## 1 Introduction  
Distributed generators (DGs) have rapidly spread around the world because of advantages such as reduced carbon emissions, decreased line losses, and improved voltage profiles [1]. Although DGs provide many benefits, they can disrupt the coordination of protective devices. For example, in recloser-fuse coordination, the recloser is planned so that it disconnects faster than the fuse for temporary faults. This can reduce the outage period and cost of fuse replacement. When DGs are installed in a power system, the total fault current (\(I_{/ll}\)) is the summation between the grid current (\(I_{S}\)) and fault currents from the connected DGs. Thus, the total fault current flowing through the fuse is higher than the grid current seen by the recloser. This results in permanent disconnection occurring even during temporary faults because the fuse is damaged before the tripping operation of the recloser [2]. In terms of fault statistics, approximately 80% to 95% of all fault occurrences are temporary faults [3]. Hence, the melting of fuses during these temporary faults reduces system reliability significantly. Over the past few years, researchers have developed a number of solutions to remedy the effects of fault current contributions from DGs on protective devices. Those solutions are reviewed as follows. Solutions involving limitations on DG capacity have been reported [4; 5]. The capacity of DGs installed in a system is limited to the maximum value that does not disrupt the coordination of the protective device. The maximum capacity is optimized by constraints of the protective device coordination. However, the limiting capacity of DGs has become an obstacle to renewable policies with ambitious targets. Solutions based on modifying protective devices have also been recommended [6; 7; 8]. The solutions in References [6; 7] applied adaptive overcurrent protections. Their operating curves were altered according to the fault current. Agent-based protection was adopted in Reference [8]. The fault clearing strategy was set by considering the information exchanged between agents. Although these solutions are interesting, they are not suitable for systems consisting of a large number of protective devices, because a large investment is required to upgrade these protective devices. Solutions based on applying fault current limiters (FCLs) are given in References [9; 10]. During normal conditions, the impedance of a FCL is nearly zero: if a fault occurs, it rapidly increases to limit the fault current from DGs. However, the use of an FCL imposes some disadvantages. A superconducting FCL (SFCL) has a long recovery time after the fault is cleared. A large voltage drop happens during the transition state. In addition, a solid state FCL (SSFCL) produces switching losses during normal conditions. This problem can be technically solved by using a cooling system at extra cost. Thus, FCL installations seem to be uneconomical. Apart from the mentioned FCLs, the solution in Reference [11] was invented to limit the fault current. A field discharge circuit was used to limit the fault current of the synchronous distributed generator (SDG). However, the voltage of the field winding increased the nominal voltage up to 20 times. The field winding of an SDG must be able to withstand overvoltage. Due to its single functionality, the installation of a field discharge circuit is also uneconomical, similarly to FCLs. Solutions based on inverter-based distributed generators (IBDGs) and inverter-based microgrids (IBMGs) were suggested in References [12; 13; 14; 15; 16]. In contrast to previous solutions, these solutions are more economical because they utilize the existing IBDGs and IBMG installed in the system and do not require any modifications of protective devices. Moreover, they do not need to limit DG capacity during normal conditions. The solutions in References [12; 13; 14] limited the fault currents from IBDGs (\(I_{IBDG}\)) by adjusting the current amplitude.