## 2 Materials and Methods  
Traditional distribution systems have only one source that contributes to a fault, i.e., the main substation and protective relays are set to see a certain distance down the radial feeder; the minimum fault current that the protective relay can detect decreases over this distance [28]. Phase-to-phase faults with fault point impedance and arc faults are normally suitable for studies as the smallest fault current dictates the operation of the protection system. Phase short-circuit and arc faults have the minimum fault currents, and they may cause more blind areas than other faults [11]. In this study, a phase-to-phase fault is used to investigate the blind areas protection. The probabilities of single phase-to-ground, double phase-to-ground, phase-to-phase and three-phase faults are 80%, 17%, 2% and 1%, respectively [29; 30]. Of course, the fault point impedance further reduces the minimum fault current. Faults with different impedances have been used in many papers. In [21; 31], various fault resistances were considered from 0 (solid fault) to 100 ohms. Blind areas in OC relays may cause delay in the operation of relays and can potentially lead to the non-tripping of the relays in the worst situation. A blind spot is more possible when DG is installed between the fault point and the feeding substation. The presence of DG decreases the fault current seen by the relay at the same time. The effect of DG on power system depends on the location, type and size of the installed DG. However, the fault current in the feeder relay decreases due to the DG contribution. This happens when the total current is divided among the feeding sources. The protection may become inoperative in the worst-case faults, thus, it should be adjusted before the presence of DG [32]. Figure 1 shows the blinding points with DG in a simple diagram of the case study. The three blinding points are the candidate points in the case study, which include Point 1 (the end of the main feeder), Point 2 (the beginning of the adjacent feeder when circuit breaker (CB) ring is closed and both feeders are fed by the main feeder) and Point 3 (local load). In this case, we have three blind points that need two recloser relays; R1 (location of recloser 1) and R2 (location of recloser 2) are the suitable locations for the reclosers as shown in the figure. This study considers only relay R1. In case of a fault at the end of the feeder, the fault current is supplied from both the utility network (I1) and DG (I2). The fault current from the utility network is reduced because of the contribution of the local generation. If the local feeder protection settings are not adjusted to incorporate DG, the relay may not see the fault and will not operate [25]. Figure 1: Possible blinding points in the case study. PCC: Point of Common Coupling CB: Circuit Breaker. Traditionally, DGs are not operated in islanded mode, and the generators need to be disconnected from the system. The remote transfer trip opens the circuit breaker of the DG in case of a fault on the feeder. The worst situation for the relay in a blind area is its inability to operate in case of fault occurrence. The relay operation depends on pickup current. When the relay cannot pick up as a short-circuit fault occurs, the relay setting is under blinding point. The three-phase short-circuit current at any point within the power system is obtained as follows:  
\[I_{SC}=\frac{U}{\sqrt{3}\times Z_{SC}} \tag{1}\]  
where \(U\) refers to the phase-to-phase voltage at the fault location before fault occurrence, and \(Z_{SC}\) is the equivalent upstream power system impedance seen at the fault point. The blind points occur when the short-circuit current (\(I_{SC}\)) value is less than the relay pickup current. In the case study, the pickup current of the main feeder is calculated as: \(I_{Pickup}=1\times I_{n}=400A\).