Fault detection and clearing control strategy in an islanded microgrid with converter-interfaced sources Konstantinos O. Oureilidis, Spyros I. Gkavanoudis, Kyriaki-Nefeli Malamaki, Charis S. Demoulias Electrical Machines Laboratory Department of Electrical & Computer Engineering Aristotle University of Thessaloniki (AUTH) Thessaloniki, Greece e-mail:
[email protected],
[email protected],
[email protected],
[email protected] Abstract—A significant factor for properly designing the protection scheme of a microgrid is the fault current contribution from the converter-interfaced distributed energy resources (CI-DERs). The fault current direction and magnitude is difficult to be defined, since the currents injected by the CI-DERs affect it considerably. The fault situation is even more complicated, considering the case of islanded looped microgrids with conventional protection devices. In such microgrids, all protection devices are settled to the same rated current. In order to overcome these issues, this paper proposes a new method for detecting and clearing faults, without utilizing any communication means. The fault identification process is carried out by measuring indirectly the microgrid impedance, while each CI-DER adapts the internal control method and injects a fault current proportional to the sensed impedance. Therefore, the source being closer to the fault injects relatively larger currents enabling the selective coordination of conventional protection devices. In order to enhance even more the selective cooridnation of the protection devices, a time delay is also incorporated in the fault control. The proposed strategy is validated in a looped microgrid, protected by simple overcurrent relays. Index Terms—distributed energy resources, microgrid protection, droop control, overcurrent devices.
I. INTRODUCTION According to the U.S. Department of Energy, the microgrid is considered as a group of interconnected loads and distributed energy resources (DERs), acting as a single controllable entity with respect to the grid. The microgrid has the ability to enable both grid-connected and islanded operation mode [1]. Since the microgrids are mainly fed by renewable energy sources, the DERs are connected via DC/AC or AC/DC/AC converter systems, being able to fully control their behavior [2]. Therefore, the converterinterfaced DERs (CI-DERs) are required to carry out basic and ancillary operations, such as voltage/frequency control, accurate power sharing among the sources, power quality enhancement, fault ride-through capability, etc. [3]. In islanded operation mode, the CI-DERs are responsible for matching the power production with the load demand [4]. In order to form the microgrid voltage and frequency in the islanded operation mode, the droop control philosophy is broadly adopted, emulating the parallel operation of synchronous generators [4], [5]. The droop control method can be implemented without needing any communication infrastructure.
Regarding the case of faults within the microgrid, the contribution of the CI-DERs to the fault current have been carefully examined in the literature [6]. The problems are the bidirectional flow of currents and the poor current capabilities of the power electronic switches of the converters, which is restricted to only a few times the nominal current. The protection issue becomes even more severe in case of grid absence, where the CI-DERs constitute the sole source for the fault current injection. The literature deals with the protection problem in microgrids with many different approaches [7], which can be categorized to adaptive protection [8], [9], differential protection [10], distance protection [11], voltage-based protection [12], protection with external devices [13] and protection based on over-current and symmetrical components [14]. However, these methods rely on extensive communication with a supervisory controller, usage of new protection devices or external devices, responsible for providing the necessary fault current. Therefore, in case of a communication failure, the protection strategy is not guaranteed that will operate properly, deteriorating the reliability of the microgrid safe operation. This paper proposes a new fault detection and clearing technique for looped islanded microgrids with CI-DERs, without requiring any communication infrastructure. The fault clearing is implemented by simple overcurrent protection devices (OPDs) with I2t characteristics [15]. Since the topology of the microgrid under study is considered looped, the loads can be arbitrarily located. Therefore, the OPDs should have the same rating. In order to introduce the selectivity in the protection, each CI-DER injects a current proportional to the relative distance from the fault location. The CI-DERs closer to the fault will inject a larger current than the ones farther from it. Furthermore, in order to enhance the fault clearing process, a relative time delay proportional to the distance from the fault is also added in the fault current injection. Furthermore, since the current capability of a renewable source cannot be guaranteed, a supercapacitor energy storage system (SESS) is also added at the DC side of each CI-DER. The proposed protection strategy is tested in a looped microgrid, as shown in Fig. 1.
CI-DER1
CI-DER 2 L1
Fault1 CB4
CB2
CB3
CB1
Zline2
CB5
where
CBDER1
CBDER2 CBload1
CB12
Zline1 Zline6
Zline3 CB6 CB7 CBload2
CB8
CB9
Zline4
CB11
CB10
(4)
θ = 2π fdt
(3)
By adding the quantity proportional to sinθ, the zerocrossing is not affected. The selection of the parameter k is such, so as the harmonic content of the current is not disturbed. In this paper, this value is considered equal to 0.05. The current of phase a can be defined by:
I a = 2 ⋅ I rms sin(θ + k sin θ )
Zline5 CBDER4
CI-DER3
CBload3 L3
CI-DER 4
Fault2
Fig. 1. Looped microgrid under study
II. ANALYSIS OF CONTROL METHODOLOGY A. Steady-state operation (islanded mode) Under steady-state operation mode, the active and reactive power sharing among the CI-DERs is defined by implementing the droop control method, which emulates the parallel operation of synchronous generators [4]. Thus, the frequency and voltage magnitude is controlled by the active and reactive power injection respectively, as described in equations below: f = f nom − mx ⋅ P − md
dP dt
(5)
Taking into account that the quantity ksinθ is quite small, consequently cos(ksinθ)≈1 and sin(ksinθ)≈ ksinθ. Therefore, (5) will become as:
CBDER3 L2
θc = θ + k sin θ
(1)
dQ (2) dt where fnom and Vnom refer to the frequency and voltage magnitude at no-load conditions, mx and nx are the droop coefficients, P, Q are the average values of the active and reactive power and md, nd to the derivative droop coefficients, respectively. In order to calculate the active and reactive power, the d, q rotating frame parameters of the measured currents and voltages at the output filter of the DC/AC converter are used, as shown in Fig. 2. Since the microgrid operates in islanded mode, the frequency will deviate among the permissible limits of 49-51Hz, as imposed by EN50160. The control strategy is basically implemented by the voltage and current control, depending on the operation mode of the CI-DER, adding the virtual impedance control for minimizing the circulating reactive currents among the connected sources [16]. Due to absence of the main grid, the maximum load corresponds to the nominal apparent power of the connected CI-DERs. Vn = Vnom − nx ⋅ Q − nd
B. Fault Detection Methodology The methodology for detecting the fault is carried out by measuring the microgrid impedance at the terminals of each CI-DERs in an indirect way. In order to perform this operation, each CI-DER injects intentionally a disturbance current and measures the respective feedback in the voltage at the terminals, by using a Phase Locked Loop (PLL). In case of a fault within the microgrid, the feedback voltage takes a value below a predefined threshold λ, indicating the fault occurrence. For this reason, the initial control angle θ is modified to θc, as it is described in the following equations:
k I a = 2 I rms (sin θ + sin 2θ ) (6) 2 As it can be seen from (6), the phase current contains two different components, where the first one coincides with the current of the normal operation and the second corresponds to the disturbance current. The equivalent Thevenin circuit for the disturbance appears in Fig. 3. By employing a PLL based on the Park Transformation [17], the feedback value of the disturbance can be isolated to the d-axis component of the voltage, Vmgd, as it can be deduced by the following equations: cos θ PLL Vmgd 2 sin θ PLL V = mgq 3 Vmg 0 2 2
2π 2π ) cos(θ PLL + ) 3 3 V a 2π 2π (7) sin(θ PLL − ) sin(θ PLL + ) ⋅ Vb 3 3 Vc 2 2 2 2
cos(θ PLL −
2 Vrms sin θ c Va V = 2 V sin(θ − 2π ) rms c b 3 Vc 2 Vrms sin(θ c + 2π ) 3
(8)
The d-axis voltage component is described as:
Vmgd = 3Vrms sin(θ c − θ PLL )
(9)
Considering that θc-θPLL≈0, then sin(θc-θPLL)≈θc-θPLL. As it is illustrated in the control scheme of Fig. 2b, the angle θPLL is resulted from the error of the d-axis voltage component Vmgd. In Laplace domain, the transfer function of (9) is the following s2 Vmgd ( s ) = 3Vrms 2 s + K 3V s + K 3V p rms i rms
ω k ⋅ ω (10) ⋅ 2 + 2 s + ω2 s
where ω=2πf, while Kp and Ki are the proportional and integral term of the PI controller. These terms can be defined by considering a limit in the response time (e.g. less than 3 cycles). According to Fig. 3, Vrms is proportional to the equivalent Thevenin impedance Zth, therefore the rms value of Vmgd is also proportional to Zth. Thus, any fault can be detected by measuring the value of Vmgdrms. In the control scheme, when Vmgdrms decreases below the threshold λ, a signal “fault” is produced, which switches the internal control from droop control mode to fault mode.
Vmgd
θ
∫
f
++
sin
1
PI Vmgq
abc dq
θPLL
θc
Isf λs
+
(a) Primary Source
Rf
ZSF
ZLS
fault
ZLF
IL Common Bus
Lf
ZL
Ifa CB CB 1 2
2
rms 50Hz
k
CI-DER
∫
-
Va,b,c
Ifb CB1 CB2
IL ZLF
Rf
ZLS Isf
ZSF
ZL
CI-DER (a)
+ -
Ioa,ob,oc
Ia,b,c
abc dq
θc
Cf
Iod,oq SESS
abc dq
Id,q
Lf
θc abc Vd,q
Va,b,c
dq
P
P&Q
Q
PWM
Eq. (1) & (2)
Idref_fault Sa,b,c abc
Sd
Current Control -+
PI
ωLf
++
fault=0
Ioq PI
-+
Iqref
-+
PI
+ +
fault=1
θc
Vd
PI
Vdref
-+
Vq
ωCf fault=0
Vn
f
Voltage Control
ωCf
Iod
ωLf
dq Sq
Idref
-+
fault=1
(b)
Fig. 4. CI-DER contribution to the fault
-+
Virtual Impedance Control
Vqref
Iqref_fault
(b) Fig. 2. (a) 1. Angle distortion control, 2. Fault detection control, (b) CIDER control strategy
is in case that the total load of the microgrid is concentrated in a single node. For this reason, a separate examination of the contribution of each CI-DER takes place, taking into account the relative position of each CI-DER with respect to the load and the fault location, as depicted in Fig. 4. Thus, two subcases are considered for calculating the current through CB1. In Fig. 4a (subcase 1), the impedance between the CI-DER and the CB1 is considered, while in Fig. 4b (subcase 2) impedance between the load and the CB1. The fault currents can be defined from the following equations:
Z L ( Z LF + Z LS ) + Z LS ( Z LF + R f )
I fa =
2 Z tot ( Z L + Z LF + R f ) − Z LF
I fb =
CI-DER Zth √2Irms ksin(2θ) 2
Fig. 3. Thevenin equivalent circuit for the disturbance signal
C. Design of Fault Protection Scheme By implementing the described fault detection technique in case of a line fault, the OPD closer to the fault should be activated first for disconnecting only the part with the fault. Since the OPDs are usually simple circuit breakers (CBs) with an overcurrent tripping curve, the quantity I2t will be measured, where I is the current and t is the time for current flow larger than the rated one. However, in a converterdominated islanded microgrid, the injected currents are restricted to only a few times the nominal one, due to manufacture constraints of the power electronic elements. Another issue faced mainly in low-voltage (LV) microgrids is the relatively large voltage drops and power losses, because of the large R/X ratio of the lines. During the fault, the RL-type loads still absorb a significant current. The situation worsens for faults of high impedances. In order to become the proposed strategy effective even in cases of active power unavailability from the CI-DERs, a SESS with proper nominal capacity is directly connected at the DC side of each CI-DER [18]. The target of the SEES will be to stabilize the voltage at the DC link voltage. The nominal capacity of the supercapacitor bank is calculated based on the nominal apparent power of the CI-DER and the time duration for clearing the fault. This time duration is assumed to be a few seconds (2-4s) in LV microgrids. When a line fault occurs, the DERs should inject a large enough current, in order to activate the CBs at both ends of the faulty line. Furthermore, the load current absorption should be taken into consideration. The worst case scenario
Z SF Z L − R f Z LS 2 Z tot ( Z L + Z LF + R f ) − Z LF
I sf
(11)
(12)
I sf
where I sf is the current injected by the CI-DER, ZL is the impedance of the aggregated load, Ztot is the aggregated line impedance, ZLF the impedance between the load and the fault, ZSF the impedance between the CI-DER and the fault, ZLS the impedance between the load and the CI-DER and Rf the fault impedance. Generally, the aggregated fault current I f of CB1 is calculated considering that the N sources will inject a current equal to I fa and other M sources with I fb : N
Z Li ( Z LFi + Z LSi ) + Z LSi ( Z LFi + R f )
i =1
2 Z tot ( Z L + Z LFi + R f ) − Z LFi
If = M
Z SFj Z L − R f Z LSj
j =1
2 Z tot ( Z L + Z LFj + R f ) − Z LFj
+
I sfi + (13)
I sfj
The rms value of If should be larger than the rated current of the CB, causing its tripping. Therefore, the coefficient c can be added for indicating the ratio among the faulty and the nominal current of each CI-DER: I sfx = c ⋅ I nomx (14) where Isfx corresponds to the fault current and Inomx to the nominal current of CI-DERx, which can be defined by the nominal apparent power and the nominal voltage. The coefficient c is limited between a lower limit clo and a higher limit chi, as shown in Fig. 5. The value clo is determined by considering (13) and (14), and assuming the current I f equal to the rated current of the CB. The worst case is when both the fault and the aggregated load are close to the node of the CI-DER with the smaller rating. According to this consideration, the other impedances of the microgrid can also be determined. Since the microgrid has a looped topology, the direction and magnitude of the current can be arbitrary. Therefore, the
rated current of each CB (denoted as Ir) equals to the aggregation of the nominal currents of all CI-DERs, in order to prevent the mal-tripping under normal operation. Since the rated current is the same for each OPD, the selective operation of the protection means cannot be guaranteed. However, in this paper, the selectivity is performed indirectly by the CI-DERs. The CI-DER closer to the fault senses a smaller impedance and injects relatively larger currents than the ones farther from it. The current injection is defined according to a droop curve, presented in Fig. 5. The Thevenin impedance is measured in an indirect way by the calculated Vmgdrms: c = chi − β ⋅ Vmgdrms (15) c
delay tdmax
chi
clo
λ
(a)
λ Vmg drm s
Vmgdrm s
(b)
Fig. 5. (a) Droop control curve, (b) delay time curve
The higher limit chi is regarded equal to the short-time maximum current capability of the power electronic elements of the respective converters and is assumed equal to 3. The parameter β is defined by considering the maximum value of Vmgdrms equal to the threshold λ. The latter corresponds to the high impedance fault being able to be detected with the proposed methodology. In order to enhance further the selective operation of the CBs, a time delay is also added in the control strategy. The delay time is determined by a second curve, being proportional to the measured value of the parameter Vmgdrms, as shown in Fig. 5(b). The maximum time tdmax is selected at the design of the protection scheme, taking into account the desired selective coordination and the tolerance of the OPDs. Therefore, the CI-DER closer to the fault will start injecting the faulty current earlier compared to the ones farther from it. The switch between the droop control strategy and fault mode is shown in Fig. 2a. The value of the signal “fault” will determine the operation mode. When it equals to 0 (steady state operation), the CI-DER operates in droop control mode. On the other hand, the signal “fault” is set to 1, in case that a fault is detected. In the latter mode, the current references are defined following the proposed methodology. Finally, the frequency of the faulty currents equals to the nominal of 50Hz. III. SIMULATION RESULTS The proposed control methodology is validated in a looped microgrid, consisting of four CI-DERS and three RL loads, as it is shown in Fig. 1. The DC-voltage of all CIDERs equals to 800V, while the switching frequency is 9.75kHz. The other parameters are listed in Table I, while the load parameters in Table II. The distribution lines are considered overhead ACSR with intersection of 16mm2 (R=1.268Ω/km and X=0.422Ω/km) and lengths: Lline1= 500m, Lline2=Lline3=Lline4=100m, Lline5=200m and Lline6=50m. The CBs are equipped with S-type characteristics, having a current sensor such as ABB PR 222DS/P with rated current Ir=80A [19], [20]. The S-characteristic is set to
I2=0.8·Ir=64A with time response equal to 0.05s. The time response is determined by the manufacturer. The I2t quantity is defined by considering 8 times the rated current: I 2 t = (8 ⋅ I r )2 t = (8 ⋅ 80) 2 0.05 = 20, 480[ A2 ⋅ s ] (16) The PI parameters of the PLL can be determined by (10) considering that λ=32.5V. Therefore, Kp=0.3 and Ki=300. For defining the high impedance fault, a short-circuit absorbing power equal to 8 times the nominal aggregated power of the CI-DERs is considered, resulting in 320kW. Thus, the respective fault resistance equals to Rf=0.5Ω. If a fault with larger impedance takes place, the respective Vmgdrms parameter will take a value larger than the threshold λ, leading in detection errors. The lower limits clo is calculated by considering the aggregated nominal load connected at the node of the smaller CI-DER, i.e. at CI-DER2. Initially, the fault occurs within Line 1. The distance between CB1 and the fault is 100m, while between CB2 and the fault is 400m. From (13), the currents at both ends of the line are 28.91A for CB1 and 27.59A for CB2. Thus, the limit clo can be determined by dividing the rated current with the current of CB1, i.e. it is equal to 2.003. Therefore, β=0.0307 and as a result the faulty droop curve is equal to c=3-0.0307·Vmgdrms. The maximum time delay tdmax is selected equal to 0.5s. The simulation software used for presenting the results is PSIM Software. TABLE I. SYSTEM PARAMETERS CI-DER3 Parameters CI-DER1 CI-DER2 400 V 400 V 400 V Nominal line voltage 10 kW 3 kW 15kW Nominal Power Pnom 4.81 A 24.06 A Nominal Current Inom 16.04 A 2 mH 0.6 mH 3 mH Filter Inductance Lf 15 μF 50 μF 12.5 μF Filter Capacitance Cf 2·10-4 6.67·10-4 1.66·10-4 Droop Coefficient mx 10.83·10-3 2.7·10-3 Droop Coefficient nx 3.25·10-3 -5 -5 10 10 10-5 Coefficients md, nd
Loads L1 L2 L3
CI-DER4 400 V 12kW 19.25 A 2.4 mH 10 μF 1.33·10-4 2.16·10-3 10-5
TABLE II. ELECTRICAL PARAMETERS OF THE LOADS P [W] at Q [Var] at R [Ω] L [Η] nominal voltage nominal voltage 10.95 0.078 14,600 6,500 7.73 0.059 20,700 8,700 32 0.231 5,000 2,200
A. Line Fault (Fault1) with Rf=0.1Ω The first simulation investigates a fault in Line 1, named as Fault1 in Fig. 1. The fault takes place at t=0.5s, having a fault impedance equal to 0.1Ω. The fault is detected when the parameter Vmgdrms drops below the threshold λ, as it appears in Fig. 6(b). However, since each CI-DER has a different time delay (according to the curve presented in Fig. 5b), the signal “fault” is produced in different times, as it is shown in Fig. 6(c). First, CI-DER2 detects the fault at t=0.56s, as being closer to the fault. The other CI-DERs identify the fault as follows: CI-DER4 at t=0.6s, CI-DER1 at t=0.64s and CI-DER3 at t=0.68s. When the fault is identified by each CI-DER, it switches the internal control from droop control mode to fault mode and injects a fault current, which is c times the nominal one (Fig. 6(d)). Therefore, the CIDER closer to the fault injects a larger current and the CB closer to the fault also senses a higher current, compared to the other CBs. As a result, the CB2 trips first (at t=3.29s), as being closer to the fault. The rms value of the currents of each CB appear in Fig. 6(e) and in Table III. In Table III, the currents are presented in different times. When CI-DER2
switches to fault mode and injects a fault current, the current is not enough to start the tripping of any CB (the current through each CB is less than 64A). Consequently, CI-DER4 also switches to fault mode. The rms value of the currents are calculated 0.02s later and are presented at t=0.62s. This procedure is continued until all CI-DERs are switched to fault mode. When the current through each CB exceeds the rated current of 64A, the I2t value is calculated. The CB trips, when the aggregated value ΣI2t reaches the value of 20,480. The parameter Δt corresponds to the time difference for tripping of the respective CB. This time is calculated by the following equation: 20, 480 − I 2 t Δt = (17) 2 I CB _ rms where ICB_rms is the rms current flow from the CB, when the first CB trips. It can be deduced from the Table III that the time difference for the tripping of CB1 is 0.388s. After the tripping of CB2, the microgrid topology changes from the looped to radial. Thus, the fault current has only direction and flows to the fault through the CB1, which trips at t=3.412s. After the tripping of CB1, the fault is isolated, allowing the normal operation of the microgrid, implementing the droop control strategy. The voltage at load L1 are illustrated in Fig. 6(a). When the fault takes place, the three-phase voltages are decreased. After the fault clearing, they recover after a seamless transient effect.
(a)
(b)
(c)
Table III. Currents AND tripping time for each CB CB1
CB3,4 CB2 CB5,6 CB7,8 CB9,10 CB11,12 t=0.64s (CI-DER2, CI-DER4 to fault mode)
Current [A] I2t [A2·s]
48.20 -
Current [A] I2t [A2·s] ΣI2t [A2·s]
73.48 216 216
79.99 256 430
Current [A] 82.49 I2t [A2·s] 17,623 ΣI2t [A2·s] 17,839 0.388 Δt [s]
87.98 20,050 20,480 -
65.99 174
52.17 -
55.03 -
59.94 -
13.47 -
(d)
30.37 -
t=0.68s (CI-DER2, CI-DER4, CI-DER1 to fault mode) 65.49 172 172
69.44 193 193
75.66 229 229
12.23 -
31.11 -
t=3.27s (all CI-DERs to fault mode) 74.02 14,190 14,362 1.16
77.95 15,737 15,930
84.68 18,572 18,801
15.75 -
37.77 -
(e) Fig. 6. (a) three-phase voltage [V], (b) Vmgdrms [V] variation for each CIDER, (c) “fault” signal, (d) coefficient c, (e) rms value of currents [A] flow for each CB
102.06 1,286 1,286 1.843
The results are presented in Fig. 7. Fig. 7(a) shows the three-phase voltage at the terminals of load L1, Fig, 7(b) the parameter Vmgdrms and Fig. 7(b) the signal “fault”. Fig. 7(c) presents the parameter c, while the rms values of the current are illustrated in Fig. 7(d). Finally, Table V presents the rms currents of each CB with the respective I2t value. Comparing this table with Table III, the rms currents are higher in this case, causing the tripping of the respective CBs in less time. This result was expected, since the fault impedance is smaller. Thus, the parameter Vmgdrms takes smaller values, leading to higher currents according to the droop curve.
t=3.392s (all CI-DERs to fault mode) Current [A] 147.02 2,641 I2t [A2·s] ΣI2t [A2·s] 20,480 Δt [s]
-
13.71 -
2.25 -
13.89 -
52.16 -
B. Line Fault (Fault1) with Rf=0.001Ω The same simulation test is conducted for a much smaller fault impedance (Rf=0.001Ω). In this test, the sensed voltage Vmgdrms is smaller, resulting in injecting higher currents. Therefore, the fault is cleared in less time, compared to the previous case. The fault is again identified, when the parameter Vmgdrms takes a value smaller than the threshold λ. The current flow through CB1 becomes larger, causing its tripping at t=3.02s. After the tripping of CB1, the fault current flows through CB2, which finally trips at t=3.173s, isolating the fault. The microgrid recovers from the fault and continues its operation in steady-state mode (droop control mode).
IV. CONCLUSION A method to effectively detect and clear faults in a looped microgrid with CI-DERs is presented in this paper. In such microgrids, the CBs have the same rating, which raises challenges in the selective protection. The protection devices are assumed to be circuit breakers with I2t inverse-
coordination, a time delay is inserted in each CI-DER. Therefore, each CI-DER delays the fault current injection, according to the measured microgrid impedance. REFERENCES (a)
(b)
(c)
(d)
(e) Fig. 7. (a) three-phase voltage [V], (b) Vmgdrms [V] variation for each CIDER, (c) “fault” signal, (d) coefficient c, (e) rms value of currents [A] flow for each CB TABLE V. CURRENTS AND TRIPPING TIME FOR EACH CB CB3,4 CB1 CB2 CB5,6 CB7,8 CB9,10 CB11,12 t=0.64s (CI-DER2, CI-DER4, CI-DER1 to fault mode) 68.23 54.28 56.08 59.57 14.33 31.27 Current [A] 48.94 186 I2t [A2·s] t=3.02 (all CI-DERs to fault mode) 92.34 77.1 79.79 84.14 14.79 39.02 Current [A] 84.49 I2t [A2·s] 16,990 20,294 14,148 15,152 16,849 ΣI2t [A2·s] 16,990 20,480 14,148 15,152 16,849 1.065 0.837 0.489 0.513 Δt [s] t=3.173s (all CI-DERs to fault mode) 13.82 3.44 11.27 54.66 105.44 Current [A] 150.87 3,490 1,701 I2t [A2·s] 1,701 ΣI2t [A2·s] 20,480 1.689 Δt [s]
time characteristics. By implementing the proposed control strategy, each CI-DER identifies the fault by measuring indirectly the microgrid impedance and changes the control mode to fault operation mode, without using any physical communication. In the latter mode, each CI-DER injects a fault current proportional to the sensed microgrid impedance at its terminals, according to a droop curve. Hence, the CIDER closer to the fault injects a relatively larger current, enhancing the selective coordination of the protection devices. In order to further enhance the selective
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