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Kenny samaroo methodology of selection, setting and analysis of anti-islanding protection for distribution generation system

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  • Sir I am currently a PG Student from India. I first want to thank you for sharing this report. I am currently working on controlled island operations in Solar PV and I would like to get in touch with you. Can you please send me your mail id to vigneshgeee@gmail.com.
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  • 1. 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) Electrical Engineering Faculty of Technology University of Guyana August 24, 2012
  • 2. 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 2|Page
  • 3. ABSTRACTWith the daily increasing demand for power, and need for alternative power generationtechnologies, such as, fuel cell, wind & water turbine and photovoltaic systems, customerdemands for better power quality and reliability are forcing the power companies to movetowards distributed generations (DG).Islanding occurs when a portion of the distribution system becomes electrically isolated from theremainder of the power system yet continues to be energized by distribution system. It isimportant when using DG in an interconnected system that the power distributed system iscapable of detecting an unintentional islanding condition.Current IEEE interconnection standards (IEEE 1547) mandate that control and protectionmeasures should be in place to lessen the probability of an unintentional island, and to minimizethe duration of an islanding condition, if one should occur. Typically, a distributed generatorshould be disconnected within 100 to 300 ms after loss of main supply [1]. To achieve this eachdistributed generator must be equipped with an islanding detection device or anti islandingdevices, 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. 3|Page
  • 4. Table of ContentsABSTRACT.................................................................................................................................................. 3List Of Tables ............................................................................................................................................... 5List Of Figures .............................................................................................................................................. 6ACKNOWLEDGEMENT ............................................................................................................................ 9INTRODUCTION ...................................................................................................................................... 10 Background ............................................................................................................................................. 10 Statement Of The Problem...................................................................................................................... 12SCOPE OF WORK ..................................................................................................................................... 14 Overview ................................................................................................................................................. 14 Literature Review.................................................................................................................................... 15 Rationale for anti-islanding protection: .............................................................................................. 15 Remote Islanding Detection Techniques ............................................................................................ 16 Local Detection Techniques................................................................................................................ 17METHODS/DESIGN APPROACH ........................................................................................................... 26 Detection of Islanded Power Systems ..................................................................................................... 26 Network Studied ..................................................................................................................................... 27 Simulation model .................................................................................................................................... 30 Conditions for Islanding ......................................................................................................................... 31 Model Description .................................................................................................................................. 33SIMULATION 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. .......................................................................................... 62CONCLUSION ........................................................................................................................................... 70RECOMMENATION ................................................................................................................................. 71BIBLIOGRAPHY ....................................................................................................................................... 72 4|Page
  • 5. List Of TablesTables 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. 5|Page
  • 6. List Of FiguresFigures 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 6|Page
  • 7. 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. 7|Page
  • 8. 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. 8|Page
  • 9. ACKNOWLEDGEMENTI would like to thank the University of Guyana’s Faculty of Technology which provided me theopportunity to conduct this study. In particular, my supervisor, Dhanraj Bachai, whoseknowledge 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 neededto help make this project a success. Also I would like to thank all my class mates for all thethoughtful and mind stimulating discussions we had, which prompted us to think beyond theobvious.Finally I cannot end without thanking my family and more so my wife ‘Priea Samaroo’, onwhose encouragement, support, and advice, I have relied on throughout my studies. 9|Page
  • 10. INTRODUCTIONBackgroundElectric power industries were traditionally designed with the power distribution systemassuming the primary substation being the sole source of power generation (as shown in Figure1). Figure 1: Power system with centralized generation.With the introduction of Distributed Generation (DG) this assumption changes, that is, powersource/s (DG) are placed within the power distribution system at points where support for activeand 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. 10 | P a g e
  • 11. Generating power on-site, rather than centrally, reduces cost of transmission, complexity, andinefficiencies associated with transmission and distribution.Recently there has been significant increase in the utilization of interconnected DG. Theincreasing incursion of DG was driven by improving cost and performance of both old-line andnew technologies, and by customers and third parties seeking to reduce costs, increase localcontrol of the energy resource, and increasing awareness of the important role of power systemreliability [1].Distribution generation generally applies to relatively small generating units at or near consumersite/s to meet specific consumer needs, to support economic operation of the existing distributiongrid, or both. Reliability of service and power quality is enhanced by the proximity to theconsumer and efficiency is often increased.While central power systems remain crucial to the local utility, their flexibility is limited. Largepower generation facilities are very expensive and require immense transmission and distributionnetwork to transmit the power. DG compliments central power by providing a relatively lowcapital cost in response to incremental increase in power demand while avoiding transmissionand distribution capacity upgrades by placing power source/s within the already existinggrid/network where it is most needed and by having flexibility to send power back into the gridwhen 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 andoperation that makes them more or less suitable to meet the various aim of installing DG. 11 | P a g e
  • 12. Statement Of The ProblemDG possesses inherent advantages, conversely it’s not without disadvantages. As a result, DGinterconnection 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 orPoint of Common Coupling (PCC) between DG plant and the rest of the power system in theevent 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 fromthe remainder of the power system, yet continues to be energized by DG connected to theisolated 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 12 | P a g e
  • 13. 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 isoften done where the DG provides backup power to the facility where it is installed. However,considerable engineering effort, control functionality, and communications infrastructure arenecessary to make intentional islanding viable where the island includes a portion of primarysystem and other loads. Even greater requirements are necessary to coordinate the operation ofmore than one DG in an island. In general, if provision has not been made for islanded operationbeyond 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 lossof main supply [1]. Hence there’s need to quickly detect and eliminate unintentional DGsupported islands in the event of a faulted condition. Ideally, the fault should be detected by theDG protection system and the DG tripped before the formation of an island. To achieve this eachdistributed generator must be equipped with an islanding detection device or anti islandingdevices, such as, vector shift relay and ROCOF relay [4] [5]. Before After Figure 3: Utility Network before and after islanding has occurred. 13 | P a g e
  • 14. SCOPE OF WORKOverviewThis project will involve examining the national utility (GPL) network (single line diagrams) toidentify potential unintentional islanding conditions, subsequently an equivalent of all theportions of the network with potential for islanding will be produced (in the form of a single linediagram). This equivalent single line diagram of the network containing the island/s will then beused 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/undercurrent 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 toevaluate and determine the performance of these relays for the purpose of assisting electricalprotection engineers in selecting the most appropriate protective devices and their correspondingsettings for DG systems. 14 | P a g e
  • 15. 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]. Islanding Detection Remote Local Technique TechniquePower Line Transfer Trip Passive Active Hybrid Signaling Scheme Technique Technique Technique Scheme Positive Rate of Change Reactive Power Voltage and Voltage/Current Rate of Change Vector Surge Phase/Frequency Feedback and of Output Export Error Reactive Power Unballance of Frequency Detection Shift Method Voltage Power Detection Shift ImballanceUnder/Over Under/Over Voltage Current Figure 4: Islanding detection techniques. 15 | P a g e
  • 16. Remote Islanding Detection TechniquesRemote islanding detection techniques are based on communication between utilities and DGs.Although these techniques may have better reliability than local techniques, they are expensiveto implement and hence uneconomical .Some of the remote islanding detection techniques are asfollows: a) Power line signaling schemeThese methods use the power line as a carrier of signals to transmit islanded or non-islandedinformation on the power lines. The apparatus includes a signal generator at the substation that iscoupled into the network where it continually broadcasts a signal. Each DG is then equippedwith a signal detector to receive this transmitted signal. Under normal operating conditions, thesignal is received by the DG and the system remains connected. However, if an island stateoccurs, the transmitted signal is cut off because of the substation breaker opening and the signalcannot 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 arealso 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 isrequired. A transformer of this voltage capacity can be very expensive.Another problem for power line communication is the complexity of the network and theaffected networks. A perfectly radial network with one connecting breaker is a simple exampleof island signaling; however, more complex systems with multiple utility feeders may find thatdifferentiation 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 andreclosers 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, thetransfer trip system determines which areas are islanded and sends the appropriate signal to the 16 | P a g e
  • 17. DGs, to either remain in operation, or to discontinue operation. Transfer trip has the distinctadvantage similar to Power Line Carrier Signal that it is a very simple concept. With a radialtopology that has few DG sources and a limited number of breakers, the system state can be sentto the DG directly from each monitoring point [5] [6].The weaknesses of the transfer trip system are better related to larger system complexity cost andcontrol. 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 substationgains control of the DG, the DG may lose control over power producing capability. If the transfertrip method is implemented correctly in a simple network, there are no non-detection zones ofoperation.Local Detection TechniquesIt 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 techniquesPassive 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 thresholdsset for these parameters. Special care should be taken while setting the threshold value so as todifferentiate islanding from other disturbances in the system. Passive techniques are fast and theydon’t introduce disturbance in the system but they have a large non detectable zone (NDZ) wherethey 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 𝑑𝑝 𝑑𝑡The rate of change of output power, , at the DG side, once it is islanded, will be much greaterthan that of the rate of change of output power before the DG is islanded for the same rate of 17 | P a g e
  • 18. load change[7]. It has been found that this method is much more effective when the distributionsystem with DG has unbalanced load rather than balanced load. [5] [8] b) Rate of change of frequency 𝑑𝑓 𝑑𝑡The rate of change of frequency, , will be very high when the DG is islanded. The rate ofchange of frequency (ROCOF) can be given by [9] = ∗ 𝑓 𝑑𝑓 ∆𝑝 𝑑𝑡 2𝐻𝐺ROCOF: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. 𝑑𝑓Large systems have large H and G where as small systems have small H and G giving larger 𝑑𝑡value for ROCOF relay monitors the voltage waveform and will operate if ROCOF ishigher than setting for certain duration of time. The setting has to be chosen in such a way thatthe relay will trigger for island condition but not for load changes. This method is highlyreliable when there is large mismatch in power but it fails to operate if DG’s capacity matcheswith its local loads [5]. Figure 5: Equivalent Circuit of Synchronous Generator equipped with ROCOF Relay operating parallel with Utility [4,6]. 18 | P a g e
  • 19. Figure 5 presents an equivalent circuit of a synchronous generator equipped with a ROCOFrelay 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 thegenerator 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 afault 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 powerimbalance causes transients in the islanded system and the system frequency starts to varydynamically. Such system behavior can be used to detect an islanding condition. However, ifthe 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 thissituation. [4, 5] The rate of change of frequency is calculated considering a measure windowover 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 thevalue of the rate of change of frequency is higher than a threshold value, a trip signal isimmediately sent to the generator CB. Typical ROCOF settings installed in 60-Hz systems arebetween 0.10and 1.20 Hz/s. Another important characteristic available in these relays is a blockfunction by minimum terminal voltage. If the terminal voltage drops below an adjustable levelVmin , the trip signal from the ROCOF relay is blocked. This is to avoid, for example, theactuation of the ROCOF relay during generators start-up or short circuits. [5] c) Vector Shift DetectionVector Shift relay measures the change of phase angle of the voltage waveform to a knownreference waveform. When an island state occurs, there can be an immediate phase shift by theDG to accommodate the change in power requirements. Once again, a threshold is set at themaximum phase jump allowed and if the DG system exceeds that threshold, the relay istriggered. [22]A synchronous generator equipped with a VS relay operating in parallel with a distributionnetwork is depicted in Figure 6. 19 | P a g e
  • 20. 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 V T and the generator internal voltage E Idue to the generator current I SG passing through the generator reactance X d . Consequently, thereis a displacement angle between the terminal voltage and the generator internal voltage, whosephasor 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, thesynchronous machine begins to feed a larger load (or smaller) because the current I SYS provided(or consumed) by the power grid is abruptly interrupted. Thus, the generator begins to decelerate(or accelerate).Therefore, the angular difference between V T and E I is suddenly increased (or decreased) andthe terminal voltage phasor changes its direction, as shown in Fig. 7(b). Analyzing suchphenomenon in the time domain we see that the instantaneous value of the terminal voltagejumps to another value and the phase changes as depicted in Fig. 8, where the point ‘A’ indicatesthe islanding instant. Additionally, the frequency of the terminal voltage also changes. Thisbehavior 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 newmeasurement 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 ofactive power in the islanded system, as shown in Fig. 8. 20 | P a g e
  • 21. This variation of the cycle duration results in a proportional variation of the terminal voltageangle, which is the input parameter of VS relays. If the variation of the terminal voltage angleexceeds a predetermined threshold, a trip signal is immediately sent to the CB. Usually, VSrelays allow this angle threshold to be adjusted in the range from 2 to 20. The relay is alsodisabled if the magnitude of the terminal voltage drops below a threshold value to avoid falseoperation. Figure 7: Internal and terminal voltage phasors (a) before opening with CB (b) after opening with CB. Figure 8: Voltage Vector Surge. 21 | P a g e
  • 22. d) Voltage unbalanceOnce the islanding occurs, DG has to take change of the loads in the island. If the change inloading is large, then islanding conditions are easily detected by monitoring several parameters:voltage magnitude, current magnitude, and frequency change. However, these methods may notbe effective if the changes are small. As the distribution networks generally include single-phaseloads, 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 innetwork condition [11] [12]. Under/Over VoltageUnder and over voltage are also used for passive islanding detection, and often as acomplementary device coupled with frequency monitoring. Voltage variations occur as a resultof a mismatch of reactive power. This relay operates on the principle that an excess of reactivepower mismatch will drive the voltage up and a deficit of reactive power will drive the voltagedown. 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 islandstates that frequency effects alone cannot. Unfortunately, there is limited experience indicatingthat the reactive power measurement relay will have higher performance than frequencyvariations. As real power draw is often much greater than reactive power, a loss of mains is morelikely to significantly change the active power than the reactive power. 22 | P a g e
  • 23. 2. Active detection techniquesWith active methods, islanding can be detected even under the perfect match of generation andload, which is not possible in case of the passive detection schemes. Active methods directlyinteract with the power system operation by introducing perturbations. The idea of an activedetection method is that this small perturbation will result in a significant change in systemparameters when the DG is islanded, whereas the change will be negligible when the DG isconnected to the grid. a) Reactive power export error detectionIn 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 ifthe level of reactive power flow is not maintained at the set value. For the synchronous generatorbased DG, islanding can be detected by increasing the internal induced voltage of DG by a smallamount from time to time and monitoring the change in voltage and reactive power at theterminal where DG is connected to the distribution system. A large change in the terminalvoltage, with the reactive power remaining almost unchanged, indicates islanding. [16]The majordrawbacks of this method are it is slow and it cannot be used in the system where DG has togenerate power at unity power factor. b) Phase (or frequency) shift methodsMeasurement of the relative phase shift can give a good idea of when the inverter based DG isislanded. A small perturbation is introduced in form of phase shift. When the DG is gridconnected, the frequency will be stabilized. When the system is islanded, the perturbation willresult in significant change in frequency. The Slip-Mode Frequency Shift Algorithm (SMS) usespositive feedback which changes phase angle of the current of the inverter with respect to thedeviation of frequency at the PCC. A SMS curve is designed in such a way that its slope isgreater than that of the phase of the load in the unstable region. [5] [17] 23 | P a g e
  • 24. The drawback of this method is that the islanding can go undetected if the slope of the phase ofthe load is higher than that of the SMS line, as there can be stable operating points within theunstable zone [18]. 3. Hybrid detection schemesHybrid methods employ both the active and passive detection techniques. The active technique isimplemented only when the islanding is suspected by the passive technique. Some of the hybridtechniques 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 𝑣 + 𝑠𝑞given as 𝑉𝑈 = 𝑣 − 𝑠𝑞V+Sq and V-Sq are the positive and negative sequence voltages, respectively. Voltage spikeswill be observed for load change, islanding, switching action, etc. Whenever a VU spike isabove the set value, frequency set point of the DG is changed. The system frequency willchange if the system is islanded [19]. b) Technique based on voltage and reactive power shiftIn 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].instead of current phase shift. The d-axis current shift, 𝑖 𝑑 or reactive power shift is given as 𝑘The ARPS uses the same mechanism as ALPS, except it uses the d-axis current shift 24 | P a g e
  • 25. 𝑇 𝑎𝑣′ − 𝑇 𝑣 (𝑘) 𝑖 = 𝑘𝑑� 𝑘 � 𝑇𝑣 𝑑 (𝑘)Where;Tav is the average of the previous four voltage periods.Uav is the mean of TavTv is the voltage periodsUV is the mean of TVkd is chosen such that the d-axis current variation is less than 1 percent of q-axis current ininverters normal operation. The additional d-axis current, after the suspicion of island, wouldaccelerates the phase shift action, which leads to a fast frequency shift when the DG is islanded[5]. 25 | P a g e
  • 26. METHODS/DESIGN APPROACHDetection of Islanded Power SystemsAn islanding situation should be detected soon after the island is formed. The basicrequirements 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. 26 | P a g e
  • 27. Network StudiedA detail examination of GPL’s DIS revealed that there were at least three cases that possess potential forislanding. Of these three cases, the Versailles/Lenora area was chosen to carry out the study, since theonly DGs present in the DIS was found to be located in this area. From Garden Of Eden 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 weremade to the system that was not documented or updated in the one line diagram, changes suchas, the ‘A1’ and ‘A3’ generator sets were no longer operational and there were three generatorssets present at Lenora instead of two show in the diagram. Hence taking the networkconfiguration as shown in the Figure 9 and the changes that were made to the system, a modifiedequivalent diagram was produced (shown in Figure 10). 27 | P a g e
  • 28. CB1 CB2 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,A2and A3) at Lenora all are the same model, that is, all having the same parameters, for connivancethey were combined and model as a single generator at each location. The equivalent one linediagram is made up of the following:Generator G1 (A6) Generator G2 (A2, A4, A7 & A8)Model#: GM AB20-24 4 Mobile Caterpillar Generator set3250 KVA 60Hz 4160V Model #: 3516 2000 KVA 60Hz 480VGenerator G3 (A1 & A2) Model #: 35163 Mobile Caterpillar Generator set 2000 KVA 60Hz 480V 28 | P a g e
  • 29. Transformer T13750KVA 4160/13800V Δ/ΥTransformer T2 (4) & T3 (3) Garden of Eden (GOE) Interconnection2500KVA 480/13800V Δ/Υ 3 phase current SourceFeedersWest Bank approx 5 MWWest Coast approx 9 MWIn creating the model shown in figure 11, it was found that Versailles and Lenora together have agenerating capacity of 17.25 MVA (11.25 MVA at Versailles and 6.0 MVA at Lenora) pluspower imported from GOE which is approximately 5.0 MVA, hence this gives a total of 22.25MVA. However the total load demand of the two feeders (west coast and west bank) connectedto Versailles and Lenora was found to be approximately 14 MVA, thus having a surplus of 8.25MVA in generation. Therefore an assumption was made that all the generators either atVersailles or at Lenora was not in operation at the same time, hence this was taken intoconsideration when creating the model, that is, instead of combining all four of the mobileCaterpillar sets at Versailles only two was combined and modeled to produce 4 MVA, however,all three at Lenora was model as being in operation. 29 | P a g e
  • 30. Simulation modelIn order to investigate the performance of the different techniques used in island detection asimulation model was implemented. The model is based upon a specific portion of GPL’sDemerara Interconnected System (DIS) (shown in figure 10), and was created so that the modelreflects the real system as much as possible. The behavior of the simulated system must besimilar 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) andis 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 feederfor the west bank and one for the west coast each consuming 5 MW and 9 MW respectively andvarious monitoring and measuring blocks. 30 | P a g e
  • 31. The synchronous generated G1 is rated at 3250 KVA 60Hz 4160 V, G2 is a combination of fourmobile Caterpillar sets each rated at 2000 KVA 60Hz 480 V and G3 is a combination of threemobile 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 fourindividual transformer each with ratings of 2500KVA 480/13800V Δ/Υ and T3 is a combinationthree individual transformer all with same rating as ones in T2.The three phase source representing GOE contribution to Versailles is based on the maximumshort circuit current level during a line-to-ground fault between Versailles and GOEinterconnection, multiplied by the line-to-line voltage (VA).Note: For all combination of generators and transformers, the rated power is summed and allimpedances are parallel.Conditions for IslandingThere 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. 31 | P a g e
  • 32. G1 T1 CB1 B1 G2 ~ CB2 3 Phase Source GOE T2 West Bank Major Island G3 T3 Minor Island B2 West CoastFigure 12: Distinction between Major and Minor Island and Conditions for Islanding in the Network Studied. 32 | P a g e
  • 33. Model DescriptionSynchronous Machine (Alternator, Diesel Engine Speed & Voltage Control)Figure 13: Simulink model of a Synchronous MachineThe Synchronous Machine block operates in generator or motor modes. The operating mode isdictated by the sign of the mechanical power (positive for generator mode, negative for motormode). The model takes into account the dynamics of the stator, field, and damper windings. Theequivalent circuit of the model is represented in the rotor reference frame (q&d frame). All rotorparameters 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) R1 L1 L2 R2 Rm LmFigure 14: Simulink model of a three phase transformer and its equivalent circuit.This block implements a three-phase transformer using three single-phase transformers. TheLinear Transformer block model shown consists of two coupled windings wound on the samecore. The model takes into account the winding resistances (R1 and R2) and the leakage 33 | P a g e
  • 34. inductances (L1 and L2), as well as the magnetizing characteristics of the core, which is modeledby 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 degreesThree-Phase SourceFigure 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 internalR-L impedance. The three voltage sources are connected in Y with a neutral connection that canbe internally grounded or made accessible. You can specify the source internal resistance andinductance either directly by entering R and L values or indirectly by specifying the sourceinductive short-circuit level and X/R ratio.Note: For the model that was created, a three phase source was used to model Garden of Edeninterconnection to Versailles and more so Versailles interconnection to the entire grid. For thissource the short circuit level (VA) and X/R ratio was specified. 34 | P a g e
  • 35. Three-Phase BreakerFigure 16: Simulink model of a three phase breaker.The Three-Phase Breaker block implements a three-phase circuit breaker where the opening andclosing 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 theoutputs of the block. You can use this block in series with the three-phase element you want toswitch.If the Three-Phase Breaker block is set in external control mode, a control input appears in theblock icon. The control signal connected to this input must be either 0 or 1, 0 to open thebreakers, 1 to close them. If the Three-Phase Breaker block is set in internal control mode, theswitching times are specified in the dialog box of the block. The three individual breakers arecontrolled with the same signal.Three-Phase Parallel RLC LoadFigure 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 parallelcombination 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 appliedvoltage. 35 | P a g e
  • 36. 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 DCcomponents, of an instantaneous current or voltage. The RMS value of the input signal iscalculated 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 runningaverage window, one cycle of simulation has to be completed before the output gives the correctvalue.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 MeasurementFigure 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 voltagesand currents in a circuit. When connected in series with three-phase elements, it returns the threephase-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. 36 | P a g e
  • 37. If you choose to measure phase-to-ground voltages in per unit, the block converts the measuredvoltages based on peak value of nominal phase-to-ground voltage: whereIf you choose to measure phase-to-phase voltages in per unit, the block converts the measuredvoltages based on peak value of nominal phase-to-phase voltage:whereIf you choose to measure currents in per unit, the block converts the measured currents based onthe peak value of the nominal current:whereV nom and P base are specified in the Three-Phase V-I Measurement block dialog box. 37 | P a g e
  • 38. Display BlockFigure 20: Simulink model of display block.The Display block shows value of an inputted signal. It accepts real or complex signals of thefollowing data types: • Floating point • Built-in integer • Fixed point • Boolean • EnumeratedScope BlockFigure 21: Simulink model of an oscilloscope (scope).The Scope block displays signal inputs with respect to simulation time and displays signalgenerated during the simulation. 38 | P a g e
  • 39. Protection BlockFigure 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 39 | P a g e
  • 40. Each relay is equipped with two display, one which indicate the status of the relay (‘1’ indicatesa trip status) and the other displays and log the time at which the relay was activated or trip. Eachrelay is only activated once during the entire simulation, that is, at the first instance to which itsenses 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 theircorresponding setting.Under/Over Current, Under/Over Voltage and Under/Over Frequency RelayFigure 24: (a) Simulink model of Under/Over Current Relay model. 40 | P a g e
  • 41. Figure 24: (b) Simulink model of Under/Over Voltage Relay model.Figure 24: (c) Simulink model of Under/Over Frequency Relay model. 41 | P a g e
  • 42. Figure 24 (a) depicts the Matlab/Simulink model of the under/over current relay. The operationof the model is based on the actual relay, where the line current (all three phases) of the system ismonitored and compared to some preset thresholds (a maximum value for over current andminimum value for under current) and if the line current goes over or under these thresholds fora 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 currentis greater than (>) or less than (<) the maximum or minimum current value respectively, itoutputs a signal to the On/Off delay. If this signal (output from the relational operator) remains atthe input of the on/off delay for longer than the preset time a ‘trip’ signal is initiated and the timefor 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 threephases, a trip signal is initiated.The under/over voltage relay and the under/over frequency relay shown in figure 24 (b) andfigure 24 (c) respectively operates on the same principle as the under/over current relay. In thecase of the under/over voltage relay the only difference is that the parameter in which the relaymonitors, that is, the under/over voltage relay monitors the three phase voltage, while theunder/over current relay monitors three phase current and similarly the under/over frequencyrelay monitors the system frequency. However the setting of these relay will be different fromeach other. 42 | P a g e
  • 43. The Rate of Change of Frequency RelayFigure 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 restof relay model describe thus far, the ROCOF relay accepts or monitor two inputs (frequency andterminal voltage Vt), therefore before the relay is activated two conditions must be satisfied. Thefrequency with time � �, the absolute value of the rate of change of frequency � � it is then 𝑑𝑓 𝑑𝑓frequency is fed into a ‘Discrete Derivative’ block which calculates the rate of change of 𝑑𝑡 𝑑𝑡compared (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 mustbe met, that is, the terminal voltage Vt (pu) of the generator is compared to a set threshold and ifit exceeds this threshold the second input of the ‘AND’ gate goes ‘true’ (that is both condition issatisfied), hence the output of the ‘AND’ gate also goes ‘true’ which immediately starts the delay 43 | P a g e
  • 44. count down. If the ‘AND’ output remains ‘true’ for longer period than a predetermine time (setby 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, thevector shift relay also accepts or monitors two inputs (three phase voltage Vabc and terminalvoltage 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 therising edge of the wave, and at the same time the duration of each cycle or the period ismeasured. Since the model operates at frequency (f) of 60 Hz, therefore the period (T) will be 44 | P a g e
  • 45. equal to (1/f) 0.01667 seconds. Hence the model computes the duration of each period bydividing the cycle time by the number of completed period/s and then compares this value to0.01667 seconds and any time value grater or less than the set threshold the first condition isreached. But before a trip is initiated the second condition must be met, that is, if the terminalvoltage (Vt) exceeds the set threshold and both conditions are met then and only then a tripsignal is sent and the time is logged. 45 | P a g e
  • 46. SIMULATION RESULTSNormal ConditionsThe complete model was simulated at normal condition for 5 seconds and the results obtainedare shown below.Note: Since the purpose of the simulation is to compare performance of the relays with respect totime, 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 usedin 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 thefigures obtained for the generators (SM1, SM2 and SM3), it can be clearly seen that theysystem/model initially takes approximately 1 second to reach a steady state condition. Using thegraphs, the steady state values of Pmec, Vf, Vt and speed can be approximated to the following: Steady State Approximated Values (pu) Synchronous Machines 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 1.000Table 1: Steady state parameters for the Synchronous Machines used in the model, under normal operating conditions. 46 | P a g e
  • 47. Figure 25 (a): Simulation result of Synchronous Machine One (SM1).Figure 25 (b): Simulation result of Synchronous Machine Two (SM2). 47 | P a g e
  • 48. 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 thesystem/model. The first figure (fig 26 a) shows the voltages and current for a three (3) secondsperiod 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 simulationwhile the currents Iabc at Bus 1 (i.e. Iabc_B1) and Iabc at Bus 2 (i.e. Iabc_B2) takesapproximately one (1) second after the simulation has started to become constant. It can also beseen that the voltages at both Bus is approximately the same while the currents vary in valuefrom each other.Figure 26 (b) shows and expanded portion of figure 26 (a). 48 | P a g e
  • 49. 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. 49 | P a g e
  • 50. 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. 50 | P a g e
  • 51. Figure 27 a, and b shows the 3 phase rms voltages and currents at bus 1 and 2 respectively, hereagain it can be clearly seen that the voltages in each phase are constant (approximately 13790volts) after about 1 second into the simulation. The currents also follow the same pattern but varyin value at each bus, that is, the average rms value for the currents in all three phase is 61.60Amps 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 offrequency. As expected, both the frequency and the rate of change of frequency reach a steadystate or become constant after the 1 second mark. It can also be observed that for a small changein frequency (60 to 60.4) results in a relatively large ‘rate of change of frequency’ or large df/dt(0 to 14). 51 | P a g e
  • 52. Islanded ConditionScenario 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) fromthe rest of the DIS or grid, a scenario which arises when CB1 (shown in figure 12) is in the openposition.To achieve this scenario and for purpose of this project, CB1 was pre configured to open on allthree phase, 3 seconds after the simulation was started hence forming a major island to illustratethe 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. 52 | P a g e
  • 53. 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. 53 | P a g e
  • 54. Figure 29 a, b, and c shows the simulation results three synchronous generators, SM1, SM2 andSM3 under a major islanded condition. All three generators basically responded to the islandedor loss of grid condition in similar manner, that is, after the island was formed (3 seconds into thesimulation), there were an immediate increase in mechanical power (Pmec) supplied to thegenerator since due to the loss in grid the three generator had to supplied the required powerdemand on their own, hence there were an increase in load to each generator. Also to counteractthis increase there were also an increase in excitation voltage (Vf) to the alternator, we can alsosee that the terminal voltage (Vt) and speed of the generator was also affected by an increaseload at each generator. Figure 30 (a): Simulation result for the 3 phase rms currents at bus 1&2 for major islanded condition. 54 | P a g e
  • 55. 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. 55 | P a g e
  • 56. Figure 31 shows the three phase voltages and currents at bus 1 and 2 and the effect that anislanding 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 powersystem or distribution network. From the figure we can see that the formation of the island hadthe same effect on the frequency at both the bus. At the instant where the island was formed, wecan observer that there was a sharp decline in frequency, that is, the frequency drop from 60 Hzto about 58 Hz in very short time (approximately 0.25 second). The figure also shows thecorresponding rate of change of frequency (df/df) for this change in frequency, where a changeof 60 Hz to 58 Hz corresponds to a df/dt of -12 Hz/s (where the minus sign indicates a drop infrequency). 56 | P a g e
  • 57. Figure 33 (a): Results obtained from the protection block at bus 1 for a major islanded condition. 57 | P a g e
  • 58. Figure 33 (b): Results obtained from the protection block at bus 2 for a major islanded condition. 58 | P a g e
  • 59. BUS 1 BUS 2 Relays Relays 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 0.135Under Frequency 1 3.135 0.135 Over Voltage 1 3.144 0.144Over Voltage 1 3.144 0.144 Under Voltage 1 3.477 0.477Under Voltage 1 3.477 0.477 Vector Shift 1 4.175 1.175 ___ ___ ___ ___Under Current 0 Under Current 0 ___ ___ ___ ___Over Frequency 0 Over Frequency 0 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 monitoringbuses 1 and 2 respectively. The table shows the ‘trip statuses’, ‘trip time’ and the ‘islanddetection 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 conditionoccurred exactly three seconds into the simulation, the trip time shows the time elapse after thespecific relays were activated and finally the detection time shows the time take for the relay torespond to the island condition in ascending order.Comparing the relays performance by detection time, where the shortest time taken to detect theisland condition the greater the performance we see that at both busses or at both protectionblock the ROCOF relay out performs the others. It can also be seen that at bus 1 the relay withthe longest detection time was the under voltages relay, similarly the relay with the longestdetection time at bus 2 was the vector shift relay. And finally the under current and the overfrequency failed entirely to detect the island condition. 59 | P a g e
  • 60. Relay Peotection at Bus 1 0.500 Relay Performance ROCOF 0.450 Decrease 0.400 0.350 Vector ShiftDetection Time (s) Over Current 0.300 Under Frequency 0.250 Over Voltage 0.200 Under Voltage 0.150 0.100 0.050 Relays 0.000 Figure 34 (a): Graph showing comparison of the relays detection time at bus 1. Relay Protection at Bus 2 1.200 Relay Performance ROCOF 1.000 Decrease Over Current Under FrequencyDetection Time (s) 0.800 0.600 Over Voltage Under Voltage Vector Shift 0.400 0.200 Relays 0.000 Figure 34 (b): Graph showing comparison of the relays detection time at bus 2. 60 | P a g e
  • 61. Figure 34 (a) and (b) shows a graphical comparison of the different relays detection time, wherethe performance of each relay decreases with an increase in detection time. It can be observe thatthe detection time or the behavior of each relay differs depending on the location placed or thepoint at which it is monitoring (i.e. bus 1 or bus 2). For example the vector shift relay was thesecond relay at bus 1 to detect the island but at bus 2 it was the last, that is, at bus 1 it took 0.073seconds to detect the island but at bus 2 it took 1.175 seconds which is approximately 16 timeslonger. It can also be observed that over current, under frequency and the over voltage relays tripin the same order at both buses but with different detection times. 61 | P a g e
  • 62. Scenario 2: Formation of a Minor Island.As stated earlier, a minor island is formed when the DGs’ at Lenora is disconnected or isolatedfrom Versailles and the rest of the DIS. Since there is only a single connection between Lenoraand 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 aminor 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. 62 | P a g e
  • 63. 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. 63 | P a g e
  • 64. Figures 35 (a), (b) and (c) shows the results obtained for the three synchronousmachines/generators (SM1, SM2, and SM3). It can be seen that SM1 and SM2 located atVersailles was not affected much by the minor island formed at Lenora, that is, the operatingparameters (Pmec, Vf, Vt and the speed) were all maintained at an appreciable level. Howeverthe DG at Lenora was severely affected since it was the source of the island and it was left tosupply a load that was far over its capacity. From figure 35 (c) we can see that due to an increasein load there were an increase in mechanical power (Pmec) and excitation voltage (Vf) requiredand 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. 64 | P a g e
  • 65. 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 1located at Versailles, however there were severe disturbances in the currents and voltages at bus1 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 itcause a trip in any of the frequency monitoring relays. Conversely we can notice that thefrequency at bus 2 was significantly affected by the formation of this islanded condition. 65 | P a g e
  • 66. 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. 66 | P a g e
  • 67. 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, atbuses 1 and 2. From figure 39 (a) it can be observed that there were no trips in any of the relaysin protection block 1 (which monitors bus 1) resulting from the islanded condition, this wasexpected 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 isshown in details in the table below. 67 | P a g e
  • 68. Protection Block 2/BUS 2 Relays Trip Status Trip Time (s) Detection Time (s) Vector Shift 1 3.035 0.035 ROCOF 1 3.036 0.036 Over Current 1 3.102 0.102 Under Frequency 1 3.115 0.115 Over Voltage 1 3.136 0.136 Under Voltage 1 4.743 1.743 Under Current 0 ___ ___ Over Frequency 0 ___ ___ 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 eachrelay.Comparing the relays performance by detection time, where the relay performance decreaseswith the increase in detection time, we see that the vector shift relay has the shortest detectiontime (0.035 seconds), that is, it was first to detect the islanded condition and the ROCOF relaycomes in second at 0.036 seconds and the last to detect the island was the under voltage relaytaking 1.743 seconds.And here again the under current and the over frequency failed entirely to detect the islandcondition. 68 | P a g e
  • 69. Relay Protection at Bus 2 1.800 1.600 1.400 Detection Time (s) 1.200 Vector Shift 1.000 ROCOF 0.800 Over Current 0.600 Under Frequency 0.400 Over Voltage 0.200 Under Voltage 0.000 Relays 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 beseen that the ROCOF and the vector shift relays had the fastest detection time with a difference of0.001 seconds. It can also be observed that over current, under frequency and the over voltagerelays trips were nearer to each other and in the same order as noticed in the first scenario or in themajor islanded condition. 69 | P a g e
  • 70. CONCLUSIONDistributed generator interconnections near consumers have created new challenges forprotection engineers. The typical protection configurations such as unplanned islanding andreclosing of distributed generator systems need to be address. Section 4.4.1 of the IEEE 1547standard states: “For an unintentional island in which the DG energizes a portion of the areaelectrical power system through the point of common coupling, the DG interconnection systemshall detect the island and cease to energize the Area electrical power system within one secondof the formation of an island” [1].This thesis describes and compares different local islanding detection techniques. Fast andaccurate detection of islanding is one of the major challenges in today’s electrical powerdistribution system with many distribution systems already having significant introduction ofDGs. Islanding detection is also important as islanding operation of distributed system is seen aviable 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 relayssuch as the Rate of Change of Frequency (ROCOF) and the Vector Shift relay has significantperformance 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 Shiftrelays had a detection time of at least three (3) times faster that these traditional protectionrelays. Also some relays (over frequency and the under current) relays failed entirely to detectthe islanded condition in both scenarios.Consequently from the research carried out and the results/evidence provided by theMatlab/Simulink simulations and also in keeping with international standards (more so IEEE1547), 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 containingDistribution Generators is imperative for maintaining good quality of power and also for safe andeffective operation. 70 | P a g e
  • 71. RECOMMENATIONThe results obtained showed evidence that the Rate of Change of Frequency and the Vector Shiftrelays were better at detecting the formation of island than the traditional relays that is currentlyused by the national utility (GPL). It was also seen from the simulation the effects thatunintentional islanding can have on a power distribution network. Therefore to minimize theseeffects and also in keeping with international standards for interconnected systems, it is thereforerecommended that these anti-islanding relays (ROCOF and Vector Shift) are implemented withinthe DIS at points where may possess potentials for the formation of island. 71 | P a g e
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