Electrical Engineering Faculty of Technology University of Guyana

August 24, 2012

Methodology of Selection, Setting and Analysis of Anti-Islanding Protection For Distribution Generation System

Kenny SAMAROO

Submitted in partial fulfillment of the requirements for Bachelor of Engineering (Electrical Engineering)

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Methodology of Selection, Setting and Analysis of Anti-Islanding Protection For Distribution Generation System

By

Kenny O. Samaroo

Under the guidance of

Dhanraj Bachai

Department of Electrical Engineering

University Of Guyana

August, 2012

© Kenny O. Samaroo 2012

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ABSTRACT

With the daily increasing demand for power, and need for alternative power generation

technologies, such as, fuel cell, wind & water turbine and photovoltaic systems, customer

demands for better power quality and reliability are forcing the power companies to move

towards distributed generations (DG).

Islanding occurs when a portion of the distribution system becomes electrically isolated from the

remainder of the power system yet continues to be energized by distribution system. It is

important when using DG in an interconnected system that the power distributed system is

capable of detecting an unintentional islanding condition.

Current IEEE interconnection standards (IEEE 1547) mandate that control and protection

measures should be in place to lessen the probability of an unintentional island, and to minimize

the duration of an islanding condition, if one should occur. Typically, a distributed generator

should be disconnected within 100 to 300 ms after loss of main supply [1]. To achieve this each

distributed generator must be equipped with an islanding detection device or anti islanding

devices, such as, vector shift relay and ROCOF relay.

This project seeks to explore the various methods of selecting, setting and analysis of anti-

islanding protection devices (relays) for distribution generation system.

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Table of Contents

ABSTRACT .................................................................................................................................................. 3

List Of Tables ............................................................................................................................................... 5

List Of Figures .............................................................................................................................................. 6

ACKNOWLEDGEMENT ............................................................................................................................ 9

INTRODUCTION ...................................................................................................................................... 10

Background ............................................................................................................................................. 10

Statement Of The Problem ...................................................................................................................... 12

SCOPE OF WORK ..................................................................................................................................... 14

Overview ................................................................................................................................................. 14

Literature Review .................................................................................................................................... 15

Rationale for anti-islanding protection: .............................................................................................. 15

Remote Islanding Detection Techniques ............................................................................................ 16

Local Detection Techniques ................................................................................................................ 17

METHODS/DESIGN APPROACH ........................................................................................................... 26

Detection of Islanded Power Systems ..................................................................................................... 26

Network Studied ..................................................................................................................................... 27

Simulation model .................................................................................................................................... 30

Conditions for Islanding ......................................................................................................................... 31

Model Description .................................................................................................................................. 33

SIMULATION RESULTS ......................................................................................................................... 46

Normal Conditions .................................................................................................................................. 46

Islanded Condition .................................................................................................................................. 52

Scenario 1: Formation of a Major Island (Loss of Grid) ................................................................... 52

Scenario 2: Formation of a Minor Island. .......................................................................................... 62

CONCLUSION ........................................................................................................................................... 70

RECOMMENATION ................................................................................................................................. 71

BIBLIOGRAPHY ....................................................................................................................................... 72

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List Of Tables Tables

1. Steady state parameters for the Synchronous Machines used in the model, under normal

operating conditions.

2. Combine results for Relay Protection Blocks 1 and 2 for a major islanded condition.

3. Results obtained for Relay Protection Block 2 for a minor islanded condition.

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List Of Figures Figures

1. Power system with centralized generation

2. Decentralized power system with DG interconnected

3. Utility Network before and after islanding has occurred.

4. Islanding detection techniques

5. Equivalent Circuit of Synchronous Generator equipped with ROCOF Relay operating

parallel with Utility [4,6]

6. Equivalent circuit of Synchronous Generator equipped with Vector Surge Relay

operating parallel with Utility [4,6]

7. Internal and terminal voltage phasors (a) before opening with CB (b) after opening with

CB.

8. Voltage Vector Surge

9. One line diagram for the Versailles/Lenora portion of GPL’s DIS.

10. Modified Equivalent One Line Network Diagram

11. Matlab/Simulink model of Versailles and Lenora.

12. Distinction between Major and Minor Island and Conditions for Islanding in the Network

Studied

13. Simulink model of a Synchronous Machine

14. Simulink model of a three phase transformer and its equivalent circuit.

15. Simulink model of a three phase source.

16. Simulink model of a three phase breaker.

17. Simulink model of a three phase parallel RLC load.

18. Simulink model of a root mean square (rms) calculation block.

19. Simulink model of a three phase voltage-current measurement block.

20. Simulink model of display block.

21. Simulink model of an oscilloscope (scope).

22. Simulink model for the protection sub-system.

23. Relays found inside the protection sub-system block

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24. (a) Simulink model of Under/Over Current Relay model.

(b) Simulink model of Under/Over Voltage Relay model.

(c) Simulink model of Under/Over Frequency Relay model.

(d) Simulink model of The Rate of Change of Frequency Relay (ROCOF)

(e) Simulink model of a Vector Shift Relay.

25. (a) Simulation result of Synchronous Machine One (SM1).

(b) Simulation result of Synchronous Machine Two (SM2).

(c) Simulation result of Synchronous Machine Three (SM3).

26. (a) Simulation result for 3 phase voltages and currents at bus 1 and bus 2.

(b) Expanded view of the 3 phase voltages and currents at bus 1 and bus 2.

27. (a) Simulation result for the 3 phase rms voltages at bus 1&2.

(b) Simulation result for the 3 phase rms currents at bus 1&2.

28. Simulation result of the rate of change of frequency and frequency for bus 1 and bus 2.

29. (a) Simulation result for Synchronous Machine One (SM1) for a major islanded

condition.

(b) Simulation result for Synchronous Machine One (SM2) for major islanded condition.

(c) Simulation result for Synchronous Machine One (SM3) for major islanded condition.

30. (a) Simulation result for the 3 phase rms currents at bus 1&2 for major islanded

condition.

(b) Simulation result for the 3 phase rms voltages at bus 1&2 for a major islanded

condition.

31. Simulation result for the 3 phase voltages and current at bus 1&2 for a major islanded

condition.

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32. Simulation result of the rate of change of frequency and frequency at bus 1 and bus 2

during a major islanded condition.

33. (a) Results obtained from the protection block at bus 1 for a major islanded condition.

(b) Results obtained from the protection block at bus 2 for a major islanded condition.

34. (a) Graph showing comparison of the relays detection time at bus 1.

(b) Graph showing comparison of the relays detection time at bus 2.

35. (a) Simulation result for Synchronous Machine One (SM1) for minor islanded condition.

(b) Simulation result for Synchronous Machine One (SM2) for minor islanded condition.

(c) Simulation result for Synchronous Machine One (SM3) for minor islanded

condition.

36. (a) Simulation result for the 3 phase rms currents at bus 1&2 for minor islanded

condition.

(b) Simulation result for the 3 phase rms voltages at bus 1&2 for a minor islanded

condition.

37. Simulation result of the rate of change of frequency and frequency at bus 1 and bus 2

during a major islanded condition.

38. (a) Results obtained from the protection block at bus 1 for a minor islanded condition.

(b) Results obtained from the protection block at bus 2 for a minor islanded condition.

39. Graph showing comparison of the relays detection time at bus 2.

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ACKNOWLEDGEMENT

I would like to thank the University of Guyana’s Faculty of Technology which provided me the

opportunity to conduct this study. In particular, my supervisor, Dhanraj Bachai, whose

knowledge and guidance played a key role in the success of this work.

I would also like to thank Mr Blackman who provided me with the relevant information needed

to help make this project a success. Also I would like to thank all my class mates for all the

thoughtful and mind stimulating discussions we had, which prompted us to think beyond the

obvious.

Finally I cannot end without thanking my family and more so my wife ‘Priea Samaroo’, on

whose encouragement, support, and advice, I have relied on throughout my studies.

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INTRODUCTION

Background

Electric power industries were traditionally designed with the power distribution system

assuming the primary substation being the sole source of power generation (as shown in Figure

1).

Figure 1: Power system with centralized generation.

With the introduction of Distributed Generation (DG) this assumption changes, that is, power

source/s (DG) are placed within the power distribution system at points where support for active

and reactive power is required after a load flow study is carried out (as shown in Figure 2).

Figure 2: Decentralized power system with DG interconnected.

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Generating power on-site, rather than centrally, reduces cost of transmission, complexity, and

inefficiencies associated with transmission and distribution.

Recently there has been significant increase in the utilization of interconnected DG. The

increasing incursion of DG was driven by improving cost and performance of both old-line and

new technologies, and by customers and third parties seeking to reduce costs, increase local

control of the energy resource, and increasing awareness of the important role of power system

reliability [1].

Distribution generation generally applies to relatively small generating units at or near consumer

site/s to meet specific consumer needs, to support economic operation of the existing distribution

grid, or both. Reliability of service and power quality is enhanced by the proximity to the

consumer and efficiency is often increased.

While central power systems remain crucial to the local utility, their flexibility is limited. Large

power generation facilities are very expensive and require immense transmission and distribution

network to transmit the power. DG compliments central power by providing a relatively low

capital cost in response to incremental increase in power demand while avoiding transmission

and distribution capacity upgrades by placing power source/s within the already existing

grid/network where it is most needed and by having flexibility to send power back into the grid

when needed [2].

Some of the main technologies used in DG are photovoltaic system, wind power, fuel cells,

microturbines and diesel generators. Each technology has limitation in their application and

operation that makes them more or less suitable to meet the various aim of installing DG.

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Statement Of The Problem

DG possesses inherent advantages, conversely it’s not without disadvantages. As a result, DG

interconnection results in operating situation which does not occur in centralized power systems.

These operating situation present unique engineering challenges to DG interconnection.

This project deals with this particular operating situation that occurs at the interconnection or

Point of Common Coupling (PCC) between DG plant and the rest of the power system in the

event of a faulted condition, a situation hereafter refer to as Islanding.

One of the new technical issues created by DG interconnection is unintentional islanding.

Islanding occurs when a portion of the distribution system becomes electrically isolated from

the remainder of the power system, yet continues to be energized by DG connected to the

isolated subsystem (shown in Figure 3).

The island is an unregulated power system. Its behavior is unpredictable due to the

power mismatch between the load and generation and the lack of voltage and frequency

control. The main concerns associated with such islanded systems are: [21]

The voltage and frequency provided to the customers in the islanded system can vary

significantly if the distributed generators do not provide regulation of voltage and

frequency and do not have protective relaying to limit voltage and frequency excursions,

since the supply utility is no longer controlling the voltage and frequency, creating the

possibility of damage to customer equipment in a situation over which the utility has no

control. Utility and DG owners could be found liable for the consequences.

Islanding may create a hazard for utility line-workers or the public by causing a line to

remain energized that may be assumed to be disconnected from all energy sources.

The distributed generators in the island could be damaged when the island is

reconnected to the supply system. This is because the generators are likely not in

synchronism with the system at the instant of reconnection. Such out-of-phase reclosing

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can inject a large current to the generators. It may also result in re-tripping in the supply

system. [21]

Islanding may interfere with the manual or automatic restoration of normal service for

the neighboring customers. [21]

It can be desirable to permit such islanded operation to increase customer reliability, and this is

often done where the DG provides backup power to the facility where it is installed. However,

considerable engineering effort, control functionality, and communications infrastructure are

necessary to make intentional islanding viable where the island includes a portion of primary

system and other loads. Even greater requirements are necessary to coordinate the operation of

more than one DG in an island. In general, if provision has not been made for islanded operation

beyond the local facility load, any unintentional islands which do occur are undesired.

Typically, according to IEEE 1547 a DG should be disconnected within 100 to 300 ms after loss

of main supply [1]. Hence there’s need to quickly detect and eliminate unintentional DG

supported islands in the event of a faulted condition. Ideally, the fault should be detected by the

DG protection system and the DG tripped before the formation of an island. To achieve this each

distributed generator must be equipped with an islanding detection device or anti islanding

devices, such as, vector shift relay and ROCOF relay [4] [5].

Before After

Figure 3: Utility Network before and after islanding has occurred.

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SCOPE OF WORK

Overview This project will involve examining the national utility (GPL) network (single line diagrams) to

identify potential unintentional islanding conditions, subsequently an equivalent of all the

portions of the network with potential for islanding will be produced (in the form of a single line

diagram). This equivalent single line diagram of the network containing the island/s will then be

used to develop a Matlab/Simulink model. The model will contain anti islanding relays, such as,

rate of change of frequency (ROCOF), vector surge, over/under voltage relays, over/under

current relays and over/under frequency relays based on the principal governing their operation.

The model will be simulated under a predefined or intentional islanding condition, so as to

evaluate and determine the performance of these relays for the purpose of assisting electrical

protection engineers in selecting the most appropriate protective devices and their corresponding

settings for DG systems.

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Literature Review

Rationale for anti-islanding protection: Anti-islanding capability is an important requirement for distributed generators. It refers to the

capability of a distributed generator to detect if it operates in an islanded system and to

disconnect itself from the system in a timely fashion. Failure to trip islanded generators can lead

to a number of problems for the generator and the connected loads. The current industry practice

is to disconnect all distributed generators immediately after the occurrence of islands.

The main philosophy of detecting an islanding situation is to monitor the DG output parameters

and system parameters, and based on system requirements whether or not an islanding situation

has occurred from change in these parameters. Islanding detection techniques can be divided into

remote and local techniques and local techniques can further be divided into passive, active and

hybrid techniques as shown in Figure 4 [5].

Figure 4: Islanding detection techniques.

Islanding Detection

Remote Technique

Power Line Signaling Scheme

Transfer Trip Scheme

Local Technique

Passive Technique

Voltage/Current Unballance

Under/Over Voltage

Under/Over Current

Rate of Change of Frequency

Vector Surge Detection

Rate of Change of Output

Power

Active Technique

Reactive Power Export Error

Detection

Phase/Frequency Shift Method

Hybrid Technique

Positive Feedback and

Voltage Imballance

Voltage and Reactive Power

Shift

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Remote Islanding Detection Techniques

Remote islanding detection techniques are based on communication between utilities and DGs.

Although these techniques may have better reliability than local techniques, they are expensive

to implement and hence uneconomical .Some of the remote islanding detection techniques are as

follows:

a) Power line signaling scheme

These methods use the power line as a carrier of signals to transmit islanded or non-islanded

information on the power lines. The apparatus includes a signal generator at the substation that is

coupled into the network where it continually broadcasts a signal. Each DG is then equipped

with a signal detector to receive this transmitted signal. Under normal operating conditions, the

signal is received by the DG and the system remains connected. However, if an island state

occurs, the transmitted signal is cut off because of the substation breaker opening and the signal

cannot be received by the DG, hence indicating an island condition [4] [5].

This method has the advantages of its simplicity of control and its reliability. However there are

also several significant disadvantages to this method, the fist being the practical implementation.

To connect the device to a substation, a high voltage to low voltage coupling transformer is

required. A transformer of this voltage capacity can be very expensive.

Another problem for power line communication is the complexity of the network and the

affected networks. A perfectly radial network with one connecting breaker is a simple example

of island signaling; however, more complex systems with multiple utility feeders may find that

differentiation between upstream breakers difficult [5].

b) Transfer trip scheme:

The basic idea of transfer trip scheme is to monitor the status of all the circuit breakers and

reclosers that could island a distribution system. Supervisory Control and Data Acquisition

(SCADA) systems can be used for that. When a disconnection is detected at the substation, the

transfer trip system determines which areas are islanded and sends the appropriate signal to the

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DGs, to either remain in operation, or to discontinue operation. Transfer trip has the distinct

advantage similar to Power Line Carrier Signal that it is a very simple concept. With a radial

topology that has few DG sources and a limited number of breakers, the system state can be sent

to the DG directly from each monitoring point [5] [6].

The weaknesses of the transfer trip system are better related to larger system complexity cost and

control. As a system grows in complexity, the transfer trip scheme may also become obsolete,

and need relocation or updating. The other weakness of this system is control. As the substation

gains control of the DG, the DG may lose control over power producing capability. If the transfer

trip method is implemented correctly in a simple network, there are no non-detection zones of

operation.

Local Detection Techniques

It is based on the measurement of system parameters at the DG site, like voltage, frequency, etc.

It is further divided into passive, active and hybrid detection technique.

1. Passive detection techniques

Passive methods work on measuring system parameters such as variations in voltage, frequency,

harmonic distortion, etc. These parameters vary greatly when the system is islanded.

Differentiation between an islanding and grid connected condition is based upon the thresholds

set for these parameters. Special care should be taken while setting the threshold value so as to

differentiate islanding from other disturbances in the system. Passive techniques are fast and they

don’t introduce disturbance in the system but they have a large non detectable zone (NDZ) where

they fail to detect the islanding condition [4] [5].

There are various passive islanding detection techniques and some of them are as follows:

a) Rate of change of output power

The rate of change of output power,𝑑𝑝𝑑𝑡

, at the DG side, once it is islanded, will be much greater

than that of the rate of change of output power before the DG is islanded for the same rate of

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load change[7]. It has been found that this method is much more effective when the distribution

system with DG has unbalanced load rather than balanced load. [5] [8]

b) Rate of change of frequency

The rate of change of frequency, 𝑑𝑓𝑑𝑡

, will be very high when the DG is islanded. The rate of

change of frequency (ROCOF) can be given by [9]

ROCOF: 𝑑𝑓𝑑𝑡

= ∆𝑝2𝐻𝐺

∗ 𝑓

Where ∆𝑝 is the power mismatch at the DG side.

H is the moment of inertia for the DG/system.

G is the rated generation capacity of the DG/system.

Large systems have large H and G where as small systems have small H and G giving larger

value for 𝑑𝑓𝑑𝑡

ROCOF relay monitors the voltage waveform and will operate if ROCOF is

higher than setting for certain duration of time. The setting has to be chosen in such a way that

the relay will trigger for island condition but not for load changes. This method is highly

reliable when there is large mismatch in power but it fails to operate if DG’s capacity matches

with its local loads [5].

Figure 5: Equivalent Circuit of Synchronous Generator equipped with ROCOF Relay

operating parallel with Utility [4,6].

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Figure 5 presents an equivalent circuit of a synchronous generator equipped with a ROCOF

relay operating in parallel with a distribution network. In this figure, a synchronous generator

(SG) feeds a load (L). The difference between the electrical powers PSG supplied by the

generator and PL consumed by the load is provided (or consumed) by the main grid.

Therefore, the system frequency remains constant. If the circuit breaker (CB) opens, due to a

fault for example, the system composed by the generator and the load becomes islanded.

In this case, there is an electrical power imbalance due to the lost grid power PSYS This power

imbalance causes transients in the islanded system and the system frequency starts to vary

dynamically. Such system behavior can be used to detect an islanding condition. However, if

the power imbalance in the islanded system is small, then the frequency will change slowly.

Thus, the rate of change of frequency can be used to accelerate the islanding detection for this

situation. [4, 5] The rate of change of frequency is calculated considering a measure window

over a few cycles, usually between 2 and 50 cycles.

This signal is processed by filters and then the resulting signal is used to detect islanding. If the

value of the rate of change of frequency is higher than a threshold value, a trip signal is

immediately sent to the generator CB. Typical ROCOF settings installed in 60-Hz systems are

between 0.10and 1.20 Hz/s. Another important characteristic available in these relays is a block

function by minimum terminal voltage. If the terminal voltage drops below an adjustable level

Vmin , the trip signal from the ROCOF relay is blocked. This is to avoid, for example, the

actuation of the ROCOF relay during generators start-up or short circuits. [5]

c) Vector Shift Detection

Vector Shift relay measures the change of phase angle of the voltage waveform to a known

reference waveform. When an island state occurs, there can be an immediate phase shift by the

DG to accommodate the change in power requirements. Once again, a threshold is set at the

maximum phase jump allowed and if the DG system exceeds that threshold, the relay is

triggered. [22]

A synchronous generator equipped with a VS relay operating in parallel with a distribution network is depicted in Figure 6.

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Figure 6: Equivalent circuit of Synchronous Generator equipped with Vector Shift Relay operating parallel with Utility [4,6].

There is a voltage drop V between the terminal voltage VT and the generator internal voltage EI

due to the generator current ISG passing through the generator reactance Xd. Consequently, there

is a displacement angle between the terminal voltage and the generator internal voltage, whose

phasor diagram is presented in Fig. 7(a). In Fig. 6, if the CB opens due to a fault, for example,

the system composed by the generator and the load L becomes islanded. At this instant, the

synchronous machine begins to feed a larger load (or smaller) because the current ISYS provided

(or consumed) by the power grid is abruptly interrupted. Thus, the generator begins to decelerate

(or accelerate).

Therefore, the angular difference between VT and EI is suddenly increased (or decreased) and

the terminal voltage phasor changes its direction, as shown in Fig. 7(b). Analyzing such

phenomenon in the time domain we see that the instantaneous value of the terminal voltage

jumps to another value and the phase changes as depicted in Fig. 8, where the point ‘A’ indicates

the islanding instant. Additionally, the frequency of the terminal voltage also changes. This

behavior of the terminal voltage is called vector shift. VS relays are based on such phenomena.

VS relays available in the market measure the duration time of an electrical cycle and start a new

measurement at each zero rising crossing of the terminal voltage. The current cycle duration

(measured waveform) is compared with the last one (reference cycle). In an islanding situation,

the cycle duration is either shorter or longer, depending on if there is an excess or a deficit of

active power in the islanded system, as shown in Fig. 8.

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This variation of the cycle duration results in a proportional variation of the terminal voltage

angle, which is the input parameter of VS relays. If the variation of the terminal voltage angle

exceeds a predetermined threshold, a trip signal is immediately sent to the CB. Usually, VS

relays allow this angle threshold to be adjusted in the range from 2 to 20. The relay is also

disabled if the magnitude of the terminal voltage drops below a threshold value to avoid false

operation.

Figure 7: Internal and terminal voltage phasors (a) before opening with CB (b) after opening

with CB.

Figure 8: Voltage Vector Surge.

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d) Voltage unbalance

Once the islanding occurs, DG has to take change of the loads in the island. If the change in

loading is large, then islanding conditions are easily detected by monitoring several parameters:

voltage magnitude, current magnitude, and frequency change. However, these methods may not

be effective if the changes are small. As the distribution networks generally include single-phase

loads, it is highly possible that the islanding will change the load balance of DG. Furthermore,

even though the change in DG loads is small, voltage unbalance will occur due to the change in

network condition [11] [12].

Under/Over Voltage

Under and over voltage are also used for passive islanding detection, and often as a

complementary device coupled with frequency monitoring. Voltage variations occur as a result

of a mismatch of reactive power. This relay operates on the principle that an excess of reactive

power mismatch will drive the voltage up and a deficit of reactive power will drive the voltage

down. Once the voltage falls out of the preset thresholds, the relay will open the breaker.

Hence, by determining the voltage change or its rate of change, it is possible to detect island

states that frequency effects alone cannot. Unfortunately, there is limited experience indicating

that the reactive power measurement relay will have higher performance than frequency

variations. As real power draw is often much greater than reactive power, a loss of mains is more

likely to significantly change the active power than the reactive power.

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2. Active detection techniques

With active methods, islanding can be detected even under the perfect match of generation and

load, which is not possible in case of the passive detection schemes. Active methods directly

interact with the power system operation by introducing perturbations. The idea of an active

detection method is that this small perturbation will result in a significant change in system

parameters when the DG is islanded, whereas the change will be negligible when the DG is

connected to the grid.

a) Reactive power export error detection

In this scheme, DG generates a level of reactive power flow at the point of common coupling

(PCC) between the DG site and grid or at the point where the Reed relay is connected [14] [15].

This power flow can only be maintained when the grid is connected. Islanding can be detected if

the level of reactive power flow is not maintained at the set value. For the synchronous generator

based DG, islanding can be detected by increasing the internal induced voltage of DG by a small

amount from time to time and monitoring the change in voltage and reactive power at the

terminal where DG is connected to the distribution system. A large change in the terminal

voltage, with the reactive power remaining almost unchanged, indicates islanding. [16]The major

drawbacks of this method are it is slow and it cannot be used in the system where DG has to

generate power at unity power factor.

b) Phase (or frequency) shift methods

Measurement of the relative phase shift can give a good idea of when the inverter based DG is

islanded. A small perturbation is introduced in form of phase shift. When the DG is grid

connected, the frequency will be stabilized. When the system is islanded, the perturbation will

result in significant change in frequency. The Slip-Mode Frequency Shift Algorithm (SMS) uses

positive feedback which changes phase angle of the current of the inverter with respect to the

deviation of frequency at the PCC. A SMS curve is designed in such a way that its slope is

greater than that of the phase of the load in the unstable region. [5] [17]

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The drawback of this method is that the islanding can go undetected if the slope of the phase of

the load is higher than that of the SMS line, as there can be stable operating points within the

unstable zone [18].

3. Hybrid detection schemes

Hybrid methods employ both the active and passive detection techniques. The active technique is

implemented only when the islanding is suspected by the passive technique. Some of the hybrid

techniques are as follows:

a) Technique based on positive feedback (PF) and voltage imbalance (VU)

This islanding detection technique uses the PF (active technique) and VU (passive technique).

The main idea is to monitor the three-phase voltages continuously to determinate VU which is

given as

𝑉𝑈 = 𝑣 + 𝑠𝑞𝑣 − 𝑠𝑞

V+Sq and V-Sq are the positive and negative sequence voltages, respectively. Voltage spikes

will be observed for load change, islanding, switching action, etc. Whenever a VU spike is

above the set value, frequency set point of the DG is changed. The system frequency will

change if the system is islanded [19].

b) Technique based on voltage and reactive power shift

In this technique voltage variation over a time is measured to get a covariance value (passive)

which is used to initiate an active islanding detection technique, adaptive reactive power shift

(ARPS) algorithm [20].

The ARPS uses the same mechanism as ALPS, except it uses the d-axis current shift

instead of current phase shift. The d-axis current shift, 𝑖𝑑𝑘 or reactive power shift is given as

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𝑖𝑑𝑘 = 𝑘𝑑 �𝑇𝑎𝑣′ − 𝑇𝑣

(𝑘)

𝑇𝑣(𝑘) �

Where;

Tav' is the average of the previous four voltage periods.

Uav is the mean of Tav'

Tv is the voltage periods

UV is the mean of TV

kd is chosen such that the d-axis current variation is less than 1 percent of q-axis current in

inverter's normal operation. The additional d-axis current, after the suspicion of island, would

accelerates the phase shift action, which leads to a fast frequency shift when the DG is islanded

[5].

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METHODS/DESIGN APPROACH

Detection of Islanded Power Systems

An islanding situation should be detected soon after the island is formed. The basic

requirements for a successful detection are:

The scheme should work for any possible formations of islands. Note that there could be

multiple switchers, reclosers and fuses between a distributed generator and the supply

substation. Opening of any one of the devices will form an island. Since each island

formation can have different mixture of loads and distributed generators, the behavior of

each island can be quite different. A reliable anti-islanding scheme must work for all

possible islanding scenarios.

The scheme should detect islanding conditions within the required time frame. The main

constraint here is to prevent out-of-phase reclosing of the distributed generators. A

recloser is typically programmed to reenergize its downstream system after about 0.5 to

1 second delay. Ideally, the anti-islanding scheme must trip its DG before the reclosing

takes place.

27 | P a g e

Network Studied

A detail examination of GPL’s DIS revealed that there were at least three cases that possess potential for

islanding. Of these three cases, the Versailles/Lenora area was chosen to carry out the study, since the

only DGs present in the DIS was found to be located in this area.

Figure 9: One line diagram for the Versailles/Lenora portion of GPL’s DIS.

The one line diagram in Figure 9 shows the Versailles/Lenora portion of the DIS, and more so,

the area of interest. However from visits made to Versailles it was found out that changes were

made to the system that was not documented or updated in the one line diagram, changes such

as, the ‘A1’ and ‘A3’ generator sets were no longer operational and there were three generators

sets present at Lenora instead of two show in the diagram. Hence taking the network

configuration as shown in the Figure 9 and the changes that were made to the system, a modified

equivalent diagram was produced (shown in Figure 10).

From Garden Of Eden

28 | P a g e

Figure 10: Modified Equivalent One Line Network Diagram.

Since the four mobile Caterpillar sets (A2, A4,A7 and A8) at Versailles and the three (A1,A2

and A3) at Lenora all are the same model, that is, all having the same parameters, for connivance

they were combined and model as a single generator at each location. The equivalent one line

diagram is made up of the following:

Generator G1 (A6)

Model#: GM AB20-24

3250 KVA 60Hz 4160V

Generator G2 (A2, A4, A7 & A8)

4 Mobile Caterpillar Generator set

Model #: 3516

2000 KVA 60Hz 480V

Generator G3 (A1 & A2)

3 Mobile Caterpillar Generator set

Model #: 3516

2000 KVA 60Hz 480V

CB1

CB2

29 | P a g e

Transformer T1

3750KVA 4160/13800V Δ/Υ

Transformer T2 (4) & T3 (3)

2500KVA 480/13800V Δ/Υ

Garden of Eden (GOE) Interconnection

3 phase current Source

Feeders

West Bank approx 5 MW

West Coast approx 9 MW

In creating the model shown in figure 11, it was found that Versailles and Lenora together have a

generating capacity of 17.25 MVA (11.25 MVA at Versailles and 6.0 MVA at Lenora) plus

power imported from GOE which is approximately 5.0 MVA, hence this gives a total of 22.25

MVA. However the total load demand of the two feeders (west coast and west bank) connected

to Versailles and Lenora was found to be approximately 14 MVA, thus having a surplus of 8.25

MVA in generation. Therefore an assumption was made that all the generators either at

Versailles or at Lenora was not in operation at the same time, hence this was taken into

consideration when creating the model, that is, instead of combining all four of the mobile

Caterpillar sets at Versailles only two was combined and modeled to produce 4 MVA, however,

all three at Lenora was model as being in operation.

30 | P a g e

Simulation model

In order to investigate the performance of the different techniques used in island detection a

simulation model was implemented. The model is based upon a specific portion of GPL’s

Demerara Interconnected System (DIS) (shown in figure 10), and was created so that the model

reflects the real system as much as possible. The behavior of the simulated system must be

similar to what happens in a real situation.

Figure 11: Matlab/Simulink model of Versailles and Lenora.

Figure 11 shows the Matlab/Simulink model for the area of interest (Versailles and Lenora) and

is based on the equivalent one line diagram depicted in figure 10.

The model contain three synchronous generator (G1, G2 & G3), three transformers (T1, T2 &

T3), two circuit breakers, a three phase source representing Garden Of Eden (GOE), one feeder

for the west bank and one for the west coast each consuming 5 MW and 9 MW respectively and

various monitoring and measuring blocks.

31 | P a g e

The synchronous generated G1 is rated at 3250 KVA 60Hz 4160 V, G2 is a combination of four

mobile Caterpillar sets each rated at 2000 KVA 60Hz 480 V and G3 is a combination of three

mobile Caterpillar sets all with same ratings used for G2.

The transformer T1 is rated at 3750KVA 4160/13800V Δ/Υ, T2 is a combination of four

individual transformer each with ratings of 2500KVA 480/13800V Δ/Υ and T3 is a combination

three individual transformer all with same rating as ones in T2.

The three phase source representing GOE contribution to Versailles is based on the maximum

short circuit current level during a line-to-ground fault between Versailles and GOE

interconnection, multiplied by the line-to-line voltage (VA).

Note: For all combination of generators and transformers, the rated power is summed and all

impedances are parallel.

Conditions for Islanding

There are basically two conditions for islanding in the network studied. These conditions are:

1. When ‘CB1’ (circuit breaker 1) depicted in figure 10 is in the open position. That is, it

disconnects the entire Versailles and Lenora from the rest of the DIS forming what we

may refer to hereafter as a major island. The term major island is used because Versailles

location is not considered to be distributed generation but since its at the end of the DIS

where there’s only one interconnection from Versailles to the rest of the grid, any

disruption in this connection can leave it isolated from the rest of the DIS and hence

islanded. Also Lenora DG’s would also be considered to be a part of the Versailles Island

as shown in figure 12.

2. When ‘CB2’ (circuit breaker 2) depicted in figure 10 is in the open position. Since it

disconnect the DG’s at Lenora from the rest of the grid thus forming a minor island. A

minor island since the Lenora location meets the criteria of being distribution generation

and the resulting island will only be made up of the generators at Lenora.

32 | P a g e

G1

~G2

G3

T2

T1

T3

B1

B2

West Coast

West Bank

3 Phase Source GOE

Figure 12: Distinction between Major and Minor Island and Conditions for Islanding in the

Network Studied.

Major Island

Minor Island

CB1

CB2

33 | P a g e

Model Description

Synchronous Machine (Alternator, Diesel Engine Speed & Voltage Control)

Figure 13: Simulink model of a Synchronous Machine

The Synchronous Machine block operates in generator or motor modes. The operating mode is

dictated by the sign of the mechanical power (positive for generator mode, negative for motor

mode). The model takes into account the dynamics of the stator, field, and damper windings. The

equivalent circuit of the model is represented in the rotor reference frame (q&d frame). All rotor

parameters and electrical quantities are viewed from the stator.

The SM voltage and speed outputs are used as feedback inputs to the diesel engine speed &

voltage control block which contains governor block as well as an excitation block.

Three Phase Transformer Block (Two Winding)

L1 L2

Rm Lm

R1 R2

Figure 14: Simulink model of a three phase transformer and its equivalent circuit.

This block implements a three-phase transformer using three single-phase transformers. The

Linear Transformer block model shown consists of two coupled windings wound on the same

core. The model takes into account the winding resistances (R1 and R2) and the leakage

34 | P a g e

inductances (L1 and L2), as well as the magnetizing characteristics of the core, which is modeled

by a linear branch (Rm Lm).

The two windings of the transformer can be connected as follows: Y Y with accessible neutral Grounded Y Delta (D1), delta lagging Y by 30 degrees Delta (D11), delta leading Y by 30 degrees

Three-Phase Source

Figure 15: Simulink model of a three phase source.

Implement three-phase source with internal R-L impedance.

The Three-Phase Source block implements a balanced three-phase voltage source with internal

R-L impedance. The three voltage sources are connected in Y with a neutral connection that can

be internally grounded or made accessible. You can specify the source internal resistance and

inductance either directly by entering R and L values or indirectly by specifying the source

inductive short-circuit level and X/R ratio.

Note: For the model that was created, a three phase source was used to model Garden of Eden

interconnection to Versailles and more so Versailles interconnection to the entire grid. For this

source the short circuit level (VA) and X/R ratio was specified.

35 | P a g e

Three-Phase Breaker

Figure 16: Simulink model of a three phase breaker.

The Three-Phase Breaker block implements a three-phase circuit breaker where the opening and

closing times can be controlled either from an external Simulink signal (external control mode),

or from an internal control timer (internal control mode).

The Three-Phase Breaker block uses three Breaker blocks connected between the inputs and the

outputs of the block. You can use this block in series with the three-phase element you want to

switch.

If the Three-Phase Breaker block is set in external control mode, a control input appears in the

block icon. The control signal connected to this input must be either 0 or 1, 0 to open the

breakers, 1 to close them. If the Three-Phase Breaker block is set in internal control mode, the

switching times are specified in the dialog box of the block. The three individual breakers are

controlled with the same signal.

Three-Phase Parallel RLC Load

Figure 17: Simulink model of a three phase parallel RLC load.

The Three-Phase Parallel RLC Load block implements a three-phase balanced load as a parallel

combination of RLC elements. At the specified frequency, the load exhibits constant impedance.

The active and reactive powers absorbed by the load are proportional to the square of the applied

voltage.

36 | P a g e

RMS Block-

Figure 18: Simulink model of a root mean square (rms) calculation block.

This block measures the true root mean square value, including fundamental, harmonic, and DC

components, of an instantaneous current or voltage. The RMS value of the input signal is

calculated over a running average window of one cycle of the specified fundamental frequency,

where f(t) is the input signal and T is 1/(fundamental frequency). Since this block uses a running

average window, one cycle of simulation has to be completed before the output gives the correct

value.

The discrete version of this block allows you to specify the initial magnitude of the input signal.

For the first cycle of simulation the output is held to the RMS value of the specified initial input.

Three-Phase V-I Measurement

Figure 19: Simulink model of a three phase voltage-current measurement block.

The Three-Phase V-I Measurement block is used to measure instantaneous three-phase voltages

and currents in a circuit. When connected in series with three-phase elements, it returns the three

phase-to-ground or phase-to-phase peak voltages and currents.

The block can output the voltages and currents in per unit (pu) values or in volts and amperes.

37 | P a g e

If you choose to measure phase-to-ground voltages in per unit, the block converts the measured

voltages based on peak value of nominal phase-to-ground voltage:

where

If you choose to measure phase-to-phase voltages in per unit, the block converts the measured

voltages based on peak value of nominal phase-to-phase voltage:

where

If you choose to measure currents in per unit, the block converts the measured currents based on

the peak value of the nominal current:

where

Vnom and Pbase are specified in the Three-Phase V-I Measurement block dialog box.

38 | P a g e

Display Block

Figure 20: Simulink model of display block.

The Display block shows value of an inputted signal. It accepts real or complex signals of the

following data types:

• Floating point

• Built-in integer

• Fixed point

• Boolean

• Enumerated

Scope Block

Figure 21: Simulink model of an oscilloscope (scope).

The Scope block displays signal inputs with respect to simulation time and displays signal

generated during the simulation.

39 | P a g e

Protection Block

Figure 22: Simulink model for the protection sub-system.

The protection block is a sub-system that contains all the protection relays (shown in figure 22).

These include the under/over current relay, under/over voltage relay, under/over frequency relay,

rate of change of frequency (ROCOF) relay and the vector shift relay.

Figure 23: Relays found inside the protection sub-system block

40 | P a g e

Each relay is equipped with two display, one which indicate the status of the relay (‘1’ indicates

a trip status) and the other displays and log the time at which the relay was activated or trip. Each

relay is only activated once during the entire simulation, that is, at the first instance to which it

senses an abnormal condition or a condition to which it was designed to sense/activate.

The following is a detail description of all the relays contained in the protection block and their

corresponding setting.

Under/Over Current, Under/Over Voltage and Under/Over Frequency Relay

Figure 24: (a) Simulink model of Under/Over Current Relay model.

41 | P a g e

Figure 24: (b) Simulink model of Under/Over Voltage Relay model.

Figure 24: (c) Simulink model of Under/Over Frequency Relay model.

42 | P a g e

Figure 24 (a) depicts the Matlab/Simulink model of the under/over current relay. The operation

of the model is based on the actual relay, where the line current (all three phases) of the system is

monitored and compared to some preset thresholds (a maximum value for over current and

minimum value for under current) and if the line current goes over or under these thresholds for

a predetermined period then a trip signal is initiated.

In the model, the line current (Iabc) is continually monitor and compared to the set thresholds,

this comparison is done by using a ‘Relational Operator’, that is, instances where the line current

is greater than (>) or less than (<) the maximum or minimum current value respectively, it

outputs a signal to the On/Off delay. If this signal (output from the relational operator) remains at

the input of the on/off delay for longer than the preset time a ‘trip’ signal is initiated and the time

for which the trip signal was initiated is logged and display. It’s important to note that since an

‘OR’ gate was used at the output of the relay, for an abnormal condition in any of the three

phases, a trip signal is initiated.

The under/over voltage relay and the under/over frequency relay shown in figure 24 (b) and

figure 24 (c) respectively operates on the same principle as the under/over current relay. In the

case of the under/over voltage relay the only difference is that the parameter in which the relay

monitors, that is, the under/over voltage relay monitors the three phase voltage, while the

under/over current relay monitors three phase current and similarly the under/over frequency

relay monitors the system frequency. However the setting of these relay will be different from

each other.

43 | P a g e

The Rate of Change of Frequency Relay

Figure 24 (d): Simulink model of The Rate of Change of Frequency Relay (ROCOF).

Figure 24 (d) shows the Simulink model of the rate of change of frequency relay. Unlike the rest

of relay model describe thus far, the ROCOF relay accepts or monitor two inputs (frequency and

terminal voltage Vt), therefore before the relay is activated two conditions must be satisfied. The

frequency is fed into a ‘Discrete Derivative’ block which calculates the rate of change of

frequency with time �𝑑𝑓𝑑𝑡�, the absolute value of the rate of change of frequency �𝑑𝑓

𝑑𝑡� it is then

compared (using a Relational Operator) to the ROCOF threshold and if it exceeds this threshold,

the output of the relational operator goes ‘true’ and a ‘1’ is sent into the first input of the ‘AND’

gate. However before the ‘AND’ gate can output a signal to initiate a trip, another condition must

be met, that is, the terminal voltage Vt (pu) of the generator is compared to a set threshold and if

it exceeds this threshold the second input of the ‘AND’ gate goes ‘true’ (that is both condition is

satisfied), hence the output of the ‘AND’ gate also goes ‘true’ which immediately starts the delay

44 | P a g e

count down. If the ‘AND’ output remains ‘true’ for longer period than a predetermine time (set

by the On Delay) then and only then a trip signal is initiated and the time of the trip is logged.

Vector Shift Relay

Figure 24 (e): Simulink model of a Vector Shift Relay.

Figure 24 (e) depicts the Simulink model of a vector shift relay. Similar to the ROCOF relay, the

vector shift relay also accepts or monitors two inputs (three phase voltage Vabc and terminal

voltage Vt), and therefore two conditions must also be satisfied before the relay can activate.

The relay monitors the three phase waveform and counts every complete cycle by detecting the

rising edge of the wave, and at the same time the duration of each cycle or the period is

measured. Since the model operates at frequency (f) of 60 Hz, therefore the period (T) will be

45 | P a g e

equal to (1/f) 0.01667 seconds. Hence the model computes the duration of each period by

dividing the cycle time by the number of completed period/s and then compares this value to

0.01667 seconds and any time value grater or less than the set threshold the first condition is

reached. But before a trip is initiated the second condition must be met, that is, if the terminal

voltage (Vt) exceeds the set threshold and both conditions are met then and only then a trip

signal is sent and the time is logged.

46 | P a g e

SIMULATION RESULTS

Normal Conditions

The complete model was simulated at normal condition for 5 seconds and the results obtained

are shown below.

Note: Since the purpose of the simulation is to compare performance of the relays with respect to

time, a small sampling time was chosen for the simulation, more specifically 50 micro seconds.

Therefore 5 seconds will be more than adequate for the entire simulation run time.

Figure 25 (a), (b) and (c) shows the results obtained from the three synchronous generators used

in the model. In each figure, the mechanical power input (Pmec), excitation voltage (Vf),

terminal voltage (Vt) and speed all in per-unit is displayed. From looking at all three of the

figures obtained for the generators (SM1, SM2 and SM3), it can be clearly seen that they

system/model initially takes approximately 1 second to reach a steady state condition. Using the

graphs, the steady state values of Pmec, Vf, Vt and speed can be approximated to the following:

Synchronous Machines

Steady State Approximated Values (pu)

Pmec Vf Vt Speed SM1 0.255 1.500 1.000 1.000 SM2 0.315 0.910 1.000 1.000 SM3 0.289 1.360 1.000 1.000

Table 1: Steady state parameters for the Synchronous Machines used in the model, under normal

operating conditions.

47 | P a g e

Figure 25 (a): Simulation result of Synchronous Machine One (SM1).

Figure 25 (b): Simulation result of Synchronous Machine Two (SM2).

48 | P a g e

Figure 25 (c): Simulation result of Synchronous Machine Three (SM3).

Figure 26 (a) and (b) shows the 3 phase voltages and currents at Bus 1 and 2 found in the

system/model. The first figure (fig 26 a) shows the voltages and current for a three (3) seconds

period after the simulation was started. It can be seen that the voltages Vabc at Bus 1 (i.e.

Vabc_B1) and Vabc at Bus 2 (i.e. Vabc_B2) are relatively constant throughout the simulation

while the currents Iabc at Bus 1 (i.e. Iabc_B1) and Iabc at Bus 2 (i.e. Iabc_B2) takes

approximately one (1) second after the simulation has started to become constant. It can also be

seen that the voltages at both Bus is approximately the same while the currents vary in value

from each other.

Figure 26 (b) shows and expanded portion of figure 26 (a).

49 | P a g e

Figure 26 (a): Simulation result for 3 phase voltages and currents at bus 1 and bus 2.

Figure 26 (b): Expanded view of the 3 phase voltages and currents at bus 1 and bus 2.

50 | P a g e

Figure 27 (a): Simulation result for the 3 phase rms voltages at bus 1&2.

Figure 27 (b): Simulation result for the 3 phase rms currents at bus 1&2.

51 | P a g e

Figure 27 a, and b shows the 3 phase rms voltages and currents at bus 1 and 2 respectively, here

again it can be clearly seen that the voltages in each phase are constant (approximately 13790

volts) after about 1 second into the simulation. The currents also follow the same pattern but vary

in value at each bus, that is, the average rms value for the currents in all three phase is 61.60

Amps at bus 1 and 84.72 Amps at bus 2.

Figure 28: Simulation result of the rate of change of frequency and frequency for bus 1 & bus 2.

The final figure (fig 28) shows the frequency at bus 1 and 2 and their respective rate of change of

frequency. As expected, both the frequency and the rate of change of frequency reach a steady

state or become constant after the 1 second mark. It can also be observed that for a small change

in frequency (60 to 60.4) results in a relatively large ‘rate of change of frequency’ or large df/dt

(0 to 14).

52 | P a g e

Islanded Condition

Scenario 1: Formation of a Major Island (Loss of Grid)

As mention earlier, a major island is formed when the interconnection between Garden of Eden

(GOE) and Versailles is lost, hence completely isolating Versailles and Lenora (together) from

the rest of the DIS or grid, a scenario which arises when CB1 (shown in figure 12) is in the open

position.

To achieve this scenario and for purpose of this project, CB1 was pre configured to open on all

three phase, 3 seconds after the simulation was started hence forming a major island to illustrate

the effects that an unintentional island has on a power distribution network.

Hence the following results were obtained from this simulated scenario.

Figure 29 (a): Simulation result for Synchronous Machine One (SM1) for a major islanded

condition.

53 | P a g e

Figure 29 (b): Simulation result for Synchronous Machine One (SM2) for major islanded

condition.

Figure 29 (c): Simulation result for Synchronous Machine One (SM3) for major islanded

condition.

54 | P a g e

Figure 29 a, b, and c shows the simulation results three synchronous generators, SM1, SM2 and

SM3 under a major islanded condition. All three generators basically responded to the islanded

or loss of grid condition in similar manner, that is, after the island was formed (3 seconds into the

simulation), there were an immediate increase in mechanical power (Pmec) supplied to the

generator since due to the loss in grid the three generator had to supplied the required power

demand on their own, hence there were an increase in load to each generator. Also to counteract

this increase there were also an increase in excitation voltage (Vf) to the alternator, we can also

see that the terminal voltage (Vt) and speed of the generator was also affected by an increase

load at each generator.

Figure 30 (a): Simulation result for the 3 phase rms currents at bus 1&2 for major islanded

condition.

55 | P a g e

Figure 30 (b): Simulation result for the 3 phase rms voltages at bus 1&2 for a major islanded

condition.

Figure 31: Simulation result for the 3 phase voltages and current at bus 1&2 for a major islanded

condition.

56 | P a g e

Figure 31 shows the three phase voltages and currents at bus 1 and 2 and the effect that an

islanding condition have on these values. Here we see a change in voltages or voltage wave form

(highlighted in fig 31) at the instant when the island was formed (3 seconds into the simulation).

We can also see a significant change in the currents or current waveform at both buses.

Figure 32: Simulation result of the rate of change of frequency and frequency at bus 1 and bus 2

during a major islanded condition.

The above figure shows the effect that an islanded condition has on the frequency of a power

system or distribution network. From the figure we can see that the formation of the island had

the same effect on the frequency at both the bus. At the instant where the island was formed, we

can observer that there was a sharp decline in frequency, that is, the frequency drop from 60 Hz

to about 58 Hz in very short time (approximately 0.25 second). The figure also shows the

corresponding rate of change of frequency (df/df) for this change in frequency, where a change

of 60 Hz to 58 Hz corresponds to a df/dt of -12 Hz/s (where the minus sign indicates a drop in

frequency).

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Figure 33 (a): Results obtained from the protection block at bus 1 for a major islanded condition.

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Figure 33 (b): Results obtained from the protection block at bus 2 for a major islanded condition.

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Trip Status Trip Time (s) Detection Time (s) Trip Status Trip Time (s) Detection Time (s)ROCOF 1 3.068 0.068 ROCOF 1 3.057 0.057Vector Shift 1 3.073 0.073 Over Current 1 3.107 0.107Over Current 1 3.120 0.120 Under Frequency 1 3.135 0.135

Under Frequency 1 3.135 0.135 Over Voltage 1 3.144 0.144

Over Voltage 1 3.144 0.144 Under Voltage 1 3.477 0.477

Under Voltage 1 3.477 0.477 Vector Shift 1 4.175 1.175Under Current 0 ___ ___ Under Current 0 ___ ___

Over Frequency 0 ___ ___ Over Frequency 0 ___ ___

RelaysBUS 1 BUS 2

Relays

Table 2: Combine results for Relay Protection Blocks 1 and 2 for a major islanded condition.

The table above shows the results obtained for the relay protection blocks 1 and 2 monitoring

buses 1 and 2 respectively. The table shows the ‘trip statuses’, ‘trip time’ and the ‘island

detection time’ for each relay. The trip status is represented by either a ‘1’ or a ‘0’, where ‘1’

indicates a trip or relay activation and a ‘0’ represent no detection. Since the island condition

occurred exactly three seconds into the simulation, the trip time shows the time elapse after the

specific relays were activated and finally the detection time shows the time take for the relay to

respond to the island condition in ascending order.

Comparing the relays performance by detection time, where the shortest time taken to detect the

island condition the greater the performance we see that at both busses or at both protection

block the ROCOF relay out performs the others. It can also be seen that at bus 1 the relay with

the longest detection time was the under voltages relay, similarly the relay with the longest

detection time at bus 2 was the vector shift relay. And finally the under current and the over

frequency failed entirely to detect the island condition.

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Figure 34 (a): Graph showing comparison of the relays detection time at bus 1.

Figure 34 (b): Graph showing comparison of the relays detection time at bus 2.

0.000

0.050

0.100

0.150

0.200

0.250

0.300

0.350

0.400

0.450

0.500

Relays

Dete

ctio

n Ti

me

(s)

Relay Peotection at Bus 1

ROCOF

Vector Shift

Over Current

Under Frequency

Over Voltage

Under Voltage

0.000

0.200

0.400

0.600

0.800

1.000

1.200

Relays

Dete

ctio

n Ti

me

(s)

Relay Protection at Bus 2

ROCOF

Over Current

Under Frequency

Over Voltage

Under Voltage

Vector Shift

Relay Performance

Decrease

Relay Performance

Decrease

61 | P a g e

Figure 34 (a) and (b) shows a graphical comparison of the different relays detection time, where

the performance of each relay decreases with an increase in detection time. It can be observe that

the detection time or the behavior of each relay differs depending on the location placed or the

point at which it is monitoring (i.e. bus 1 or bus 2). For example the vector shift relay was the

second relay at bus 1 to detect the island but at bus 2 it was the last, that is, at bus 1 it took 0.073

seconds to detect the island but at bus 2 it took 1.175 seconds which is approximately 16 times

longer. It can also be observed that over current, under frequency and the over voltage relays trip

in the same order at both buses but with different detection times.

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Scenario 2: Formation of a Minor Island.

As stated earlier, a minor island is formed when the DGs’ at Lenora is disconnected or isolated

from Versailles and the rest of the DIS. Since there is only a single connection between Lenora

and Versailles, any disruption in this connection results in the formation of an island.

For the purpose of this project this scenario will be achieve by intentionally configuring CB2

(shown in figure 12) to open on all three phases 3 seconds into the simulation thus forming a

minor island and observing the effects of the island condition on the portion of the network.

Hence the following results were obtained from this simulated scenario.

Figure 35 (a): Simulation result for Synchronous Machine One (SM1) for minor islanded

condition.

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Figure 35 (b): Simulation result for Synchronous Machine One (SM2) for minor islanded

condition.

Figure 35 (c): Simulation result for Synchronous Machine One (SM3) for minor islanded

condition.

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Figures 35 (a), (b) and (c) shows the results obtained for the three synchronous

machines/generators (SM1, SM2, and SM3). It can be seen that SM1 and SM2 located at

Versailles was not affected much by the minor island formed at Lenora, that is, the operating

parameters (Pmec, Vf, Vt and the speed) were all maintained at an appreciable level. However

the DG at Lenora was severely affected since it was the source of the island and it was left to

supply a load that was far over its capacity. From figure 35 (c) we can see that due to an increase

in load there were an increase in mechanical power (Pmec) and excitation voltage (Vf) required

and since the DG could not have satisfied this increased load demand, the terminal voltage (Vt)

and speed decreased.

Figure 36 (a): Simulation result for the 3 phase rms currents at bus 1&2 for minor islanded

condition.

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Figure 36 (b): Simulation result for the 3 phase rms voltages at bus 1&2 for a minor islanded

condition.

For the 3 phase rms currents and voltages at bus 1and 2 illustrated in figures 36 (a) and (b)

respectively, we see again that there were no major disturbance in voltages and current at bus 1

located at Versailles, however there were severe disturbances in the currents and voltages at bus

1 located at Lenora due to the islanded condition of the DG.

In figure 37 we can observe that there was some amount of disturbance in the frequency at bus 1,

however the extent of the disturbance would be determine by the protection block and whether it

cause a trip in any of the frequency monitoring relays. Conversely we can notice that the

frequency at bus 2 was significantly affected by the formation of this islanded condition.

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Figure 37: Simulation result of the rate of change of frequency and frequency at bus 1 and bus 2

during a major islanded condition.

Figure 38 (a): Results obtained from the protection block at bus 1 for a minor islanded condition.

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Figure 38 (b): Results obtained from the protection block at bus 2 for a minor islanded condition.

Figures 38 (a) and (b) shows the results obtained from protection blocks 1 and 2 respectively, at

buses 1 and 2. From figure 39 (a) it can be observed that there were no trips in any of the relays

in protection block 1 (which monitors bus 1) resulting from the islanded condition, this was

expected since the results obtained (for the minor island) showed no disturbances in the voltages,

currents or frequency. However figure 38 (b) showed multiple trips in various relays, which is

shown in details in the table below.

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Trip Status Trip Time (s) Detection Time (s)Vector Shift 1 3.035 0.035ROCOF 1 3.036 0.036Over Current 1 3.102 0.102Under Frequency 1 3.115 0.115Over Voltage 1 3.136 0.136Under Voltage 1 4.743 1.743Under Current 0 ___ ___

Over Frequency 0 ___ ___

RelaysProtection Block 2/BUS 2

Table 3: Results obtained for Relay Protection Block 2 for a minor islanded condition.

The table above shows the results obtained for the relay protections block 2 monitoring bus 2.

Here again the table shows the ‘trip statuses’, ‘trip time’ and the ‘island detection time’ for each

relay.

Comparing the relays performance by detection time, where the relay performance decreases

with the increase in detection time, we see that the vector shift relay has the shortest detection

time (0.035 seconds), that is, it was first to detect the islanded condition and the ROCOF relay

comes in second at 0.036 seconds and the last to detect the island was the under voltage relay

taking 1.743 seconds.

And here again the under current and the over frequency failed entirely to detect the island

condition.

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Figure 39: Graph showing comparison of the relays detection time at bus 2.

Figure 39 shows a graphical representation of the different relays detection time. Here is can be

seen that the ROCOF and the vector shift relays had the fastest detection time with a difference of

0.001 seconds. It can also be observed that over current, under frequency and the over voltage

relays trips were nearer to each other and in the same order as noticed in the first scenario or in the

major islanded condition.

0.000

0.200

0.400

0.600

0.800

1.000

1.200

1.400

1.600

1.800

Relays

Dete

ctio

n Ti

me

(s)

Relay Protection at Bus 2

Vector Shift

ROCOF

Over Current

Under Frequency

Over Voltage

Under Voltage

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CONCLUSION

Distributed generator interconnections near consumers have created new challenges for

protection engineers. The typical protection configurations such as unplanned islanding and

reclosing of distributed generator systems need to be address. Section 4.4.1 of the IEEE 1547

standard states: “For an unintentional island in which the DG energizes a portion of the area

electrical power system through the point of common coupling, the DG interconnection system

shall detect the island and cease to energize the Area electrical power system within one second

of the formation of an island” [1].

This thesis describes and compares different local islanding detection techniques. Fast and

accurate detection of islanding is one of the major challenges in today’s electrical power

distribution system with many distribution systems already having significant introduction of

DGs. Islanding detection is also important as islanding operation of distributed system is seen a

viable option in the future to improve the reliability and quality of the power supplied.

From the results obtained from the various simulations, it is apparent that anti-islanding relays

such as the Rate of Change of Frequency (ROCOF) and the Vector Shift relay has significant

performance with respect to detection time over traditional relays, such as, Under/Over Current,

Under/Over Voltage and Under/Over Frequency relays, where the ROCOF and Vector Shift

relays had a detection time of at least three (3) times faster that these traditional protection

relays. Also some relays (over frequency and the under current) relays failed entirely to detect

the islanded condition in both scenarios.

Consequently from the research carried out and the results/evidence provided by the

Matlab/Simulink simulations and also in keeping with international standards (more so IEEE

1547), it is of the views of the researcher that the implementation of these anti-islanding relays

(ROCOF and Vector Shift) on electrical power distribution system and more so, those containing

Distribution Generators is imperative for maintaining good quality of power and also for safe and

effective operation.

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RECOMMENATION

The results obtained showed evidence that the Rate of Change of Frequency and the Vector Shift

relays were better at detecting the formation of island than the traditional relays that is currently

used by the national utility (GPL). It was also seen from the simulation the effects that

unintentional islanding can have on a power distribution network. Therefore to minimize these

effects and also in keeping with international standards for interconnected systems, it is therefore

recommended that these anti-islanding relays (ROCOF and Vector Shift) are implemented within

the DIS at points where may possess potentials for the formation of island.

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