Real Time Simulation of New Adaptive Overcurrent Technique for Microgrid Protection

Transcription

1 Real Time Simulation of New Adaptive Overcurrent Technique for Microgrid Protection Harikrishna Muda and Premalata Jena Electrical Engineering Department Indian Institute of Technology Roorkee Roorkee, India E.mail: and Abstract In this paper, an adaptive overcurrent coordination technique for the microgrid having both rotating and inverter based distributed generation systems (DGs) is considered. During a fault, the magnitude and direction of fault current contributed by both the DGs vary differently with respect to the prefault current. Moreover, the fault current contributed by the inverter based DGs is clamped within 2 p.u of the rated current due to the thermal limit of the inverter present within it. Further, the fault current phasors during the islanded and grid-connected modes of operation vary to different values and lead towards false trip by overcurrent relays. This situation leads to the miscoordination between the primary and backup relays used to protect the feeders of the microgrid system. This work proposes an adaptive overcurrent relaying technique which uses the positive sequence and negative sequence components of fault current to coordinate the primary and backup overcurrent relays. A 2.47 kv, 5 Hz, 3 bus system is simulated using the real time digital simulator (RTDS) and performance of the proposed approach is tested for various fault scenarios. Keywords Adaptive overcurrent protection technique, microgrids, the mode of operation, sequence components I. INTRODUCTION Distributed generations (DGs) are integrated with the main grid to implement a microgrid. The microgrid operation has opened one plausible alternative to use renewable sources which has several benefits such as reduced transmission losses, improved power quality, improved reliability, proper utilization of resources and reduced overall impact on the environment []-[]. However, integration of synchronous based distributed generators (SBDGs) and inverter based distributed generators (IBDGs) to the existing sub-transmission or distribution level poses many challenging issues. One of the main issues is the overcurrent relay (OCR) protection coordination. When a microgrid is not grid tied, and operated in autonomous mode, the fault current seen by OCRs is reduced. Further, the protection of /4/$3. 26 IEEE the low fault current contribution of IBDGs becomes extremely difficult and ensuring a reliable protection coordination becomes challenging. To extenuate the DG s impact on the protection system, there are many adaptive overcurrent relaying techniques are available in the literature []-[]. In [], instantaneous and time overcurrent characteristics based relaying schemes are proposed for grid connected and islanded modes of operations. The technique is dependent on the voltage signal to detect the islanded situation of the microgrid system. An adaptive technique as explained in [2] is considered to coordinate the OCRs by monitoring the operating modes such as islanded mode, grid connected mode, out of or in service of DGs. Suitable OCR settings have been estimated by adopting the steady state fault current using the reduced network in [3]. A multi agent based technique is suggested in [4] to coordinate OCRs that are installed in the microgrid system. The differential relaying technique as explained in [5]-[6] is used to protect feeders in microgrid for different types of faults. The differential technique used in [6] is dependent of communication facility to calculate the differential current. In [7], the scalable and fast method is explained in order to update the relay settings (calculated on off-line basis) using a communication link to update the status of the islanded mode of operation. In [8], the technique changes the settings of protection relays that can fit into the grid connected and the islanded mode is described. In the grid connected mode of operation, an IBDG change the contribution of the grid fault current during a high resistance fault as given in [9]. Single-pole tripping (SPT) of microgrid system offers an improvement in reliability by avoiding unnecessary outage of healthy distribution lines during a single phase to ground faults []. The integrated of phase and sequence components based protection scheme is suggested in []. However, the effect of SPT condition needs to be considered in the microgrid protection due to changes in the magnitude and direction of sequence components flowing through the relay. II. FAULT CURRENT CONTRIBUTION DURING OPERATION OF MICROGRID MODES The microgrid operation can be classified into four modes: ) the islanded mode consisting of only IBDGs; 2) the islanded mode having IBDGs as well as synchronous

2 based DGs (SBDGs); 3) the grid connected mode; and 4) out of or in service of DGs depending on the situation. In order to evaluate fault current contribution during different modes of operation of microgrid, a 2.47 kv, 5 Hz, the test distribution system (with the presence of two DGs) as shown in Fig. is considered [2]. This system is modelled using a real time system computer aided design (RSCAD) software [3] of RTDS and is illustrated in Fig.. The 3-bus system comprises one synchronous generator (SG) associated with a governor and excitation system, PV generation system including control mechanism and unbalanced impedance type of loads. A voltage controlled voltage source inverter (VSI) is used for IBDGs. Sinusoidal pulse width modulation technique is used to determine the pulses for the inverter switches. The operation of the VSI using voltage controller is considered as mentioned in [4]. The parameters of the VSI and the PV module (Tata power TS23 MBT) are provided in Appendix A. In this microgrid, R2 and R3 are treated as primary OCRs and R and R4 are their corresponding backup OCRs. Fig.. Three-phase power system with DGs modelled in RSCAD environment. Fig. 2. Waveforms for several scenarios. Islanded mode. (b) Grid connected mode. A single-phase to ground fault is created on the line- (F 2 ) at.4 s in Fig. during grid connected and islanded mode of operations. The phase-a current (dashed line) measured at R4 location is shown in Fig. 2 during the islanded mode of operation with the presence of IBDG only. The phase-a current for other two scenarios (i.e. with the presence of SBDG (solid line) and SBDG along with IBDG (dotted line)) are also shown in Fig. 2. It is observed that the fault current contributed by only IBDG is less in comparison to the other two scenarios. Thus, the protection technique is largely influenced during the islanded mode consisting of only IBDGs in a microgrid environment. For the same scenarios, the phase-a current for ag-type fault incepted at F2 position during grid connected mode of operation is shown in Fig. 2(b). It can be observed that the fault current contributed by SBDG operating with IBDG is more in comparison to other two scenarios (with the presence of SBDG only and with the presence of IBDG only). This analysis leads to a conclusion that there is a wide variation in fault current level for different operating modes of microgrid with and without presence of different types of DGs. As a result, the conventional OCR setting is insufficient to handle these variations and one adaptive technique is sought for overcoming such situations. III. ADAPTIVE TECHNIQUE FOR OVERCURRENT PROTECTION DURING MICROGRID OPERATION This paper introduces a new adaptive overcurrent relaying technique using sequence currents. In [], negative sequence (NSQ) based overcurrent relaying scheme is used to protect the feeder of a distribution system. However, the performance of the technique is not tested for the microgrid operations. Mostly the distribution system is unbalanced in nature []. In the majority of possible microgrid operating modes, positive sequence (PSQ) and NSQ components may arise from unequal voltage sources or loads. By exploiting this condition, a NSQ based OC relaying scheme is incorporated in the proposed method for the protection of feeders in microgrids. It is to be noted that each fault point (FP) will have primary relay and backup relay and the backup relay will operate after a time interval when its respective primary relay fails to clear the fault during protection coordination process. Initially, time of operation of the relay nearest to the FP is computed by considering the minimum fault current and pickup current of the relay. Lowest time dial setting (TDS) is selected for the primary relay. It is to be noted that the fault current seen by the relay is obtained by considering the phase-to-ground fault of ag-type at the end of the line in the distribution system. The pickup current is calculated based on the maximum load current passing through the relay. For the same FP, fault current seen by the relay (i.e. backup relay) next in the line is measured. To obtain the protection coordination, the coordination time interval (CTI) is added to the time of operation of the primary relay and the time of operation of the backup relay is determined. By knowing the time of operation of the backup relay, pickup current and the TDS for backup relay is computed [5]. The following constraints are applied in this method for the computation of relay settings. The operating time of each relay is limited to be less than s and CTI is greater than.3 s. The TDS is chosen to be the range of.5 to. The lower and upper limits on the pickup setting are chosen to be. and respectively. The fault current contribution of SBDG is greater than the fault current contribution of IBDG which may not exceed the pickup current of overcurrent relay. Since the overcurrent relay cannot operate for low fault current of IBDG, the adaptive fault current is computed using superimposed component of positive sequence current. Therefore, overcurrent relays must equip with adaptive fault current in case of microgrids to improve the performance of overcurrent relays and protection coordination. The superimposed component of current using the prefault current (I pre ) and fault current (I F ) phasors is provided as [6] Δ I = I I () F F pre

3 A. Consideration of IBDGs In order to ensure safe protection of inverter based the islanded microgrid, the relay current is adjusted as supervision of NSQ and PSQ fault components. During the faults, the adaptive fault current (I F ) measured by the relay is therefore ( ) IF = IF + I2F Χ Δ IF (2) where I F and I 2F are PSQ and NSQ fault currents respectively. ΔI F is the impact factor as provided in (3). I F Δ IF = (3) Δ IF where the superimposed PSQ fault current ( ΔI F ) is equal to the difference between prefault PSQ current ( I pre ) and PSQ fault current ( I F ). Numerous fault situations are simulated and corresponding impact factors are calculated. It is observed that the impact factor is in between 2 to 3 as the fault current contributed by IBDG is within.5 to 2 p.u. of rated current. I_R2 f I_R2 p TRG_R2 Counter_limit RESET _R2 where TDS is the relay time dial setting and M is multiple of pickup current which is equal to the ratio of adaptive fault current (I F ) passing through the relay to its pickup setting (I P ). The pickup setting is selected based on the maximum load current passing through each relay []. Detailed real time modelling of IDMT OCR is depicted in Fig. 3. The values of TDS and function of pickup current multiple are initialized as. to calculate the expected relay time to operate. Coordination time interval of.3 s is added to trip time of primary OCR for the computation of backup OCR s TDS. The proposed technique verifies an operation time limit of s typically used in utility requirements for the prevailed relay settings. If the value of TDS is satisfying constraints, then the TDS value is maintained in relay location. NSQ and PSQ components are calculated using a real-time phasor diagram as shown in Fig. 3. Further, superimposed components are computed by including a capture component in the process. It is to be noted that the adaptive fault current in (2) is dependent on both the PSQ and NSQ components of fault current. During three-phase fault, the magnitude of PSQ current is substantially high enough to operate the OCR. The proposed technique takes proper decision even though there is absence of NSQ component for such a balanced fault situation. Thus, aforementioned rule base is adapted to protect against all faults in the microgrid. The proposed method must take into account that during overloading conditions, NSQ and PSQ current may not increase similarly as in the case of fault. Therefore, calculation of the ratio between NSQ and PSQ current could be used to make a difference between the overloading and fault condition to avoid nuisance tripping of the proposed technique. I_R2 a I mag _R2 IV. PERFORAMNCE EVALUATION OF THE PROPOSED ADAPTIVE OVERCURRENT TECHNIQUE I_R2 b I_R2 c I_R4 f time_r2 TDS_R4 I_R4 p Fig. 3. RTDS/RSCAD model of the proposed adaptive overcurrent relay. I 2mag _R2 TDS_R2 B. Consideration of both IBDGs and SBDGs To obtain the adaptive OC relaying scheme for microgrid system in presence of both IBDG and SBDG, the corresponding modified fault current is calculated using the relationship provided in (2). In this case, the impact factor is different than the previous case and it is provided as ΔIF Δ I = (4) F Δ IF Ipre An adaptive fault current expressed in (2) is used with inverse definite minimum time (IDMT) characteristic to calculate the trip time of the breaker, which is depicted as [].4 t = TDS= f.2 ( M) TDS (5) M ( ) A. Performance Results for The Islanded Mode of Operation (considering IBDGs only) To test the performance of the proposed technique, the system as shown in Fig. is operated in islanded mode with presence of IBDG by disconnecting the substation and SBDG. The ag-type fault is created at F 2 at t=.3 s. The prefault and fault currents are stored at a sampling rate of khz. The prefault and fault current phasors are calculated using one cycle discrete fourier transform technique [7]. The phase-a current is taken as the reference quantity for the sequence component calculation. The prefault PSQ current is considered as I P of every relay. Table I presents the values of current transformer (CT) ratio, protection settings (i.e TDS and Ip) and sequence components of fault current for all relays. For R2 and R4 OCRs, the pickup currents are.3 A and.89 A respectively. TDS is maintained as.2 for backup OCR R4 such that it should clear fault after.3 s of primary OCR R2 time of operation. As a result, the CTI between the primary and backup relays is maintained as.3s. It is seen that the PSQ fault current is in the range of.5 to 2. p.u. Thus, the impact factor as considered in the proposed adaptive technique is estimated using (3). Further, the adaptive fault current in (2) is computed using the NSQ and

4 PSQ fault currents that are shown in Table I. The time of operation (t) is obtained using (5) and it is found that the CTI is maintained at least of.3 s as shown in Table I. The performances of the proposed approach for other fault cases are found to be accurate. TABLE I RESULTS FOR RELAY SETTINGS, ADAPTIVE FAULT CURRENTS AND TIME OF OPERATION FOR ISLANDED MODE IN PRESENCE OF IBDG R/FP CT I p, A I TDS 2, A I,A CTI, ΔI Ratio F t, s Mag Mag Mag s R/F3 / R3/F3 5/ R4/F2 5/ R2/F2 / TABLE II RESULTS FOR RELAY SETTINGS, ADAPTIVE FAULT CURRENTS AND OPERATING TIMES FOR ISLANDED MODE IN PRESENCE OF IBDG AND SBDG R/FP CT I p, A I TDS 2, A I, A CTI, ΔI Ratio F t, s Mag Mag Mag s R/F3 / R3/F3 5/ R4/F2 5/ R2/F2 / B. Performance Results for The Islanded Mode The performance of the proposed technique is evaluated for the islanded mode of operation where both SBDG and IBDG are connected to the microgrid as shown in Fig.. To test the performance of the proposed technique, ag-type fault is created at the FP F 2 at t=.3 s. The respective PSQ and NSQ components are shown in Table II. It is observed that with the inclusion of SBDG, the sum of NSQ and PSQ fault components is increased. With the substitution of NSQ and PSQ fault components in (4), the impact factor is determined. Table II shows the impact factor, time of operation, relay settings and CTI obtained from the operating time of primary and backup OCRs. The technique provides an effective protection coordination and time of operation for different types of faults. C. Performance Results for The Grid Connected Mode Next, the proposed technique is tested for the grid connected mode of the microgrid. The calculated values of TDS and I P are provided in Table III. Ag-type of fault is created at t=.3 s at FP S (F 2 or F 3 ). The respective PSQ and NSQ components are shown in Table III. It is seen that the amount of NSQ and PSQ fault component increases with the inclusion of the grid. The reason for the variation is due to the major fault current is contributed by the grid during faults. However, the impact factor computed using (4) is significant in order to limit the sum of sequence fault components and obtain the correct time of operation of both the primary and backup OCRs. It is seen that TDS of OCRs has increased due to the variation in function of pickup current multiple. Table III shows the impact factor, time of operation, relay settings and CTI obtained from the operating time of primary and backup OCRs. TABLE III RESULTS FOR RELAY SETTINGS, ADAPTIVE FAULT CURRENTS AND TIME OF OPERATION FOR GRID CONNECTED MODE R/FP CT Ip, A I TDS 2, A I, A CTI, ΔI Ratio F t, s Mag Mag Mag s R/F3 / R3/F3 5/ R4/F2 5/ R2/F2 / Ph. C Ph. B Ph. A (b) (c) Time(s) (f) Time(s) Fig. 4: Results for the traditional method during islanded mode in presence of IBDG and SBDG. Three phase currents at R2. (b) Phase fault current at R2. (c) signal at R2. Three phase currents at R4, Phase fault current at R4. signal at R4. D. The Impact of High Resistance Faults Considering the islanded mode of operation with presence of both IDBG and SBDG, the performance of traditional phase overcurrent relay as discussed in [2] is studied and corresponding response is provided in Fig. 4. ag-type fault with a fault resistance of 5Ω is created at the FP-F2 at t=.3 s. For R2 and R4 relays, the pickup currents are.32 A and.96 A respectively. TDS of R2 and R4 is maintained as.5 and.72 respectively. The time taken by R2 and R4 to clear FP-F2 is.24 s and.62 s respectively. The CTI between the primary and backup relays is.38 s and which may take more time than the desired CTI. The same fault situation is cleared with help of the proposed technique within the desired time as set in between the primary and backup relays. The performance of the proposed technique is shown in Fig. 5. With the adaptation of fault current, OCRs R2 and R4 are correlated well where the trip time is.2 s and.58 s respectively. Ph. C Ph. B -.6 Ph. A (b) (c) Time(s) (f) Time(s) Fig. 5: Results for the proposed method during islanded mode in presence of IBDG and SBDG. Three phase currents at R2, (b) Adaptive fault current at R2 (c) signal at R2 Three phase currents at R4, Adaptive fault current at R4 signal at R4. To present the impact of high resistance faults, the system as shown in Fig. is operated in islanded mode with presence of IBDG by disconnecting the substation and SBDG. The corresponding fault current waveforms obtained at the same relay locations are shown in Fig. 6. However, the phase overcurrent relay fails to provide protection measures for islanded mode of operation with the presence of IBDG only as the magnitude of phase fault current is not sufficient. To have a relative assessment, obtained results by

5 the proposed technique are provided in Fig. 7. It is to be noted that relay settings are maintained as shown in Table I. R2 and R4 OCRs work correctly with adaptation of NSQand PSQ- fault components as being.69 s and.2 s. Thus, the time of operation of the OCRs lies perfectly within the desired requirements. Sig (b) (c) Time(s) (f) Time(s) Fig. 6: Results for the traditional method during islanded mode in presence of IBDG only. Three phase currents at R2. (b) Phase fault current at R2. (c) signal at R2. Three phase currents at R4. Phase fault current at R4. signal at R (b) Time(s) (c) Time(s) (f).3 Fig. 7: Results for the traditional method during islanded mode having IBDG only. Three phase currents at R2. (b) Phase fault current at R2. (c) signal at R2. Three phase currents at R4. Phase fault current at R4. signal at R4. Mag. Ph. A Ph. B Ph. C (b) t count (c) Fig. 8: Results for variable fault resistance fault. a) Measured fault currents at R4. (b) Adaptive fault current. (c) Counter response of proposed technique. signal. Counter response of conventional technique. E. The Impact of Line to Ground Fault with Variable Fault Resistance Performance of the proposed technique is also tested for line-to-ground fault at FP-F3 with variable fault resistance at t=.4 s. The estimated sequence currents at R4 position are shown in Fig. 8. Many protection techniques are affected by unbalanced fault with variable fault resistance due to different pattern of fault current. Using the adaptive fault expression in (2), the time taken to clear such a fault situation is within.34 s. It could be observed that the time taken by the relay is more in comparison to other fault situations. However, the CTI between the primary and backup relays are within the desired time gap. Mag Ph. A Ph. B Ph. C (b) t (c) t count count Fig. 9: Results for bc fault during tripping of line2 a-phase. Measured fault currents at R4. (b) Adaptive fault current. (c) Counter response of proposed technique. signal. Counter response of conventional technique. F. The Impact of Single Pole ping and The Islanded Mode Single-pole tripping is an unbalanced situation. This situation is created by opening the poles of phase-a breakers present at the two ends of line-2 following an ag-type fault created in phase-a. This situation leads to presence of NSQ and zero sequence components in voltage and current signals. During such a situation, bc-type fault is created at FP-F4 at t=.4 s. The correction factor is calculated to obtain the desired time of operation by the primary and backup relays. The dynamic plots of current signals are shown in Fig. 9. The extreme magnitude of adaptive fault current is seen by OCR, R4 as shown in Fig. 9(b). Subsequently, trip time t is computed as adaptive fault current is greater than the pickup current of OCR R4. Fig. 9(c) shows the trip time setup is based on every full cycle adaptive fault current and the counter starts to ramp until reach trip time set value. Fig. 9 shows the trip is produced at.73 s by the proposed relay. Reclosing each phase may independently lead to the potential relay coordination issue. G. The Impact of Voltage Source Inverter Controllers: The fault response of the inverter based system is dependent on the controller associated with the inverter to control the switching action of the electronic devices [8]. The controller of the inverter affects the current signal of the IBDG in the event of fault. The voltage controlled IBDG and current controlled IBDG responses were examined during ag-type fault at FP-F4 as shown in Fig. with a fault resistance of.ω. Fig. illustrates the phase-a current of the inverter during operation of voltage controller as well as current controller. In contrast to the voltage controlled

6 IBDG, the current controlled IBDG has regulated output current that was not affected by the fault. Current (ka ) Fig.. Phase-a current of IBDG for ag-type fault at t=.4s. Voltage control mode Current control mode The implementation of the adaptive overcurrent coordination technique is requiring little effort on digital hardware platform as this is based on sequence transformation based phasor estimation. Further, the protection coordination optimization model [5] is capable of providing effective protection measure in comparison to the simple protection coordination approach. This is being considered as a future study. V. CONCLUSION Sequence component analysis may draw widespread attention as inverter based power resources are emerging for many economic and environmental benefits. In this paper, sequence component based adaptive overcurrent relaying technique is presented for the microgrid. The technique is found to be working effectively under a wide range of realtime operating modes of microgrid. It found that the proposed method provides reliable protection performance in certain critical cases where phase OCR fails. The performance of the proposed approach is satisfactory for different critical situations like single-pole tripping and lineto-ground fault with variable fault resistance. REFERENCES [] P. Mahat, Z. Chen, B. Bak-Jensen and C. L. Bak, A simple adaptive overcurrent protection of distribution systems with distributed generation, IEEE Trans. Smart Grid, vol. 2, no. 3, pp , Sep. 2. [2] F. Coffele, C. Booth, and A. Dysko, An adaptive overcurrent protection scheme for distribution networks, IEEE Trans. Power Deliv., vol. 3, no. 2, pp. 8, Apr. 25. [3] J. Ma, X. Wang, Y. Zhang, Q. Yang, and A. G. Phadke, A A novel adaptive current protection scheme for distribution systems with distributed generation, Int. J. Electr. Power & Energy Syst., pp , Dec. 22. [4] H. 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APPENDIX A TABLE IV SPECIFICATIONS OF THE VOLTAGE SOURCE INVERTER Parameter Value Rated voltage 23 V Rated current 25 A Filter inductance.52 mh Filter resistance.6 mω Filter inductance µf Switching frequency 2. khz System frequency 5 Hz Transformer rating.23/4.6 kv TABLE V SPECIFICATION OF TS23 MBT TATA POWER SOLAR AT STANDARD TEST CONDITIONS (25 C AND W/M2) Parameter Value Peak power (P max ) 23 W Max. voltage (V mpp ) 29. V Max. current (I mpp ) 7.9 A Open circuit voltage (V oc ) 36.7 V Short-circuit current (I sc ) 8.4 A Max. series fuse 2 A