 So, welcome to class 12 of topics in power electronics and distributed generation. In the last class, we were talking about grounding of distribution systems. And we saw that, in the example that we were discussing in class, that there is a possibility where you might have a upstream breaker in your circuit opening, when a DG is, when a downstream DG is still connected to the system. And there is a possibility that this connected DG may operate and continue to excite the feeder, even when upstream breaker has opened. And this particular situation of a upstream device opening and the rest of your distribution system operating, being excited is called an unintentional island, where for some unintentional reason an upstream breaker opened. But the DG, if it can actually stay connected and provide power to the loads on the system, it will continue to actually excite the feeder. And we will see that islanding is important issue, when we look at distributed generation. So, when we talk about islands in distribution network, in geography an island is a land body, which is disconnected from the main land separated by water. So, if you look at an electrical system, electrical island is essentially a small part of the distribution and electrical network in the distribution system. And this is the smaller network is disconnected from the main grid, due to a open circuit. And the typical cause of open circuit may be a upstream breaker opening or as shoes are blowing, it can be just the wire physically breaking. So, there can be a variety of reasons why you might result in an island, commonly situation would be a breaker opening. And electrical islanding situation can be of two varieties, one is you have an intentional island or you can have an unintentional island. So, if you look at intentional island, the reason why one would typically have an intentional island is for reason of power quality. And the idea is you open say a breaker, which connects to the main grid and then your source can actually feed a local load, when there is a poor power quality in the main grid. So, you want to isolate yourself from the main grid and continue to feed higher quality power to your load in a dedicated manner. So, there might be reasons why you intentionally operate as an island. So, the question comes what do you mean by power quality or it is more often measured by what do you mean by power quality being poor as seen by the load. So, load seeing poor power quality from the supply can be for a variety of reasons, the primary reason being that there is no supply at all, there is a outage and you want to actually feed your load. So, that is a primary reason. If you have, if you are having electric supply, you expect your voltage, line to neutral voltage to be 230 volts, some nominal voltage. Typically, a band around the nominal might be acceptable, you might have your voltage say plus 10 minus 20 percent band around nominal might be considered acceptable power quality. If you go beyond that, you may want to disconnect rapidly, you might have say voltage imbalance, I mean your voltages might be close to nominal, but your phases may not have equal amplitude voltage or there may be some phase shifts. It depends on the type of load, I mean say for example, if you are feeding single phase loads, then the imbalance may not be a major thing, but if you are feeding say induction machine load, then even imbalance of 3 percent would be considered unacceptable. I mean you can see why say 3 percent might be considered unacceptable, a typical induction machine has leakage inductance in the range of say 15 to 20 percent. So, a 15 to 20 percent imbalance would mean that even at no load, your current drawn, imbalance current drawn would correspond to almost full load, when there is 15 percent imbalance. So, if you are having something like 3 percent imbalance, it means that you are having 20 percent of your current coming in because of the imbalance. So, you might have a service factor of 20 percent on your machine. So, that might be the maximum that you can tolerate on a continued basis. So, your imbalance percentage is typically much tighter than what is your acceptable voltage amplitude. Also, your frequency might be outside what is your acceptable range, I mean depending on what is the process that you are trying to do. You might be trying to do some speed control, there might be some machines which are susceptible for mechanical resonances. Say if you are having something like a computer power supply, it might be able to accept a wider range of frequencies, but if you have fans, mechanical loads, you might need a tighter range of frequencies. Say locally, we might say 48 hertz to 50.5 hertz might be considered as something which might be acceptable. If you go outside that range, you might want to disconnect again depending on your load, what is expected at the load and your nominal frequency is 50 hertz. Another thing that you might say would be a situation of poor power quality is when you have harmonics in your load, you have distorted waveforms. People measure harmonics in waveforms in terms of total harmonic distortion. So, acceptable THD level for your voltage might be less than 2 percent. So, you want to make sure that your voltage that is being supplied to you is not very highly distorted. Again, it depends on how sensitive your load is. You might have some tighter requirement for very sensitive type of load. You can have transient effects which would also affect power quality. An example is short term duration of voltage amplitude increasing or a short duration where the voltage dips. This is a swag or as well. You might have notches in the waveforms. If you have equipment such as thyristor power converters connected to your point of common coupling, you can have flicker in your load. If say someone is operating an electric arc welder in your same street as where you are living, then chances are you will see a lot of flicker in your voltage. So, you can see that as lights that are glowing brightly and then it becomes again glowing brightly. Some people are extremely sensitive to variation of light intensity. So, for many of these power quality reasons you might want to intentionally disconnect from the grid and open a breaker and then feed your local load from a DG. So, that when the power quality is poor, you have your critical load being fed from your DG. When the grid power quality comes back to an acceptable range, you would then close the circuit breaker and operate in a normal condition. The common systems that use such a property are UPS systems, Gensets. They all operate in this particular manner where you are addressing poor power quality by adding such components. You can also have a situation where to address poor quality, it may not be just your own facility breaker that you open. You might for some reason be capable of opening a breaker at the network and providing poor power, improved power quality on the feeder itself. It depends on whether your distributed generator set has the capability to provide that level of power both real and reactive. Also, whether it can operate stably with such a big network, wider network. You could also have other technical conditions which may need to be satisfied. This is DG capable of clearing faults in your neighboring load. There may be non-technical issues such as what is the economic benefit of providing power to your neighbor. There may be legal questions like who owns different aspects of the system. The utility might own the lines, one entity might own the DG, another entity would own the next load. So, there are number of issues to be addressed where if you are trying to operate in as a intentional island on a broader sense and people refer to such situations as microgrid at the distribution level. Not microgrid at within a small facility, but microgrid at the distribution level. So, if you look at then the other situation where you can have an island. So, what we discussed so far was when you have an intentional island. You can also have the situation where you have an unintentional island and the unintentional island as we just saw in the example that we discussed. It is not because you intended to actually open an upstream breaker, but it opened for a variety of reasons. For some unintentional reason now your DG is exciting the feeder, the common network, the feeder network and it can lead to a variety of problems. Even for forming an unintentional island you have requirement that the DG that you have should be capable of providing the power for your neighboring loads. So, if your load total load on the feeder is of the order of megawatt and your DG is 1 kilowatt. Obviously, it cannot form an island. So, you are talking about capability of your DG and your load to be similar both in terms of real and reactive power requirement being able to match that and for the unintentional island to be operated in a sustained manner. You need to have a stable operating point of the DG and the load. So, the variety of reasons why an unintentional island is not desirable and the primary reason is safety concern. Typically, when you open a upstream breaker in a distribution system the assumption is whatever downstream of it is deenergized which means it is potentially safe to go and touch. Whereas, now you have a DG system you open an upstream breaker. Now, potentially the downstream system is still energized. So, if a person lineman goes to repair the downstream system he can potentially get shock he can get electrocuted. So, safety is a major concern. So, you can address this issue in a variety of ways. You can try to have a live line type of repair. When you go to larger transmission systems you can do repair of the transmission system components without deenergizing the line using people in fair day cages etcetera. But, that makes it a more complicated operation it is more expensive. So, safety is a big concern when you are having possibility of DG source forming an unintentional island. Also, you can damage the utility equipment in an unintentional island and we saw that the faults may not clear the capability of the DG to provide fault current to trigger a protective device might be lesser than the main grid. So, you might have the change in protective coordination settings as we saw in our example. You can have sectionalizers that open under load. You also have the possibility of what people refer to as ferro resonance. So, on a distribution feeder you would have capacitors could be for power factor correction. Then, when you are connected with the grid you have those capacitors and your magnetizing branches of your transformers etcetera which are connected in parallel to a stiff grid which prevents your voltage from going to be different from your nominal value. When you connect DG source which might have much higher impedance and you disconnect the voltage source the chances of resonances could be high. So, the resonance between your magnetizing branch and capacitors might be power factor correction capacitors or it can be capacitors of cables can actually lead to ferro resonance. You can see highly distorted waveforms with sharp peaks and that can damage utility equipment. You can also damage the distributed generation source itself because you can have overloading because you are trying to carry a wider set of loads of the entire feeder. Your frequencies might drift outside nominal values also you have something that is a possibility is that is out of phase reclosing. We will see that out of phase reclosing is actually a important issue when we consider a situation of damage it can actually damage the DG it can damage other customer equipment it can also damage utility equipment. Such a situation can arise where say you have a upstream recloser. We will look at an example where say the upstream recloser has off duration of say 5 seconds. So, we will look at an example where your grid frequency is 50 hertz and you assume that after the recloser opened then the loads with your DG for in the island the frequency shifted to some other value say the DG the system frequency shifted to f of the island shifted to say 49.9 hertz after disconnection of the main breaker and the recloser say stayed open for 5 seconds and then it tries to reclose. So, we will look at what would be the phase of the voltage on the grid side and the phase of the voltage on the island when the recloser is reclosing and to determine the phase of the voltage you have you know your delta f is 0.1 hertz and then you look at what is the phase shift that occurred in this duration your delta shift in phase is delta f into t of into 360 degrees. So, this is 0.1 into 5 into 360. So, this is 180 degrees. So, you can see that this the waveform would be a sine wave like this over here it could be to have the opposite polarity. So, when the recloser closes it is trying to introducing a abrupt 180 degree phase shift in the voltage that is now getting applied to the system. So, you can see that in any electrical system you want a nominal direct online start will cause a large in rush. Now, you are having a star almost like a 180 degree phase shift your currents that can flow in such a situation is much higher than a normal say direct online start and you can have severe repercussions you can if this is a synchronous machine type of then you could potentially damage the DG source if there are fuses on the distribution system the current that it might draw might be large enough to damage open the fuses. And what we will see is that if you have neighboring load when the voltage over here drifted for 5 seconds and became out of phase then essentially the phase of your flux vector in your machine is also following that particular voltage in the island. So, now you have now induction machine where it is induced magnetic field is in one polarity and then voltage that is now being applied from the grid is 180 is trying to create a magnetic field 180 degrees out of phase. So, the current that flows into this in in rush into the machine can be as high as twice your current that you would see in direct online start or even higher because of saturation effects. So, you can possibly have things like 10 per unit peak torque that you would see on the shaft of the machine potentially you can actually damage the shaft the shaft can actually crack open. So, that can be extensive damage now not just for the DG, but for all loads that are connected on the feeder. So, you can see that this is a very important consideration when you have a DG system. So, the other customers and if you are applying a step voltage of twice the peak value you can have resonances with a capacity capacitances on the line you can get resonant over voltages that go up to 4 per unit. So, that is really high voltage and if you end up damaging the neighbors electrical equipment then there is a big question of who is liable. So, if you look at a typical electrical system the cost of all the equipment that is connected to the electrical system you might have very expensive process equipment you go to data center you might have lots of expensive computers. So, the connected loads would have much higher value than the original electrical system which is actually providing the energy feed and if you end up damaging all the loads then there is a severe liability issue and typically your electricity service provider takes insurance that they would cover in case they provide extremely poor service that your equipment is damaged they are liable to actually pay you for the damage that they have caused. So, now if DG is doing this then the question is who is responsible is it the DG owner is it the service provider or should the customers themselves be taking the liability. So, the issue of how to deal with electrical island especially the unintentional island is important concern in DG systems. So, if you look at the example that we saw over here here we looked at a recloser where your T of was is 5 seconds and the amount of duration that your T of can have can vary I mean you can have fast reclosing you might have slow reclosing and people consider 2 seconds to be a reasonably fast reclosing. So, if you look at standard such as IEEE 1547 it says that distributed generation source should disconnect before 2 seconds after opening of a upstream device and the reason is that before the upstream device recloses you need to be able to detect that something upstream has opened and deenergize the DG so that you do not have possibilities of out of phase reclosing. So, minimum T of so you need to detect a situation of an unintentional island in a fairly short time frame you cannot use algorithms which might take 10s of seconds or minutes you need to be able to detect that something like this has happened in a second or two or faster. So, if you want to detect a situation of an unintentional island people have employed methods people called it anti islanding algorithm essentially what detects a situation that there has been an unintentional island and the types of anti islanding detection methods can be thought of as being passive or it can be active or it can involve signaling or communication. When you look at passive methods for anti islanding what you are essentially doing is you are measuring your voltage and current at the terminals of your DG device and or at the interconnection point of interconnection with your main grid you are measuring it through potential transformers CTs into some protective relay and you decide on whether to open or keep the interconnection breaker you decide on whether to keep it open or closed based on the decision of the algorithm. It typically does not directly interact with your DG controls and that is one of the reasons why it is called passive because it does not actively try to shift the control action and the passive methods are not always 100 percent effective especially if it is based on pure voltage measurements and or you might have restrictions on how the DG is operated which will prevent and how the loading is being done in the facility so there might be restrictions on operation. If you are looking at the voltage essentially pure voltage based methods might be looking at if the voltage goes too high or too low and potentially there might be a islanding situation or you might be looking at under or over frequency or you might be looking at the direction of power flow. So, we will look at some of these methods of passive and anti islanding before that we will also discuss some of what would constitute active and anti islanding method. So, this is based on adjusting the distributed generation source operation based on your actual measurements and the idea in this particular case is that you destabilize the island so that the operating point that you get when you disconnect the an upstream device would not be stable and because your operating point is not stable it means that your voltage amplitude or your frequency would go outside it would go outside what would be a nominal range and the fact that your voltage or frequency went outside the nominal range would be used to actually open your interconnection device. And if you look at the method of active and anti islanding it makes use of measurements it makes use of active controls. So, its reliability would be a little bit less compared to the passive method ideally if a passive method can operate reliably that would be the better method because active method is now using not just your detection, but also now active controls. So, you could think of it as being slightly less reliable, but the chances of detecting an island might be more in the active method. The third method is communication based methods or signaling based methods in the traditional transmission systems people have used pilot relays to transfer information from one point to another point to make better decisions. So, you could use information may be from the substation to the DG to inform whether a substation breaker is open or whether some feeder need to be reenergized. So, you could make use of explicit signaling or communication and in this case now you need an additional channel rather than just the power lines you need now communication channel to be also available. So, the cost can potentially be higher when you want such systems to work also reliability of the communication channel may not be as high as the underlying electrical network. So, you have reliability concerns to address some of the cost issues people have looked at power line carrier communication methods to see whether the power line itself could also carry this information on the status. So, people have looked at a variety of such methods to see whether you could have explicit signaling based methods that can be effective, but again in this particular case reliability is a concern because in this case you have coordination between multiple agencies for some algorithm to work. You have to have coordination from your utility which is sending the information and coordination at the DG side which is taking that information and using it to open a breaker. So, that becomes more complex a problem rather than one entity making the decision by itself in a reliable manner. So, we just mentioned that the effectiveness of an anti aligning algorithm it may not be effective at all times especially in the context of a passive method and you might have a range of values where the method may not work well for a range of parameters or a range of system values where the aligning method may not function in a effective manner and the range of region where the region of the parameter space where the aligning detection may not be effective is called a non detection zone. So, a non detection zone and the objective of a good anti aligning algorithm is to make the size of this non detection zone to be 0. So, the ideally it should be 0 which means that it would be a very good anti aligning algorithm. So, what we will do next is to look at a model of your feeder with your distributed generation source. So, as to look at the situation of passive anti aligning detection on that feeder. So, we will look at what it means for this simplified description of the feeder. So, what you have over here is the upstream grid modeled as a voltage source. This is essentially what comes from your substation and you might have a breaker upstream breaker modeled as the switch S 1 which can open. All the loads on the feeder are modeled as it is modeled as a R L C a parallel R L C load. Typically, you might have your real power consumed by your R load reactive power being drawn by L your transformers whatever components machines etcetera. And you might have power factor correction capacitors etcetera on your feeder. So, you could think of your overall load to consist of a R L C equivalent network. And you can model your distributed generation source as something that injects power and reactive power. And we will assume that the reactive power that is injecting is under is 0. It is operating under unity power factor trying to inject power at unity power factor at its point of common coupling. And we will look at a situation where the amount of power that is being drawn by the load matches well with the power that is being supplied by the d g. If the q reactive power from the d g is 0 it means that the balance reactive power is the difference between the reactive power drawn by L and C. And if the feeder is well compensated it means that your q of the load would be almost 0. So, if there is any difference between what is being drawn by the load and what is being supplied by the d g that is essentially delta p and delta q coming in from your main source which is your main grid. So, the problem can be simplified as when the switch is closed your main grid sets your voltage and frequency seen by your RLC load. Then when the switch S 1 opens there might be some deviation in the voltage and frequency seen at this particular load. And can you operate switch S 2 which is downstream by looking at this voltage and frequency can you operate the switch S 2 to actually disconnect the d g in response to the changed value of voltage and frequency. So, that is essentially the anti aligning problem. If S 1 opens under what conditions can the anti aligning algorithm determine the situation this that such a situation has occurred and it needs to open S 2 as a result. So, the other assumptions over here that the d g is capable of providing power whatever power is being drawn by your load. The other thing is that because your d g is providing power at unity power factor then the assumption is you have very good reactive power compensation. So, the feeder is well compensated. So, if you look at the first situation you have if V square by R is your load power. So, this implies that your delta P is P of the load minus P of your d g is 0. So, the second situation is if your feeder is well compensated at 50 hertz then your omega is which is 1 by root L c would turn out to be 2 pi times 50. So, if you have a parallel resonant circuit if your resonant frequency is 50 hertz in a parallel resonant circuit whatever you draw would be in phase if there is a resistive load or it would not draw any current if there is no resistance load which means that your reactive war of your capacitor is exactly balanced by the wars of your inductor. So, your Q L is Q L of your inductor is and you can calculate both of this would turn out to be equal to V square divided by square root of L by C. So, if you look at your delta Q that is being drawn from your source this is equal to Q of your load minus Q of your d g and Q d g is 0 and Q L is equal to Q C. So, this is equal to 0. So, essentially if you look at conditions 1 and 2 what you are going to have in the ideal situation is that you are going to have sustained L C E oscillations even after opening the circuit breaker. So, the third aspect that will look at is what is a quality factor of this resonance and your resonant frequency is 1 by square root of L C. So, it turns out that your Q f is R divided by root of L by C and you also know that omega is 1 by root L C. So, you can substitute for this you will see that essentially Q f is equal to Q of your inductor divided by your P load is equal to Q of your capacitor divided by. So, in a situation where if Q f is high what this implies is your P load is less than your Q of your inductor or Q of your capacitor. It means that your system response is going to be dominated by your L C oscillations and your loading some even if there is some level of loading mismatch your exponential term which is essentially your damping term may not be the dominant term in your overall response in the time frame required in your analysis. So, for your the anti aligning test what we look at is a situation where Q f is greater than or equal to 1 and essentially what you are looking at is if under in the ideal condition if you are opening the switch and your delta P and delta Q is close to 0 what it means is that after opening the switch there is almost delta P and delta Q is 0 it means that the current flowing through the switch is 0 and opening the switch will not cause any disturbance your V and F will continue to be where it originally was which means that any method that was that is measuring your voltage and frequency to open the circuit breaker of the D G would not be effective. So, having small values of delta P and delta Q it would mean that method with pure voltage or frequency measurement would not work. So, you need to have some mismatch in your delta P and delta Q for just pure voltage based methods to work in our next discussion on aligning what we will do is try to look at the threshold of your voltage and the threshold of your frequency and look at how that relates to how much delta P is there how much delta Q is there to look at what is the relationship between essentially you can think of delta P and delta Q to be aspects of your non detection zone which is which can again be reflected in terms of what your R L and C parameters are and relating that to the D G and we will try to see how that can be used to set voltage and frequency thresholds to determine a situation of an unintentional island in a passive manner. Knowing well enough that it would not be 100 percent effective in a situation where you have a feeder where your feeder load is 1 megawatt and your D G is also providing 1 megawatt there is a potential that such a method may not work, but if you you would be able to say if you are now feeder is 1 megawatt can I introduce up to half a megawatt of D G and still be able to detect an unintentional island. So, you could ask questions like that with such an analysis. Thank you.