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Distance and Differential Protection Simulation for Transmission Line and Components Using Matlab/Simulink

Zosuliwe P. Ndlondlwana

1

Distance and Differential Protection Simulation for

Power Transmission Line and Components UsingMatlab/Simulink

Prepared for:

K. Awodele

Department of Electrical Engineering

University of Cape Town

Prepared by:


Undergraduate Electrical Engineering

October 2008

This thesis was prepared in partial fulfilment of the requirement for the Bachelor of

Science degree in Electrical Engineering at the University of Cape Town.


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Declaration

I, Zosuliwe P. Ndlondlwana, hereby declare that the work contained in this thesis is my

own and references have been made in acknowledgement of the work of others.

Signature: _____________________

Date: _____________________


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Acknowledgements

“If I have seen further than others, it is by standing on the shoulders of giants.”

-Sir Isaac Newton

I would like to thank the following giants:

• God – for knowing my destiny and implanting potential in me.

• My family, especially my late mother for encouragement. I hope to make you proud.

• My friends – for being there for me and making varsity a wonderful experience.

•

Eskom – for their financial contribution towards my undergraduate studies.• My supervisor Mrs Kehinde Awodele – for the opportunity of increasing my

knowledge and sharing it with my fellow students.


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Terms of Reference

In June 2007, Mrs. K. Awodele proposed a simulation program to demonstrate distance

and differential protection for power system components. The simulation had to use

Matlab/Simulink and would be used by students.

Mrs. Awodele’s instructions were to:

1. Investigate ways of producing the simulations.

2. Write code or have a model simulation for the demonstration.

3. Produce a manual and/or lab sheet to introduce students to the concepts of

distance and differential protection.


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Abstract

Background to the thesis

A need exists in the electrical engineering department, particularly power engineering, to

engage students in more interactive tasks, laboratory exercises and demonstrations, so

as to improve students’ understanding of the fundamental principles of power systems

operation. There already exists a protection simulation panel, constructed in 1995 by C.

Hoyle et al demonstrating OC protection and grading. In 2007, a basic protection panel

was built by Bonga D. Ntshangase demonstrating OC, undervoltage and transformerprotection (oil and gas, and differential protection).

This thesis project arose as a result of the need to display other protection schemes,

namely distance and differential protection.

Probe into practical protection literature

Theoretical models of distance and differential protection are relatively simple. A simple

radial system may use over current relays for protection. However as in practice, power

systems are seldom simple. With an increase in system complexity, over current

protection may be the unviable option especially in terms of coordination. The time delay

for the relay close to the source may become excessively long. The concept of

protective zones thus becomes important. Protection zones can be defined for:

• Generators• Transformers

• Buses

• Transmission and distribution lines

Zones are overlapped, with circuit breakers located in the overlap regions.


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Transmission and distribution lines are commonly protected by impedance relaying.

Each relay is configured to have three elements. The first element (zone 1) is set to a

reach of 80% and operates instantaneously as primary protection to a line. The second

element (zone 2) is set to a 120% reach, operating at typically 0.2 to 0.3 seconds, and

offers backup protection to the line. Zone 3 extends to the next zone and acts as remote

backup protection with a time delay of between 0.6 and 1 second offering secondary

backup to the adjacent line and remote backup the protected line.

Many factors however contribute to the malfunction of distance relays. These include

composite circuit lines, series compensation and the infeed effect. There are various

methods that are practically used to try and mitigate these problems. For composite

lines, an RCL model is used in conjunction with signal processing methods in order to

get the correct reach for the relay. For a thyristor controlled series capacitor (TCSC)

compensated line, Directional comparison blocking (DCB), Permissive overreaching

transfer trip (POTT) and Directional comparison unblocking (DCUB) is used.

Busbars and transformers are protected by means of differential protection. CT’s of the

differential protection may saturate leading to relays tripping. In order to avoid this,

methods such as harmonics-based restraining and third difference function algorithm areemployed. The transformer core itself may become saturated due to magnetic inrush or

overexcitation. This may also destabilize relay discrimination. Several methods for

stabilization are explored, such as harmonic-based methods, flux restraining methods,

compensated differential current and even the use of neural networks.

Generator protection methods investigated include the employment of a wavelet

transform-based partial differential protection scheme, which uses the presence of high

frequency currents generated during internal faults.


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Choice of Simulation

The requirement of this thesis was to use MATLAB/Simulink for the simulation. Several

options were investigated, but the following were the viable options:

• For distance protection, the theoretical model with three zones was used. The

practical methods could not be used due to IEEE restrictions as well as their

complexity given the time frame. A graphical user interface was chosen based

on the fact that uniformity wanted to be achieved with the ProtectionIntro

program. The idea of an interactive program while learning something new was

appealing.

• For differential protection, a compensated-current differential relay was chosen.

This was prompted by the need to introduce something practical, a saturable

transformer. A chance to expand ones knowledge on Simulink as well as expose

other students to it was a good option, while noting the components that Simulink

possesses that could be used.

Simulation scenarios and results

On completion of the coding and modeling phase, the simulations were run.

For the distance protection simulation, four scenarios were investigated.

A 345kV network was chosen. The protected line positive sequence impedance was

8+50i Ω and the adjacent line positive sequence impedance was 5.3+33i. CT and VT

ratios were set as 1500:1 and 3000:1 respectively. It can be assumed that these are

practical values as they were obtained in [1].

Case 1: Normal condition with the correct settings, where relays operate correctly.

Normal current was set at 500A.

Case 2: Steady condition with incorrect settings, where relays malfunction. Fault current

was set at 3000A.


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Case 3: Fault condition with the correct settings, where relays operate correctly. Normal

current was set at 2800A.

Case 4: Fault condition with incorrect settings, where relays malfunction. Fault current

was set at 2000A.

For each case, the program displays the appropriate messages, whether relays trip or

restrain. Where relays operate correctly, the user will know that the entered values and

settings could work. Where relays trip or restrain unnecessarily means that protection is

either too sensitive or insensitive. The user will then have to change the input currents

and/or CT or VT ratios. This demonstration shows how changing settings affect the

impedance diagram.

A real life fault on the Koeberg-Stikland 400kV line was also investigated, using

DigSilent Power Factory software and comparing the results to the proposed simulation.

Positive sequence impedances of the lines were used.

For the differential protection simulation:

A Y-Y 154kV/23kV, 55MVA saturable transformer was used for the case study. Theoffset current was chosen to be 15A, a practical value, while K was set at 0.3. The aim

was to test and observe the effect of transformer core saturation on the conventional

differential relay.

The transformer parameters were set such that R1 = 0.002 p.u, X

1l = 0.08 pu, R

2 =

0.002 p.u, X2l = 0.08 p.u, core-loss resistance (referred to as R m in Simulink) was 500

p.u. These values were the default values in the simulation. However the initial flux was

chosen to be 1.2 p.u, which is a value for high saturation.

Various values for the initial flux could be used, all showing the effect of saturation on

exciting current. It was observed that the higher the level of saturation (initial flux) the

higher the exciting current. The conventional differential relay would trip, whilst the

compensated-current differential relay would restrain for all values of saturation.


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For fault conditions both relays operated correctly.

Conclusions

Based on the results of the final design product, the following conclusions can be made:

1) The objectives were achieved in terms of the fulfillment of the aim. Various

MATLAB/Simulink tools were used. Although more could have been incorporated

into the programs, the foundation was satisfactorily set. A lab sheet will supplement

the simulations where certain concepts need to be demonstrated that the simulation

did not include, such as the effect of an infeed in distance relaying.

2) There was a discrepancy between the DigSilent results and the simulation results in

that the simulation showed some underreaching, diagnosing the fault as zone 2

instead of zone 1. However, incorporating the 3 factor into the currents and

obtaining correlating results with the pair of the simulations suggests that the current

in DigSilent was measured as delta. Hence to obtain the line current required for the

distance protection simulation, the current had to be multiplied by 3 thus having an

input fault line current of 77.121kA.

3) The chosen aspects of simulation were well demonstrated in that:

• For the distance protection simulation:

a) Four different scenarios that a student may encounter have been

investigated, with the program responding accordingly.

b) The simulation demonstrates how communication channels between

relays can isolate a line at both ends.

c) The impedance diagram provides a good visualization for the

protection concept.

• For the differential protection simulation:

a) A concept which may be new to students was introduced together

with the knowledge of how in practice saturation of a transformer core

is a problem to protection, and the solution to that.


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Recommendations

As the outcomes of this thesis were aimed at students and the increase of their

knowledge, the following recommendations can be made:

1) There should be adherence to the program requirements. For the distance

protection simulation, voltages should be line-to-line and current values are

line currents (phase and line currents should be the same, else employ

the 3 factor). Attention should be paid to units, particularly those in per unit

used in the differential protection simulation.

2) Adding some material to the syllabus, such as factors and situations that

affect protection in practice.

3) An investigation into real line data (impedances) and CT and VT ratios should

be made. The simulation just demonstrates the principle behind distance

protection.

4) This thesis is only a foundation on which improvements and adaptations can

be made, hence further research needs to be undertaken, in order to obtain

more ideas in improving learners’ understanding and knowledge.


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Table of Contents

Declaration i

Acknowledgements ii

Terms of Reference iii

Abstract iv

List of Figures xiii

List of Tables xiv

List of Acronyms xv

List of Symbols xvi

Chapter 1 Introduction

1.1 Background to the thesis 1

1.2 Objectives of thesis 2

1.3 Methodology 2

1.4 Scope and limitations of the thesis 2

1.5 Thesis layout 3

Chapter 2 Literature review

2.1 Power system protection philosophy 4

2.2 Overcurrent protection schemes 5

2.3 Line protection using distance relays

2.3.1 Radial system and a line fed from both ends 7

2.3.2 Line with an infeed 13

2.4 Differential protection for generators, buses and transformers 14

Chapter 3 Theory development

3.1 Distance protection

3.1.1 Distributed generation 15

3.1.2 Composite circuits 16

3.1.3 Thyristor Controlled Series Capacitor 17


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3.2 Differential protection

3.2.1 Busbar differential protection 19

3.2.2 Transformer protection 21

3.2.3 Generator protection 23

3.2.4 Transmission line protection 24

Chapter 4 Coding

4.1 Distance protection simulation code

4.1.1 Decision-making process 25

4.1.2 How the simulation works 264.2 Differential protection simulation

4.2.1 Decision-making process 30

4.2.2 How the simulation works 31

Chapter 5 Simulation cases and results


5.1.1 Case 1: Normal condition with correct settings 34

5.1.2 Case 2: Fault condition with correct settings 35

5.1.3 Case 3: Normal scenario with a high steady state current 36

5.1.4 Case 4: Fault scenario with too low a current 37

5.1.5 Koeberg-Stikland 400kV line fault 37


5.2.1 High saturation with no fault 41

5.2.2 High saturation with a fault 43

Chapter 6 Conclusions and recommendations

6.1 Conclusions 45

6.2 Recommendations 46

References 47


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Appendix A: Manual for running demo1.m 48

Appendix B: Exercise sheet for distance protection 49

Appendix C: Manual for running differential.mdl 51

Appendix D: Koeberg-Stikland 400kV line fault report 55


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List of figures

Figure 1: Time-current curve for time delay OC relay 5

Figure 2: Illustration of protective zones 6

Figure 3: R-X diagram for non-directional impedance relay 7

Figure 4: Zone partitioning for distance relaying 8

Figure 5: Impedance relay with directional restraint for CB12 and CB32

respectively 8

Figure 6: Modified impedance relay for CB12 9

Figure 7: Diagram showing connection for single line-to-ground fault and its

equivalent Thevenin network 11

Figure 8: Diagram showing connection for line-to-line fault and its equivalent

Thevenin network 11

Figure 9: Diagram showing connection for double line-to-ground fault and its

equivalent Thevenin network 12

Figure 10: System with an infeed 13

Figure 11: Illustration of differential current protection concept 14

Figure 12: Composite circuit model 16

Figure 13: TCSC module 17

Figure 14: Per phase transformer model 22

Figure 15: Obtaining flux at t0 23

Figure 16: Obtaining magnetizing current 23

Figure 17: Compensated differential current model 32

Figure 18: Normal scenario with correct settings 34

Figure 19: Fault scenario with correct settings 35

Figure 20: Normal scenario with incorrect settings 36

Figure 21: Fault scenario with too low a fault current 37

Figure 22: Single line diagram of affected network 38Figure 23: Setup for compensated-current differential protection on a

saturable transformer 38

Figure 24: Large exciting current in a saturated transformer 39

Figure 25: Differential current in a conventional relay 40

Figure 26: Restraining compensated-current relay 40

Figure 27: Operating conventional differential relay 41


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Figure 28: Operating compensated-current differential relay 42

List of Tables

Table 1: Sequence of events for Koeberg-Stikland fault 38

Table 2: Line data for Koeberg-Stikland line 39


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List of acronyms

OC overcurrent

CT current transformer

VT voltage transformer

DG distributed generation

FIR finite impulse response

TCSC thyristor controlled series capacitor

SSR subsynchronous resonance

TCR thyristor controlled reactor

DCB directional comparison blocking

Transmit a block trip signal by a reverse looking element, with or withoutnon-directional overcurrent start. Trip when blocking signal is notreceived and with supervision from a local terminal forward overreachingelement.

POTT permissive overreaching transfer trip

Transmit from an overreaching element, trip upon receiving permissionwith supervision from a local terminal overreaching element.

DCUB directional comparison unblocking

Send a blocking signal continuously, switch to permission from a forwardoverreaching element. Trip upon receiving permission, or temporarilyafter the loss of reception of the blocking signal, with supervision from alocal terminal forward overreaching element.

UHV ultra high voltage

GUI graphical user interface


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List of Symbols

Z o , Z1 , Z 2 zero-, positive and negative sequence impedance

Z f fault impedance

V f prefault voltage

[I abc ] phase components of the current

[I012

] sequence components of the current

[A] symmetrical components transformation matrix

a phasor a = 1 o120∠

V LN line-to-neutral voltage

I L line current

Z1r , Z

2r , Z

3r zone 1, zone 2 and zone 3 impedance relay settings

Z12

impedance on line 1-2


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1 Introduction

1.1 Background to the thesis

A need exists in the electrical engineering department, particularly power engineering, to

engage students in more interactive tasks, laboratory exercises and demonstrations, so

as to improve students’ understanding of the fundamental principles of power systems

operation. Emphasis of this thesis is placed in the area of power systems protection.

There already exists a protection simulation panel, constructed in 1995 by C. Hoyle et al,

in the Power Engineering Laboratory which demonstrates the operation of over current

(OC) relays. Students are able to configure relay settings to observe grading: the co-

ordination of different relays of a feeder to ensure effective back-up protection, while still

ensuring sensitivity and selectivity. That protection panel, however, is limited as its

functionality only demonstrates one type of protection scheme.

In 2007, a basic protection panel was built by Bonga D. Ntshangase as a thesis project

to solve the problem of limited exposure of students to practical protection practices. The

panel demonstrates OC, under voltage and transformer protection (oil and gas, and

differential protection).

Other protection schemes need to be investigated. This thesis will, in addition to

previous efforts, assist students in enhancing their understanding by taking advantage of

the availability of simulation tools such as MATLAB/Simulink. Students will be able to

simulate fault conditions on components where distance and differential protection is

used, so as to observe the reaction of protection schemes.

1.2 Objectives of the thesis

The objectives of this thesis are to:


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• Demonstrate an understanding of protection systems, particularly distance and

differential protection schemes.

• Provide MATLAB codes and Simulink models for simulation, as well as a

laboratory sheet to be used as a supplement to the simulations.

• Draw conclusions and make recommendations.

1.3 Methodology

To achieve the set objectives, a literature review shall be undertaken to understand the

fundamentals of power system protection. From there the simulation code will be written,having reviewed MATLAB coding literature [12], as well as the Protection Intro

Simulation program.

1.4 Scope and limitations of the thesis

Although the area of power systems protection is investigated, the outcome of this thesis

is limited to the field of distance and differential protection schemes on power system

components. The software to be used is MATLAB/Simulink, as this is coding many

students are familiar with. The practical results were limited due to the lack of test

equipment. Many papers were also inaccessible due to IEEE membership constraints or

had to be purchased. Time also became a constricting factor in providing the

deliverables.

1.5 Thesis layout

Chapter 2: This chapter presents the theoretical literature review.


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Chapter 3: Additional practical approaches to distance and differential protection

problems and their solutions.

Chapter 4: MATLAB coding and the process of obtaining the code is documented in

this chapter.

Chapter 5: Results of the simulations are presented here.

Chapter 6: Interpretation, conclusions and recommendations.

Chapter 1

2 Theory Literature Review


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In order to gain a deeper understanding of this thesis, literature concerning protection

schemes was read and surveyed. This chapter begins with an overview of the protection

philosophy. Various protection schemes are examined, and why they are used. As

previously mentioned, direction is towards distance and differential protection schemes

and their theoretical models.

2.1 Power system protection philosophy

Short circuits or faults in power systems occur as a result of equipment insulation failure

due to system overvoltages, caused by lightning or other natural causes, switching

surges, insulation contamination or simply of mechanical causes. These faults can

damage system components if not quickly removed. The core idea behind protection is

to establish undesirable conditions, and note the difference between permissible and

undesirable conditions. These differences can be sensed by relays. From hereon the

faulted equipment is isolated by means of circuit breakers, while maintaining supply to

as much of the healthy system as possible.

There are certain qualities by which a protection scheme is assessed [1]. These are:

• Reliability: The scheme should operate dependably at all times.

• Selectivity: Unnecessary trips should be avoided, meaning protection should only

operate in fault conditions.

• Speed: In order to minimize damage to components and ensure safety of

personnel, reaction time is critical.

• Economy: Maximum protection should be offered at minimum cost.

• Simplicity: The minimization of protection equipment and circuitry is desirable.

2.2 Overcurrent relay protection schemes

Faults in a system cause a steep increase in current magnitude. When a current

threshold is exceeded, action is initiated by overcurrent relays to clear faults. They are


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often applied to radial systems, where relatively high currents need to be cleared quickly.

Two types of overcurrent relays can be observed, namely:

I. Instantaneous OC relays

These respond to the magnitude of an input current, operating on a trip or block

system. Where the input current is less than the threshold, relay action is

restrained (block), else the relay operates (trip).

II. Time delay OC relays

These relays operate similarly to instantaneous OC relays, but with an intentional

time delay which is dependant on the magnitude of the input current relative to the

pickup or threshold i.e. the larger the input current, the shorter the time delay.

Figure 1 below illustrates this concept.

Figure 29: Time-current curve for time delay OC relay

Overcurrent relays are effective for simple radial systems. As a system becomes more

complex, there are challenges that are prevalent. Co-ordination of time delay OC relays

becomes difficult for radial systems as the time delay for the breaker closest to the

source is very long. The concept of protection zones is thus necessary [1], also for non-

radial configurations. Protection zones can be defined for:


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• Generators

• Transformers

• Buses

• Transmission and distribution lines

Zones are overlapped, with circuit breakers located in the overlap regions.

Figure 30: Illustration of protective zones

2.3 Line protection using distance relays

2.3.1 Radial system and a line fed from both ends


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Distance relays respond to a voltage-to-current ratio. When a three phase fault occurs

on a line, the current increases and the voltage at the bus closest to the fault decreases.

This means the voltage-to-current ratio or impedance decreases. These quantities are

measured by means of current and voltage transformers, also known as instrument

transformers. For a radial system, the relay will operate for impedances less than the

threshold setting i.e. for |Z|


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Figure 32: Zone partitioning for distance relaying

For a system where there is more than one direction for the flow of current, non-

directional relays are inadequate. Directional relays need to be used. There are two

ways of including directional capabilities, namely:

• Using an impedance relay with directional restraint, by adding a directional relay

in series to an impedance relay (figure 5)

• Using a modified impedance relay (mho relay), where the center of the

impedance circle is offset from the origin (figure 6)

Figure 33: Impedance relay with directional restraint for CB12 and CB32 respectively


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Figure 34: Modified impedance relay for CB12

Figure 4 shows a line fed from both ends. CB12 and CB23 detect faults to their right,

while CB32 and CB21 detect faults to their left.

For a fault occurring on line 1-2, CB12 and CB21 should open, while for a fault on line 2-

3 CB23 and CB32 should open. This means that a zone 1 fault for CB12 is a zone 3 fault

for CB32, and a zone 3 fault for CB12 is a zone 1 fault for CB32. Adaptive relaying is

used to achieve the coordination of the opening of circuit breakers. This is achieved by

means of communication channels.

In order to obtain the relay settings for CB12, the secondary impedance viewed by the

relay is calculated using the equation

Z’ = (V LN /VT ratio) / (I L /CT ratio)

= Z / (CT ratio/VT ratio) (1)

From here the zone relay settings were obtained as follows:

Z1r = 0.8 * Z’(line 1-2) (2)

Z2r = 1.2 * Z’ (line 1-2) (3)


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Z3r = 1.0 *Z’(line 1-2) + 1.2 * Z’(line 2-3) (4)

Where Z’(line) is the positive sequence secondary impedance for that line

Distance to the fault was calculated as a percentage of the line using the equation

D = (Z’ * (CT ratio/VT ratio)) / Z(line 1-2)) * 100

A three phase system is normally balanced, and remains symmetrical even after the

occurrence of a three phase fault. However, other types of unsymmetrical faults do

occur, such as single line to ground and double line to ground faults, which make use of

the other sequence components. This also complicates relay settings.

A quick review of sequence networks and fault current calculation:

A three phase network is represented by its sequence networks, which are the positive-,

negative- and zero sequences. These can be used as a powerful tool to determine the

state of a network, particularly during fault conditions.

Since fault current is an important value, the symmetrical components pertaining to

currents will be examined. The relationships among the currents of a balanced system

can be expressed in matrix form as:

[I abc ] = [A][I 012 ] or [I 012 ] = [A]1− [I abc ]

Where [I abc ] are the phase components of the currents i.e. currents in phases a, b and c.

[I012

] are the sequence components of the current.

[A] =

2

2

1

1

111

aa

aa and [A] 1− =3

1

aa

aa2

2

1

1

111

a = 1 o120∠


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Depending on the type of fault that occurs, the sequence networks will vary thus

affecting the current in the system. Z o , Z 1 , Z 2 denote the zero-, positive- and negative

sequence network impedances at the fault location. Z f is the fault impedance, while V f

is the prefault voltage.

Single line-to-ground fault:

Figure 35: Diagram showing connection for single line-to-ground fault and its equivalent Thevenin

network

I b = I c = 0 and I 0 = I1 = I2 = f

f

Z Z Z Z

V

3210

+++

Line-to-line fault:

Figure 36: Diagram showing connection for line-to-line fault and its equivalent Thevenin network


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I a = 0 ; I b = -I c

I1 = -I

2 =

f

f

Z Z Z

V

++21

I0 = o

Double line-to-ground fault:

Figure 37: Diagram showing connection for double line-to-ground fault and its equivalent Thevenin

network

I a = 0

I1 =

)3(||[021 f

f

Z Z Z Z

V

++

I2 = - I

1

++

+

f

f o

Z Z Z

Z Z

3

3

02

I0 = - I

1

++ f Z Z Z

Z

302

2

Three phase fault:

I0 = I

2 = 0 and I

1 =

1 Z

V f


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For simplicity, only bolted three phase faults will be considered in the simulation i.e.

Z f =0. Positive sequence impedance is used, because during a three phase fault, there

is only positive sequence current flowing in the system. The zero and negative sequence

impedances are uncoupled and thus do not contribute to fault current.

The impedance to the fault is then calculated using equation (1) where I L is substituted

with the fault current. It is noted that the relays discussed thus far use line-to-neutral

voltages and line currents. These relays are ground fault relays and respond well to the

aforementioned faults. However, line-to-line faults may occur, hence the need for line-to-

line voltage and current measurements. In practice both ground fault relays and phase

relays are used.

2.3.2 Line with an infeed

The reach of a relay is affected when there is a source of fault current within the

operating zone of the distance relay, for example a line fed from both ends. Figure 10

below shows a phase of a line with an infeed.

Figure 38: System with an infeed

Z apparent = Z12 + Z 24 +12

32

I

I Z

24

Z actual = Z12 + Z 24


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In the case of an infeed, underreaching of the relay occurs. This is called the “infeed

effect”. The apparent primary impedance seen by the relay for CB12 is larger than the

actual impedance, and the effect is worsened by a strong infeed i.e. the larger the infeed

current contribution I32

to fault current, the larger the apparent impedance resulting in

greater underreaching. A fault close to bus 4 might go undetected by CB12, thereby

rendering remote backup for line 2-4 at CB12 ineffective.

2.4 Differential protection for generators, buses and

transformers

The principle of differential protection lies with the comparison of currents on both sides

of the equipment under protection, whether it is a generator, a busbar or transformer.

Under normal conditions or for a fault outside the protected zone, the currents I1 and I

2

are equal hence the secondary currents on the current transformers i1 and i

2 are equal

(figure 11). The relay will operate for an internal fault where the difference between

these currents exceeds a preset value. Although one relay is shown in the diagram,

three differential relays are needed, one on each phase. The operation of any one would

result in the isolation of all three phases.

Figure 39: Illustration of differential current protection concept


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Chapter 2

3 Theory development

The previous chapter provided a basic theoretical principle to distance and differential

protection. Distance relaying in transmission and distribution lines is more favourable

than OC relaying, particularly in non-radial systems, or when the complexity of a system

increases. Differential protection is unit protection used for expensive components suchas transformers, generators, busbars and even transmission lines.

In practice protection schemes are imperfect, but relays should operate as accurately as

possible. Research into the methods used to try and imitate the theoretical model of

distance and differential relays is currently being done. This chapter investigates

practical approaches to problems experienced by current protection schemes. These

methods will be attempted to be incorporated into the simulations where possible.


3.1.1 Distributed Generation

Existing OC and earth fault protection experiences problems, particularly where

distributed generation is connected to the system. Because of varying source impedance

and bidirectional currents, relay selectivity is difficult to obtain. Excessive clearing times

affect the stability of DG. Adaptive distance relaying is thus used as it has shorter fault-

clearing times and is less sensitive to impedance variation [6].


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3.1.2 Composite Circuits

Distance relaying is also commonly used for composite circuit protection. Relay settings

are however complicated by the differing electrical characteristics between cable and

line sections. The model used for relay circuits is the RL model. This model is accurate

when excited by power system frequency voltages and currents i.e. 50Hz. Transmission

lines are also modeled using hyperbolic parameters for higher accuracy. If a wide

frequency range is used, noisy traveling waveforms can be represented, thus slower

operating times or even overreaching is experienced. To remove noise, relays usually

have an internal finite impulse response (FIR) filter, but there is a compromise between

operating time and the effectiveness of the filter. The behaviour of this model is also

different for cable sections.

A new model proposed by [5], suggests the circuit be modeled as a series of RCL

sections as seen in figure 5. Greater reach point accuracy is achieved because of the

more accurate model.

Figure 40: Composite circuit model

The busbar relaying voltage and current signals are applied to the left-hand side of the

circuit model, and then sequentially calculating each section of the model until the reach

point voltage and current values are produced. Digital signal processing techniques are

used.


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3.1.3 Thyristor Controlled Series Capacitor

Transmission lines are compensated by TCSC to increase power transfer capability, limit

short circuit currents, and mitigate subsynchronous resonance (SSR), damp power

oscillations and also to enhance transient stability. This however affects relay operation

because of rapid changes in load currents and line impedances. Forward overreach of

the main compensated line and adjacent lines, as well as reverse overreach of the

adjacent line protection is experienced as a result of this compensation attempting to

suppress overvoltages during faults.

Figure 13 shows a TCSC module. This consists of a series capacitor C in parallel with a

varistor, MOV, and thyristor controlled reactor (TCR), L s . The varistor across the

capacitor prevents high capacitor overvoltages. A circuit breaker is used to bypass the

TCSC module during severe faults or equipment malfunction. The current limiting

inductor L d limits the magnitude and frequency of capacitor current during bypass

mode.

Figure 41: TCSC module

The apparent impedance seen by the relay depends on the TCSC mode of operation,

where Z seen = Z actual + R f + Z TCSC .


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The TCSC module has the following operating modes:

I. Capacitive boost mode without MOV conduction

In this mode, the protection function of the TCSC is not working because the fault

current is low. Overreaching occurs because of the high impedance perceived by

the relay.

II. Capacitive boost mode with MOV conduction

For high fault currents, MOV operates for the suppression of overvoltages across

C. ZTCSC

= TCR||C||MOV in low resistance mode. The relay overreaches but not

to the extent of the previous mode.

III. Blocking mode

Thyristors are kept in a non-conducting state, thus TCSC behaves like a series

capacitor. The relay overreaches, but less than the capacitive boost mode.

IV. Bypass mode

Thyristors are triggered continuously and the TCR branch conducts. TCSC acts

as a parallel combination of the series capacitor with the inductor in the thyristor

branch. Z TCSC is a pure inductance with a small value. The distance relay thus

underreaches slightly.

V. Circuit breaker bypass mode

This mode is only used for backup protection should primary protection fail to

respond in time. The circuit breaker then closes. Z TCSC is approximately zero

because the series inductance is a small value. The relay operates correctly.

The aforementioned over- and underreaching problems can be mitigated by the

modification of:

• Directional comparison blocking (DCB)

• Permissive overreaching transfer trip (POTT)

• Directional comparison unblocking (DCUB)


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These methods can be implemented by using inputs, outputs and trip-logic equations of

numerical relays [7].

3.2 Differential Protection

3.2.1 Busbar differential protection

Saturation of current transformers may cause the malfunction of differential relays,

disabling the discrimination of a protection scheme between internal and external faults.

The operating current threshold is thus set larger than the differential current that arises

from CT saturation. Low internal fault currents however are then undetected. Various

methods of CT saturation detection have been developed namely:

I. Harmonic-based restraining method

This method relies on the idea that relay operation will be inhibited if harmonics

in the differential current are larger than the threshold. Stability for external faults

is ensured at the cost of a time delay on an internal fault, because the DC

component must decay to a low value.

II. First difference function of the current

This method assumes that current immediately collapses to zero when a CT

enters saturation. Problems are encountered when a low value is not obtained.

III. Solid state busbar protection relay

Saturation detection is made possible by the detection of the collapsing of current

to a low value, then shunting the current away from the operating circuit.

However, operating time is delayed.


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IV. Microprocessor-based busbar protection relay including a countermeasure for CT

saturation

The assumption that differential current is approximately between periods

corresponding to CT saturation, is the basis of the wave discriminating element

(WDE). A comparison between the change in differential current to the

restraining current is made, where relay restraint is exercised in the case of the

latter being much larger than the former. The WDE is unable to determine which

CT is saturated and the blocking scheme may delay relay operation.

V. Impedance-based CT saturation detection algorithm

Assuming that current decreases during saturation hence impedance increases,

this method can be employed. Impedance at the relaying point is calculated and

compared with the source impedance. A blocking signal is issued where the

impedance is greater than the source impedance: this corresponds to saturation.

This method however is only valid after fault occurrence where change in

impedance is negligible until saturation starts. It is difficult to detect saturation

when impedance increases significantly after fault occurrence.

A CT saturation detection algorithm based on the third difference function was proposed

by [3]. At the start and end of saturation, the magnitude of the third difference function is

significantly larger than normal or in the period where there is no saturation. The relay

discriminates between internal and external faults by means of a logic system. A

blocking signal is issued during saturation and for one cycle after. For internal faults that

cause saturation the relay operates before activation of the blocking signal.


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3.2.2 Transformer protection

During magnetic inrush or overexcitation, saturation of the transformer core occurs. This

saturation causes a large excitation current to be drawn. Differential relays may perceive

this as a fault, and thus trip unnecessarily. In order to stabilize the relay, various signals

derived from current, voltage and flux are used in different restraining methods mainly:

a) Harmonic-based methods, but delay operating time if harmonics are seen in the

differential operating current. These methods also fail for some modern core

materials, where contrary to the belief that higher second harmonic components are

generated during magnetic inrush than internal faults, the opposite is true: higher

second harmonic components are generated during internal faults than magnetic

inrush for modern core materials.

b) Flux restrained current differential relays: They calculate the core flux using primary

voltage. Where magnetizing current and flux comply with the OC magnetization

curve, relay operation is inhibited. Remanent flux causes a deviation from the

magnetization curve, creating problems.

A method proposed by [4] is the use of a compensated-current differential relay. This

relay derives a modified differential current that compensates for the excitation current.

A conventional differential relay operates as follows:

The differential current is calculated as Id = | I

1 -a I

2|. a = N2 /N1

The restraining current is calculated as Ir =

2

||21 II a+ .

The differential current is set such that I d ≥ I offset + κ I r .

Provision for excitation current is not made in the conventional differential relay.

The compensated-current differential relay operation is as follows, based on the per

phase model in figure 14:


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Figure 42: Per phase transformer model

I d (t) = I 1 (t) - aI 2 (t) - I e (t) (5)

Where

I e (t) = I c (t) + I m (t) (6)

V1(t) = R

1 I

1(t) + L

1ldt

t dI )(1 + e

1(t) (7)

Rearranging this, we obtain e1(t) = V

1(t) - R

1 I

1(t) - L

1ldt

t dI )(1

I c (t) =c R

t e )(1 (8)

Before saturation Id (t) = I

1(t) - aI

2(t) - I

c(t). If the differential current exceeds the

threshold, saturation is detected. This differential current is regarded as the magnetizing

current I m (t), used to estimate λ(t 0 ) from the magnetization curve (figure 15).


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Figure 43: Obtaining flux at t0 Figure 44: Obtaining magnetizing current

The flux can then be obtained by the equation:

λ(t) = ∫ +t

t

t dt t e

0

)()(01

λ (9)

From there the magnetizing current, I m (t), can be obtained from the magnetization curve

as seen in figure 16.

More modern schemes suggest the use of neural network based protection [9].

3.2.3 Generator protection

Wideband signals are produced during a fault in a generator. These signals are often

outside the reception of protection. A wavelet transform-based partial differential

protection scheme is suggested by [11], which uses the presence of high frequency

currents generated during internal faults.


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3.2.4 Transmission line protection

With the increase in voltage and length of power lines, distributed capacitance current

arises particularly in UHV lines. This distributed capacitance current is a major factor

affecting selectivity and sensitivity of current differential protection. Several methods

have been employed to reduce the effects of distributed capacitance, namely:

a) Shunt reactor. This method only partially compensates the power frequency steady

state capacitive current but fails in the event of transient capacitive current.

b) Capacitive current compensation. At present phasor-based algorithms are a good

option but operate slowly during faults.

A capacitive current compensation algorithm which can compensate both transient and

steady capacitive current without the increase in sampling rate or telecommunication

traffic is needed. Time-domain compensation in conjunction with a phaselet algorithm

was proposed by [8]. The calculation is done in the following steps:

1) Sampled data is processed through a low pass filter.

2) The sampled electric quantities, at both terminals of the π model, are converted

to modules using the Karenbauer phase-mode transform.

3) Instantaneous values of compensated capacitive current are calculated in α, β

and ο components.

4) Using KCL, instantaneous line current values are calculated after the capacitive

current is offset by α, β and ο module components.

5) Instantaneous currents in three phases are obtained after compensation, by

taking the inverse Karenbauer phase-mode transformation.

Where transmission lines are tapped, [10] proposes a wavelet transform-based

protection scheme.


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Chapter 4

4 Coding

This chapter contains the design processes of obtaining the code or models used. The

choice of the simulation type is explained. Sections of code are also included. MATLAB

7.0.1 was used.

4.1 Distance protection simulation code

4.1.1 Decision-making process

Type of protection

What MATLABprogramming could beused?

Command line prompt

Simulink

Graphical User Interface

Distance with direction

Why? Learn something new Most interactive Simple and compact Visuals can be added Can be used in conjunction withProtectionIntro


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A GUI (graphical user interface) was chosen as this is the most user interactive and

compact method as compared to command line prompt type programming. Another

reason that prompted the use of a GUI was to create uniformity in terms of the existing

Protection Intro program. This program can be viewed as a “sister program”. This

thought process can be explained in terms of the flowchart above.

Simulink was considered, but found not to be viable due to the unavailability of current

transformers in the toolbox.

There are many ways for determining the distance to the fault under various conditions.

These have been discussed in chapter 3. As time was a limiting factor, distance

protection in a radial system was chosen as the basis for the simulation, assuming the

line is not series compensated or experiences practical problems such as mutual

coupling or high fault resistance. This code demonstrates the theoretical principle of

distance relaying. As was also mentioned in the scope and limitations of the thesis, IEEE

restrictions caused the unavailability of relay settings literature pertaining to a system

with an infeed, but demonstration of the effect of an infeed is included in the laboratory

sheet in Appendix C.

As was previously mentioned, for simplicity and owing to time and membership

constraints, bolted three phase faults will be the basis of the simulation.


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4.1.2 How the simulation works

When a GUI is initiated in MATLAB, a skeleton code M-file is generated automatically

according to the elements that have been placed in the layout editor, of which the

programmer must insert code in the relevant areas to perform the intended functions.

The portion of code demonstrates the function as illustrated in the figure above.

The current entered must be the line current, while the voltage is line-to-line.

%read in user values

handles.normalI = str2num(get(handles.edit6,'String'));

handles.faultI = str2num(get(handles.edit7,'String'));

handles.sys_voltage = str2num(get(handles.edit8,'String'));

handles.impedance_12 = str2num(get(handles.edit9,'String'));

handles.impedance_23 = str2num(get(handles.edit10,'String'));

Start

User InputsSystem voltage (V)Normal current (A)Fault Current (A)Positive sequence lineimpedances (Ω)VT ratioCT ratio

Simulate state(normal/fault)

Return relay settings,impedance to fault and

comments


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temp = get(handles.listbox1,'String');

temp = char(temp(get(handles.listbox1,'Value')));

handles.vtratio = str2num(temp); set(handles.listbox2,'Value',15);

temp = get(handles.listbox2,'String');

temp = char(temp(get(handles.listbox2,'Value')));

handles.ctratio = str2num(temp);

%calculate relay settings according to equations

handles.zprime = (1/handles.vtratio)/(1/handles.ctratio);

handles.zr1 = abs(0.8*(handles.zprime)*(handles.impedance_12));

handles.zra =

(180/pi)*angle(0.8*(handles.zprime)*(handles.impedance_12));

handles.zr2 = abs(1.2*(handles.zprime)*(handles.impedance_12));

handles.zrb =

(180/pi)*angle(1.2*(handles.zprime)*(handles.impedance_12));

handles.zr3 = abs(1*(handles.zprime)*(handles.impedance_12) +

((1.2)*(handles.zprime)*(handles.impedance_23)));

handles.zrc = (180/pi)*angle(1*(handles.zprime)*(handles.impedance_12)

+ ((1.2)*(handles.zprime)*(handles.impedance_23)));

Depending on whether the normal condition or fault condition is chosen, the voltage-to-

current ratio will be calculated.

%calculate impedance for normal condition

handles.impedance =

(handles.sys_voltage/(sqrt(3)*handles.normalI))*handles.zprime;

%calculate impedance for fault condition

handles.impedance =

(handles.sys_voltage/(sqrt(3)*handles.faultI))*handles.zprime;


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The impedance diagram will be plotted with the given information, using this portion of

code below. The relay settings are plotted on the assumption that the relays used are

those with directional restraint.

%plot directional impedance diagram

axes(handles.axes2);

semi_zr1 = handles.zr1*exp(2*i*[1:180]*pi/360);

plot(semi_zr1,'r')

hold on


plot(semi_zr2,'y')

hold on


plot(semi_zr3,'g')

axis('equal')

hold on

plot(handles.impedance,'o')

It should be noted that the code shown here pertains to CB12 in the simulation.

Under normal conditions when the allowable current is flowing in the system, impedance

is high thus protection should not operate, or during fault conditions, impedance is low

and protection should operate. At times the settings entered by the user may cause the

relay to malfunction. Suitable comments are also made for the user to take note of.

if (handles.impedance < handles.zr3)

set(handles.edit14,'String','Protection too sensitive');

set(handles.edit18,'String','Trip');

if handles.impedance > handles.zr3

set(handles.edit14,'String','Protection too insensitive');

set(handles.edit18,'String','No tripping');

The user must then make changes either to the current, CT and/or VT ratios.


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4.2 Differential protection simulation

4.2.1 Decision-making process

Differential protection can be applied to many components such as busbars, generatorsand even transmission lines. The busbar simulation was not viable due to current

transformers not being available on Simulink. Due to the complexity of the methods used

in practice, with time being a constraint, transformer differential protection was chosen

as the basis for this simulation.

In addition to that, this simulation will demonstrate the effect of transformer core

saturation on differential protection which is a phenomenon observed in practice, which

would otherwise cause the malfunction or delay of relay operation.

Type of protection

What MATLABprogramming could be

used?

Command line prompt

Simulink

Differential - transformer

Why? Wanted to implement thecompensated differential current

protection Has most of the tools needed (e.g.saturable transformer) and scopeprobes can be used to view someelements Other methods are dull or notviable Learn something new in additionto GUI’s

Graphical User Interface


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4.2.2 How the model works

Start

User InputsTransformer rating (MVA)Transformer parametersV1(V), R1(pu), X1(pu)V2(V), R2(pu), X2(pu)Core-loss resistance (pu)Initial flux (pu)

a = V2/V1 & k

Run theprogram

Viewdifferential currentsettingconventional diffentialcurrent Idcompensateddifferential current

Observe how transformerdoesn’t trip fromsaturationhow a fault will causedifferential protection toact


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Figure 45: Compensated differential current model

Figure 17 shows the Simulink model for the chosen simulation. All the parts that are

green in colour (a, K and I_offset) are the user inputs, as well as the inputs to the

saturable transformer model, which the user inputs by double clicking the component

and editing the relevant sections as will be explained by the laboratory sheet in Appendix

B. The scopes may also be used to view the state of the system by double clicking on

them.


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Chapter 5

5 Simulation cases and results

Base cases or simulation scenarios were chosen for both the distance and differential

simulations so as to showcase the outcomes of running the programs. A real life fault

scenario was also tested using the program.


A 345kV network was chosen. The protected line positive sequence impedance was

8+50i Ω and the adjacent line positive sequence impedance was 5.3+33i. CT and VT

ratios were set as 1500:1 and 3000:1 respectively. It can be assumed that these are

practical values as they were obtained in [1].

Relays with directional restraint were used as explained in Chapter 2, figure 5.


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5.1.1 Case 1: Normal condition with correct settings


Figure 46: Normal scenario with correct settings

As can be seen from figure 18 above, the impedance marked with an ‘o’ or ‘x’ lies

outside the relay settings, hence no tripping of any relay occurs. The relay settings for

CB12 are returned.


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5.1.2 Case 2: Fault condition with correct settings

Fault current was set at 3000A.

Figure 47: Fault scenario with correct settings

As can be expected, the impedance marked by ‘o’ and ‘x’ falls within the relay settings

zone and thus the relays operate correctly. For CB12 zone 1 on the impedance diagram

is red, zone 2 is yellow and zone 3 is green. The impedance marked with an ‘o’ falls in

zone 3 hence the time delay comment stating that CB12 trips after 1 second. CB12communicates to CB32 to trip. The ‘x’ mark shows the impedance as viewed by CB32.


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5.1.3 Normal scenario with a high steady state current


Figure 48: Normal scenario with incorrect settings

When the steady state current is too high for the settings selected, malfunction of the

relay can occur. Figure 20 shows a comment for CB12 displaying the tripping of a relay

because the settings entered are too sensitive. The user will have to then change eitherthe normal current to a lower value, and/or the CT and VT ratios and re-run the

simulation.


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5.1.4 Fault scenario with too low a fault current

Fault current was set at 2000A.

Figure 49: Fault scenario with too low a fault current

When the situation in figure 21 occurs, the relays do not detect the fault as the settings

are too insensitive. Again, the user will have to reconfigure their settings to obtain the

correct response of the relays during fault conditions.

5.1.5 Koeberg-Stikland 400kV line fault

On 13 October 2008, a fault was registered on the Koeberg-Stikland 400kV line. This

was caused as a result of a sagging line being pulled by a truck.


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Figure 50: Single line diagram of affected network

The network in figure 22 is a 400kV network. The three lines from Koeberg Station are

protected in such a way that should a fault occur, all three phases are isolated by means

of circuit breakers. This was an ideal situation as the distance protection simulation

assumes a three phase fault.

As was mentioned, a fault occurred on the Koeberg-Stikland line, which is the line of

interest. The sequence of events is as follows: (The complete sequence is in Appendix

D)

Table 1: Sequence of events for Koeberg-Stikland fault

TIMESTAMP Parent DESCRIPTION Operation type STATUS

13/10/2008

05:42:47

Stikland S/S Stikland/Koeberg

400kV bkr

Supervisory Tripped

13/10/2008

05:42:48

Koeberg S/S Koeberg/Stikland

400kV bkr

Supervisory Tripped


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From the above table, it can be seen that the fault was a zone 2 fault according to the

Koeberg S/S Koeberg-Stikland breaker relay settings, tripping a second later than its

counterpart.

The distance protection simulation agrees with the sequence of events. It could not be

determined however what the conditions were in terms of fault current and impedance to

the fault, as data was unavailable at the time of this investigation. It was then proposed

to model a fault on the line so as to relate as closely as possible to the actual event.

The line data was obtained from [14] using DigSilent software.

Line Length

km

R1

Ω

X1

Ω

Three phase fault phase

current at 50% of the line kA

Koeberg-Stikland 19.4 0.461 6.172 44.526

Stikland-Muldersvlei 16.3 0.418 5.161 45.68

Table 2: Line data for Koeberg-Stikland line

The data in table 2 was used in the simulation, where Koeberg-Stikland was line 1-2,

while Stikland-Muldersvlei was line 2-3. Normal current was set at 1 704A, which is the

rated current for both lines. Fault current was set at 44 526A which is the fault current for

line 1-2. VT and CT ratios were set at 3000:1 and 1500:5 respectively.

Having run the simulation for both normal and fault conditions, the following results were

obtained:

• The relay did not trip under normal conditions, meaning the program responded

correctly.

• Under fault conditions, the relay operated, but saw the fault as a zone 2 fault with

the distance to the fault from CB12 being 83.83% instead of a zone 1 fault at

50%.

• It was noted that when the input currents were first multiplied by 3 , the program

restrained for normal conditions, and saw the fault as a zone 1 fault at 48.38% of

the line. This value is close to the desired value of 50%.


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A Y-Y 154kV/23kV, 55MVA saturable transformer was used for the case study. The

offset current was chosen to be 15A, a practical value, while K was set at 0.3 [4]. The

aim was to test and observe the effect of transformer core saturation on the conventional

differential relay. Figure 23 shows the simulation window.

The transformer parameters were set such that R1 = 0.002 p.u, X

1l = 0.08 pu, R

2 =

0.002 p.u, X2l = 0.08 p.u, core-loss resistance (referred to as R m in Simulink) was 500

p.u. These values were the default values in the simulation. However the initial flux was

chosen to be 1.2 p.u, which is a value for high saturation.

Figure 51: Setup for compensated-current differential protection on a saturable transformer


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5.2.1 Case 1: High saturation with no fault

As mentioned in Chapter 3, a highly saturated transformer will draw large exciting

current. This fact is illustrated in figure 24, with a maximum at 500A. A conventional

differential relay would malfunction, perceiving this as a fault as seen in figure 24, where

there is an imbalance between primary and secondary current as determined by the

turns ratio.

Figure 52: Large exciting current in a saturated transformer


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Figure 53: Differential current in a conventional relay

The compensated-current differential relay however makes provision for this exciting

current, and thus does not trip on the basis of saturation. This is illustrated in figure 26,

where a 0 value denotes a restraint in relay operation.

Figure 54: Restraining compensated-current relay


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5.2.2 Case 2: High saturation with fault

As can be expected, the conventional relay will operate in fault conditions as seen in

figure 27 below, as there is an extremely large differential current in the order of 60MA.

Figure 55: Operating conventional differential relay


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The compensated-current differential relay also operates during fault conditions as

shown by figure 28, where a value of 1 denotes operation of protection.

Figure 56: Operating compensated-current differential relay


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Chapter 6

6 Conclusions and Recommendations

6.1 Conclusions

The aim of this thesis was to produce distance and differential protection simulations for

transmission lines and components using MATLAB/Simulink. These simulations would

be used for demonstration or laboratory exercises. Based on the results of the final

design product, the following conclusions can be made:

4) The objectives were achieved in terms of the fulfillment of the aim. Various

MATLAB/Simulink tools were used. Although more could have been incorporated

into the programs, the foundation was satisfactorily set. A lab sheet will supplement

the simulations where certain concepts need to be demonstrated that the simulation

did not include, such as the effect of an infeed in distance relaying.

5) There was a discrepancy between the DigSilent results and the simulation results in

that the simulation showed some underreaching. However, incorporating the 3

factor into the currents and obtaining correlating results with the pair of the

simulations suggests that the current in DigSilent was measured as delta. Hence to

obtain the line current required for the distance protection simulation, the current had

to be multiplied by 3 thus having an input fault line current of 77.121kA.

6) The chosen aspects of simulation were well demonstrated in that:

• For the distance protection simulation:

a) Four different scenarios that a student may encounter have been

investigated, with the program responding accordingly.

b) The simulation demonstrates how communication channels between

relays can isolate a line at both ends.


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c) The impedance diagram provides a good visualization for the

protection concept.

• For the differential protection simulation:

a) A concept which may be new to students was introduced together with

the knowledge of how in practice saturation of a transformer core is a

problem to protection, and the solution to that.

6.2 Recommendations

As the outcomes of this thesis were aimed at students and the increase of their

knowledge, the following recommendations can be made:

5) There should be adherence to the program requirements. For the distance

protection simulation, voltages should be line-to-line and current values are

line currents (phase and line currents should be the same, else employ

the 3 factor. Attention should be paid to units, particularly those in per unit

used in the differential protection simulation.

6) Addition of some material to the syllabus, such as factors and situations that

affect protection in practice.

7) An investigation into more real line data (impedances) and CT and VT ratios

should be made. The simulation just demonstrates the principle behind

distance protection.

8) This thesis is only a foundation on which improvements and adaptations can

be made, hence further research needs to be undertaken, in order to obtain

more ideas in improving learners’ understanding and knowledge.


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References:

[1] J. Duncan Glover, Mulukutla S. Sarma & Thomas J. Overbye. Power System

Analysis and Design. Fourth Edition. United States of America: Chris Carson: 492-529.

[2] Prof C.T. Gaunt and A.K. Awodele. EEE4089F Class Notes

[3] Y.C. Kang, S.H. Kang & P.A. Crossley. 2004. Design, evaluation and

implementation of a busbar differential protection relay immune to the effects of current

transformer saturation. IEE Proceedings – Generation, Transmission and Distribution.

151(3)

[4] Y.C. Kang, E.S. Jin, S.H. Kang & P.A. Crossley. 2004. Compensated-current

differential relay for protection of transformers. IEE Proceedings – Generation,

Transmission and Distribution. 151(3)

[5] P.J. Moore, Z.Q. Bo & R.K. Aggarwal. 2005. Digital distance protection for

composite circuit applications. IEE Proceedings – Generation, Transmission and

Distribution. 152(2)

[6] I. Chilvers, N. Jenkins & P. Crossley. 2005. Distance relaying of 11kV circuits to

increase installed capacity of distributed generation. IEE Proceedings – Generation,


[7] T.S. Sidhu & M. Khederzader. 2005. TCSC impact on communication-aided

distance protection schemes and its mitigation. IEE Proceedings – Generation,


[8] Z. Yining & S. Jiale. 2008. Phaselet-based current differential protection scheme

based on transient capacitive current compensation. IET – Generation, Transmission

and Distribution. 2(4): 469-477

[9] M. Tripath, R.P. Maheshwari & H.K. Verma. 2007. Probabilistic neural network-

based protection of power transformer. IET Electr. Power Appl. 1(5): 793-798

[10] B. Bhalja & R.P. Maheshwari. 2008. New differential protection scheme for

tapped transmission line. IET Generation, Transmission and Distribution. 2(2): 271-279

[11] T. NengLing et al. 2004. New generator incomplete differential protection based

on wavelet transform. Electric Power Systems Research . 69: 179-186

[12] Brian D. Hahn. 2002. Essential MATLAB for Scientists and Engineers

[13] Prof. Komla A. Folly. EEE4090F class notes.

[14] Sibulele Dlova. Network Security Engineer. Eskom Distribution, Bellville.


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Appendix A: Manual for running demo1.m

This simulation shows how distance (impedance) relaying works, in terms of zone

partitioning.

2) Start Matlab

3) Click File → Open → Protection folder

4) Open demo.m

5) Click Debug → Run (You might be required to change the directory)

6) Fill in information in the “Input Data” panel only.

7) Click on “Normal condition” or “Fault condition”, whichever you wish to simulate

8) The results to the simulation will be returned on the “Output Data” panel and the

“Impedance diagram” panel.

9) Where the relay trips unnecessarily or does not trip, change the input currents

and/or CT or VT ratios and observe their effect on the impedance diagram.


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Appendix B: Exercise sheet for distance protection

Section A:

Given a 345kV system, with positive sequence impedances for line 1-2 being 8+50i Ω

and line 2-3 being 5.3+33i Ω,

a) Calculate the relay settings for CB12 when the VT ratio is 3000:1 and the CT

ratio is 1500:1

b) If a current of 3000A flows in line 1-2, how does CB12 react?

Answer: This is the same as the simulation and students can check their answers by

running the simulation.

Section B:

CB12’s relay is set to protect line 1-2 and 2-4. Let the line impedances for line 1-2 be

2Ω, line 2-4 is 8Ω. A fault occurs on line 2-4, 1Ω from bus 2.

Given that I_12 = 10.95 A and I_32 = 14.51A:

a) Calculate the apparent impedance seen by the relay at CB12

Answer: Z_apparent = Z_12 + Z_24 + (I_32/I_12)*Z_24

= 2 + 1 + (14.51/10.95)*(1)

= 4.33 Ω


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b) What is the actual impedance?

Answer: Z_actual = Z_12 + Z_24

= 2 + 1

= 3 Ω

c) Does the relay underreach?

Answer: Underreach because the fault will be seen as a zone three fault.

d) What is this event called?

Answer: Infeed effect


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Appendix C: Manual for running differential.mdl

This model demonstrates how saturation of a transformer draws a large exciting current.

A conventional transformer may see this as a fault. It is undesirable for differential relays

to trip in this situation; hence methods in practice have been developed to bypass this.

One of these is a compensated-current differential protection scheme, demonstrated by

this simulation.

Some background on the compensated-current differential relay:

A conventional differential relay operates as follows:

The differential current is calculated as I d = | I 1 -a I 2 |. a = N2 /N1

The restraining current is calculated as I r =2

||21

II a+.

The differential current is set such that I d ≥ I offset + κ I r .

The compensated-current differential relay subtracts the exciting current during

saturation, thus the relay doesn’t trip unnecessarily:

I d (t) = I 1 (t) - aI 2 (t) - I e (t).

Part 1: Simulation without a fault

1) Start Matlab

2) Click File → Open → Differential.mdl

3) If you wish you can modify the model (although typical values are already there,

but you may wish to see them or even modify them). You do this by:

• Double clicking on the AC voltage source and changing the voltage level and

frequency.


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• Double clicking on the saturable transformer and entering the following

information:

Transformer MVA rating and frequency

V1 and V

2

(R1, L

1, R

2, L

2are typical values so perhaps you should not change the

default values)

Rm

and initial flux

Take note of inputs that require per unit values

(You can try v

simulación de 21 y 87l con simulink

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