Figure 7.

Figure 7. Example system.

In Figure 7, the prefault voltage at the relay location is E. A voltage drop in source impedance Zs is due to load and can be ignored. When the fault occurs, the fault current IF

flows into the fault. Just after the fault, the prefault voltage E can be represented as E = IF

Zs + VF. So now the polarizing voltage is E = I Zs + V.

Next, we draw the phasors.

Figure 8. Phasors for fault.

In Figure 8, the two new vectors are shown in red. Now, the Vpol is not V anymore, as it would be in a self-polarized relay. We can see from Figure 8 is that Vpol is shifted in the counterclockwise direction. The point that was right at the boundary means 90 degrees for self-polarized relay is now higher than 90 degrees.

The trip criteria for the mho characteristic are still the same. The balance point is 90 degrees between Vpol and V – IZR. This means that the characteristic is a circle with a diameter that is the vector connecting IZR and I Zs. The characteristic with memory polarization is shown in Figure 9.

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The mho characteristic is the blue circle, and the self-polarized relay characteristic is the smaller green circle.

Figure 9. Example characteristics for memory-polarized relay.

Error: Reference source not found shows the actual characteristics obtained for memory-polarized mho relay. (removed)

We can make the following observations based on the figure:

This is the characteristic for the forward fault only. The characteristic in green (circle) that intercepts the origin is the self-polarized relay while the

characteristic in blue (larger circle) shows the memory-polarized relay. Memory-polarized characteristics are obtained by performing dynamic state simulation tests,

while the self-polarized characteristics are plotted by doing simple routine testing. The memory-polarized characteristic expands to allow the relay to cover more fault resistance but

does not overreach or underreach because the circle still passes through the reach line like a self-polarized mho characteristic.

The memory-polarized characteristic circle expands depending on the source impedance. A strong source means a smaller source impedance, so the circle does not expand very much. For a weak source where the source impedance is quite high, the circle expansion is greater compared with a strong source. Thus, fault resistance coverage can be small for close-in faults with a strong source.

To understand how the mho relay behaves during a reverse fault, we reconsider the vectors the relay will see during a reverse fault. The figures below show how the vectors are developed to aid understanding of how the mho characteristic will operate for a reverse fault.

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Now we can look into the actual implementation of the phase comparator. Figure 10 is based on actual implementations by a few manufacturers.

Figure 10. Actual implementation of phase comparator for reverse fault.

In short, the advantages of a memory-polarized mho relay are as follows:

Provides additional fault resistance coverage compared with a self-polarized mho relay.

Is very stable against a reverse fault.

The memory-polarized mho relay is limited because the expansion of the mho characteristic depends on the value of source impedance and reach of the relay; therefore, the fault resistance coverage is not very large. This is due to a low source impedance value (strong source) and a short line. In this case, the additional fault resistance coverage is almost negligible.

Consider the implementation of a mho measurement. The block diagram in Figure 11 shows how a mho characteristic can be implemented in a relay. This is based on some of the most popular relay designs by manufacturers.

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Figure 11. Block diagram of mho implementation with polarizing voltage.

The angle comparator measures the angle between V and V – IZR to determine if it is greater or less than 90 degrees. In practice, most relays use a polarizing voltage (Vpol) different than the operating quantity V, so that angle is actually between Vpol and V – IZR. Some older designs use a healthy phase voltage(s) and most newer designs implement some type memory polarization, where healthy voltage from the prefault is dynamically updated as the polarizing quantity. [1 E.O Schweitzer, J. Roberts, “Distance Relay Element Design”]

Element Operating Quantities

Self-polarized

Cross-polarized

V1 memory

AG Va – IZR

I = Ia + k0* IR

Va 1@90deg * Vbc

Va1mem

BG Vb – IZR

I = Ib + k0* IR

Vb 1@90deg * Vca

Vb1mem or

Va1mem*1@240deg

CG Vc – IZR

I = Ic + k0* IR

Vc 1@90deg * Vab

Vc1mem or

Va1mem*1@120deg

Table xx: Typical polarizing choices for gorund distance elements

3. Ground Distance Element Design of Quadrilateral ElementsFor ground distance protection, fault resistance coverage is quite important. A strong source with a short line typically does not result in adequate fault resistance coverage. Therefore, a quadrilateral characteristic can be used that allows independent reach

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settings and resistance coverage. A typical and very basic quadrilateral characteristic is shown in Figure 12.

Figure 12. Basic quadrilateral characteristic.

The line crossing the origin is called the directional line. The line passing through the reactive axis is called the reach line. The lines parallel to the reach line are called load blinders. Each line is a measure of fault direction. The output from each line passes through the logic to decide the fault position.

Each line is a directional comparator. It provides the output for a fault in one direction only. The basic comparator logic is shown in Figure 136.

Figure 13. Basic directional comparator logic.

For all line comparators, two signals are needed to make a decision on the direction of the fault. If one signal is A and another signal is B, the logic used here is that when Signal A lags Signal B by 0 to 180 degrees, it produces an output.

Each comparator in the quadrilateral characteristic has Signal A and Signal B derived from appropriate voltage and current signals. The quadrilateral characteristic is the combination of four line comparators.

The fault is inside the characteristic and results in a trip based on the following logic:

Fault is above directional line.

Fault is below reach line.

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Fault is left of right load blinder line.

Fault is right of the left load blinder line.

Figure 14. Trip logic for quadrilateral characteristic.

If all four of the line comparators produce the output, the protection assumes that the fault is in the zone. Here we can see that ZR is based on the length of the line, and Kr (resistive reach) is based on the maximum load condition. This allows the best fault resistance coverage.

Note for the quadrilateral characteristic that there are four line comparators involved in making the trip decision compared with the one used in the mho characteristic. The trip time depends on the longest decision time of these comparators.

Now, we consider how each of the line comparators makes the decision on the direction of the fault.

3.1 Directional Line Comparator

In the case of the directional line, Signal A is IZR. This is fault current multiplied by the reach impedance setting, ZR. Signal B is the fault voltage, VF, phase-shifted by 90 degrees.

Figure 15 shows the condition of both signals for the forward fault, and the trip condition is satisfied. Signal A is lagging Signal B by 0 to 180 degrees.

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Figure 15. Condition of signals for forward fault.

Now, in Figure 16, we can see the same type of vector diagram for the reverse fault, which represents the vector position of Signal A and Signal B for the reverse fault condition.

Figure 16. Condition of signals for reverse fault.

Compared with Figure 15, the only difference is that the direction of the fault voltage, V ,

is reversed. In this case, Signal A does not lag Signal B and the comparator output will be zero.

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Therefore, the directional line provides the output only for the forward fault and not for the reverse fault.

3.2 Reach Line Comparator

The vector diagram shows the fault under the reach line. This is the direction for which the reach line comparator is programmed to produce an output as an internal fault.

Here, the two signals being compared are as follows:

Signal A = V – IZR

Signal B = IKr

The output of the line comparator will be true if Signal A is lagging Signal B by 0 to 180 degrees. In this case, the condition is satisfied and a fault underneath the reach line will produce a trip output.

The same comparator will not produce the trip output if the fault is outside the reach line, as shown in the vector diagram in Figure 17.

Figure 17. Caption.

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Figure 18. Caption.

In Figure 18, the comparator logic of Signal A is not lagging Signal B by 0 to 180 degrees, so it will not produce an output.

Using a similar principle, the load blinder can be designed to produce the desired output by selecting an appropriate measuring signal for comparison.

3.3 Load Blinder Comparator (Blinders)

The right-side load blinder is programmed to produce and output an internal fault result if the fault is on the left-hand side of the blinder.

Here, the two signals being compared are as follows:

Signal A = V – IKr

Signal B = V – IZr

Kr is the resistive reach setting on the quadrilateral characteristic.

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Figure 19. Caption.

Figure 19 depicts the internal fault. The output of the line comparator will be true if Signal A is lagging Signal B by 0 to 180 degrees. In this case, this condition is satisfied for the fault inside the quadrilateral characteristic. The comparator will produce a trip output.

The same comparator will not produce the output if the fault is outside quadrilateral characteristic, as shown in Figure 20.

Figure 20. Vector diagram for fault outside reach line.

In Figure 23, the comparator logic of Signal A is not lagging Signal B by 0 to 180 degrees, therefore so it will not produce an output.

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For the left load blinder, the same logic applies, but Signals A and B are swapped. If the fault is on the right-hand side of the left load blinder, it will produce an output.

In summary, the basic quadrilateral characteristic is a four-line comparator producing an output if Signal A lags Signal B.

4. Comparison of Mho and Ground Quadrilateral ElementsGround distance elements are traditionally defined as having either a circular (mho) or polygonal (quadrilateral) characteristic. These two shapes are shown together in Figure 21. In electromechanical relays, it was much simpler to apply the mho characteristic. This was because it can be derived with a single operating element, an induction cup, using an operating quantity on one axis (IZ – V) and a polarizing quantity (Vpol) on the other axis.

In a microprocessor-based relay, it is easy to derive any shape.

Figure 21. Mho and quadrilateral distance elements.

The quadrilateral element has three basic advantages in an operating system:

A quadrilateral element has a simple defined reach in the Y (reactance) direction. This constant reach makes zone coordination and coordination with adjacent lines simpler.

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The X (resistance) reach is independent of the Y (reactance) reach. In other words, the fault resistance coverage does not need to be the same or even related to the reactance reach, as shown in Figure 22.

The resistive reach is the same for all fault positions along the line.

Figure 22. Different X and R reach in a quadrilateral element.

This difference in X and R reach provides for selectable fault resistance coverage. This is an advantage in cases with poor tower grounding of a transmission line, with high soil resistivity, or where there is concern that outside objects (such as tree branches) can cause a high resistance to ground.

The resistance reach is not without limit. Nonhomogeneous infeed from the two different ends of the line can cause the apparent location of the fault to “tip” from beyond the end of the line into the characteristic.

Here are some general observations when comparing mho and quadrilateral ground distance elements. [2 S.Ward, “ Comparison of Quadrilateral and Mho Distance Characteristic”]Mho ground distance elements provide excellent field experience, are familiar to relay engineers, are easy to test, provide enough fault resistance coverage for a majority of applications, are inherently secure during heavy load, and detect fault resistance detection capability comparable to quadrilateral elements for pilot systems.

Quadrilateral ground distance characteristic can be beneficial for stepped distance, non-pilot systems, and for short lines with strong sources when directional ground relays are not used.

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5. Basic Setting ConsiderationsBasing the ground distance settings strictly on the protected line’s impedance parameters, in many cases will not suffice. On parallel lines, the mutual impedance may cause ground distance elements to overreach or underreach. The Zone 1 for ground distance relaying should be set at 80 percent of the smallest zone reach that the relay can see for a single-line-to-ground fault at the remote bus. Eighty percent should even be used for faults beyond the remote bus if a closely coupled parallel line exists and a fault on it creates even less impedance than that for the remote bus fault. Zone 2 should be set using the same criteria as the phase relays (i.e., 125 percent for two-terminal lines, 130 percent for three-terminal lines, etc.), using the largest zone reach that the relay can see for the remote bus fault.

6. Application Challenges6.1 Parallel Lines With Zero-Sequence Mutual CouplingMutual coupling is the effect of one transmission line on other nearby lines when current is flowing in the line. The current flowing in the line creates a magnetic field that in turn induces a current on the adjacent line or lines. The effect of mutual coupling is present in all sequence components, but it is negligible in positive- and negative-sequence components and can have a significant impact on the zero-sequence components. Figure 23 shows the effect of mutual coupling where the current flowing in one line induces the current flowing in an adjacent line.

Figure 23. Effect of mutual coupling.

The impact of the mutual coupling can be affected by various factors. Some factors that influence the amount of mutual coupling are the characteristics of the transmission line and the direction of the current. For instance, the following characteristics of the transmission line can impact the amount of mutual coupling:

Conductor type

Tower configuration

Tower spacing

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Grounding

The length that the lines are in parallel

The direction of current flowing in the adjacent lines will also impact the behavior of the system. This is illustrated in Figure 24. For instance, when current is flowing in the same direction on both lines, the apparent impedance observed at one line terminal will increase. Conversely, when the current in the lines is flowing in the opposite direction, the apparent impedance observed at one line terminal will decrease.

Figure 24. Effect of current direction on apparent impedance.

In order to adequately account for the effects of mutual coupling on the ground distance elements, it is imperative that the fault study model includes the mutual impedances for each set of lines with appreciable distances in parallel. Figure 25 shows the positive- and zero-sequence impedance for two parallel 17-mile lines and the mutual impedance between the two lines. Figure 26a and Figure 26b show the impact that modeling the mutual impedances can have. Figure 26a shows examples where the mutual impedance was not modeled, and Figure 26b shows examples where the mutual impedance was modeled.

Figure 25. Impedances for two parallel lines.

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Figure 26. Impact of modeling mutual impedances.

Case 1 – Two Coupled Lines

Figure 27 shows a case where the apparent impedance as seen by a relay on the right side of one of the lines increases because the current on the lines flows in the same direction. Figure 28 shows the case where the apparent impedance as seen by a relay on the right side of one of the lines decreases because the current on the lines flows in opposite directions.

Figure 27. Apparent impedance increases because current flows in same direction.

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Figure 28. Apparent impedance decreases because current flows in opposite direction.

Case 2 – Double-Circuit Lines

Figure 29 shows the case where the apparent impedance as seen by a relay on the right side of one of the lines increases because the current on the lines flows in the same direction. Figure 30 shows the case where the apparent impedance as seen by a relay on the right side of one of the lines decreases because the current on the lines flows in opposite directions.

Figure 29. Apparent impedance increases because current flows in same direction.

Figure 30. Apparent impedance decreases because current flows in opposite direction.20


Case 3 – Double-Circuit Lines With Additional Line

Figure 31 shows the case where a third line is in parallel with two double-circuit lines. In this case, the current flowing on Line 3 will decrease the apparent impedance on Lines 1 and 2 because the current flows in the opposite direction. Meanwhile, Lines 1 and 2 will increase the apparent impedance on one another because the current flows in the same direction.

Figure 31. Double-circuit lines with an additional line.

Case 4 – Two Lines With Partial Coupling

Figure 32 shows the case where two lines are mutually coupled for a portion of the line length. In the case shown, the apparent impedance of Line 2 is decreased at the common bus.

Figure 32. Two lines mutually coupled for a portion of the line length.

Case 5 – Double-Circuit Lines With Series Station

Figure 33 shows a pair of double-circuit lines with one line having a series station in the middle, effectively creating three lines. This example shows that for a fault at the bus of the series station, the apparent impedance on Line 1 would decrease while the apparent impedance on Line 2 will increase.

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Figure 33. Double-circuit lines with a series station.

Case 6 – Four Parallel Lines

Figure 34 shows the case where there are four parallel lines, and each of the lines is mutually coupled to each of the other lines. Because the strength of the mutual coupling is proportional to the distance between the lines, the interior lines (Lines 2 and 3) are impacted the most.

Figure 34. Four parallel lines.

Case 7 – Current Reversal

Figure 35 shows what can happen after a breaker close to a fault opens during a fault event and the current changes direction. When this happens, not only can it cause issues with directionality, it can also cause a situation where the apparent impedance varies widely. Before the breaker opens, the apparent impedance was increased because the currents were originally flowing in the same direction, and after the breaker opens, the apparent impedance decreases because the currents are now flowing in the opposite direction.

Figure 35. Breaker opening causes current to flow in opposite direction.

Case 8 – Grounded Line

Figure 36 shows the case where one of the parallel lines is open and grounded at both ends. In this case, the current flowing down the in-service line will induce a current in the grounded line. This is important to know because, while under normal balanced conditions, there is not much current induced. In unbalanced fault or load conditions, the current could be significant.

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Figure 36. Current on in-service line induces current on grounded line.

To summarize, the presence of mutual coupling can cause several challenges when setting ground distance elements. These challenges apply to both mho and quadrilateral characteristics. Mutual coupling may cause the Zone 1 elements to overreach and likewise cause Zone 2 elements to underreach. Also, as shown in the examples, current reversals may occur and will impact the directionality of the relay and cause a misoperation. Mutual coupling may also impact the polarizing of the directional element because both the zero-sequence voltage and zero-sequence current are affected by mutual coupling. Therefore, negative-sequence voltage polarization is preferred in the presence of significant mutual coupling. Also, mutual coupling may cause the zero-sequence current to be higher than expected.

In order to deal with the mutual coupling while setting ground distance elements, the following steps can be taken. First, use the apparent impedance of the line (the impedance seen by the relay for a fault at the remote end of the line) instead of the positive-sequence impedance for setting the ground distance element reach. For underreaching zones, use the lowest apparent impedance for a remote-end single-line-to-ground fault for the cases where both lines are in service and where only one line is in service. For overreaching zones, use the highest apparent impedance for a remote-end single-line-to-ground fault for the cases where both lines are in service and where only one line is in service. Second, use a second compensation factor (K factor) for overreaching zones on parallel lines that include the zero-sequence mutual impedance in the K factor calculation. Table I shows the resulting apparent impedances for the lines shown in Figure 1 if the compensation factor used does not include the zero-sequence mutual coupling. As shown, the line actually appears longer than the positive-sequence impedance would indicate and an overreaching zone using just the positive-sequence impedance as the basis for the reach may not see a remote bus fault with both lines in service.

Table ICaption

Apparent Impedance Without Z0m in K Factor

Apparent Impedance Local Bus 1

Apparent Impedance Local Bus 2

Positive-Sequence Impedance

One line in service 13.2 13.2 13.2

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Both lines in service 18.6 16.7 13.2

There are also other methods to deal with the impact of mutual coupling. Among them is inputting residual current from the adjacent parallel line into the line relay and setting the relay to compensate based on the input. Another method is to use a status from the breaker on the adjacent parallel line and input the status into the line relay and change set points or setting groups when the breaker on the adjacent line is open [3. B. Jackson, “Zero Sequence Coupling of Parallel Transmission Lines and Effect on Ground Relays,” proceedings of the 65th Georgia Tech Protective Relaying Conference, Atlanta, GA, May 2011.].

6.2 Weak Source Effect on Ground Distance Protection Element

Figure 37 depicts a one-line diagram of a system with an extremely weak zero-sequence current source at Station A. A planned 69 kV line, which is parallel to a 138 kV line and mutually coupled to it, is to be protected by ground distance elements for phase-to-ground and phase-to-phase-to-ground faults. The system is very weak in the area, as the respective fault study for the 69 kV line presented in Table II indicates.

Figure 37. Weak source system one-line diagram.

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Table IIFault Study for 69 kV Line

Fault Study Zapp Ohms Primary Amperes Primary

Fault Location & System Configuration SLG SLG Aph SLG 3I0

Local end, close-in, with remote end open NA 5,425 5,425

Remote end, with strongest local

source out of service41.83 398 40

Strongest source =Station A Transformer 1 is out of service

Remote end, all network equipment in service 41.77 447 44

As shown in Table II, the 3I0 fault current is very low and the ground distance fault detector cannot be set below this available fault current because the relay’s ground fault detector minimum setting is 0.5 A secondary and its connected CT ratio is 600/5 (120), which cannot be set lower since it has to support the maximum available loading on the line. Therefore, the ground fault detector may be insensitive and not pick up for Zone 2 faults on the 69 kV line that are near the remote terminal at Station B.

One option to overcome this problem is to utilize the instantaneous ground overcurrent element as part of the communications-based permissive overreaching transfer trip (POTT) scheme on the line. The line does possess a communications channel. The pickup setting of the instantaneous ground overcurrent element may be set lower; its minimum setting is 0.25 A secondary. Therefore, it may be set as low as 30 A primary with a CT ratio of 120 and could boost relay sensitivity for the Zone 2 faults on the 69 kV line, although insignificantly, since this is in the lowest portion of the relay setting range and where it could be at odds with the relay’s ability to determine whether the fault is in forward or reverse direction.

Another option is to rely on sequential tripping to trip the Station A terminal for a ground fault on the 69 kV line after the Station B terminal clears such a fault first. This option will introduce a delay in clearing the fault, which may be acceptable since the fault current magnitude is considerably low.

An option of utilizing a weak terminal echo keying logic as part of the POTT communications scheme on the line can also be considered. The weak terminal would convert the echo signal of the strong terminal, which is a qualified permissive trip, into a trip if it senses a high neutral or a low phase voltage. An issue may be a very low neutral

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voltage, which is in the lowest portion of the relay setting range, although the low phase voltage setting could be available.

Also, the protected 69 kV line is in parallel and mutually coupled to a 138 kV line, and it is important to examine the proper coordination of the elements of the POTT schemes on both parallel lines. It is possible for the two terminals of the faulted line to open at different times. When it happens, the current on the nonfaulted line will suddenly reverse and, if the keying and blocking elements and timers are not properly coordinated, a misoperation will occur. The weak terminal echo keying logic can complicate the coordination and needs to be thoroughly verified and tested.

Finally, a fourth option would be to utilize the quadrilateral ground element.

This particular utility’s philosophy is to apply a Zone 2 timed quadrilateral element only on 69 kV lines without a communications channel. Since the communications channel is utilized to protect this 69 kV line, the quadrilateral ground element cannot be applied for ground fault protection on the line because the mho and quadrilateral characteristics share the same logical outputs in the chosen protective relays.

If utilizing more advanced relays with independent logic outputs for the mho and quadrilateral ground distance elements, a Zone 2 quadrilateral element will provide coverage for a high-impedance ground fault and could still be beneficial for tripping ahead of the ground-timed overcurrent element, typically coordinated to 1 second.

The quadrilateral ground distance reactive element should be set the same as the Zone 2 mho ground distance element. If the Zone 2 mho ground distance element is set past 50 percent into the next shortest line without infeed, the Zone 2 timer is typically set to coordinate; therefore, the quadrilateral setting will be set to the same time delay.

Applying the quadrilateral element may be beneficial to reduce fault clearing time since its operating time may be faster than sequential tripping time.

6.3 Transients Due to Capacitive Voltage Transformers (CVTs), CT Saturation, and Transformer Inrush

6.3.1 Effect of CVT Transients

CVTs are installed in high-voltage and extra-high-voltage substations to transform transmission-level voltages down to lower levels for revenue metering, protection, and control purposes. These CVTs offer various advantages over potential transformers in a high-voltage environment. These advantages include a reduced size of the iron core, more economical operation, an enhancement to transient recovery voltage performance of high-voltage circuit breakers when installed in close proximity with them, and ability to couple with power line carriers (PLCs) to use the PLC for distance protection and

26


communication between the connecting substations. All these advantages are due to the presence of capacitors in the construction of a CVT.

The basic form of CVT construction consists of Capacitors C1 and C2, which are used as a voltage divider to step down the line voltage before it is applied to a wound step-down transformer (SDT) via a tuning reactor LC, as shown in Figure 38.

Figure 38. Basic CVT structure.

When there is a short circuit on the primary, the discharge of the stored energy in the capacitors and inductors will result in a transient oscillation in the secondary. There are basically six parameters that determine the transient response of a CVT.

Point on the Voltage Wave When the Fault Occurs

The worst-case or longest transient response occurs when the primary voltage is at a zero crossing or when the maximum energy is stored in the capacitor, as shown in Figure 39 and Figure 40, respectively.

Figure 39. CVT response for a fault at voltage maximum (peak).27


Figure 40. CVT response for a fault at voltage zero.

Magnitude of the Tap and the Stack Capacitance (Value of C1 and C2)

The capacitive reactance of the CVT circuit is derived from the following expression:

11\* MERGEFORMAT ()

As the magnitude of effective capacitance (CE) becomes larger, the capacitive reactance becomes smaller. The voltage drop thus gets reduced. The lower value of voltage results in a smaller discharge transient but increased duration. Figure 41 is a plot of the transient response of a normal-value and high-value capacitance CVT.

Figure 41. High-capacitance CVT response more closely replicates ratio voltage.28


Design of the Ferroresonance Suppression Circuit (Active or Passive)

An active ferroresonance suppression circuit contains capacitors and inductors, which are both energy storage devices. The circuit performs like a band-pass filter and introduces an added time delay in the CVT secondary voltage output. On the other hand, the passive ferroresonance suppression circuit uses resistance. The resistive load increases the primary current, subsequently causing a hike in the capacitor voltage.

Figure 42. The passive ferroresonance suppression circuit (PFSC) CVT transient is less distorted than the active ferroresonance suppression circuit (AFSC) CVT transient.

Composition of the Burden (Found in Microprocessor-Based Relays) Connected to the CVT

The transient response worsens and becomes oscillatory at a subnominal frequency if the inductive reactance is added to the burden and the burden power factor decreases. The greater the burden, the greater the energy storage is in the reactive components and the greater the transient response is at the zero crossing fault initiation.

Excitation Current of the Intermediate Transformer

Distance relays measure the voltages from the output of the CVT and then calculate the impedance to the fault and operate for different zones if the calculated impedance is within its reach setting. The CVT transients cause a dip in the fundamental value of voltages for a very short period of time, usually 1.5 cycles. This decreased fundamental voltage results in decreased calculated impedance in distance relays. Figure 42 shows the nature of fundamental voltage across CVT output during a transient.

During a severe CVT transient, the reduction of calculated impedance might be great enough to cause Zone 1 distance elements (with no time delay) to overreach for out-of-zone faults. This means that the calculated impedance might fall within the Zone 1 characteristic and cause a misoperation. Zone 2 and Zone 3 elements are usually not

29


affected by these transients because the intended time delay for those elements to operate is greater than the transient duration.

Several strategies over the years have been adopted that take care of this issue and avoid any relay misoperation during such transients. Some of them are listed below:

Disable the Zone 1 element for certain transient conditions where the maximum secure Zone 1 reach is less than the minimum allowable setting on the relay. Further, without any additional logic, the relay Zone 1 setting must be disabled for systems with source impedance ratios (SIRs) greater than or equal to 20 when AFSCs are present in CVTs. PFSCs are much better because they do not require disabling the element for SIRs as high as 30.

Reduce the Zone 1 reach or put a greater time delay with that element than the transient duration. CVTs with AFSCs do not require a reduction in Zone 1 reach for systems with SIRs less than or equal to 4.

Detect high SIR system conditions using the measured voltage and current signals and then introduce narrow band-pass filtering of the voltage or a time delay in the distance element output decision. There are some evident drawbacks with this kind of design such as no flexibility to set an overcurrent threshold and reduction in tripping speed for close-in faults on high SIR systems. To overcome these shortcomings, some microprocessor-based relays use CVT detection logic, as shown in Figure 43. This logic automatically computes voltage and current according to system conditions, irrespective of any SIR. It also overrides the time delay block to permit rapid tripping for close-in faults.

Figure 43. Advanced CVT detection algorithm.

6.3.2 CT Saturation

See [4 technical report, “Distance Element Response to Distorted Waveforms”, 2-3 other sources ]

6.3.3 Transformer Inrush

See [4 technical report, “Distance Element Response to Distorted Waveforms”]

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6.4 Faulted Phase Selection

Faulted phase selection is necessary to prevent distance protection from incorrect operation. Once a fault is detected, the next important step is to find the faulted phase. According to the faulted phase, the right loop for the directional element and the distance element can be selected.

In the typical three-phase system, there are many short-circuit possibilities, depending on which phases are involved and whether a connection to ground is present. The fault loops applicable to the type of fault must be evaluated. For single-phase and two-phase faults without ground, the allocation is straightforward, as only one useful fault loop exists. For all other short-circuit types, several possible loops are available, as shown in Table III.

Table IIIShort-Circuit Types and Fault Loops for the Distance Measurement

Fault Type Phases Involved Fault Loops for the Distance Measurement

Two-phase short circuit without ground

A-B

B-C

C-A

A-B

B-C

C-A

Three-phase short circuit without ground A-B-C A-B or B-C or C-A

Single-phase-to-ground fault

A-G

B-G

C-G

A-G

B-G

C-G

Two-phase short circuit with ground

A-B-G

B-C-G

C-A-G

A-G or B-G or A-B

B-G or C-G or B-C

C-G or A-G or C-A

Three-phase short circuit with ground A-B-C-G

A-B or B-C or C-A or

A-G or B-G or C-G

To detect the faulted phases and loops, we can apply different methods, depending on the technology of the relay. Simple methods are applied using electromechanical relays. With microprocessor-based relays, more sophisticated methods were developed. Table IV provides an overview of the most common methods and explains conditions that are not covered by these methods.

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Table IVMethods for the Detection of Faulted Phases

Method Description Disadvantage

Current

These methods are based on the assumption that the current in the faulted loops increases in case of a short circuit. The ratio of the current root-mean-square (rms) value to the rated current provides information on the type of short circuit.

Problems in case of weak infeed.

Problems if ground current does not belong to the fault (CT saturation, Bauch paradox, and so on).

Voltage

These methods are based on the assumption that the voltage in the faulted loops collapses in case of a short circuit. The ratio of the voltage rms value to the rated voltage provides information on the type of short circuit.

Problems in case of strong infeed, small SIR.

Delta current

These methods use different kinds of delta currents based on rms, instantaneous currents or current-phasors.

The ratio between the delta currents of different phases/loops provides information on the type of short circuit.

Problems in case of weak infeed.

Delta voltage

These methods use different kinds of delta voltages based on rms, instantaneous voltages or voltage phasors.

The ratio between the delta voltages of different phases/loops provides information on the type of short circuit.

Problems in case of switch onto fault (SOTF).

Problems due to transients that are not related to the fault.

Impedance

These methods calculate impedances for all short-circuit loops. The ratio of the lowest impedance value to the individually calculated loop impedance provides information on the type of short circuit.

Problems in case of “ghost impedances.”

Symmetrical components

These methods are based on the symmetrical components. The relation between zero-, negative-, and positive-sequence provides information on the type of short circuit.

Problems if parts of the symmetrical components do not belong to the fault.

Jump detection

These methods use current and voltage jumps as input variables. The logical combination of current and voltage jumps provides information on the type of short circuit.

Problems due to transients that are not related to the fault.

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Due to increasing processor power, modern microprocessor-based relays should apply multiple methods in parallel to be sure to select faulted phases only.

Figure 44 shows an example of a multicriteria loop selector using multiple methods in parallel to select the faulted loop. Due to the structure of the loop selector, the final result is correct even if a single method does not give the correct result

Figure 44. Multicriteria loop selector.

Example: Incorrect Operation of Distance Protection Due to Wrong Result of Single Method for Loop Selection

The information in this section is from a presentation given by Charles Henville at the Working Group meeting in January 2015 [1].

Figure 45 shows the one-line diagram of an example 230 kV system. Substations ABC and XYZ are connected by the parallel Lines L1 and L2. A Phase-B-to-ground fault at Line L1 close to Substation ABC was tripped on a single phase. During the open-pole period, the fault evolved to a B-C fault without ground and was tripped on three phases after reclosing.

During reclosing, the relay at Substation XYZ erroneously tripped line L2 for an apparent Phase-C-to-ground fault in Zone 1. The main reason for this incorrect operation of distance protection was determined to be wrong loop selection because of using only a single criterion.

33


Figure 45. One-line diagram of the 230 kV system.

Figure 46 shows the fault record of the event seen by the relay at Line L2 at Substation XYZ. After reclosing to the B-C fault of Line L1 at Substation ABC, the relay at XYZ selected Phase C (see signal FSC) and gave a trip command due to the “ghost impedance” C-G located in Zone 1 (see signal Z1G). The single-phase fault was identified based on the angle of I0 with respect to I2. But I0 was not related to a fault; it was related to power flow and asymmetry of the power system.

Figure 46. Event fault record seen by the Line L2 relay at Substation XYZ.

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Analyzing the angle between I2 and I0 according to Figure 47, we can see that this criterion clearly identifies a C-G or A-B fault. Taking into consideration the small magnitude of I0, we can state that the quality of this criterion is not very strong in this case.

Figure 47. Phasor diagram of symmetrical components at Line L2 at Substation XYZ.

Analyzing the apparent impedances for all phase-to-phase and phase-to-ground loops in the complex plane according to Figure 48, we can see that several impedances are close to the origin. The impedance of Phase B to Phase C (green impedance trajectory on the right side of Figure 48) is located in the first quadrant of the complex plane with an angle close to the line angle. Due to this, it seems to be the faulted loop. The impedance of Phase C to ground (blue impedance trajectory on the left side of Figure 48) is located in the second quadrant of the complex plane, which is not very typical for the impedance of a faulted loop.

35


Figure 48. Impedances at Line L2 at Substation XYZ.

36


The rms values of the currents and voltages also provide some indication of the fault type. The current of Phase C is increasing the most, but there is also a significant rise of the current of Phase B. The rms values of the voltages provide a very clear indication for Phase B and Phase C because both phase voltages show a significant decrease compared with the stable value of the voltage of Phase A.

Figure 49. RMS of currents and voltages at Line L2 at Substation XYZ.

This example shows that relying on a single criterion for the selection of the faulted phases and loops can sometimes fail. Combining different criteria, however, gives the best result.

6.5 Short Lines, Effect of High SIR

SIR Definition

A short line may be defined based on many factors, such as physical length (miles/km), primary ohm value, and SIR. The IEEE C37.113 classifies a line as short by the SIR [Line Guide C37.113-2015], where a short line has an SIR greater than 4. SIR is the ratio of the source impedance behind the relay to the impedance of the line the relay is protecting. The ratio could be high due to low line impedance, a weak source behind the relay, or both.

Table V shows calculated SIR values for some randomly selected lines at one Midwestern utility. Generally, a high SIR occurs with a physically short line with a weak

37


source behind the relay. However, as the table shows, this is not always the case. An SIR calculation should be performed to determine if the line to be protected is considered short (SIR > 4). Additionally, a medium or long line under normal conditions may become a short line under a contingency, such as when a source behind the relay is out of service. In general, the higher SIR will lead to lower measured voltage at the potential location.

Table VSIR Calculations Performed at One Midwestern Utility

Volts (kV) Distance (miles) SIR SIR (N-1)

69 5.2 0.7 1.2

69 1.2 14.1 57.9

138 9.2 1.2 1.7

138 8.6 2.2 19.7

345 17.6 3 8.8

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Transient (CVTs)

As discussed earlier, CVT transients can produce errors in distance relay response.

Instrument Transformers (CTs/VTs)

Many papers are written on the performance of CVTs on short lines and the possibility of transient overreach. However, very few papers are written on short lines with traditional wire wound VTs. For instrument transformers, the performance error is almost exclusively steady state, so it is more important to know whether a line is physically short rather than electrically short (has a high SIR). This is because having a physically short line amplifies typical magnitude errors in measurement, calculation, settings, and modeling.

Arc Impedance/Fault Resistance

The fault resistance performance of ground distance relays was covered in Section III. However, it is important to briefly discuss additional complications when dealing with short lines. For faults that involve ground, the total resistance includes both arc impedance and fault resistance. The actual value of the arc impedance is difficult to predict. However, it is known that the overall voltage drop of the arc impedance compared with the line impedance becomes more significant at higher SIRs. This additional impedance measured by the relay can cause the distance function to overreach or underreach, depending on the phase angle shift [3]. While it may be possible to incorporate overreaching zones to cover for arc impedance, the Zone 1 distance reach may need to be pulled back due to overreach concerns.

Quadrilateral elements are sometimes applied over mho elements to increase the fault resistance coverage. However, caution should be applied, because reported cases have occurred of quadrilateral elements overreaching when applied to short lines. On a nonhomogenous system, an underreach can occur during an external fault with high fault resistance. In Figure 51 and Figure 52, an example of a nonhomogenous system was modeled in Mathcad®. To emphasize the issue, we held the line impedance angle constant and the source angles were adjusted. The figures illustrate that fault resistance not only has a larger effect on short lines, but it can also enter the quadrilateral trip region. In Figure 52, if a quadrilateral element was applied with a very long resistive reach, the fault resistance could modify the angle such that the measured impedance enters the trip region.

Figure 50. Example system one-line diagram.

Assume a B-G fault occurs at Bus 2.

39


VsecLL := 115 V Rf := 0 ohm, 0.25 ohm, …, 5 ohm

ZL1 := 3 ohm • ej • 85° ZS1 := 6 ohm • ej • 85° ZR1 := 6 ohm • ej • 55°

ZL2 := ZL1 ZS2 := ZS1 ZR2 := ZR1

ZL0 := 3 • ZL1 ZS0 := 3 • ZS1 ZR0 := 3 • ZR1

4 2 0 2 4

4

2

2

4Im LineZ( )

Im Zone1k Im ZBG Rf Im R1( )

Im R2( )

Im X1( )

Im X2( )

Re LineZ( ) Re Zone1k Re ZBG Rf Re R1( ) Re R2( ) Re X1( ) Re X2( )

Figure 51. ZS impedance angle is 85 degrees, and ZR is 55 degrees. B-G fault impedance loop while the fault resistance is varied from 0 to 5 ohms. Measured impedance from Bus 1.

4 2 0 2 4

4

2

2

4Im LineZ( )

Im Zone1k Im ZBG Rf Im R1( )

Im R2( )

Im X1( )

Im X2( )

Re LineZ( ) Re Zone1k Re ZBG Rf Re R1( ) Re R2( ) Re X1( ) Re X2( )

40


Figure 52. ZS impedance angle is 55 degrees, and ZR is 85 degrees. B-G fault impedance loop while the fault resistance is varied from 0 to 5 ohms. Measured impedance from Bus 1.

Summary

For short lines, both the physical and electrical length of the line can affect the intended performance of distance elements in the relay. It is important to gather this information and refer to the relay manufacturer for the expected performance in each application. Once established, the relay engineer can use this information to weigh possible coverage as well as transient overreach concerns. For example, to prevent overreach, it may be necessary to delay or pull back the reach; consequentially, making either quadrilateral or mho ground resistance coverage less effective. If no compromise can be made or it is still difficult to differentiate between in-zone and out-of-zone faults, the relay engineer should consider pilot protection. Communications-assisted schemes such as current differential, phase comparison, POTT, and directional comparison blocking (DCB) work well with short lines. Additionally, an underreaching Zone 1 distance element is not required for these schemes.

6.6 Underground Cables, Z0 Errors

Introduction

Underground cables must be protected against excessive overheating caused by fault currents that could damage the cable, requiring lengthy and costly repairs. Faults in pipe-type cables may burn partially into the steel pipe even if high-speed relaying systems are applied. If the fault is not cleared fast, the arc resulting from an internal pipe-type cable fault tends to burn through the steel pipe. The time required to locate and repair a fault in an underground cable is three to five times longer than the time required for an overhead line.

Most cable faults initially involve ground, and for this reason, ground fault protection sensitivity is of utmost importance. The protection principles applied to underground cable circuits and hybrid circuits are similar to those applied in overhead transmission circuits. However, the differences in the electrical characteristics of underground cables and their method of grounding create challenges for some protective relaying principles, especially for ground distance protection [3] [4].

Line current differential is typically applied for the protection of high-voltage cables. Negative-sequence directional elements have also been used as an alternative to line current differential protection [5]. Negative-sequence elements provide very good fault resistance coverage and directional security since the negative-sequence impedances are stable and predictable. Zero-sequence directional elements are not recommended because of the uncertainty of the zero-sequence impedance of underground cables.

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Application of ground distance relays on underground cables is quite challenging because the effective zero-sequence impedance of the cable depends on the return paths of the fault current. These paths vary over a wide range, depending on the fault location, bonding and grounding methods of the sheath or shields, resistivity of the cable trench backfilling, and presence of parallel cable circuits, gas pipes, and water pipes [3]. Using ground distance relays requires extended setting ranges for the zero-sequence compensation factor. In addition, the short distances (and thus, low impedances) used for cables may make application of distance relays prohibitive in many cases.

Electrical Characteristics of High-Voltage Cables

Electrical characteristics of underground cables differ significantly from overhead transmission lines. Underground cables exhibit a much lower series inductance and a much higher shunt capacitance. The series inductance of cable circuits is typically 30 to 50 percent lower than overhead lines because of the close spacing of cable conductors. The difference in the cable shunt capacitance is even more pronounced and can be 30 to 40 times higher than that of overhead lines.

The positive-sequence impedance of underground cables is much lower than the positive-sequence impedance of overhead lines in ohms per unit of length. The zero-sequence series impedance varies significantly with the resistance of the sheath, the soil electrical resistivity, ρ, and the presence of any other conductors, water pipes, and adjacent cables. The cable zero-sequence impedance angle is also much lower than the zero-sequence impedance angle for overhead lines. Therefore, zero-sequence angle compensation requires a complex zero-sequence compensation factor and a large setting range that accommodates all possible cable and overhead line angles.

Underground cables have sheaths that are grounded in one or in several locations along the cable length. During unbalanced faults, the ground current can return through the sheath only, through the ground only, through the sheath and the ground in parallel, or through the ground and sheath of adjacent cables. The presence of water pipes, gas pipes, railways, and other parallel cables makes the zero-sequence current return path rather complex. All of the above factors make the zero-sequence impedance calculations often difficult to compute precisely and, in many cases, questionable, even with the use of modern computers. Many utilities perform field tests during cable commissioning to measure the zero-sequence impedance value of single-conductor cables [3].

Note that in overhead transmission lines, the positive- and zero-sequence impedances are proportional to distance, assuming the total line length has homogeneous tower geometry, line conductors, and earth resistivity. However, this is not true for underground cables, where the zero-sequence impedance may be nonlinear with respect to distance [6]. The zero-sequence compensation factor (k0) for solid and cross-bonded cables is not constant for internal cable faults, and it depends on the location of the fault along the cable circuit. Because ground distance relays use a single value of k0, the compensated fault loop impedance displays a nonlinear behavior [4].

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Impedance calculation methods for pipe-type cables are the least refined. The nonlinear permeability and losses in the steel pipe make it very difficult to calculate the flux linkage within the wall of the pipe and external to the pipe. The zero-sequence impedance of pipe-type cables varies with the effective permeability of the steel pipe, and the permeability of the steel pipe varies with the magnitude of the zero-sequence current. Under unbalanced fault conditions, a pipe made of magnetic material, such as steel, can be driven into saturation. Because the pipe forms part of the return path for ground currents, changes in its effective resistance and reactance alter the cable zero-sequence impedance. The nonlinear magnetic characteristics of the steel pipe cause the equations that relate the series voltage drop along the pipe-type cable to the current flowing in each of the conductors to become nonlinear simultaneous equations [3]. Figure 53 illustrates the variation of the zero-sequence impedance with ground fault current for a 230 kV, 3,500 kcmil HPOF pipe-type cable in a 10.75-inch pipe.

Figure 53. Variation of zero-sequence resistance and reactance in a 230 kV pipe-type cable as a function of ground fault current.

Ground Distance Relay Application Considerations

This subsection is a shortened version of [6]. Most faults in underground single-conductor cables involve ground. For that reason, it is important to calculate the fault quantities seen by relays during line-to-ground faults along the cable in order to calculate the apparent impedances seen by ground distance relays. The study of intermediate faults in underground cables using symmetrical component theory is quite complex. One limitation of the symmetrical component theory is the assumption that power system element impedances are balanced. This is not true in underground cables because of the different methods used for cable sheath bonding and grounding. Another difficulty in applying symmetrical component theory is the requirement to retain the sheaths, including their transpositions and grounding along the cable path, to properly study faults along the entire cable length or mixed conductor technology circuit.

All of these difficulties are overcome by using the phase frame of reference approach (instead of using the symmetrical component frame of reference) and by using a software program like Electromagnetic Transients Program (EMTP) or good mathematical programming software as discussed in great detail in [7]. The phase frame of reference

43


approach allows modeling of complex cable installations where the protection engineer can introduce additional complexities such as multiple cable sections with sheath and/or core transpositions, different sheath grounding methods, the presence of a ground continuity conductor, core-to-sheath or core-to-sheath-to-ground faults, and faults through an impedance.

Ground distance relay element application for cable protection requires knowledge of cable electrical parameters and cable grounding and bonding methods, as well as a good understanding of the relay functionality. Calculating the compensated ground loop impedance seen by ground distance relays for ground faults along the cable or in mixed conductor technology circuits is very important in determining appropriate relay settings to discriminate internal from external faults and faults in the cable section of the hybrid circuit.

Frequently, protection engineers apply ground distance elements in directional comparison relaying schemes for cable ground fault protection. They also use ground distance elements for Zone 1 instantaneous tripping, as well as Zone 2 and higher zone time-delayed tripping for backup cable protection.

Since most faults in underground single-conductor cables involve ground, it is therefore important to focus on the impedances seen by ground distance relays for faults in the underground cable and faults external to the cable zone of protection.

Table VI summarizes the input signals to traditional ground distance elements. For bolted faults, ground elements that receive only faulted phase information (referred to as the fault loop elements) measure the positive-sequence impedance of the faulted line section.

Table VIVoltage and Current Input Signals to Traditional Ground Distance Elements

Element Voltage Current

AG Va Ia + k0 Ir

BG Vb Ib + k0 Ir

CG Vc Ic + k0 Ir

44


Ground distance elements require the phase currents to be compensated by residual current Ir times a multiplying factor k0, called the zero-sequence current compensation factor. Equation 2 gives the impedance ZAPP measured by the AG ground distance element and 3 gives the residual current.

22\* MERGEFORMAT ()

33\* MERGEFORMAT ()

where:

Ia is the measured Phase A current.

Ib is the measured Phase B current.

Ic is the measured Phase C current.

The zero-sequence current compensation factor is given by 4.

44\* MERGEFORMAT ()

where:

Z0L is the line zero-sequence impedance.

Z1L is the line positive-sequence impedance.

Let us look at the Phase A compensated ground loop impedances of the underground cable shown in Figure 54 [3]. The cable sheaths are solidly grounded at both ends of the cable.

Figure 54. Solidly bonded cable—sheaths grounded at both end of the cable.

There are two ground fault current return paths for faults that involve the cable core with its own sheath. The first path is directly in the faulted cable sheath. The second path is the faulted cable sheath, the sheaths of the other two phases of the cable, and the ground via the grounding of the sheaths at the cable ends, as shown in Figure 55.

The amount of fault current flowing in each return path varies continuously depending on the resistance of each path as the fault location changes along the cable circuit. The continuous variation of the ground current return path causes a nonlinear relation between the fault point and the compensated loop impedance.

45


Figure 55. Paths for ground current return for a core-to-sheath fault in single-conductor solid-bonded cables.

Figure 56 shows the Phase A receiving-end compensated loop impedance nonlinear behavior for ground faults along the cable. The compensated ground loop impedance varies continuously without any discontinuities for internal or external cable faults because the sheaths are solidly grounded at both ends of the cable [6].

Figure 56. Bus R compensated ground loop impedance (k0 = 0.660°).

Figure 57 and Figure 58 show the sending-end (Bus S) compensated ground loop resistance and reactance with a zero-sequence compensation factor k0 = 0.660°. Note that the Phase-A-to-ground faults are applied starting with m = 0 pu at the sending end (Bus S) and ending at m = 1 pu at the receiving end (Bus R).

46


Figure 57. Bus S compensated ground loop resistance (k0 = 0.660°).

Figure 58. Bus S compensated ground loop reactance (k0 = 0.660°).

47


Next, we look at the compensated ground loop impedances of the same cable with a cross-bonded arrangement. The cable consists of three minor sections (1,000 meters each). The sheaths are transposed at each section and solidly grounded at each cable end. Figure 59 shows the compensated ground loop resistance, and Figure 60 shows the compensated ground loop reactance in ohms as seen from Bus S. The ground current compensation factor was set to k0 = 0.660° for illustration purposes, which is typical of a transmission line where the zero-sequence impedance is three times the positive-sequence impedance.

Figure 59. Compensated ground loop resistance (k0 = 0.660°) for cross-bonded cable.

Figure 60. Compensated ground loop reactance (k0 = 0.660°) for cross-bonded cable.

Note that in cross-bonded cables where the sheaths are transposed at each section and grounded at both cable ends, the compensated loop resistance is not the maximum for a fault at the remote end. Note also that moving the fault from the end of a section to the beginning of the next section causes a different return path for the ground fault current and, consequently, causes a discontinuity in the compensated ground loop impedance. This discontinuity, shown in Figure 61, offers some advantages in obtaining selectivity for a Zone 1 distance element for faults in the last section. Note that the discontinuity is more pronounced when the fault is moved from the first to the second section.

Ground distance elements measure fault impedance in terms of positive-sequence impedance only. Set the zero-sequence current compensation factor so that the Zone 1 ground distance elements do not see faults external to the protected cable, while the Zone

48


2 and Zone 3 overreaching ground distance elements see all internal cable faults and coordinate with distance relays on adjacent line or cable circuits.

The choice of a zero-sequence current compensation factor can influence the reach and performance of ground distance relays. Choose a zero-sequence current compensation factor that obtains a constant or increasing slope of the compensated loop reactance for faults at the end of the cable. Do this by choosing a complex zero-sequence current compensation factor corresponding to the cable under study or by selecting a fictitious scalar ground zero-sequence current compensation factor that would compensate correctly for faults at the end of the cable [7].

Consider other parameters in addition to the different behavior of the compensated loop impedance, depending on sheath bonding and grounding methods. Network topology plays an important role in selecting settings for underground cable applications. In some applications, parallel cables are installed between two substations. In others, there are mixed overhead and underground sections. Also consider adjacent line sections, whether cables or overhead lines [7].

For example, in the case of parallel cables, select the proper zero-sequence current compensation factor for Zone 1 by placing a phase-to-ground fault at the remote terminal with the parallel cable out of service. Find the ground distance reactance measurement that does not overreach for that fault using the two zero-sequence current compensation factors that correspond to two different return paths: sheath return only and sheath and ground return. Use all three different cable zero-sequence impedances in the fault study [7]. Select the zero-sequence compensation factor that does not provide any overreach for the sheath return alone or for the sheath and ground return path.

For the overreaching zones, select the zero-sequence compensation factor so that the ground distance overreaching zones do not underreach for any internal ground faults. Select the zero-sequence current compensation factor that corresponds to the zero-sequence impedance of the cable with ground return only. Place both parallel cables in service, simulate a line-to-ground fault at the remote terminal, and calculate the ground distance reactance measurement for each of the three possible zero-sequence cable impedances.

Modern digital ground distance relay elements offer the user more options in achieving better performance of ground distance element measurement than do their older electromechanical and static counterparts. Modern elements offer more than one complex zero-sequence current compensation factor, with a wide range of magnitude and angle settings. In general, negative-sequence current polarizing is the preferred choice for cable applications because the negative-sequence network is more homogeneous than the zero-sequence network. In addition, modern digital relays offer a nonhomogeneous correction angle setting to help prevent overreach or underreach for ground faults at a specific fault point by compensating the angle of the reactance line.

49


The authors in [8] modeled a 10 km section of a cable in a simple two-source system with the source impedances set equal to each other. The cable is an 800-kcmil copper, paper insulated, lead sheath cable having the following sequence impedances:

Z1 = 0.113 /km 56.8

Z0 = 1.041 /km 6.8 Sheath Return Only

Z0 = 0.977 /km 27.9 Sheath and Earth Return

Z0 = 2.414 /km 84.4 Earth Return Only

Using Equation (4), the zero-sequence compensation factors for each zero-sequence impedance are listed below:

k0 = 8.604 –55.1 Sheath Return Only

k0 = 7.786 –32.4 Sheath and Earth Return

k0 = 20.482 28.9 Earth Return Only

Ground faults were applied at 100 percent of the cable length using the three different zero-sequence line impedances and zero-sequence compensation factors. The apparent ground fault impedance was calculated for each earth return path and zero-sequence compensation factor. The ground distance element measurements for a ground mho, a ground quadrilateral with zero-sequence current polarizing, and a ground quadrilateral with negative-sequence current polarizing were also calculated.

Table VII, Table VIII, and Table IX list the resulting distance element measurements in per unit of line length. A per-unit measurement of less than one indicates that the distance element overreaches. A per-unit measurement greater than one indicates that the distance element underreaches. All faults and measurements are taken at 100 percent of the line impedance.

Table VIIZero-Sequence Compensation Factor Using Sheath Return Only

Sheath Return Only (k0 = 8.604 –55.1)

Z0 Impedance Apparent Z Mho Quad–IR Quad–I2

Sheath return only

1.13 56.8 1.00 1.00 1.00

Sheath and earth return

1.1 74.6 1.40 2.08 1.72

Earth return 2.42 120.1 5.04 6.76 7.84

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Table VIIIZero-Sequence Compensation Factor Using Sheath and Earth Return

Sheath and Earth Return (k0 = 7.786 –32.4)


Sheath return only

1.15 39.0 0.76 0.46 0.61


1.13 56.8 1.00 1.00 1.00

Earth return 2.42 102.9 3.18 3.65 3.89

Table IXZero-Sequence Compensation Factor Using Earth Return Only

Earth Return Only (k0 = 20.482 28.8)


Sheath return only

0.53 –10.7 0.31 0.12 0.19


0.52 7.7 0.37 0.25 0.28

Earth return 1.13 56.8 1.00 1.00 1.00

The results shown in Table VII, Table VIII, and Table IX demonstrate that selecting the appropriate zero-sequence compensation factor is critical to ensure correct distance element reach. Using the wrong zero-sequence compensation factor can result in severe under- or overreach.

The test results also show that using a distance-based scheme for this particular cable may not be the best choice. However, of the three ground distance elements studied, the mho ground element provided the best performance in terms of minimizing under- and overreach.

For this cable configuration, the best selection for the zero-sequence compensation factor for an underreaching distance element is the sheath return only. Note that if the current return path is not the sheath, the underreaching ground distance element may not operate. Using the earth or sheath and earth return would result in severe overreach when the ground current return path is not the path selected for setting the zero-sequence compensation factor.

The best selection for an overreaching ground distance element would be the earth return only. However, this choice may not be appropriate for time-delayed backup protection

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where the relay may have a tendency to underreach for external faults if the return path is not the earth return. If the overreaching element is used in a pilot scheme, then using the earth return is the appropriate choice, as the element always operates correctly for internal faults regardless of the ground current return path. Additional setting guidelines for protecting underground cables are provided in [3], [4], [6], [7], and [8].

Protecting underground cables with ground distance relays can be quite challenging and difficult to achieve because of cable electrical characteristics, the influence of grounding methods and return currents in the zero-sequence impedance of the cable, the nonlinear behavior of the compensated ground loop impedance, and the short cable length in many applications. For all these reasons and the complexities involved in calculating the proper settings, most users prefer to protect underground cables in transmission systems using line current differential protection schemes.

6.7 Breaker Pole Scatter

Three-phase power circuit breakers are capable of very fast interrupting times with currents usually extinguished within 30 to 100 ms, depending on design. The basic operational principle of a circuit breaker is to open contacts with enough separation such that the resultant arcing across the parting contacts cannot be sustained within the insulating medium. Current is typically interrupted at or near the next zero crossing after the contact separation needed to prevent arc restrike has been reached.

Since zero crossings will not occur simultaneously, some momentary zero-sequence current may result for fault types that do not normally yield zero-sequence current (i.e., three-phase or phase-to-phase faults). Breaker pole scatter is a term applied to this phenomenon of dissimilar current interrupting times in a three-phase power circuit breaker.

An example of the effect of pole scatter on measured currents is illustrated by the three-phase fault oscillography shown in Figure 61 and the resulting zero-sequence current illustrated in Figure 62. For a balanced three-phase fault, zero crossings are separated by 60 electrical degrees, or one-sixth of a power system cycle. In this case, the last phase will typically interrupt within one-third of a cycle from the initial phase interrupting, so unbalanced (zero-sequence) current exists for one-third of a cycle or about 5.6 ms for a 60 Hz system. However, if current from a faulted phase is delayed in clearing by an additional zero crossing, then the duration of the resulting zero-sequence current can be a total of one-half a power system cycle.

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Figure 61. Simulated current oscillography with typical interruption pattern at zero crossings.

Figure 62. Zero-sequence current resulting from pole scatter during interruption of the currents shown in Figure 61.

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Figure 63. Actual relay event showing zero-sequence current due to normal pole scatter.

In rare instances, it is possible for an instantaneous ground distance element or relay (e.g., Zone 1) on a nearby unfaulted line to misoperate due to the pole scatter of the circuit breaker interrupting the remote fault. Because the unbalance resulting from the fault interruption will typically last no longer than 0.5 cycles, the pickup response delay of most distance relays will provide security against misoperation. However, if the impedance to the fault falls within the reach throughout a longer duration and only the fault identification algorithm within the relay is blocking a trip, it is possible that the momentary occurrence of zero-sequence current could indicate a fault type that allows the ground distance element to trip. Quadrilateral ground distance elements have been known to misoperate due to pole scatter in this manner [9].

<are there any examples of mho elements mis-operating?>

It is unlikely that a protection engineer can predict where pole scatter may cause a relay element to misoperate. Most factors, such as the prefault load, fault location, fault impedance, and likelihood of the breaker to experience longer than normal pole scatter will be random.

[a paragraph on methods of securing relays against pole scatter misoperations here]

6.8 Single-Pole Tripping and Open Pole

Single-pole (single-phase) tripping (SPT) is used to open the faulted phase during a single-line-to-ground fault. SPT improves system stability and maintains power transfer capacity during single-line-to-ground fault conditions by allowing the system to remain interconnected on two phases. SPT tripping on a set of parallel lines causes unbalanced load conditions. Figure 64 below depicts the parallel lines of a real transmission system, where Line 1 is struck by a Phase B single-line-to-ground fault.

Figure 64. Caption

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During the SPT, the load from the faulted phase is transferred from faulted Line 1 to unfaulted parallel Line 2. This condition subjects the relays on the unfaulted Line 2 to zero-sequence and negative-sequence currents while the faulted Line 1 maintains a zero-sequence current.

In Figure 65, the blue signal depicts the faulted Phase B current of the line prefault load of 600 amperes peak.

Figure 65. Caption

Figure 69 depicts the Phase B current of the unfaulted Line 2.

Figure 66. Caption

As shown in Figure 66, the prefault current peak is approximately 750 amperes, while the post-fault current peak is 1,350 amperes.

Figure 67 shows the neutral current of both lines at their respective peak current values.

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Figure 67. Caption

During high-load conditions, it is possible for sensitive long-reaching ground distance elements to pick up during open-phase conditions on the unfaulted Line 2. These elements on Line 2 must be set to be secure from false operations during the dead time of the reclosing relays on the faulted line. This is accomplished by setting the time delay of the extended-zone ground element longer than the reclosing cycle of the faulted line. As shown in Figure 68, the open-phase condition of the faulted line lasts for 1.472 seconds.

Figure 68. Caption

Therefore, a ground distance backup tripping time delay should be set to at least 1.5 seconds.

Why Perform SPT?

According to statistics, most faults on overhead lines are temporary single-phase faults. If breakers with independent pole operation are available, these faults can be cleared automatically by means of single-pole autoreclosure. The advantages of a single-pole autoreclosure compared with a three-pole autoreclosure are:

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During the single-pole interruption, the load flow can be continued via the remaining two phases.

The risk of power swings and out-of-step conditions will be reduced.

The synchronism between the two ends of the faulted line will not get lost during the single-pole-open state. The reclosing can be performed without any check of synchronism.

Challenges of Distance Protection to Select the Right Phase for SPT

To perform SPT, the distance protection must be able to select the faulted phase. A wrong selection of the faulted phase would either lead to a wrong SPT or no SPT being performed.

Faulted phase selection is necessary to prevent distance protection from incorrect operation. Once a fault is detected, the next important step is to find the faulted phase. According to the faulted phase, the right loop for the directional element and the distance element can be selected.

The following example, copied from [10], explains the problem of faulted phase selection. Figure 69 shows the impedances for a Phase-A-to-ground fault (A-G) close to the relay terminal. The left picture shows the impedance of the faulted loop A-G, which is close to the origin of the complex plane. The right picture shows the location of the phase-to-phase impedances for the same fault in the complex plane. Even in the case of the single-phase-to-ground fault A-G, the impedance ZAB is close to Zone 1 of the distance protection. The impedance ZAC is located inside the Zone 1 distance protection.

Figure 69. Impedances for a fault AG close to the relay location.

If the distance protection is not equipped with an advanced loop selection, the condition shown in Figure 69 will result in a three-pole trip of the distance protection because the phase-to-phase impedance ZAC is seen inside the Zone 1 distance protection.

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For conventional relays to avoid the above situation, the phase-to-phase resistive range setting should be evaluated, especially near a strong source area where high phase-to-ground short-circuit current is expected. In this example, the Zone 1 resistive range was reduced to 10.5 ohms. With this new setting, instantaneous Zone 1 phase-to-phase tripping (Phases A to C) will be avoided, as shown in Figure 70.

Figure 70. Impedance trajectories ZAB and ZAC with reduced Zone 1 resistive reach setting.

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Challenges of Stable Distance Protection During the Single-Pole Dead Time

Once SPT is performed, the distance protection must be featured to deal with the special conditions during the single-pole-open state.

Due to the single-pole opening, zero- and negative-sequence voltage and current will appear, even if no evolving fault exists on the line. In cases of heavy load on long lines, this condition can move the impedances of the remaining phases into the zones of distance protection. The distance protection must work in a special mode to avoid unwanted pickup for phase-to-ground loops during a single-pole-open condition.

Figure 71 explains this problem. The figure shows an evolving fault A-G during a single-pole dead time in Phase B. The magnitudes of currents and voltages during the single-pole dead time of Phase B before fault inception at t = 0.00 s (black cursor) are shown in the left part of Figure 71. The right part of Figure 71 shows the corresponding phase-to-ground impedances in the complex plane. The impedance ZCG (blue impedance trajectory, ZL3E) is located in the red marked reverse zone Z3E during the single-pole dead time of Phase B (position of the yellow cursor).

In this case, the distance protection detects the single-pole dead time (see signal “1-pole open” in Figure 71 left) and blocks phase-to-ground loops from wrong pickup even if they are measured to be in the zones of the distance protection. In this case, the signal “Z3:Pickup” in Figure 71 left is inactive even if the impedance ZL3E is measured to be in the red marked zone Z3E.

Figure 71. Impedance trajectories during single-pole dead time of Phase B.

Challenges of Distance Protection for Detecting Evolving Faults During the Single-Pole Dead Time

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Another challenge for the distance protection is to detect evolving faults during the single-pole dead time.

Figure 72 explains this problem. The scenario is the same as shown in Figure 71, an evolving A-G fault during a single-pole dead time in Phase B.

In Figure 72, the yellow and the blue cursor are placed to show the location of the impedances at the evolving fault. The yellow cursor marks the impedance of Phase C to ground, which is located in the reverse zone Z3E. The blue cursor marks the impedance of Phase A to ground, which is located in Z1. The binary signals show that the distance protection only selects the faulted Phase A in this case. The signal “Z3:Pickup” is still inactive even if the impedance of Phase C to ground is located in the reverse zone Z3E.

Figure 72. Impedance trajectories for an evolving fault during single-pole dead time of Phase B.

Detection of a Single-Pole Open State

The detection of a single-pole open state is an important condition for the correct behavior of the distance protection during the single-pole dead time. Different manufacturers implemented different algorithms to detect the single-pole open state based on the following criteria:

Single-pole trip command of the relay.

Auxiliary contacts of the breaker(s).

Currents and voltages of the line.

Care should be taken for the correct setting of the open-pole detection according to the equipment of the bay (breaker arrangement, location of VT).

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6.9 Series-Compensated Lines

Series capacitors are applied to power networks for good reason (e.g., to add to grid capacity without requiring new transmission lines). Unfortunately, at the same time, they introduce phenomena that have a significant impact on the line protection, including the ground distance elements. Such phenomena include voltage inversion, current inversion, low-frequency oscillations, the effect of capacitor bank unbalance due to single-pole tripping, phase-segregated bypass (i.e., the impact on line protection of the series capacitor protection and bypassing mechanisms), and current distortion.

Line protection intelligent electronic devices (IEDs) that include the ability to handle series capacitors are required. It is important to note this requirement on the line protection IEDs is not limited to just those IEDs protecting the line with the series capacitor. It also extends to the adjacent lines and maybe even to the lines adjacent to the adjacent lines because the phenomena introduced by the addition of the series capacitor is not limited to just the line where it is located. The phenomena extend beyond, into the adjacent network. Careful upfront studies need to be performed to determine how far into the network the phenomena introduced by the addition of the series capacitor will be felt. Any existing line protection within this zone of impact will need to be series-compensation-capable and, if not, it will need to be replaced.

Of course, the IEDs on the line with the added series capacitor, or new line with a series capacitor, will require complete settings calculation. But this effort is not limited to just these IEDs, but to all IEDs within the zone of impact. Factors that must be considered and that impact the settings include the size and location (mid-line, end-line) of the capacitor, and for end-line located capacitors, the location of the voltage source for protection measurement (i.e., VT line-side of capacitor or bus-side of capacitor), etc.

Good practice would be to fine-tune the calculated settings, including the ground distance elements, for all IEDs in the zone of impact by testing using a real-time digital simulator before commissioning. Such an effort would be justified on a cost versus reliability comparison.

Reviews of the line protection settings are needed over the life of the series capacitor due to the addition of further series capacitors, or other system changes that would warrant such a review. The performance and reliability of the grid should, and can, remain the same before and after the installation of a series capacitor.

6.10 High-resistance Grounded Systems

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6.11 Inline AutotransformersApplications with an inline autotransformer, such as the 138/161 kV step-up autotransformer depicted in Figure 73 and Figure 74, can present some challenges that must be considered when applying ground distance protection. The distance relay can be connected in various arrangements depending on the availability of CTs and PTs, each presenting unique challenges that should be considered.

CT Connection on the Bus Side and PT Connection on the Line Side of the Autotransformer

As shown in Figure 73, when the distance relay is connected with the CTs on the bus side of the autotransformer and the PTs on the line side, fault current for faults on the line or inside the autotransformer will appear to be a forward-looking fault. However, a fault near the bus terminals appears to the relay as a fault down the line, and a fault on the line side of the autotransformer will appear as a fault directly in front of the autotransformer. This is due to the voltage dropping to 0 V for the line-side fault but being above 0 V for the fault at the bus terminal. If the ground distance element is being used to protect the autotransformer, it must be set to cover the apparent impedance of the autotransformer.

If the CT ratio in the relay is adjusted to reflect the primary currents of the autotransformer where the PT is connected (for example, if the PT is connected to the 161 kV side and the CTs are connected through a 1,200/5 CT on the 138 kV side), the CT ratio should be set at 1,200/5 • 138/161 = 205/1. This will affect the reach of the ground distance elements due to the autotransformer providing a zero-sequence source of current.

Figure 73. Distance relay connected with CTs on the bus side and PTs on the line side of an inline transfomer.

CT Connection on the Line Side and PT Connection on the Bus Side of the Autotransformer

As shown in Figure 74, when the distance relay is connected with the CTs on the line side of the autotransformer and the PTs on the bus side, a fault on the line will appear to the relay as a forward-looking fault and a fault inside the autotransformer will appear as a reverse-looking fault due to the direction of the current flow. Any line faults will have the added impedance of the autotransformer with any close-in faults on the line operating off the origin of the distance element mho plot. For this configuration, since the distance

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element sees autotransformer faults in the reverse direction, a reverse-looking zone will be necessary to protect the autotransformer if the ground distance relay is required to protect the autotransformer.

If the CT ratio in the relay is adjusted to reflect the primary currents of the autotransformer where the PT is connected (for example, if the PT is connected to the 138 kV side and the CTs are connected through a 1,200/5 CT on the 161 kV side), the CT ratio should be set at 1,200/5 • 161/138 = 280/1. This will affect the reach of the ground distance elements due to the autotransformer providing a zero-sequence source of current.

Figure 74. Distance relay connected with PTs on the bus side and CTs on the line side of an inline transfomer.

Considerations for Looking Through an Autotransformer

When both the CT and PT connections are connected on the same side of the autotransformer so the distance relay sees though the autotransformer, whether locally or remotely, various factors should be considered. The autotransformer impedance is measured during transformer testing and can be considered to be more accurate than the line impedance; therefore, while not necessary needed, margins can be adjusted for ground distance zones. Autotransformer impedance can also significantly affect the overall angle of the line and autotransformer series impedance. Distance elements will need to be adjusted to account for the change in the over angle.

Tapped Transformers as Zero-Sequence Sources

Transmission lines can be tapped from transmission lines, and if the transformer is a zero-sequence source, the resulting zero-sequence current infeed must be considered, since it desensitizes the ground distance relays at the main terminals. Winding configurations include two-winding transformers that are wye-grounded primary and delta-connected secondary and three-winding banks that have wye-grounded primary with one of the other two windings delta-connected. Wye-grounded autotransformers with delta-connected tertiaries can also present a problem.

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Figure 75. Load tapped near center of line.

For example, consider the system shown in Figure 75, where the tapped transformer is a ground source. The line from Bus A to Bus B has a positive-sequence impedance of 1481 ohms primary and a zero-sequence impedance of 4776 ohms primary. For a ground fault at Bus B, the ground distance relay at Bus A protecting the line to Bus B sees the quantities listed in Table X with and without the tapped transformer in-service, using the calculated k0 using only the line parameters (14–7). With the tapped ground source connected, the apparent impedance for a ground fault at Bus B is higher than the actual positive-sequence impedance.

It is clear that zero-sequence infeed must be taken into account when setting both Zones 1 and 2. Methods of accomplishing this include modifying the reach of each zone or modifying the k0 factor to include the effect of the tapped ground source.

Reducing the Zone 1 reach by basing it on the actual positive-sequence line impedance with the tapped ground source disconnected means it will underreach when the ground source is connected.

Zone 2 should be based on the largest apparent impedance which results from the tapped ground source that is connected.

As mentioned, it is also possible to modify the k0 factor so that the ground distance reach is some percentage of the positive-sequence line impedance.

Table XTable Title

Tapped Ground Source

Faulted Phase Voltage Bus A (kV)

Angle

Faulted Phase Current (A)

Angle

3I0 (A)

Angle

Apparent Z at Bus A Using Line k0 (ohms primary)

Angle

Connected 40 –1.3 1,972 –82 567 –73 16.5 80

Disconnected 37.6 –0.7 2,050 –82 825 –76 13.9 82

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It is also possible to mitigate this problem by installing an impedance (typically reactance) in the wye-grounded primary. Neutral impedances are not so helpful for autotransformers.

For tapped transformers that are three-winding with wye-grounded primary, wye-grounded primary, and delta-connected tertiary or a wye-grounded autotransformer with delta-connected tertiary, ground distance elements may reach through the tapped transformer to detect secondary ground faults. This is particularly true for long lines that have tapped transformers with a relatively low impedance (large MVA) and located near one of the terminals. Studies should be performed with the remote terminal open and closed; it is more likely to be an issue if the tap is fed radially from the terminal to which it is closest with the remote terminal open. In such cases, it may be necessary to reduce the Zone 1 reach and/or for directional comparison pilot schemes to add some method of blocking the overreaching pilot ground distance zone for ground faults on the low-side secondary of the tapped transformer.

As an example, consider the arrangement in Figure 76 where the tap is 0.38 miles from Bus A, and the line section from the tap to Bus B is 22.22 miles. The tapped transformer bank is a 90 MVA autotransformer. The line from Bus A to Bus B has a positive-sequence impedance of 1880 ohms primary, and a zero-sequence impedance of 5874ohms primary, with a calculated k0 (0.75–8). Assume the Zone 1 ground distance element is set on 90 percent of the positive-sequence line impedance, or 16 ohms primary. With the breaker at the Bus B terminal open, a fault on the low side of the tapped transformer results in the Bus A terminal seeing an apparent impedance of 15 ohms, which would result in a misoperation.

Figure 76. Load tapped near one terminal.

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6.12

7. Setting and Application Guidelines

7.1 Application Guidelines for Ground Mho and Quadrilateral Elements

7.2 Setting Mho and Quad Elements in Direct Tripping (Zone 1, Zone 2)

7.3 Setting Considerations When Applying Ground Distance in Pilot Schemes

The first three zones of ground distance protection (Zones 1 through 3) should be set for high-speed operation—typical detection time is less than one cycle. When pilot tripping (e.g., POTT) is available, Zone 2 and Zone 3 ground elements are used in the permissive tripping logic. The Zone 2 ground element should be set sensitive, with a long overreach, to allow it pick up as rapidly as possible in a POTT scheme. An example of a sensitive setting would be 200 percent of line overreach, and this would require that the Zone 2 trip time to be extended even longer in a back-tripping scheme. Zone 3 is set to reverse and does not trip, Zone 3 sets the POTT transient blocking logic timer. This logic timer blocks echo back if it is enabled and blocks permissive tripping when fault clearing on a parallel line creates a momentary current reversal. Zone 3 must overreach the remote Zone 2. Zone 3 should be set in the reverse direction to pick up instantaneously and should always coordinate to overreach the remote Zone 2 and Zone 4 ground overreaching elements. Zone 4 should be set to overreach the remote bus and set time-delayed tripping element back up tripping scheme. On lines with transfer trip, Zone 4 provides backup—time-delayed tripping similar to a conventional Zone 2 function. If possible, Zone 4 should be coordinated with the remote Zone 1 relays but should not be set to less than 125 percent of line impedance. The time-delayed Zone 2 and Zone 4 elements must coordinate with the remote Zone 1 ground and ground overcurrent elements. The Zone 2 trip time is increased to prevent miscoordination at the remote terminal. If it is not possible to coordinate with relays at the remote terminal, and if 51S1 is the primary ground fault protection element, Z2GT and Z4GT can be removed from the trip equation.

When transfer trip is not available, and ground fault protection at the remote terminal is by directional ground time-overcurrent relays, it may not be possible to coordinate the overreaching ground distance relays with the remote ground overcurrent relays. Typically, only the Zone 1 is ground distance element can be enabled in this case.

Mutual coupling from adjacent or parallel lines can affect the ground distance impedance measurement. For parallel lines, the measurement will usually underreach, but under some conditions, overreaching can occur. This can happen if the parallel line is out of

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service and grounded at both terminals. Be sure that Zone 1 does not overreach the remote terminal. Underreaching can be a problem for Zones 2, 4, and 5. These elements must never underreach the remote terminal.

8. References[1] [1] C. Henville, presentation at the PSRC Working Group D30 meeting. January 2015.[2] [2] B. Jackson, “Zero Sequence Coupling of Parallel Transmission Lines and Effect on Ground Relays,” proceedings of the

65th Georgia Tech Protective Relaying Conference, Atlanta, GA, May 2011.[3] [3] D. Tziouvaras, “Protection of High-Voltage AC Cables,” proceedings of the 32nd Annual Western Protective Relay

Conference, Spokane, WA, October 2005.[4] [4] V. Leitlof[1]f, X. Bourgeat, and G. Duboc, “Setting Constraints for Distance Protection on Underground Lines,”

proceedings of the 7th International Conference on Developments in Power System Protection, Amsterdam, Netherlands, April 2001.

[5] [5] J. Vargas, A. Guzmán, and J. Robles, “Underground/Submarine Cable Protection Using a Negative-Sequence Directional Comparison Scheme,” proceedings of the 26th Annual Western Protective Relay Conference, Spokane, WA, October 1999.

[6] [6] D. Tziouvaras and J. Needs, “Protection of Mixed Overhead and Underground Cable Lines,” proceeding of the 12th IET International Conference on Developments in Power System Protection, (DPSP 2014), Copenhagen, Denmark. March 2014.

[7] [7] D. Tziouvaras, “Calculating Intermediate Faults in Underground Cables,” proceedings of the 39th Annual Western Protective Relay Conference, Spokane, WA, October 2012.

[8] [8] G. Alexander, J. Mooney, and W. Tyska, “Advanced Application Guidelines for Ground Fault Protection,” proceedings of the 28th Annual Western Protective Relay Conference, Spokane, WA, October 2001.

[9] [9] [cite SEL/FP&L paper][10] [10] H. Wihartady and M. Popov, “Determining Arc Parameters in 150 kV System Based on Disturbance Record Data During

Single Open Pole Process,” CIGRE C4 Colloquium on Lightning and Power System, Kuala Lumpur, Malaysia, May 2010.

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