The recent developments in technology and the growing concerns for global warming motivated engineers to search for cleaner and more efficient systems. In order to decrease the impacts of fossil fuel based generation on the environment, the new vision is to generate electricity from cleaner energy sources and closer to the consumption areas. Consequently, the power industry is moving towards Distributed Generation (DG), which may be Renewable Energy (RE) based DG such as wind turbines, solar systems and etc. This also decreases the burden on transmission lines which already operate close to their limits.
Although DG has recently become irreversibly popular, there are some serious challenges for the large scale integration to the utility grids. Existing distribution systems are not designed for significant penetration of DG as they were traditionally designed with the assumption of a passive network. The interconnection of RE based DG systems to such networks inevitably changes the characteristics of the system and presents key technical challenges which were
previously unknown to grid operators and power engineers [2]. Moreover, DG systems also make contributions to the fault currents around the network. Hence, in case of a fault, the transient characteristics of the network become completely different [3]. These are only a few of the issues that have arisen in relation with the revolutionary changes occurring in the grids and the way they are operated.
In an effort to tackle these problems, the microgrid concept has been introduced [5, 7, 9]. The motivation behind using microgrids is to divide the enormous conventional utility network into smaller and more easily operable grids. These smaller electrical networks will manage distributed generators, loads, storage and protection devices in their own grid. Provided that each microgrid is operating as a model citizen, i.e. either as a load receiving power or as a power supply supplying power with stable voltage and frequency, then the overall utility grid can be operated properly. It is a well-known fact that higher penetration levels of DGs, especially those that require Power Electronics (PE) interface, alter the grid structure and jeopardize safe and reliable operation. The microgrid concept is introduced to manage these generators in smaller quantities rather than trying to tackle the whole network in a holistic manner. In this way, more DGs can be employed in the grid and side-effects on the grid operation can be eliminated.
However, there are technical challenges regarding microgrids and their full integration into existing grids such as control, management and protection [9, 10]. Especially, the conventional protection schemes totally collapse since two fundamentals of traditional utility grids, which are the “radial” structure of the grid and passive transmission and distribution
networks, do not hold anymore. Instead of making small amendments in these protection systems that are no longer applicable, revolutionary changes are required for safe operation.
The integration of DGs to the grid and the increasing levels of penetration change the fault current levels and their direction in networks [4, 72]. In conventional networks, transmission and distribution networks are passive and do not contribute to faults. In a microgrid, DGs will contribute to fault currents and the contribution level depends on the DG type. So the ratings of the protection equipment should be re-planned accordingly.
Consider the case shown in Figure 3.1, where a microgrid operates in grid connected mode and an internal fault occurs at the load just downstream from the relay R3. In a passive distribution network, the relay R3 ideally needs to interrupt the fault current contribution of the grid, i.e. IfaultGRID. However, in the case given in Figure 3.1, there will also be fault current
contributions from the DG1 and DG2, namely the IfaultDG1 and IfaultDG2. The rating and the
settings of R3 should therefore be adjusted accordingly to take into account these extra fault current contributions. When the number of DGs in a system increases, this difference will obviously be higher.
Figure 3.1. Grid connected-Mode, Internal Three-phase Fault
If an external fault occurs in the same system (a fault outside microgrid), it requires that the relay R1 opens and islands the microgrid to protect its stability. This requires R1 to detect not
only downstream faults but also upstream ones. Since faults may occur at different locations and there may be several DGs at different places, bi-directional operable relays meet the requirements of microgrid protection much better than traditional unidirectional relays.
Assume that when the microgrid is islanded from the utility, in the case of a power disturbance such as an under-voltage scenario, an internal fault occurs as shown in Figure 3.2. In this case, there will be no grid fault contribution and the overall fault current will only be due to IfaultDG1 and IfaultDG2. Relay R3 is now supposed to operate at this fault level, i.e.
IfaultDG1 + IfaultDG2, while in the previous case it was set to trip a much higher fault current, i.e.
IfaultGRID + IfaultDG1 + IfaultDG2. The operating tripping current of R3 should therefore needs to
be adjusted according to the operation mode of the microgrid to ensure proper protection. The related simulation results are given in Chapter 7.
Figure 3.2. Islanded Mode – Internal Three-phase Fault
Using the lower of the two fault currents as the relay operating current may seem like a good idea in the beginning. However, this is not necessarily safe or reliable and may cause unnecessary trippings in larger systems. For example, a microgrid with a different topology is
illustrated in Figure 3.3. In this grid connected microgrid, if the tripping current of the relay R2 is set very low then it will trip under normal operating conditions. Alternatively, a small oscillation in the system will trigger R2 to open. This concept is referred as nuisance tripping [14]. These erroneous trippings cause unwanted islanded sections in the microgrid and they may cause power interruption in some parts of the network while there is no fault in the system. Depending on the complexity and size of the microgrid, if the necessary precautions have not been taken, nuisance tripping might become a frequent occurrence. This makes operation impossible and reliability of the network will be put to question. Consequently, both network operators and consumers would like to eliminate nuisance tripping by setting correct operating conditions on the relays.
Figure 3.3. Nuisance Tripping
In conventional power networks, the fault current contributions of large generators are much larger than normal operating currents. Therefore, there is a huge gap between the normal
operating currents flowing in the network and the trigger currents set for relays to interrupt fault currents. However, IIDGs do not have very large fault current contributions [14, 15, 153, 154]. For this reason, the trigger current settings of relays are relatively closer to normal operating currents flowing in the network. This is inevitable for proper operation in networks with DG penetration. At the same time, it makes nuisance tripping more probable since the operation gap between trigger currents and normal operating currents is much smaller.
Selectivity is another vital concept in protection systems. It means if the downstream circuit breaker (CB) fails to interrupt, then the upstream CB with larger capacity should operate and isolate the fault. It is intended to isolate the fault with the nearest relay so that the rest of the system will not be affected. For better understanding consider the case shown in Figure 3.4. The fault occurring just below R8 draws fault current from all corners of the network. Proper selective operation requires that that the relay R8 operates to single out the fault and the rest of the network remains unchanged.
However, if R2 has not been properly set, then the large fault current coming downstream may cause R2 to operate. In this case, the whole lower bus will be isolated from the system instead of the faulty 8th bus. Similar to the case with nuisance tripping explained above, this will cause undesirable islanded sections in the power network. This may cause convenience problems for the consumers, i.e. power might be interrupted at the healthy sections of the microgrid, as well as protection issues where unexpected topologies may emerge in the microgrid and the protection system may become completely useless. Furthermore, the desirable protection measure is the disconnection of R8 which will completely disconnect the fault from the rest of the microgrid. If R2 is used to isolate the fault, the fault is not
completely isolated as there are DG3 and DG4 present in the lower bus which can still provide fault current. This shall create a serious safety infringement.
Figure 3.4. Selectivity Issue
Therefore, it is required that not only the current levels but also the time constants of the relays should be controlled dynamically. That is to say, merely changing the operating current levels of R2 or R8 does not warrant proper protection. Also, operation of some relays, which are upstream, may be delayed so that other relays may isolate the fault according to selectivity principles. For the case given above, the fault current flowing might be larger than the triggering currents of R2 and R8. However, with proper time delay operation R2 shall be delayed to see whether R8 can isolate the fault. Should the allocated delay time expire and R8 fail in interrupting the fault current for any reason, e.g. malfunction or insufficient capacity, then R2 shall operate to isolate the fault so that no further damage is caused in the microgrid.
This delay is limited by a number of discriminating time steps as the maximum time allowed before a fault must be cleared, i.e. toperation, is preferred to be less than a certain value to
prevent microgrid from becoming unstable [73].
Selectivity requires directional operation of relays. Figure 3.5 shows a case where an external fault occurs in a microgrid-power grid connection. In contrast to the case given above in Figure 3.4, the fault currents flow out of the microgrid and the direction of fault currents are different. The amplitude of the currents flowing through some relays, such as R2, is completely different. This shows that the same microgrid topology with same set of grid components requires non-identical operating parameters for faults inside the microgrid and outside of it. The forward and reverse trigger currents of the relays shall be different and assigned accordingly. The proper selective operation in this case shall necessitate R1, coupling relay, to operate first to isolate the fault and disconnect the microgrid from the faulty grid.
Special attention shall be paid to the difference between forward and reverse currents of R1. Forward trigger current is IfaultGRID which is a very large value whereas reverse trigger current
is a combination of DG fault current contributions which is known to be much less. Protective relays require to be able operate at these different fault current levels. Should there be a problem with the disconnection of R1, then the proper selective operation triggers R2, R3 and R5 to disconnect from the grid to prevent any possible damage on the generators. As seen, selective order is almost reversed in this case. Further precaution can be taken by disconnection loads for protection against oscillations and transient currents.
Figure 3.5. Reverse Selectivity for Faults outside the Microgrid
In short, microgrids are very beneficial for the wide-spread use of DGs and simpler management of interconnected systems. However, this unprecedented network structure brings along some less familiar protection issues along with it. Some of these issues have been explained above due to their importance in the development of the conceptual design. In summary, this section has demonstrated that;
a. The connection and disconnection of DGs alter the fault levels in the microgrid,
b. In a microgrid, the fault levels in grid-connected and islanded modes would be different,
c. Nuisance tripping could occur if islanded mode fault levels are taken as the reference,
All these demonstrate that for proper protection of microgrids, an intelligent control system is required that using various communication channels and infrastructure continuously monitors the microgrid and updates the protection settings in response to changes occurring. The protection system presented in Section (3.3) has been developed to address these new issues of new generation microgrids.