jalthotage dewadasa thesis.bak

8/12/2019 Jalthotage Dewadasa Thesis.bak

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Protection of distributed generation

interfaced networks

Manjula Dewadasa

B.Sc (Hons) in Electrical Engineering

A Thesis submitted in partial fulfilment of the requirements for

the degree of

Doctor of Philosophy

F lt f B ilt E i t d E i i


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Keywords

Distributed generation, Microgrids, Distributed generator protection, Converter

interfaced distributed generators, Protective relays, Inverse time admittance relay,

Relay coordination, Relay Grading, Islanded operation, Re-synchronisation,

Reclosing, Fold back current control, Fault detection, Fault isolation, Arc extinction,

System restoration.


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Abstract

With the rapid increase in electrical energy demand, power generation in the

form of distributed generation is becoming more important. However, the

connections of distributed generators (DGs) to a distribution network or a microgrid

can create several protection issues. The protection of these networks using

protective devices based only on current is a challenging task due to the change in

fault current levels and fault current direction. The isolation of a faulted segment

from such networks will be difficult if converter interfaced DGs are connected as

these DGs limit their output currents during the fault. Furthermore, if DG sources are

intermittent, the current sensing protective relays are difficult to set since fault

current changes with time depending on the availability of DG sources. The system

restoration after a fault occurs is also a challenging protection issue in a converter

interfaced DG connected distribution network or a microgrid. Usually, all the DGs

will be disconnected immediately after a fault in the network. The safety of

personnel and equipment of the distribution network, reclosing with DGs and arc

extinction are the major reasons for these DG disconnections.

In this thesis, an inverse time admittance (ITA) relay is proposed to protect a

distribution network or a microgrid which has several converter interfaced DG

connections. The ITA relay is capable of detecting faults and isolating a faulted


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to some of the existing protection schemes. The relay performance is evaluated in

different types of distribution networks: radial, the IEEE 34 node test feeder and a

mesh network. The results are validated through PSCAD simulations and MATLAB

calculations. Several experimental tests are carried out to validate the numerical

results in a laboratory test feeder by implementing the ITA relay in LabVIEW.

Furthermore, a novel control strategy based on fold back current control is

proposed for a converter interfaced DG to overcome the problems associated with

the system restoration. The control strategy enables the self extinction of arc if the

fault is a temporary arc fault. This also helps in self system restoration if DG

capacity is sufficient to supply the load. The coordination with reclosers without

disconnecting the DGs from the network is discussed. This results in increased

reliability in the network by reduction of customer outages.


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Table of Contents

List of figures ix

List of tables xiii

List of appendices xv

List of symbols and abbreviations xvii

Chapter 1: Introduction ............................................. 1

1.1 Background .............................................................................................. 1

1.2 Aims and objectives of the thesis ............................................................. 3

1.3 Significance of research ........................................................................... 3

1.4 The original contributions of the research ............................................... 4

1.4.1 A novel relay characteristic for DG connected networks ................. 4

1.4.2 A new DG control strategy for fast system restoration ..................... 4

1.5 Structure of the thesis ............................................................................... 5

Chapter 2: Literature review ..................................... 7

2.1 Introduction .............................................................................................. 7

2.2 Protection issues and solutions ................................................................ 8

2.2.1 Islanding operation and anti-islanding protection ............................. 9

2.2.2 Coordination between protective devices ....................................... 12


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Chapter 3: Protective relay for DG connected

networks ................................................. 27

3.1 Introduction ............................................................................................ 27

3.2 ITA relay characteristics ........................................................................ 28

3.3 ITA relay reach settings ......................................................................... 30

3.4 Different ITA relay elements ................................................................. 34

3.4.1 Earth elements ................................................................................. 34

3.4.2 Phase elements ................................................................................. 34

3.4.3 Directional elements ........................................................................ 35

3.5 Connection of ITA relays to a network .................................................. 35

3.6 Settings of ITA relays to detect resistive faults ..................................... 37

3.6.1 Zone-1 settings ................................................................................ 38

3.6.2 Zone-2 settings ................................................................................ 39

3.6.3 Zone-3 settings ................................................................................ 39

3.7 Practical issues for admittance calculation ............................................ 41

3.8 Summary ................................................................................................ 43

Chapter 4: Evaluation of ITA relay performance . 45

4.1 Introduction ............................................................................................ 45

4.2 Inverse time overcurrent relays .............................................................. 46

4.3 Distance relays ....................................................................................... 48

4.4 ITA relays ............................................................................................... 51

4.5 ITA relay performance ........................................................................... 54


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Chapter 5: Fold back current control and system

restoration .............................................. 79

5.1 Introduction ............................................................................................ 79

5.2 Fold back current control characteristics ............................................... 80

5.2.1 Fold back during contingency ......................................................... 80

5.2.2 Restoration process .......................................................................... 835.2.3 Coordination with reclosers ............................................................ 86

5.2.4 DG protection .................................................................................. 87

5.3 Arc fault model selection for simulation ............................................... 88

5.3.1 Primary arc fault .............................................................................. 89

5.3.2 Secondary arc fault .......................................................................... 90

5.3.3 Arc extinction .................................................................................. 91

5.4 Simulation studies .................................................................................. 91

5.4.1 Results for permanent faults ............................................................ 93

5.4.2 Results for Arc Faults ...................................................................... 97

5.4.3 Auto reclosing ............................................................................... 100

5.5 Summary .............................................................................................. 104

Chapter 6: Experimental results ........................... 105

6.1 Introduction .......................................................................................... 105

6.2 Test feeder arrangement ....................................................................... 105

6.3 Relay performance evaluation ............................................................. 109

6.4 Relay response for different fault locations ......................................... 111


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6.5.2 The effect of fundamental extraction ............................................ 124

6.6 Summary .............................................................................................. 130

Chapter 7: Conclusions and recommendations ... 131

7.1 Conclusions .......................................................................................... 131

7.2 Recommendations for future research ................................................. 134

7.2.1 Consideration of rotary type DGs for protection........................... 134

7.2.2 Fold back type current control for rotary type DGs ...................... 134

7.2.3 The effect of single phase converters ............................................ 134

References 135

Publications arising from the thesis 143

Appendix-A 145

Appendix-B 147Appendix-C 153


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List of Figures

Fig. 2.1 Different types of communication networks (Adapted from [55]) .... 24

Fig. 3.1 A radial distribution feeder ................................................................. 28

Fig. 3.2 The variation of normalised admittance ............................................. 29

Fig. 3.3 Relay tripping characteristic curve ..................................................... 30

Fig. 3.4 A radial distribution feeder with relays .............................................. 31Fig. 3.5 Relay protection zones and relay coordination .................................. 32

Fig. 3.6 Relay settings based on different forward and reverse reach ............. 33

Fig. 3.7 Relay connection diagram to the system ............................................ 36

Fig. 3.8 Process of relay tripping decision making ......................................... 36

Fig. 3.9 Relay tripping characteristics of different zones ................................ 41

Fig. 4.1 A radial distribution feeder with relays .............................................. 47

Fig. 4.2 Inverse time overcurrent relay grading .............................................. 47

Fig. 4.3 MHO relay characteristic ................................................................... 50

Fig. 4.4 MHO relay zone settings and timing diagram ................................... 50

Fig. 4.5 ITA relay grading ............................................................................... 52

Fig. 4.6 Faulted line with a relay ..................................................................... 52

Fig. 4.7 ITA relay characteristic in R-X diagram ............................................ 54

Fig. 4.8 Radial distribution feeder with DGs ................................................... 55

Fig. 4.9 OC and ITA relay grading .................................................................. 57Fig. 4.10 OC and ITA relay response when DG1 is connected ....................... 58

Fig. 4.11 Distance and ITA relay response when DG1 is connected .............. 58

Fig. 4.12 OC and ITA relay time-current characteristic .................................. 59


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Fig. 4.20 Fault current seen by each ITA relay along the feeder ..................... 65

Fig. 4.21 Random load and DG distribution profiles along the feeder............ 66Fig. 4.22 ITA relay response for random load and DG distribution profiles .. 66

Fig. 4.23 IEEE 34 node test feeder with ITA relays ........................................ 67

Fig. 4.24 ITA relay response for SLG fault at node 858 ................................. 69



Fig. 4.27 Mesh network under study ............................................................... 71

Fig. 4.28 Equivalent representation of the faulted network ............................. 74

Fig. 4.29 ITA relay response for different values of fault resistances and DG

currents ............................................................................................ 76

Fig. 5.1 Proposed fold back characteristics ..................................................... 82

Fig. 5.2 System restoration .............................................................................. 85

Fig. 5.3 Simulated radial feeder with DGs ...................................................... 92

Fig. 5.4 Calculated ITA relay response for a three phase fault ....................... 94

Fig. 5.5 DG1 response (a) output voltage (b) output current (c) real poweroutput ................................................................................................. 95

Fig. 5.6 DG1 response (a) output voltage (b) output current (c) real power

output ................................................................................................. 97

Fig. 5.7 System behaviour for an arc fault (a) arc voltage (b) arc current (c) arc

resistance (d) relay response ............................................................... 99

Fig. 5.8 DG1 behaviour for an arc fault (a) output voltage (b) output current 99

Fig. 5.9 DG1 behaviour when downstream relay fails (a) output voltage (b)

output current 100


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Fig. 6.6 Calculated relay response in different zones for bolted faults ......... 111

Fig. 6.7 The variation of voltage and current for SLG faults at BUS-2 ........ 113Fig. 6.8 The variation of voltage and current for SLG faults at BUS-3 ........ 114

Fig. 6.9 The variation of voltage and current for SLG faults at BUS-4 ........ 116

Fig. 6.10 The variation of voltage and current for SLG faults at BUS-5 ...... 117

Fig. 6.11 Voltage and current for a fault at BUS-2 ....................................... 118




Fig. 6.15 Change of parameters during a resistive fault at BUS-2 ................ 122

Fig. 6.16 Test feeder with an infeed .............................................................. 123

Fig. 6.17 Change of parameters for a fault at BUS-2 with fault resistance and

infeed ............................................................................................. 124

Fig. 6.18 A SLG fault at synchronous generator connected feeder ............... 125

Fig. 6.19 Current and voltage during a SLG fault ......................................... 126

Fig. 6.20 Values of relay parameters during a SLG fault .............................. 127Fig. 6.21 Faulted current and voltage during a SLG fault ............................. 128

Fig. 6.22 Values of calculated relay parameters during a SLG fault ............. 129


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List of Tables

Table 3.1 Selection criterion of a directional element ..................................... 35

Table 4.1 System parameters ........................................................................... 55

Table 4.2 OC relay settings ............................................................................. 56

Table 4.3 Zone characteristics of ITA relay .................................................... 56


Table 4.5 ITA relay forward and reverse reach settings .................................. 68


Table 4.7 Zone-3 grading of ITA relays .......................................................... 72

Table 4.8 Fault clearing time of ITA relays .................................................... 73

Table 5.1 Simulated system data ..................................................................... 92

Table 5.2 Arc model parameters ...................................................................... 97

Table 6.1 System parameters of the experimental setup ............................... 108

Table 6.2 Relay reach setting and tripping characteristic in each zone ......... 110

Table 6.3 ITA relay response for faults at BUS-2 ......................................... 113




Table 6.7 ITA relay response for SLG faults with higher source impedance 118

Table 6.8 Relay parameters during a resistive fault ...................................... 121Table 6.9 Change of relay parameters due to fault resistance and infeed ..... 123


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List of principle symbols and abbreviations

A, , k Relay tripping constants

CB Circuit breaker

CT Current transformer

DFT Discrete Fourier transform

DG Distributed generator

FFT Fast Fourier transform

IDG Distributed generator current

Ip Pickup current

IRa, IRb Current in faulted phases A and B

Ir Rated current of converter

ITA Inverse time admittance

lp Primary arc length

ls Secondary arc length

MI Multiple of pickup current

OC Overcurrent

PCC Point of common coupling

R1, R2, R3 Protective relays


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VT Voltage transformer

Ym Measured admittance

Yr Normalised admittance

YRK1 Positive sequence measured admittance

Yt Total admittance

Zdg Source impedance of distributed generator

ZLG Apparent impedance


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Statement of original authorship

The work contained in this thesis has not been previously submitted to meet

requirements for an award at this or any other higher education institution. To the

best of my knowledge and belief, this thesis contains no material previously

published or written by another person except where due reference is made.

Signature:.

Date:.


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Acknowledgements

First and foremost, I would like to convey my sincerest and deepest thanks to

my supervisors, Prof. Gerard Ledwich and Prof. Arindam Ghosh, for their

incomparable guidance and endless encouragement throughout my doctoral research.

It has been a great privilege for me to work under this supervision.

I wish to express my thanks to the Faculty of Built Environment and

Engineering, Queensland University of Technology (QUT) for providing me with

financial support during my research candidature.

I would also like to thank staff in the research portfolio office in QUT for their

generous support and assistance throughout the candidature, and the staff in the

School of Engineering Systems for providing such a helpful environment. Further, I

am thankful to staff in the Power Engineering Group for their valuable advice.

I would like to extend my appreciation to all the technical staff who supported

me during the laboratory experiments. Without this support, experimental work

would not have been successful.

I would further like to thank to all of my friends for sharing valuables ideas, for

supporting me during the experimental work, and for making the research period an

enjoyable one. Also, I am grateful to my parents for encouraging me to pursue higher

studies, and I thank them and my relatives for their constant support.


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Chapter 1: Introduction1.1Background

With the rapid increase in electrical energy demand, power utilities are seeking

for more power generation capacity. However, environmental and right-of-way

concerns make the addition of central generating stations and the erection of power

transmission lines more difficult. Thus, newer technologies based on renewable

energy are becoming more acceptable as alternative energy generators. This

renewable energy push is starting to spread power generation over distribution

networks in the form of distributed generation and will lead to a significant increase

in the penetration level of distributed generation in the near future. It is expected that

20% of power generation will be through renewable sources by the year 2020 [1].

However, by that time, the penetration level of DGs is expected to be higher in many

countries which are seeking accelerated deployment of renewable technologies. The

DGs based on renewable energy sources will help in reducing greenhouse gas


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Chapter 1: Introduction

fully controllable load which at peak hours can even supply power back to the utility

grid. A microgrid can operate in either (utility) grid connected mode or islanded

mode and can seamlessly change between these modes. In an islanded mode, the

DGs connected to the microgrid supply its loads, where a provision for load shedding

exists if the load demand is higher than the total DG generation.

Most of the existing distribution systems are radial where power flows from

substation to the customers in a unidirectional manner. Overcurrent protection is

used for such systems because of its simplicity and low cost [1, 4]. However, once a

DG or a microgrid is connected within the main utility system, this pure radial nature

is lost [2, 5, 6] and the existing protection devices may not respond in the fashion for

which they were initially designed [4]. This change in response may be due to the

change in parameters, such as source impedance, short circuit capacity level and

change of fault currents and fault current directions at various locations.

Solar photovoltaic cells produce power at dc voltage. Similarly, fuel cells and

batteries also produce dc output power. These are then converted into ac voltage

through dc-ac converters. Also, other sources such as wind and microturbines use a

converter stage for grid interconnection. All the converters try to protect themselves

by limiting their output currents. This becomes more crucial during faults. In general,

fault current is usually limited to a value that is twice the converter rated current [7,


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1.2Aims and objectives of the thesisThe main objective of this thesis was to design and develop efficient protection

strategies to achieve the fault detection, faulted segment isolation, system restoration

and reclosing for both grid connected and islanded operations of a microgrid or a

distribution network which mainly consists of current limited DGs. To achieve this

goal, the aims of the research project were identified as:

analysing the protection issues related to a microgrid and a distribution networkin the presence of DGs

determining the applicability of the existing protection strategies determining the new protection strategies that are required to achieve

appropriate fault detection and protection of a network

addressing the protection issues associated with system restoration, arcextinction and reclosing in the presence of converter interfaced DGs in a

network

While the main objective of the thesis was to propose a generic protection

solution for DG connected distribution networks, the focus was limited to converter

interfaced DGs. Moreover, the protection of DG connected distribution networks

without communication was considered for a simple and cost effective solution.

Ch 1 I d i


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minimize the protection issues in implementation with the use of the proposed

strategies.

1.4The original contributions of the researchThe main objective of this research was to propose protection strategies to

incorporate DGs into a micro grid or a distribution network by overcoming the

identified protection issues. The main contributions of this research can be listed as

follows.

1.4.1A novel relay characteristic for DG connected networksAn inverse time admittance (ITA) relay characteristic is proposed to overcome

the deficiencies of the existing overcurrent relays. The ITA relay has the capability

of detecting faults under different fault current levels which is the usual scenario that

can be seen in a distribution network when several DGs are present. These relays can

isolate the faulted segments and allow the unfaulted segments to operate either in

grid connected or islanded mode. Moreover, the relay is capable of providing

adequate protection for the islanded system which has several converter interfaced

DGs.

1.4.2A new DG control strategy for fast system restoration

Ch t 1 I t d ti


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extinction of arc is achieved by reducing the output current of DGs. Furthermore, an

effective method is proposed to coordinate the operations of reclosers and converter

interfaced DGs in a network. The fold back control provides maximum benefits to

customers by reducing outages since the DGs are not disconnected immediately

when there is a fault in the system.

The proposed ITA relay and fold back current control strategy for a converter

interfaced DG provide a complete protection solution for a DG connected network.

The relays detect and isolate faults effectively while the fold back current control

helps in arc extinction, system restoration and recloser coordination with DGs.

1.5Structure of the thesisThis thesis is organised in seven chapters and three appendices. The research

aims and objectives are outlined in Chapter 1. The need and justification for the

research in this field are identified in Chapter 2. In this chapter, a literature review is

carried out to identify the protection issues related to DG connected distribution

networks and microgrids. Moreover, the deficiencies of the existing protection

schemes are identified and some of the already proposed solutions to overcome these

protection issues are analysed.

As a result of identification of the protection issues and the deficiencies of the



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features are then compared with the ITA relays. Different case studies are carried out

to show the efficacy of the ITA relays. Moreover, simulation studies related to the

ITA relays are also presented in this chapter. Applications of ITA relays for both

radial and mesh networks are examined and their limitations are identified.

A fold back current control characteristic for a converter interfaced DG is

proposed in Chapter 5. The protection issues related to the system restoration, arc

extinction and reclosing are also addressed in this chapter. Different case studies of

both permanent and temporary faults were carried out and are presented here to show

the efficacy of proposed fold back converter control.

Chapter 6 presents the hardware results obtained through the experimental

laboratory tests. The ITA relay characteristic is modelled using LabVIEW software

and the relay performance is investigated for different fault locations and different

system configurations.

Conclusions drawn from this research and recommendations for future research

are given in Chapter 7. The list of references and a list of publications arsing from

the thesis are provided at the end of the last chapter. In Appendix-A, different types

of relay elements are discussed, while Appendix-B give a detailed description of the

converter structure and control used in simulation studies. The LabVIEW program

used in ITA relay implementation is presented in Appendix-C.


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Chapter 2: Literature review2.1Introduction

The cost of transmission and distribution is rising with the rapid increases in

the load demand. However, the costs of distribution generation technologies are

falling [2]. So from a costing point of view, it is becoming more worthwhile to

increase the generation at the distribution level by connecting a distributed generator

(DG) to meet the load requirement without expanding the transmission and

distribution infrastructure. In addition, there are several advantages of having DGs;

short construction time, lower capital costs, reduction in gaseous emissions, reduced

transmission power loss since generation is now closer to the load, improving voltage

profile, enhancing reliability and diversification of energy sources [9-11].

A microgrid can be considered as a small grid based on DGs. Generally, the

microgrid consists of renewable energy based DGs and combined heat and power

plants. It can operate either grid connected or islanded mode. Most of the DGs are

Chapter 2: Literature review


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the smallest possible set of faulted lines of the microgrid must be isolated for a fault

within this grid.

However, protection of a distribution network becomes more complicated and

challenging once several DGs are connected (as in a microgrid). In this chapter, the

complications in system protection arising due to the connection of DGs to a

distribution network are discussed. Also some of the already proposed solutions are

mentioned.

2.2Protection issues and solutionsThe present practice is to disconnect the DGs from the network using an

islanding detection method when there is a fault in the system [13, 14]. This is as per

the IEEE recommended practice, standard 1547 [15]. This may work satisfactorily

when the penetration of DGs in a distribution system is low. However, as the

penetration levels increase or in the case of micro or mini-grid, the DGs will be

expected to supply power even when the supply from the utility is lost and the DGs

form a small island. This will prevent unnecessary customer power interruption.

Thus, the benefits of DG installations can be maximized allowing the DGs to operate

in both grid connected and islanded modes of operation, especially when the DG

penetration level is high.



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p w

2.2.1Islanding operation and anti-islanding protectionIslanding occurs when the main supply is disconnected and at least one

generator in the disconnected system continues to operate. If a DG is allowed to

operate in this islanding condition, it will bring benefits to customers by reducing

outages [16]. However, if DGs are not designed to operate in islanded operation, this

can cause a number of safety issues [17]. The point where the islanded system is

created after the disconnection of the utility for a fault cannot be identified exactly.

Therefore at the moment of islanding, the generation and load capacity may not be

equal.

When synchronous generators are present in the islanded region and if loads

are larger than the generation then the generators tend to slow down which can lead

to under frequency tripping of generators. In this case, a load shedding scheme

should be implemented to maintain the stability in the islanded system. On the other

hand if load capacity is less than the generation, generators could experience over

frequency tripping and require a fast governor controller to respond and balance the

power [18]. Thus there is a need to identify the islanding condition in an expanded

islanded system which has the loads beyond the PCC. The type of prime mover and

controller mode (i.e. droop control, constant power, etc) affect the response of the

system at the event of the islanding. These responses have been described according



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p

Power quality may not be guaranteed within the island and there could be abnormal

conditions in voltage and frequency [19, 20]. In the islanded mode, short circuit

levels may drop significantly upon disconnection from the utility [1, 4, 19]. These

factors are the reason why anti-islanding protection is traditionally applied to achieve

the safety of personnel and equipment of the distribution system. Under and over

voltage relays, under and over frequency relays, vector shift and relays for detecting

rate of change of frequency (ROCOF) can be used as devices to detect islanding [10,

19, 21]. The common practice is to disconnect the DGs before the first reclosing

occurs after a fault in the system. Therefore anti-islanding protection devices should

be appropriately coordinated with other protective devices such as reclosers in the

system. From the reliability point of view, applying the anti-islanding protection to a

microgrid is disadvantageous.

An anti-islanding protection relay should detect the islanding condition within

the required time (typically 200 to 400 ms) and should trip all the generators. On the

other hand, it should not trip for small frequency variations in the system. A micro-

processor based line tracking system is suggested for detecting islanding condition of

a hydro power distributed generator (HPDG) using the changes of voltage,

frequency, active power and reactive power [10]. This method can be used to detect

the islanding condition of HPDG quickly and to isolate it from the main grid.



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detection. However, these two relays are operated based on the system frequency.

Reference [21] has proposed a graphical method based on application region of the

frequency relay to determine the islanding requirements without disturbing the

frequency tripping requirements. Further this paper outlines how to coordinate the

operation of the islanding detection relay and standard frequency tripping relay.

Reference [20] also provides a mathematical development to determine the

application region of a frequency relay which satisfies both the islanding detection

and frequency tripping requirements. It has been shown that the frequency relay can

be replaced by an islanding detection vector shift relay if the proper settings are

selected. Similarly, a method is suggested to find out the application region of a

voltage relay to satisfy both the anti-islanding and voltage variation protection in

[22]. After disconnecting the main utility, the loading effect on DG is suddenly

changed. As a result, balance condition of loads and harmonic currents will change.

Therefore Total Harmonic Distortion (THD) of current and voltage unbalance at the

DG terminal have been introduced as two new monitoring parameters to detect the

islanding condition with voltage magnitude in [23]. Test results have shown that this

method can be used efficiently for improved performance.

The DGs are expected to supply either an increase of load at grid connected

operation or emergency loads at the islanding operation. Thus the islanding operation



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from the faulted feeder after the fault occurs and a micro-processor based line

protection relay is used to implement the scheme. However this scheme may increase

the fault clearing time which can affect the dynamic condition of the system. Voltage

and frequency should be maintained in the desired range, in the presence of

disturbances in the islanding system. Control strategies should be implemented

considering over-generated and under-generated islanding conditions [10].

It has been mentioned that the only way to maintain the existing coordination

system in the presence of arbitrary DG penetration level is to disconnect all DGs

instantly in the case of a fault [2]. It would result in the DG disconnection for a

temporary fault as well. Therefore it is clear that new protection strategies are

required to investigate with the DG penetration to the utility. In addition, if the DG is

not disconnected from the system at the event of a fault, the fault arc would not

extinguish during an automatic recloser open time, since the source feeding the fault

still remains. Thus a compromise solution between islanding operation and anti-

islanding protection needs to evolve.

2.2.2Coordination between protective devicesThe coordination of protective devices based on current is relatively easy when

the distribution network is radial. However, with the connection of microgrids or

DGs to the utility the radial nature no longer exists and it permits the power flow to



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implemented fast enough to prevent personal hazards and equipment damage [25].

Generally, the protection of the distribution network is done using the current

measurement based on the coordination of fuses, overcurrent relays, reclosers and

sectionalisers [26]. It should consist of a primary and backup protection system

which has proper time grading between each devices. As an example, tripping time

increases towards the main utility source from the fault location and operation device

sequences for a fault in a DG may be the first low voltage breaker, then the fuse,

after that the line recloser, finally if fault still exits it should be cleared by the

substation circuit breaker.

The coordination based on the current is relatively easy in the unidirectional

power flow networks, because the fault current reduces along the feeder [26].

However, with the growth of distributed generators, the system permits the power

flow to be bi-directional rather than uni-directional [5, 27]. This may create a number

of feeder protection issues. It causes relays to under-reach or over-reach [28]. The

DG location in the distribution network influences the relay reach to reduce or

increase. It has been shown that the reach of an overcurrent relay will reduce in the

presence of a DG [29]. Among the protective devices currently used, reclosers and

fuses usually do not have the directional sensing feature but a relay can easily be

made to have that feature [2]. In addition to that, the DG can contribute by suppling



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An adaptive protection method is proposed for the distribution system with

high DG penetration level in [2]. In this approach, several zones are formed with a

reasonable balance of loads and DGs. Each breaker and recloser should have

communication capability and each individual zone breaker should be available to

check the synchronization function. At the beginning, load flow and short circuit

analysis for all types of faults need to be carried out. After the changes of system

configuration due to the loads or DGs , the load flow and short circuit analysis again

have to be repeated. This will not be feasible when a larger number of plug and play

DGs is connected /disconnected. Moreover, this adaptive method is complex as it is

not easy to define zones with the fluctuation of loads and DG generation. However,

protection is independent of DG size and location. The impact of DG capacity on

relay operation and coordination in a radial distribution system has been studied in

[31]. It has been shown that for a downstream fault from the connection point of a

DG, the relay selectivity remains unchanged and sensitivity improves due to the

increase in fault current. But there is a maximum capacity for the DG to keep the

relay coordination. Further a method was suggested to find out the maximum value

for the DG capacity. On the other hand for an upstream fault from the DG connection

point, it has been shown that the misoperation can occur for a low capacity DG.

Problems of protective devices coordination in a distribution network have



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around 80% of the total faults in the distribution system, are temporary. Therefore

protective devices coordination should be done in an appropriate way when recloser

and fuse are present in a distribution system. Moreover the recloser should operate

fast enough to give a chance to clear the fault before the fuse [2, 5]. To achieve this

fast characteristic, the recloser should lie below the MM curve of the fuse. The fuse

should only operate for a permanent fault. This operation is obtained if the slow

characteristic of recloser lies above the TC curve of the fuse within the considered

minimum and maximum fault currents region. If DG is connected upstream to a

recloser, the fault current seen by the recloser and further downstream fuses will

increase. As a result the required margin between the fast characteristic of recloser

and minimum melting curve will tend to reduce. Thus there is a probability of losing

the coordination with any fuse further down to the recloser [32]. On the other hand, if

a DG is connected between a recloser and a fuse, the fault current seen by a fuse

increases and this may cause it to lose coordination. Before the DG connection, the

recloser and fuse see the same fault current. However, after the connection, the fuse

will see more current than the recloser and it responds before the recloser in the event

of a fault downstream to the fuse location. The effect on coordination increases with

DG capacity. Studies in [33] have shown that traditional reclosers are unable to keep

the coordination with fuses in the presence of high DG penetration. Further this



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protection and in transmission as backup protection [34]. There are several types of

overcurrent relays available to select from depending on the application.

Instantaneous overcurrent relays are mostly used to protect sub-transmission lines

while definite time relays are used in ungrounded or high impedance grounded

systems. Moreover inverse time relays can easily coordinate with other protective

devices and they are usually employed to protect distribution networks. A software

model of a inverse time overcurrent relay has been developed to simulate in PSCAD

[34].

High backup time for the minimum fault currents is a disadvantage of

overcurrent relays. A method which proposes to find the time element function for an

overcurrent relay to reduce the back-up time to a constant value independent of the

fault current magnitude rather than in the conventional overcurrent relay is given in

[35]. References [36] and [37] present the IEEE standard analytical equation for the

different types of overcurrent relays (i.e. moderately inverse, very inverse, and

extremely inverse) and operating and reset characteristics that can be taken for

coordination purposes. Relays employed in the radial networks have both inverse

time and instantaneous elements to achieve a quick response for the severe faults as

well as the coordination among relays [26].

Also in the case of the islanded microgrid, the ratio between the source



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elements to achieve high speed fault clearing [38]. Reference [39] shows a method

to calculate directional overcurrent relays setting for both grid connected and

microgrid which consists of synchronous generator based DGs. In this method, the

Particle Swarm Optimization algorithm is used in the relay coordination problem to

obtain the optimal settings for the directional overcurrent relays while maintaining

the minimum operating time and coordination among relays. It has been shown that

it is not possible to calculate a setting time for the relays in both the grid connected

and islanded modes of operation. Hence a central control protection unit is required

to change the setting according to the system configuration. However fault current

seen by each device may change according to the location of microgrid connected to

the utility and fault location. Hence attention to coordinate protective devices is

essential.

There are numerous papers which address the coordination issues with the

presence of DGs in the distribution network. However, so far there is little attention

to the coordination analysis of the current limited converter interfaced DGs.

2.2.3Protection in the presence of current limited convertersThe fault current may change due to the presence of DGs in the network [2, 16,

19, 39, 40]. Its impact depends on the size, type, number of the DG, location of the

DG [5 31] Basically three types of DGs exist with different properties; synchronous



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are studied in [40] considering the sensitive equipment response. Fault current

behaviour and fault detection in a distribution network for different types of faults in

the presence of an induction generator has been studied in [4]. The system which is

not designed with DGs may not work properly with existing protective devices once

several DGs are connected to the system [6]. In the presence of a generator within

the network, the fault current detected by a protective device located at the beginning

of the feeder can be reduced due to the rise of voltage drop over the feeder section

between the generator and the fault [4]. Therefore the faults previously cleared in a

very short time may now require a significant time to clear.

Most of the distribution resources in the microgrid are connected through the

power electronic converters [12]. For example, the dc power is generated by using

the sources such as fuel cell, micro turbine, or a photovoltaic and converters are

utilised to alter the dc power into ac power. These converter interface generators

supplies the currents not much greater than the nominal load currents [26]. Basically

the controller of the converter mainly consists of two control schemes named voltage

control and current control and it regulates the output active and reactive power [42].

In the voltage control mode, the converter produces a three phase balanced ac

voltage at the terminal. The current control scheme, which is explained in [42], uses

two control loops, an inner loop for the current output and outer loop for the power



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protecting a converter dominated microgrid is a challenging technical issue under the

current limited environment [25]. Moreover there is a requirement to find other

protection techniques to solve this problem [7, 26, 27]. One possible approach which

facilitates using the existing overcurrent protection is up-rating of converters to

supply the required fault current. However this will be a costly process. Another

approach that is proposed to overcome this problem is to use a flywheel energy

storage system to obtain the necessary fault current in the event of a fault [44]. The

flywheel supplies the required fault current to operate the overcurrent protective

devices in the islanding operation.

A stand-alone three phase four leg voltage source converter model has been

studied to observe the fault behaviour of an islanded microgrid for different types of

faults in [7]. During a fault, the converter works as a constant current source

supplying the positive sequence current to the system. There are no active sources in

the negative or zero sequence networks. So it has been shown that the microgrid is

equivalent to a current source with parallel impedance which depends on the fault

type. In this converter topology, large voltages can be seen in healthy phases for

unbalanced faults. In [25], fault behaviour in a converter supplied microgrid has been

presented considering different types of converter topologies and microgrid earthing

systems. The paper concludes that the fault response strongly depends on the



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proposes an adaptive overcurrent scheme which selects the lower current threshold to

operate the overcurrent device based on the value of voltage detection. In reference

[45], abc-dq transformation of the voltage waveforms is used to identify if the short

circuit condition is inside or outside a set zone in a microgrid. Voltage disturbance at

each relay location is calculated by comparing the reference value with the obtained

dc values in the d-q synchronous rotating frame. The tripping decision is made by

selecting the location which has the highest mean average disturbance value with the

help of a communication link among relays.

A differential relay based protection scheme is proposed to protect a microgrid

in either grid connected or islanded mode in [16]. In this, a central control unit is

used to make decisions on control and protection devices. Line parameters of the two

ends of a protected line have to be monitored by means of a wire connection if the

line is short or by a pilot wire communication if the line is long. The need for

communication channel is a disadvantage of the differential protection scheme.

Moreover, the response of DGs places between two relays will affect their

performance. Another approach for the protection of microgrid with converters in

both islanded and grid connected operation is presented in [8]. A static switch has

been designed to open the microgrid for all types of faults and faults should be

cleared using techniques which do not rely on high fault currents within the



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minimum pickup current of the relay is update depending on the fault type and

location. Further, the response of an converter interfaced fuel cell under a fault

conditions has been investigated and it has been shown that the fault will cause the

voltage to drop below to a value such that the undervoltage relay would operate to

trip the DG if the fault occurs near the DG. Therefore undervoltage relay can be used

under a fault condition to determine the status of the DG. Furthermore, IEEE

standard 929-2000 states that converters will sense a short circuit by voltage drop

rather than sensing the short circuit current. Another option is to design the

protective devices to operate for small fault currents. However, this may cause

nuisance tripping [16, 19, 46]. Thus there is a need to assure that for both the

microgrid itself and for the grid connected modes, the protection system is operating

in an adequate fast, selective and reliable way to clear the faults [39].

2.2.4Reclosing, re-synchronization and arc faultsMost of the faults (around 90%) in the power system are temporary arc faults

(such as insulator failures, conductors clashing due to strong wind, animal contacts,

lightning strikes, etc). These faults can be successfully cleared by de-energizing the

line long enough such that the arc self extinguishes. Usually reclosers which open

and close a few times successively are used to clear such faults without any large

scale power interruption [47] Maximum dead time of single phase reclosing in



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based on artificial neural network algorithms to solve this problem by analysing the

voltage of the open phase conductor during the recloser dead time interval [47].

Usually three phase reclosers are used in distribution networks. In a DG or

microgrid connected distribution network, the reclosing should be done with proper

synchronization since this will join two live systems. The maximum time available

for automatic reclosing without losing synchronism should be considered. During the

auto recloser open time, if the island and main grid undergo a phase mismatch, then

it may lead to damage to the equipment and DGs in the microgrid [5]. However, if

the DG is connected using a converter, the risk of damage to the DG is low as it has

its own protection [49]. Dead line voltage relay and sync-check relay can be used to

prevent out of phase reclosing [19]. In general, a DG is disconnected before the first

reclosing occurs in the system. This requires that any anti-islanding protection should

operate very quickly. As a result, the recloser should coordinate with the anti-

islanding protection, which is a challenging task [19]. A communication link can be

established between the line recloser and the DG to transfer trip signal to disconnect

the DG quickly [50]. An automatic synchronizing or synchronism check relay should

be used at the PCC breaker when restoring the system after disconnection [18]. Re-

synchronizing can be done manually or automatically using synchronism check relay

with a synchronous generator based DG. However for a converter interfaced DG,



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rate after successful arc extinction at the current zero crossing [51]. Also the arc

extinction time is proportional to the arc time constant [52]. On the other hand, the

fault current magnitude of an arc fault is limited by the arc resistance. Sometimes it

results in difficulties of detecting the fault [53]. Moreover, the arc voltage at the fault

point is a source of errors in the fault locating process [54]. Therefore protection of

distribution network and restoration under arc fault is a challenging task.

2.2.5Communication based protectionThe distribution system protection will be complicated when the DGs are

spread throughout the network. As a result new protection issues will arise for the

traditional distribution networks. To address some of the issues, a protection based

on a communication medium has been developed. Communication media including

power line carrier (PLC), microwave and optical fibre have long been used for the

transmission line applications. However, in nature, the distribution lines are different

from transmission lines. These lines are shorter and they have numerous tapped

loads. Therefore a particular communication method for a distribution system

protection should be fast and reliable. Basically three types of communication

networks can be identified as shown in the Fig. 2.1 [55]. In centralised networks, all

nodes are connected to a central point, which is the acting agent for all

communications A network distributed across many nodes rather than centralized



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Fig. 2.1 Different types of communication networks (Adapted from [55])

The installation of a larger number of DGs can cause the loss of protection

selectivity. Communication media may be the internet, PLC, wireless

communication, etc. In [56], PLC based methods are proposed for the coordination

of voltage control, islanding detection for a DG and controlling the interface devices

at the PCC. The Islanding detection method is introduced to minimize the problems

of traditional methods based on frequency and voltage measurements. High

attenuation levels can be expected in distribution lines when their structure is

complex and lines are long. To avoid such problems, repeaters need to be installed in

this implementation. Application considerations of internet as the real time

communication medium for providing the loss of mains protection of a DG has been

studied in [55].

The distribution system becomes a multi-source when one after another DG

gets connected at different locations. This change in system configuration will cause



49/179

agent approach based on communication is proposed in [17] to provide protection of

the power system and coordination between the protective devices in the presence of

DGs. A new method is proposed in [13] based on analysing the sign of wavelet

coefficients of the fault current transient to locate and isolate a faulted segment. In

this, relay agents are proposed to implant the proposed protection scheme. A fault

location and fault isolation technique of a DG connected distribution network using

neural networks is presented in [59]. In this, the system has different zones and the

relay at substation communicates with zone breakers to take appropriate actions.

With the use of communication, relay coordination has the ability to rapidly

select the faulted region. However, installation of extensive communication will

require time. Once the power system is smart grid ready, various smart relays can be

installed. Till that time, protection without any or low levels of communication will

be the most cost effective solution.

2.3SummaryIn this chapter, a brief summary is presented based on the review of the

previous published research work on the protection issues which arise after the

connections of DGs and microgrids to distribution networks. There are several

benefits available for both the network operator and customer by utilising DGs or



50/179

The proposed protection scheme should isolate the faulted segment as quickly

as possible from the network. The DGs can then supply the power to unfaulted

segments in the network if they have been designed to operate in islanded mode. To

achieve that solution, several protection solutions have been proposed based on

communication for DG connected networks. However, most of them need reliable

communication medium for fast operation.

Most of the time, current sensing protective devices have been used to detect

the faults in the network. However, with the high penetration level of converter based

DGs, protection of the system has been identified as a key challenging issue.

Although different solutions have been proposed to solve this problem, further

studies are still required to identify and improve the efficient fault detection methods.

In the near future, when more DGs come into operation, protection will be a

challenging task due to the network complexity.


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Chapter 3: Protective relay for DG connectednetworks

3.1IntroductionIn a high penetrative DG network, a small possible portion should be isolated

during a fault allowing unfaulted segments to operate in either grid connected or

islanded mode to increase the system reliability by maximizing the DG benefits. To

achieve the faulted segment isolation, both upstream and downstream protective

devices should detect and isolate the fault. However, with the connection of DGs to a

distribution network or within a microgrid, fault current level can vary depending on

the DG connectivity, DG type and DG location. It results in difficulty of coordinating

existing overcurrent protective devices since network configuration changes.

Moreover, settings of these overcurrent relays to incorporate DGs are not possible if

DG power output changes with time or their connectivity is not consistent.

Furthermore, protection will be a challenging task when using converter

Chapter 3: Protective relay for DG connected networks

l I Ti Ad itt (ITA) t ti l i d b d th


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novel Inverse Time Admittance (ITA) protective relay is proposed based on the

measured admittance of the protected line to avoid deficiencies of existing protection

schemes. The fundamentals of ITA relays are explained in this chapter.

3.2ITA relay characteristicsA radial distribution feeder as shown in Fig. 3.1 is considered to explain the

ITA relay characteristics. It is assumed that the relay is located at nodeRand node K

is an arbitrary point on the feeder. The total admittance of the protected line segment

is denoted by Yt while the measured admittance between the nodes R and K is

denoted by Ym. Then the normalised admittance (Yr) can be defined in terms of Ytand

Ymas

t

mr

Y

YY = (3.1)

Fig. 3.1 A radial distribution feeder

The variation of normalised admittance along a radial feeder is shown in Fig.

3.2 by assuming the feeder has a length of 3000m while the total feeder impedance is



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Fig. 3.2 The variation of normalised admittance

The change of normalised admittance along the feeder is used to obtain an

inverse time tripping characteristic for the relay. The general form for the inverse

time characteristic of the relay can be expressed as

k

Y

At

r

p +

=

1

(3.2)

whereA, and kare constants, while the tripping time is denoted by tp. The values

for these constants can be selected based on the relay location in a feeder and the

protection requirements. The shape of the proposed inverse time tripping

characteristic can be changed by varying the constants to obtain the required fault

clearing time. When a network consists of different types of protective devices, these


tripping time for a fault near to the relay On the other hand higher fault clearing


54/179

tripping time for a fault near to the relay. On the other hand, higher fault clearing

time can be obtained when the fault is further away from the relay location.

Fig. 3.3 Relay tripping characteristic curve

It is to be noted that the normalized admittance in (3.2) should be greater than

1.0 for relay tripping. This implies that the measured admittance is greater than the

total admittance as shown in (3.3). This constraint is used by the relay algorithm to

detect a faulted condition in the network. Moreover, the relay algorithm checks this

constraint continuously during the faulted condition until relay issues the trip

command to avoid any unnecessary tripping due to the effect of transients. The

tripping time is decided depending on the calculated value of measured admittance.

Y


to generate a number of required zones of protection In each zone the relay has a


55/179

to generate a number of required zones of protection. In each zone, the relay has a

unique tripping characteristic. It checks whether the measured admittance is greater

than the total admittance of that particular zone before starting the relay tripping time

calculation. A large coverage and minimum tripping time can be achieved by

increasing the number of zones. It also leads to a good coordination amongst the

relays in a feeder. Any upstream relay always provides the back up protection for the

immediate downstream relay in the feeder.

The radial feeder shown in Fig. 3.4 is considered to explain the relay reach

settings. The relays are located at BUS-1, BUS-2 and BUS-3. It is assumed that each

relay has two zones of protection. Zone-1 of each relay is selected to cover the whole

line segment between two adjacent relays, while Zone-2 is selected to cover twice

the length of the first line segment. The reach setting is set based on the positive

sequence admittance of the considered line segments. Zone-1 and Zone-2 tripping

characteristics are the same for all the relays. For example, relay tripping

characteristic curves for two adjacent relays R1and R2are illustrated in Fig. 3.5. The

locations of relays R1and R2and the tripping time of these relays against the distance

to the fault from the relay locations are shown in the figure. Each zone has different

values for the constants in (3.2) resulting different relay tripping characteristic

curves. It can be seen from Fig. 3.5, Zone-2 of R1will provide a backup for the relay



56/179

Fig. 3.5 Relay protection zones and relay coordination

The proposed new relay does have the ability to isolate the faults occurring at

either side of the relay in a radial feeder. This is because the absolute value is taken

into consideration in admittance normalizing process. However, for the relay to

operate for reverse faults there must be an infeed that is located downstream from the

relay. If the distribution network consists of these relays located at equal distances,

the same forward and reverse reach can be used to isolate forward and reverse faults.

The value for the reach of a particular zone should be selected according to the

requirement.

However, the reach setting should be different for forward and reverse faults,

when the relays are not placed equidistant from one another. In this case, each relay


relays are not equal. To accomplish forward and reverse reach in relays, the relay


57/179

y q p y , y

should sense the fault direction. Moreover, the relay has the capability to identify

whether the fault is in the forward or reverse direction. Any method which will

determine the fault direction can be used for this purpose.

One possibility is to measure the relative difference of angle between the

current and bus voltage. The fault current lags the bus voltage for a forward fault

while for a reverse fault the fault current leads the bus voltage. In [60], relative phase

angle between fault current and pre-fault voltage is used to determine the fault

direction. Another possibility is to calculate the negative sequence impedance seen

by the relay. Based on the calculated value, the relay identifies the fault direction to

select the appropriate reach setting. This approach is only valid if the fault is

unsymmetrical since negative sequence will not be present for symmetrical faults.

The negative sequence impedance is always positive for the reverse faults and it is

negative for the forward faults [61]. The positive sequence directional element

proposed in [62] can be also used to identify the fault direction. After identifying the

fault direction, the process of tripping time calculation can be implemented as shown

in Fig. 3.6.


3.4Different ITA relay elements


58/179

y

The ITA relay has different types of protection elements to detect different

faults. All elements are designed to operate based on measured admittance of the

protected line. These elements are explained below.

3.4.1Earth elementsThese elements will respond for the line to ground faults. The number of

elements varies depending on whether protection has been configured as directional

or non-directional. If protection is directional, then there are two independent earth

elements per phase. The positive sequence measured admittance; YRK1 seen by this

relay element is given by (3.4). The derivation of this formula is given in Appendix-

A.

Ra

RK

RK

RaR

RKV

Y

YI

aI

Y

+

=

10

1

01

(3.4)

where IRa is the rms line fault current through the relay while IRa0 is the zero

sequence fault current seen by relay and VRa is the faulted phase rms voltage. The

line parameters are used to calculate the ratio of YRK1/ YRK0. The relay reach is set

based on the positive sequence admittance of the protected line segment. This relay


example, for phase A, two phase elements are employed, if protection is non-


59/179

directional, one for the faults between phase A and phase B and another for the faults

between phase A and phase C. Measured admittance seen by a phase element for a

line to line fault, between phase A and phase B, can be expressed as,

RbRa

RbRRK

VV

IaIY

=1 (3.5)

whereIRaandIRbare rms phase currents in faulted phases and VRaand VRbare faulted

phase rms voltages. This measured admittance in (3.5) is used by relay logic to detect

a line to line fault in the network.

3.4.3Directional elementsThe directional elements can be used to identify whether the fault is in forward

or reverse direction from the relay. This will help to implement separate reach

settings for each direction especially when a relay protects non-equidistant zones.

The user has been given the facility to select the preference as listed in Table 3.1.

Table 3.1 Selection criterion of a directional element

Setting Operation

Directional Each element has two settings to cover both forward

and reverse direction faults

Non-directional Each element operates regardless of the fault direction


current transformer (CT) respectively. The relay output is linked to the tripping coil


60/179

of the circuit breaker (CB). The relay continuously monitors the input parameters and

executes the relay logic to identify a faulted condition in the network. The process of

making the tripping decision is shown in the Fig. 3.8. Based on the fundamental

voltage and current, the admittance is calculated, which is the measured admittance

of the relay point at a given time. The measured admittance and values for the relay

reach settings are the inputs to the relay logic. This logic consists of normalized

admittance calculation, relay characteristic equations, relay tripping time

calculations, identification of fault direction and defined relay constraints. The

faulted condition is detected by using the constraint in (3.3). Once fault is detected,

the calculated tripping time based on measured admittance is fed through an

integrator to obtain the tripping signal for the CB. Also relay checks whether the

fault detection signal exists until relay issues the tripping command to avoid any

nuisance tripping.

Fi 3 7 R l i di h


3.6Settings of ITA relays to detect resistive faults


61/179

Higher fault resistance can affect the operation of ITA relays. Therefore a

method of relay settings is described to achieve successful relay operation in the

presence of fault resistance. The relay carefully checks the constraint in (3.3)

continuously, which is the comparison between the measured admittance (Ym) and

the total admittance (Yt) setting of a particular zone. The relay detects a fault in the

network when Ymbecomes higher than Yt. For a fault within a particular zone, Ymis

always greater than Yt, if fault resistance is zero. However, with the increase of .fault

resistance, Ym can become less than Yt. Also the maximum fault resistance which

allows the relay to operate depends on the fault location of the line. For example, the

relay can operate for a higher resistive fault, if the fault is near the relay than when it

is further away from the relay since a higher value of fault resistance can be

compensated by each zone for near faults.

Another protective zone is introduced to achieve the tripping operation of the

relays under resistive faults. The maximum fault resistance which can be tolerated by

the relay is decided based on the loads of the feeder. In this case, the relay operation

can be obtained up to a pre-defined value of fault resistance. This method will not

work for higher resistive faults, where fault currents are in same levels as load

currents. The minimum equivalent impedance of loads (i.e. the maximum load


effect of cold load inrush can be considered. Therefore, it is proposed to select one


62/179

third of minimum equivalent impedance of loads as the fault resistance setting.

A relay, if it has two zones, has two tripping characteristic curves. In this case,

total admittance, Ytshould be set separately for each zone depending on protection

requirements. Instead of these two zone characteristics, another characteristic will be

introduced to discriminate the high resistive faults as mentioned above. Hereinafter,

this zone is denoted by Zone-3. In this case Yt consists of corresponding line

impedance and the maximum fault resistance which is determined based on loading

condition. A coordination time interval should be kept between adjacent two Zone-3s

of relays to obtain the correct relay grading. Otherwise relay characteristic of Zone-3

in each relay will not show a considerable time difference for the faults with low

fault resistance. Also the tripping time is set to a little higher value than the settings

in the normal zone operations, since there is no requirement to isolate the faults with

lower fault currents faster than the faults with higher fault currents. The radial

network shown in Fig. 3.4 is considered again to illustrate the relay settings for all

the zones.

3.6.1Zone-1 settingsZone-1 reach setting is similar for all the relays if they are located equidistant.

Therefore Yt is set by assuming the Zone-1 will protect 120% of the first line Z12


3.6.2Zone-2 settings


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Ytis set by assuming Zone-2 will protect 200% of the first line. This setting is

also similar for all the relays. The reach setting and tripping characteristic can be

given by

)2(

1

122_

ZY Zonet

= (3.8)

15.01

0037.01.0 +

=

r

pY

t (3.9)

3.6.3Zone-3 settingsThis zone represents a broader coverage of the protected line including the

compensation for fault resistance. The value of Yt can be set using the allowable

maximum fault resistance. The allowable maximum fault resistance is denoted by Zf

after calculating the maximum load and adjusting it using the safety margin. It

should be noted that Zfis the maximum fault resistance that can be handled by the

relay when fault occurs in the far end of the protected zone. It is not the fault

resistance in a particular fault condition. In this case, Ytfor the Zone-3 can be set as,

)(1

123_

fZonet

ZZY

+= (3.10)

Zone-1 and Zone-2 tripping characteristics are same for all the relays.


reverse faults. If the relay detects the fault as forward, then forward tripping


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characteristic, t_Zone3Fis activated. On the other hand, reverse tripping characteristics,

t_Zone3Ris activated if fault is detected by the relay as reverse.

The Zone-3 tripping characteristic of each relay can be modified by assigning

different constant values. A minimum tripping time characteristic should be selected

for the furthest downstream relay to discriminate the forward faults. It can be then

increased according to the coordination time interval between two adjacent relays.

This Zone-3 grading is similar to the TDS setting of an overcurrent relay in a radial

feeder. On the other hand, the minimum tripping time characteristic for reverse fault

is selected to the furthest upstream relay. The settings of Zone-3 for the relays R1, R2,

and R3 in the radial feeder of Fig. 3.4 can be given as shown in (3.11)-(3.13)

respectively. These settings can be changed according to the protection requirements.

15.1

1

0037.0

1.01_3 +

=

r

RFZone

Y

t

45.01

0037.01.01_3

+

=

r

RRZoneY

t

(3.11)

85.01

0037.01.02_3

+

=

r

RFZoneY

t

75.01

0037.01.02_3

+

=

r

RRZoneY

t (3.12)

5500037.0

3 +=t


tripping characteristics of R2 and R3 are calculated using (3.12) and (3.13)


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respectively. The figure also shows the combined forward relay characteristics of

Zone-1 and Zone-2. It can be seen that forward Zone-3 as well as reverse Zone-3

characteristics of each relay have been graded appropriately to achieve the backup

protection. For example, it is assumed that a fault between BUS-1 and BUS-2 in the

system cannot be detected by the primary zones (i.e., Zone-1 and Zone-2) of R 1and

R2. Then, in this case, R2detects the fault in reverse Zone-3 to isolate the fault from

downstream side while R3provides the backup protection as shown in Fig. 3.9.

Fig. 3.9 Relay tripping characteristics of different zones

3.7Practical issues for admittance calculation


usually appear in current signal. However, the decaying dc magnitude and time


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constant cannot be calculated before a fault occurs since it depends on the system

configuration (X/R ratio), fault location and the value of fault resistance.

Fast Fourier Transform (FFT) or Discrete Fourier Transform (DFT) can be

used to extract the fundamental component from a sampled waveform. FFT is a fast

way of calculating the DFT. FFT can accurately calculate the fundamental in the

presence of harmonics and signal noises. However, it is not immune to decaying dc

component.

DFT is widely used in digital protective relays. DFT can extract the

fundamental in the presence of harmonics, however it is also not immune to decaying

dc component [63]. Some previous studies propose some interesting techniques to

calculate the fundamental component accurately in the presence of decaying dc

component. A method is proposed in [63] to eliminate the effect of decaying dc

component by calculating the time constant of the faulted current waveform. In this

algorithm, the dc magnitude is then calculated based on the calculated time constant

for a cycle and subtract the dc magnitude from samples to obtain the DFT without

decaying dc component. A DFT based filter algorithm is presented in [64] for digital

distance relays to extract the fundamental accurately. In [65], a method is described

to remove the decaying dc component for an application of protective relays. It can


tripping time calculation. However, the speed of the calculation and burden on the


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processor should be carefully considered when selecting a particular algorithm to

avoid the errors coming form decaying dc component on tripping time calculations.

3.8SummaryIn this chapter, the basic features of the proposed ITA relay to protect a

distribution network or a microgrid which has several DGs are discussed. The relay

inverse time characteristic and relay reach setting have been explained. Furthermore,

different relay elements and a method of relay setting to achieve fault detection under

higher resistive faults have been explained. Finally, the challenges of implementing

ITA relays and possible solutions to avoid them are identified.


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Chapter 4: Evaluation of ITA relayperformance

4.1IntroductionFaults can be usually identified by sensing the current level in an electrical

power system since high currents can be seen during the faults. Overcurrent (OC)

relays, fuses and moulded case circuit breakers (MCCBs) are the common type of

current sensing protective devices used in distribution networks. The OC relays can

be classified as definite current or instantaneous, definite time and inverse time based

on the operating characteristics. In this chapter, features of inverse time OC relays

are briefly considered since they are commonly used in distribution networks. On the

other hand, distance type relays are commonly used to protect the transmission

networks where speed of operation and reliability are very important. Fundamentally,

MHO type distance relay are considered in this chapter. These existing OC and

distance relay protection schemes are compared with the proposed ITA relay to

demonstrate the performance of the ITA relay. The grading and coordination of

Chapter 4: Evaluation of ITA relay performance

4.2Inverse time overcurrent relays


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Most of the existing distribution networks are radial and they are employed

with OC protective devices because of their simplicity and low cost [4, 30].

Coordination of such protective devices based on current is relatively easy in the

radial networks. The IEEE Standard inverse time relay tripping characteristic is

given by [37]

TDSBM

At

pp

+

=

1 (4.1)

where the constants A, Band pare used to select the relay characteristic curve and

time dial setting (i.e. TDS) is used for the coordination between several OC relays.M

is the multiple of pickup current and it is defined by

=

p

f

I

IM (4.2)

whereIfis the fault current seen by the relay andIpis the relay set current (i.e. pickup

current). Three inverse time OC relay characteristic equations are given in the IEEE

report [37]. They are moderately inverse, very inverse and extremely inverse. Each

relay curve has different constants values in (4.1).

To illustrate the grading of inverse time OC relays, a four bus bar radial feeder

Chapter 4: Evaluation of ITA relay performance

4.2. The relay tripping time tp is shown with the fault location. Coordination time

i t l f R R d R R d t d b t d t ti l L t TDS


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intervals for R1-R2 and R2-R3are

jalthotage dewadasa thesis.bak

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