Method and system for fault location and protection of inverter-dominated ungrounded island microgrids

Abstract

To provide a method for effective fault location identification and protection for inverter-dominated islanded microgrids, and a power system.SOLUTION: A method comprises: a step of using an interface 153 to receive zero-sequence current, negative-sequence current, and phase current measurements from terminal buses of branches arranged in a microgrid via a communication network; a step 130 of receiving zero-sequence current, negative-sequence current, and phase current measurements from the terminal buses of the branches arranged in the microgrid via the communication network; a step 132 of using a hardware processor 155 to determine negative-sequence magnitude difference attributes for each measured branches of the microgrid; a step 134 of determining phase current sign change attributes for each measured branch in the microgrid; and a step 136 of locating faulted line segment on the basis of the determined difference attributes between terminal buses of each line segments within the microgrid.SELECTED DRAWING: Figure 1A

Description

[Technical Field]

[0001] FIELD OF THE DISCLOSURE The present disclosure relates generally to power systems, and more particularly to fault location and protection for microgrids. [Background technology]

[0002] Recently, with the progress of renewable energy-conscious society, microgrids have attracted much more attention. Microgrids are localized power grids that can operate autonomously and independently from the conventional power grid, thereby enhancing grid reliability and mitigating grid disturbances. Furthermore, they are considered a promising solution for operating future power systems integrated with distributed generators (DG) and renewable energy sources (RES).

[0003] Microgrid operation is highly flexible in that it can operate in either grid-connected or islanded mode. However, microgrid characteristics, such as the fault level and control strategy of inverter-based distributed generators (IBDGs), will vary significantly between different operating modes. Therefore, conventional fault protection schemes are not applicable to island microgrids. In particular, the fault level varies significantly between modes. In grid-connected mode, large fault currents (10 to 50 times the full-load current) are available to activate conventional overcurrent protection devices, whereas the available fault current in island microgrids is only about 5 times the full-load current. In particular, in island microgrids with a high penetration rate of inverter-based distributed generators (IBDGs), the maximum output fault current is generally limited to 1.2 to 2 times the rated current. Nevertheless, conventional overcurrent protection devices, typically configured to operate at 2 to 10 times the full-load current, cannot detect and protect the island microgrid.

[0004] Furthermore, the control techniques for IBDGs also differ in each mode. Common control strategies for IBDGs include active-reactive power (PQ) control (grid feeding) and voltage-frequency (VF) control (grid following). PQ control can supply constant power by referencing active and reactive power. VF control can regulate the voltage and frequency of the IBDGs through voltage and current control loops. All IBDGs in a microgrid can operate under PQ control in grid-connected mode, while in islanded mode, IBDGs under VF control are required to support the grid voltage. These IBDG control strategies can also have a significant impact on fault behavior. Both of the above factors create new technical challenges for fault localization and protection, especially in islanded microgrids.

[0005] There is some related research on microgrid fault detection, location, and protection. One example of this research can be found in European Patent Application EP3605776. This application presents a method for locating phase faults in a microgrid in off-grid mode. The method includes acquiring a grid topology of a microgrid having at least two busbars and determining the locations of all circuit breaker positions in the grid topology. The method further includes acquiring measurement data including current magnitudes and voltage magnitudes, monitoring a voltage sag in one of the phase-to-phase voltages or phase-to-neutral voltages of the at least two busbars, and upon detecting the voltage sag, determining a faulty phase with the lowest phase-to-neutral voltage value, and performing busbar analysis and feeder analysis for the faulty phase using the phase direction information.

[0006] Another example is US Patent Application US2020 / 0350761 A1, which discloses a method for protecting and controlling a microgrid using dynamic boundaries. The method includes detecting a fault in a microgrid including a dynamic point of common coupling (PCC), isolating the fault by tripping a microgrid-side smart switch and a grid-side smart switch located immediately adjacent to the fault in response to determining that the microgrid is operating in a grid-connected mode, initiating reclosure of the grid-side smart switch, and initiating reclosure of the microgrid-side smart switch by resynchronization if the grid-side smart switch is successfully reclosed, and isolating the fault by tripping a microgrid-side smart switch located immediately adjacent to the fault in response to determining that the microgrid is operating in an islanded mode.

[0007] However, neither the first nor the second patent disclosure takes into account the characteristics of inverter-dominated microgrids and the impact of IBDGs.

[0008] Another example of microgrid fault detection is the paper "The fault detection method of islanded microgrid with the v / f controlled distributed generation" by Z. Liang et al. (International Journal of Electrical Power & Energy Systems, vol. 112, pp. 28-35, 2019). The paper disclosed a fault detection method for islanded microgrids that utilizes the phase difference between the pre-fault bus voltage of the feeder and the positive-sequence current fault component. However, the difference between the main fault types is ignored.

[0009] Therefore, there is a need for an effective fault location and protection method for inverter-dominated island microgrids. Summary of the Invention

[0010] This disclosure provides a fault location and protection method or scheme for ungrounded islanded microgrids with inverter-dominated distributed generators (IGDBs) equipped with fault current limiters (FCLs). Microgrids are gaining increasing interest because they can operate under islanded mode by disconnecting from the large-scale utility grid during a large-scale disaster. However, isolated microgrids do not include appropriate protection systems, which are often installed only at distribution substations. Furthermore, the well-penetrated IGDBs significantly limit fault currents.

[0011] The disclosed method is developed based on transient analysis during various types of faults in an ungrounded island microgrid, where multiple IBGDs are deployed under various control strategies. Furthermore, a fault detection and location method based on two-terminal measurements is proposed, instead of the single-terminal measurements often utilized in conventional protection schemes such as overcurrent protection. The proposed method does not rely on the exchange of large amounts of information. It locates various types of faults in the island microgrid by monitoring the zero-sequence component, negative-sequence component, and phase currents collected from the microgrid's line segments. Simulation results for a sample system are provided to demonstrate that the proposed method also works well in island microgrids with lower fault current levels.

[0012] Some embodiments of the present invention provide a computer-implemented method for protecting a power grid system including a primary bus and an island microgrid isolated from a distribution system. The island microgrid forms a branch from the primary bus, and the island microgrid includes at least one distributed generator (DG). Each DG includes at least one switchable device for isolating its power source from the power grid. Each of the branches includes a first terminal sensor located near the primary bus and a second terminal sensor located on a terminal bus opposite the branch. The first and second terminal sensors indicate a branch position of each of the branches within the power grid. In this case, the method uses a processor coupled to a memory storing instructions implementing the method. When executed by the processor, the instructions perform the method steps. The method includes receiving measurement data from each of the branches, including the branch position, from the first terminal sensor and the second terminal sensor. The measurement data includes zero-sequence currents of the first and second terminal sensors, negative-sequence currents of the first and second terminal sensors, and phase currents of the first and second terminal sensors. The method further includes determining that the branches exhibit a fault status between the branches when there is a phase angle difference of approximately 180 degrees between the zero-sequence currents, when the magnitude of the difference between the negative-sequence currents of the first and second terminal sensors in a branch is equal to or greater than a threshold, or when the difference in sign of any phase current as a function of time exhibits a transition between 0 and 2. The method further includes sending a control command to a switching device that can isolate the determined branch exhibiting the fault status from a power source of the DG based on a distance from a switching location to the determined branch. The control command instructs the switching device to disconnect the determined branch exhibiting the fault status.

[0013] Further, some embodiments of the present invention provide a fault location and protection system for protecting a power grid system including a primary bus and an island microgrid isolated from a power distribution system. The island microgrid forms a branch from the primary bus, and the island microgrid includes at least one distributed generator (DG). Each of the at least one DG includes at least one switchable device for isolating a power source of the at least one DG from the power grid. Each of the branches includes a first terminal sensor disposed near the primary bus and a second terminal sensor disposed on a terminal bus opposite the branch. The first and second terminal sensors indicate a branch position of each of the branches within the power grid. The method uses a processor coupled to a memory storing instructions implementing the method. When executed by the processor, the instructions perform the steps of the method. The system includes an interface configured to receive measurement data from each of the branches, including the branch position, from the first terminal sensor and the second terminal sensor. The measurement data includes zero-sequence currents of the first terminal sensor and the second terminal sensor, negative-sequence currents of the first terminal sensor and the second terminal sensor, and phase currents of the first terminal sensor and the second terminal sensor. The system further includes a processor configured to execute a computer-implemented method and a memory configured to store the computer-implemented method. The method uses the processor coupled to the memory having instructions stored therein that implement the method. When executed by the processor, the instructions perform steps of the method.The method includes determining that a branch exhibits a fault status between the branches when there is a phase angle difference of approximately 180 degrees between the zero-sequence currents, when the magnitude of the difference between the negative-sequence currents of the first and second terminal sensors in a branch is equal to or greater than a threshold, or when the difference in sign of any phase currents as a function of time exhibits a transition between 0 and 2, and sending a control command to at least one switchable device configured to isolate the determined branch exhibiting the fault status from the at least one DG, the at least one switchable device being determined based on a distance from the at least one switchable device to the determined branch. The control command instructs the switchable device to isolate the determined branch from the at least one DG.

[0014] The presently disclosed embodiments are further described with reference to the accompanying drawings, in which the drawings are not necessarily to scale, emphasis instead generally being placed upon illustrating the principles of the presently disclosed embodiments. [Brief explanation of the drawings]

[0015] [Figure 1A] FIG. 1 is a block diagram illustrating a method for detecting and locating faults in an inverter-dominated ungrounded microgrid according to an embodiment of the present disclosure. [Figure 1B] FIG. 1 is a schematic diagram illustrating components and steps for detecting and locating faults in an inverter-dominated ungrounded microgrid according to an embodiment of the present disclosure. [Figure 1C] FIG. 1 is a block diagram illustrating a fault location and protection system for detecting faults in an inverter-dominated ungrounded microgrid according to some embodiments of the present disclosure. [Figure 2] FIG. 1 is a schematic diagram illustrating a control block diagram of a VF-controlled IBDG according to some embodiments of the present disclosure. [Figure 3]FIG. 1 is a schematic diagram illustrating a control block diagram of a PQ-controlled IBDG according to some embodiments of the present disclosure. [Figure 4A] FIG. 1 is a schematic diagram illustrating a configuration of an IBDG without an FCL, according to some embodiments of the present disclosure. [Figure 4B] FIG. 1 is a schematic diagram illustrating a configuration of an IBDG with an FCL, according to some embodiments of the present disclosure. [Figure 5A] FIG. 1 is a schematic diagram illustrating an original microgrid model, according to some embodiments of the present disclosure. [Figure 5B] FIG. 1 is a schematic diagram illustrating a zero-sequence fault model, according to some embodiments of the present disclosure. [Figure 6A] FIG. 1 is a schematic diagram illustrating a negative sequence equivalent model of a VF-controlled IBDG according to some embodiments of the present disclosure. [Figure 6B] FIG. 1 is a schematic diagram illustrating a negative sequence equivalent model of a PQ-controlled IBDG according to some embodiments of the present disclosure. [Figure 7] FIG. 1 is a schematic diagram illustrating a simulated microgrid model according to some embodiments of the present disclosure. [Figure 8] FIG. 1 is a schematic diagram illustrating a phase diagram of a zero-sequence current, according to some embodiments of the present disclosure. [Figure 9] FIG. 10 is a schematic diagram illustrating a monitoring angle difference of zero sequence current according to some embodiments of the present disclosure. [Figure 10] FIG. 10 is a schematic diagram illustrating the difference in magnitude of negative sequence current, according to some embodiments of the present disclosure. [Figure 11] FIG. 1 is an equivalent circuit diagram of a microgrid with a three-phase ground fault according to some embodiments of the present disclosure. [Figure 12] FIG. 1 is a schematic diagram illustrating a comparison between iA and iB under multiple scenarios, according to some embodiments of the present disclosure. [Figure 13] FIG. 10 is a schematic diagram illustrating the difference in monitoring magnitude of current according to some embodiments of the present disclosure. [Figure 14]FIG. 1 is a schematic diagram illustrating an implementation of fault location and protection for an inverter-dominated island microgrid. DETAILED DESCRIPTION OF THE INVENTION

[0016] big picture FIELD OF THE DISCLOSURE The present disclosure relates generally to power systems, and more particularly to fault location and protection for microgrids.

[0017] The following description provides exemplary embodiments only and is not intended to limit the scope, applicability, or configuration of the present disclosure. Rather, the following description of exemplary embodiments will provide those skilled in the art with an enabling description for implementing one or more exemplary embodiments. It is contemplated that various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the disclosed subject matter as set forth in the appended claims.

[0018] In the following description, specific details are provided to provide a thorough understanding of the embodiments. However, those skilled in the art will understand that the embodiments may be practiced without these specific details. For example, systems, processes, and other elements in the disclosed subject matter may be shown as components in block diagram form so as not to obscure the embodiments with unnecessary detail. In other instances, well-known processes, structures, and techniques may be shown without unnecessary detail so as to avoid obscuring the embodiments. Furthermore, like reference numbers and names in the various figures indicate like elements.

[0019] Many distribution networks are grounded at distribution substations, and protective relays are often installed at distribution substations and at customer sites. Portions of the distribution network begin islanding during or after a power outage, necessitating additional protection schemes. This disclosure first develops a transient analysis during various types of faults for an ungrounded island microgrid, where multiple IBDGs are deployed under various control strategies, taking into account the effects of the FCLs of these IBDGs. A set of fault location and protection schemes or methods for island microgrids based on measurements of zero-sequence components, negative-sequence components, and phase currents is then proposed. The effectiveness of this method is demonstrated through a simulation study on a sample microgrid.

[0020] FIG. 1A is a block diagram illustrating a method for detecting and locating faults in an inverter-dominated ungrounded microgrid according to an embodiment of the present disclosure.

[0021] Step 125 includes the method 100 receiving, using the interface 153, measurements of zero sequence current, negative sequence current, and phase current from a terminal bus of a branch located in the microgrid over a communication network.

[0022] Step 130 includes the method 100 using the hardware processor 155 to determine a zero sequence phase angle difference attribute for each measured branch of the microgrid.

[0023] Still referring to step 132 of FIG. 1A, a hardware processor 155 is used to determine a negative sequence magnitude difference attribute for each measured branch of the microgrid.

[0024] Step 134 uses the hardware processor 155 to determine the phase current sign change attribute for each measured branch in the microgrid.

[0025] Step 136 uses the hardware processor 155 to locate the faulted line segment, i.e., the faulted branch, based on the determined difference attributes between the terminal buses of each line segment in the microgrid.

[0026] Still referring to step 140 of FIG. 1A, method 100 includes isolating the faulted line segment by initiating switching operations of connected switches using a computing device 157 over a communication network.

[0027] FIG. 1B is a schematic diagram illustrating components and steps for detecting and locating faults in an inverter-dominated ungrounded microgrid according to an embodiment of the present disclosure.

[0028] 1B may include a hardware processor 155 in communication with an input interface 135, a memory 137, an interface 153, and a computing device 157. The computing device 157 may be connected to a set of switches 110 installed in a microgrid 115. The microgrid may have a set of sensors including a first terminal sensor 145 and a second terminal sensor 146 for monitoring the microgrid 115 and collecting status information of the microgrid 115. The fault control system implemented by the method 100 may control the set of switches 110 and may also transmit and receive information. It is contemplated that the hardware processor 155 may include two or more hardware processors depending on the requirements of a particular application. Obviously, other components, including input interfaces, output interfaces, and transceivers, may be incorporated into the method 100.

[0029] Still referring to FIG. 1B, an aspect of the system 100 includes receiving 125 zero-sequence currents, negative-sequence currents, and phase currents from a terminal bus of a branch in the microgrid via a communication network using an interface 153.

[0030] Step 130 includes the method 100 using the hardware processor 155 to determine a zero-sequence phase angle difference attribute for each measured branch in the microgrid.

[0031] Step 132 includes determining a negative sequence magnitude difference attribute for each measured branch in the microgrid.

[0032] Step 134 includes determining a phase current sign change attribute for each measured branch in the microgrid.

[0033] Step 136 includes locating the faulted line segment based on the determined difference attributes between the terminal buses of the line segments located in the microgrid.

[0034] Step 140 includes the method 100 isolating the faulty line segment by initiating switching action of a connected switch using a computing device 157 over a communication network.

[0035] FIG. 1C is a block diagram of a fault location and protection system for locating faults in an inverter-dominated ungrounded microgrid according to some embodiments of the present invention.

[0036] The fault location and protection system 100 includes a human machine interface (HMI) 167 connectable to a keyboard 111 and a pointing device / medium 112, a processor 155, a storage device 154, a memory 137, a network interface controller 163 (NIC) connectable to a network 151 including a local area network and an internet network, a display interface 161 connected to a display device 165, an input interface 139 connectable to an input device 135, and a printer interface 133 connectable to a printing device 131.

[0037] The fault location and protection system 100 can receive electrical signals 195 indicative of current or associated sequence components of measurement devices located on the inverter-dominated ungrounded microgrid 115 via a network 151 connected to a NIC 153. The network 151 is connected to an external system 101, which can provide control signals to measurement devices on the microgrid 115 for remote control of the measurement devices. Additionally, the fault location and protection system 100 can provide fault location status data (signals) to the external system 101 via the network 151 so that the external system 101 can control switching operations located on the microgrid 115. Additionally, the fault location and protection system 100 can be controlled from the external system 101 by receiving control data (signals) of the fault location and protection system 100 via the network 151.

[0038] The storage device 154 includes pre-fault topology and normal status parameters 158 for the microgrid 115 and a fault location and protection program module 159. The input device / medium 135 may include a module that reads a program stored on a computer-readable recording medium (not shown).

[0039] To locate a fault or faults in the microgrid 115 , the fault location and protection system 100 may receive status data of the microgrid 115 from measurement devices included in the microgrid 115 .

[0040] According to some embodiments of the present invention, the microgrid 115 may include a set of terminal buses connected to the branches and a set of inverter-based or synchronous generators. The fault location and protection system 100 receives, via a network 151 (a communication network), a measured vector indicating the zero-sequence current, negative-sequence current, and phase current for each branch measured at the terminal buses using an interface 153. The memory 137 may be loaded with a computer-executable program stored in a storage 154, the computer-executable program including a pre-fault (normal status) topology 157 and normal current vectors (not shown) of the terminal buses, and a fault location and protection program (module) 159 configured to locate a fault occurring in the microgrid 115 and determine a protection scheme for the fault in the microgrid 115. At least one processor 155 connected to the memory 137 and the interface 153 is used to execute the fault location program 159 loaded from the storage 154. For example, when executed by processor 155, fault location program 159 causes processor 155 to receive the zero-sequence component of current from measurements 195, and processor 155 determines whether an asymmetrical fault is occurring on any line segment in microgrid 115 by comparing the phase angle differences for all measured line segments. Once a faulted line segment is identified, such as the branch between bus D1 and bus D, fault location program 159 further requests processor 155 to provide the normal connection topology from storage 154, and then, through connection tracing, program 159 determines a primary protection scheme by identifying a first layer disconnector 176 to isolate the determined faulted branch by cutting it off from access to all power sources, and further determines a backup protection scheme by identifying a second layer disconnector 178 to isolate the fault if the primary protection scheme does not work.The processor 155 then outputs a post-fault topology showing the location of the fault and the associated switch operations required by the determined primary and backup protection schemes. In this case, each line segment, or branch, may include two current measurement units installed on two terminal buses connected to a communication network. Furthermore, the interface (NIC) 153 may receive measured signals from the microgrid 115 via the network 151 at predetermined intervals.

[0041] In some cases, commands to initiate / perform fault location may be sent to the fault location and protection system 100 using the keyboard 111 or from the external system 101 via the network 151.

[0042] Modeling an Island Microgrid Problem description and assumptions Most distribution networks are typically earthed at distribution substations. Protection relays, such as overcurrent relays and overvoltage earth fault relays, are installed at distribution substations and on customer-side networks. Parts of the distribution network begin islanding operation during or after a power outage. Therefore, an island microgrid, which is isolated from the main grid during a disaster or power outage, requires additional protection schemes. We assume that island microgrids are equipped with both conventional synchronous generators (SGs) and inverter-based RESs, which is common in practice. When a microgrid operates in island mode, one of the RES inverters is a VF-controlled inverter and the others are PQ-controlled inverters. All inverters are equipped with their own fault current limiters (FCLs).

[0043] IBDG Control Strategy VF control and PQ control are the two main control strategies for IBDGs. VF-controlled inverters, also known as grid-forming inverters, are used to support autonomous operation of microgrids in islanded mode. Islanded microgrids must largely meet all load requirements while maintaining voltage and frequency at reference values. VF control is typically used with controllable power sources such as fuel cells and micro gas turbines. The control block diagram for a VF-controlled IBDG is shown in Figure 2. PQ-controlled inverters, also known as grid-following inverters, are typically used with intermittent power sources such as photovoltaic (PV) generation or wind turbines to follow power standards. They maximize the utilization of intermittent renewable energy sources. The control block diagram is shown in Figure 3.

[0044] In grid-connected mode, all IBDGs should be under PQ control because the frequency and voltage of the microgrid should follow the main grid. The PQ-controlled inverter injects maximum power into the microgrid to achieve economical operation. When the microgrid is disconnected from the main grid during a power outage, it transitions to island mode. One of the IBDGs in the microgrid should then start operating under VF control to support the voltage and frequency.

[0045] FCL design A virtual impedance-based FCL is deployed in each power inverter to suppress overcurrent damage based on the principle described by (1).

[0046]

number

[0047] According to (1), the d-axis current I d and q-axis current I q are their corresponding thresholds I thd and I thqAbove this, a significant virtual impedance Z0 is activated. The configurations of the IBDG without and with an FCL are shown in Figures 4A and 4B, respectively.

[0048] Furthermore, the d-axis current I d and q-axis current I q can be measured by a pair of sensors 145 and 146. The pair of sensors 145 and 146 allows the system 100 to measure the d-axis current I d and q-axis current I q A set of sensors 145 and 146 are connected to the fault location and protection system 100 via a network 151 using a wired or wireless network to detect the d-axis current I. d and q-axis current I q is the threshold I thd and I thq is configured to activate / control the switchable device 110 to protect the power grid system when the

[0049] Zero-sequence and negative-sequence equivalent circuits In many microgrids around the world, such as the Japanese microgrid, generators and loads are typically ungrounded. A delta-wye transformer is often installed at the output of each generator. Considering that zero-sequence current cannot flow through a delta-wye transformer, the zero-sequence equivalent circuit of a DG is equivalent to an open circuit. An example is shown in Figures 5A and 5B. Figure 5A is a graph showing an island microgrid with multiple generators. Figure 5B is a graph showing a zero-sequence circuit model for the original system shown in Figure 5A. Assume that a fault voltage is applied to branch C1C in Figure 5A. From the zero-sequence fault model in Figure 5B, the zero-sequence fault current flowing into each terminal can be expected to come from each direction via the first terminal sensor 145 and the second terminal sensor 146, providing information for locating the fault. Thus, information (measured data or signals) regarding the zero-sequence fault current occurring in the microgrid 115 is received by the fault location and protection system 100 via the interface 163 and the network 151 configured to perform data communication with the sensor network of the first terminal sensor 145 and the second terminal sensor 146. When the fault location and protection system 100 determines, using a computer-executed program (method) 159 for protecting a power grid system stored in a storage 154 coupled to the memory 137, that the branch C1C indicates a fault status based on the information regarding the zero-sequence fault current, the fault location and protection system 100 sends a control command (signal) to the switching device 110 to isolate the faulted line connected to the branch C1C, thereby protecting the power grid system by isolating the faulted branch C1C.

[0050] Negative-sequence currents can flow through delta-wye connected transformers, making modeling of the negative-sequence equivalent circuit a burden. The negative-sequence model of an IBDG is shown in Figure 6. It is noteworthy that the control block of a VF-controlled IBDG loses the controllability of the negative-sequence circuit, and the negative-sequence impedance is defined by the filter rather than the control block.

[0051] Fault detection and location methods A microgrid electromagnetic transient model is employed to analyze the transient process of a microgrid during faults at the microsecond level. Data is collected by sensors deployed at each terminal, providing useful information about the transient signals for fault detection and location. Common faults occurring within a microgrid can be classified into asymmetric and symmetric faults. Asymmetric faults include one-line-to-ground short circuits, line-to-line short circuits, and two-line-to-ground short circuits, while symmetric faults usually refer to three-phase short circuits. In the following subsections, we will separately consider the fault detection and location methods for these two main types of faults.

[0052] The negative sequence (denoted by subscript 2) component I2, the zero sequence (subscript 0) component I0 of a set of three-phase current signals, along with the positive sequence (subscript 1) component I1, can be calculated as follows:

[0053]

number

[0054] In the formula, I a ,I b and I c are the three current phasors at power frequency, and a=e j2π / 3 is a complex operator. First, a Fourier analysis over a sliding window of one period of the power frequency is applied to the three input signals. It is the phasor value I at the fundamental frequency a ,I b and I cThen, a transformation is applied to obtain a positive sequence, a negative sequence and a zero sequence.

[0055] Asymmetrical faults The island microgrid with multiple RESs and SGs in Figure 7 was simulated using the Simscape Electrical Library. DG#1 is under VF control, DG#2 and DG#3 are conventional SGs, and DG#4 is under PQ control. From the zero-sequence fault model, we can theoretically conclude that the direction of the zero-sequence current is reversed only at the two ends of the faulted branch, even for limited fault current levels. In this simulation, the system starts up at t = 0 s, and a single-line-to-ground fault occurs in each of the various branches at t = 0.1 s. The phase diagrams of the zero-sequence current for each case are visualized in Figures 8A–8D. Figure 8A shows a fault occurring at branch AB, Figure 8B shows a fault occurring at branches C1C, Figure 8C shows a fault occurring at branches D1D, and Figure 8D shows a fault occurring at branches E1E. In Figures 8A-8D, each arrow represents the zero sequence current flowing through a different terminal, measured 60 milliseconds after the fault occurred (t = 0.16 seconds).

[0056] It can be seen that the direction of the zero-sequence current is opposite only at the two ends of the faulted branch. The dynamics of the SG and IBDG do not show any obvious influence on the transient behavior of the faulted branch during a short period at the onset of the fault.

[0057] Therefore, the protection scheme can be designed as follows. First, the phase angle difference of the zero-sequence current between the two ends of each branch is monitored. It operates chaotically when the microgrid is operating normally. This is because in a balanced or nearly balanced three-phase power system, the magnitude of the zero-sequence current is infinitesimally small, making the angle unstable and insignificant. Conversely, when a single-wire-to-ground fault occurs, a detectable zero-sequence component exists, making the angle stable. As visualized in Figure 9, the angle difference is 180 degrees only in the faulted branch 910, while the angle difference is 0 degrees in the other branch 920, allowing the fault to be effectively located.

[0058] Symmetrical fault Fault location techniques based on the zero-sequence component cannot be adapted to locate symmetrical faults because the zero-sequence component is insignificant in a balanced or nearly balanced three-phase power system. However, during the transient state immediately after a symmetrical fault occurs (e.g., a few microseconds after the fault occurs), the negative-sequence fault current (both magnitude and phase angle) shows significant differences only at the two terminals of the faulted branch. It is worth mentioning that the above explanation is consistent with our basic knowledge that the negative-sequence component can be ignored in a symmetrical circuit system. Here, we emphasize that the observed period is the transient state immediately after the fault occurs (approximately 10 milliseconds), and the microgrid system is not strictly symmetrical at this time. Take the model in Figure 7 as an illustrative example. Assume that three-phase short-circuit faults occur in different branches. Tables I to IV below show the negative-sequence currents flowing through the two terminals of each branch when the fault occurs in different branches. The negative-sequence currents are measured 10 milliseconds after the fault occurs. The simulation results effectively verify the theoretical conclusions. Furthermore, it can be seen that the dynamics of SG and IBDG do not show any obvious influence on the transient behavior of the faulted branch during a short period at the onset of the fault.

[0059] [Table 1]

[0060] [Table 2]

[0061] A protection scheme is proposed that relies on measuring the difference in magnitude of the negative-sequence current between the two ends of each branch. The negative-sequence component is negligible when the microgrid is under normal operation, but is detectable when a fault occurs. As shown in Figure 10, the difference in magnitude of the faulted branch 1010 is significantly larger than that of the other branches 1020, thereby efficiently locating the fault.

[0062] Special Conclusions for Three-Phase Earth Faults In this section, we will consider alternative fault detection and location techniques, specifically for three-phase to ground faults. Taking one phase as an example, a microgrid with a three-phase to ground fault can be simplified as seen in the circuit diagram in Figure 11. R f is the resistance of the ground fault. Other symbols are introduced in Figure 11.

[0063] The output voltages of all DGs flowing through the transformer are usually required to be uniform or close to uniform in a microgrid. Here, the voltages of all DGs flowing through the transformer must be the same value, i.e., V1 = V2 = V m cos(ωt+θ). In this case, the state equation of the circuit model is expressed as follows:

[0064]

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[0065] R1, L1, R2, L2 are the resistance and inductance of the equivalent line impedance. The solution is shown below:

[0066]

number

[0067] In the formula, i A (1) and i B (1) is a particular solution, i.e., the zero-state response (ZSR), and i A (2) and i B (2) is the co-solution, or zero-input response (ZIR). ZIR is the response of a circuit with zero initial conditions, resulting only from the circuit's external inputs or driving functions, and not from the initial conditions. Also called the natural response, ZIR results only from the circuit's initial conditions, and not from any external driving.

[0068]

number

[0069] Due to the presence of harmonics, the phase current i A and i B It is not difficult to define and utilize the concept of phase angle. Instead, A and i B The sign of the current i is used to describe its characteristics. A and i B Let the reference direction of be as shown in Figure 11. Then, if no fault occurs, i A and i B The sign of is always opposite. Furthermore, from the above derivation, the following assumptions are true: (a)i A and i B (b) if φ1≒π / 4 or φ2≒0 or φ2≒π or (λ2-a)(-1 / a-2a / b)=(a-λ1)(1 / a-2a / b), then i A and i BIt can be seen that the signs of are not necessarily reversed. The ratio R / X of a microgrid is usually 0.1 to 10. When the fault resistance is small, assumption (a) and assumption (b) where φ2 ≒ 0 apply. Therefore, when a three-phase ground fault occurs, i A and i B It can be concluded that the opposite is not necessarily true.

[0070] This conclusion is verified by simulation tests using MathWorks Simulink. First, we use the simplified circuit in Figure 11 to test several scenarios with various line impedances and initial phase angles. The simulation results are shown in Figure 12. The curves in the upper and lower parts, plotted with the same line type, represent the same scenarios. A and i B It represents i A and i B It can be seen that the signs of the phase currents are not reversed. In fact, three-phase to ground faults can be identified by monitoring the real-time phase currents. The signs of the phase currents can be quantified to determine the DS c Calculate the difference in phase current between the two ends of each branch, denoted by

[0071]

number

[0072] In the formula, I M and I N are the currents flowing through the two ends of the branch MN. Take the model in Figure 7 as an illustrative example. DS of each branch c is plotted in Figure 13. DS c It can be seen that in the faulted branch 1310, ρ transitions between 0 and 2, while in other branches 1320, ρ is always equal to 0 (due to noise, it is very rarely equal to 2). This phenomenon can verify our derivation, and we can conclude that this technique can effectively locate three-phase to ground faults occurring in microgrids.

[0073] Microgrid Fault Localization and Protection Implementation Example 14 is a schematic diagram illustrating a proposed fault location and protection implementation for an inverter-dominated islanded microgrid. In this diagram, each line segment 1410 may include two sensors, including a first terminal sensor 1420 and a second terminal sensor 1421, and one or two switchable devices 1430 used to connect or disconnect the power supply to the branch from the distributed generators.

[0074] The fault location task may be performed centrally or distributed. In a centralized implementation, a central processor is implemented for the entire microgrid. It collects measurements from all line segments in the microgrid and determines the faulty line segment based on all the measurements.

[0075] In a distributed implementation, each bus has a processor for locating possible faults in the connected segments. It only collects measurements from the connected segments and only identifies faults in those connected segments.

[0076] If the distance is measured by the number of switches between two destinations, the set of first-tier switches closest to the faulted line segment will serve as the primary protection scheme to isolate the faulted line from the sources of all distributed generators.

[0077] Similarly, if the distance is measured by the number of switches between two destinations, the set of second-tier switches next closest to the faulted line segment acts as a backup protection scheme to isolate the faulted line from the power sources of all distributed generators if the primary protection scheme fails.

[0078] For example, the first layer switches for isolating a fault on line C1C include a switch at bus C1 on line C1C and a switch connected to DG#2, and the second layer switches include a switch connected to #1SG, a switch at bus D1 along line D1D, and a switch at bus F1 along line F1F.

[0079] To isolate a fault on line D1D, the first layer includes switches in bus D1 and bus D along line D1D, and the second layer includes switches connected to #1SG, switches connected to DG#4, switches in bus C1 along line C1C, switches in bus E along line E1E, and switches in bus F1 along line F1F.

[0080] Each of the above embodiments may be described as a process that is depicted as a flowchart, flow diagram, data flow diagram, structure diagram, or block diagram. While a flowchart may describe operations as a sequential process, many of these operations may be performed in parallel or simultaneously. The order of operations may also be rearranged. A process may terminate when its operations are completed, but may have additional steps not described or included in the diagram. Moreover, not all operations in any specifically described process are performed in all embodiments. A process may correspond to a method, a function, a procedure, a subroutine, a subprogram, etc. When a process corresponds to a function, the end of the function may correspond to a return of the function to a calling function or a main function.

[0081] Furthermore, embodiments of the disclosed subject matter may be implemented at least in part manually or automatically. Manual or automatic implementations may be performed, or at least assisted, by using machines, hardware, software, firmware, middleware, microcode, hardware description languages, or any combination thereof. When implemented in software, firmware, middleware, or microcode, the program code or code segments to perform the necessary tasks may be stored on a machine-readable medium. A processor may perform the necessary tasks.

[0082] Furthermore, the embodiments and functional operations of the present disclosure described herein may be implemented in digital electronic circuitry, tangibly embodied computer software or firmware, computer hardware containing the structures disclosed herein and their structural equivalents, or a combination of one or more of them. Furthermore, some embodiments of the present disclosure may be implemented as one or more computer programs, i.e., one or more modules of computer program instructions encoded on a tangible, non-transitory program carrier for execution by or control of the operation of a data processing apparatus. Furthermore, the program instructions may be encoded on an artificially generated propagated signal, e.g., a machine-generated electrical, optical, or electromagnetic signal, generated to encode information for transmission to a suitable receiver device and execution by the data processing apparatus. The computer storage medium may be a machine-readable storage device, a machine-readable storage substrate, a random-access or serial-access memory device, or a combination of one or more of them.

[0083] In accordance with embodiments of the present disclosure, the term "data processing apparatus" may encompass all types of apparatus, devices and machines for processing data, including, by way of example, a programmable processor, a computer, or multiple processors or computers.

[0084] A computer program (which may also be referred to or described as a program, software, software application, module, software module, script, or code) can be written in any type of programming language, including compiled or interpreted languages, or declarative or procedural languages, and can be deployed in any form, such as a stand-alone program or as a module, component, subroutine, or other unit suitable for use in a computing environment. A computer program may, but need not, correspond to a file in a file system. A program may be stored as part of a file that holds other programs or data, such as, for example, one or more scripts stored in a markup language document; it may be stored in a single file dedicated to the program in question; or it may be stored in multiple linked files, such as files that store one or more modules, subprograms, or portions of code. A computer program can be deployed to be executed on one computer or on multiple computers, which may be located at one site or distributed across multiple sites and interconnected by a communications network. A computer suitable for executing a computer program may, by way of example, include or be based on a general-purpose microprocessor or special-purpose microprocessor or both, or other types of central processing units. Generally, a central processing unit receives instructions and data from a read-only memory or a random access memory or both. The essential elements of a computer are a central processing unit for performing or executing instructions and one or more memory devices for storing instructions and data. Generally, a computer also includes one or more mass storage devices, such as magnetic, magneto-optical, or optical disks, for storing data, or is operatively coupled to receive, send, or transmit data to and from such one or more mass storage devices.However, a computer need not have such a device. Furthermore, a computer can be incorporated into another device, such as, for example, a mobile phone, a personal digital assistant (PDA), a portable audio or video player, a game console, a Global Positioning System (GPS) receiver, or a portable storage device (e.g., a Universal Serial Bus (USB) flash drive), to name a few.

[0085] Although the present disclosure has been described with reference to certain preferred embodiments, it is to be understood that various other adaptations and modifications are possible within the spirit and scope of the disclosure. It is, therefore, the object of the appended claims to cover all such modifications and variations that fall within the true spirit and scope of the disclosure.

Claims

1. 1. A computer-implemented method for protecting a power grid system including a primary bus and an island microgrid isolated from a distribution system, the island microgrid forming a branch from the primary bus, the island microgrid including at least one distributed generator (DG), each DG including at least one switchable device for isolating a power source of the DG from the power grid, each of the branches including a first terminal sensor located on a near side of the primary bus and a second terminal sensor located on a terminal bus on an opposite side of the branch, the first terminal sensor and the second terminal sensor indicating a branch location of each of the branches within the power grid, the method using a processor coupled to a memory having instructions stored thereon implementing the method, the instructions, when executed by the processor, performing steps of the method, the method including: receiving measurement data from each of the branches including the branch positions from the first terminal sensor and the second terminal sensor, the measurement data including zero sequence currents of the first terminal sensor and the second terminal sensor, negative sequence currents of the first terminal sensor and the second terminal sensor, and phase currents of the first terminal sensor and the second terminal sensor; determining that the branches exhibit a fault status between the branches if there is a phase angle difference of approximately 180 degrees between the zero sequence currents, if the magnitude of the difference between the negative sequence currents of the first terminal sensor and the second terminal sensor in a branch is equal to or greater than a threshold, or if the difference in sign of any phase currents as a function of time exhibits a transition between 0 and 2; sending a control command to the at least one switchable device; the at least one switchable device is configured to isolate the determined branch exhibiting the fault status from the at least one DG; the at least one switchable device is determined based on a distance from the at least one switchable device to the determined branch; The control command instructs the switchable device to disconnect the determined branch from the at least one DG.

2. the primary bus is a common coupling point between the island microgrid and the distribution system; The method of claim 1 , wherein distributed generators are connected to the island microgrid through ungrounded transformers.

3. The method of claim 1 , wherein each of the island microgrids includes at least one inverter-based distributed generator (IBDG).

4. The method of claim 3 , wherein each of the IBDGs comprises a Fault Current Limiter (FCL).

5. The method of claim 4, wherein one of the IBDGs is operated under a voltage-frequency (VF) control mode and the remaining IBDGs are operated under a real-reactive power (PQ) control mode.

6. 2. The method of claim 1, wherein the amount of the difference between the negative sequence currents of the first terminal sensor and the second terminal sensor in the branch is calculable using a magnitude or a phase angle of the negative sequence currents.

7. The method of claim 1 , wherein the threshold value of the difference amount between the negative sequence currents is configurable as a multiple of a maximum difference amount under pre-fault conditions, such as 2.

5.

8. A function DS of the sign difference of the phase currents on the branch between bus M and bus N ｃ (t) is defined as follows: [Equation 1] In the formula, I Ｍ and I Ｎ 2. The method of claim 1, wherein ΘΘ is the current flowing through the two ends of the branch MN.

9. 2. The method of claim 1, wherein the step of determining that the branch exhibits the fault status can be performed centrally by using one central processor for the entire microgrid to locate the faulted branch upon receiving current measurements from all branches.

10. 2. The method of claim 1, wherein the step of determining that the branch exhibits the fault status can be performed in a distributed manner by using one distributed processor for each monitored bus to locate the faulted branch from the branches connected to the bus upon receipt of current measurements from the branches connected to the bus.

11. 2. The method of claim 1, wherein the switches for isolating the branch exhibiting the fault status are determined as the set of switches located closest to the faulted branch along the path by measuring the distance as a number of switches between two destinations along the path to each of the distributed generators.

12. 1. A fault location and protection system for protecting a power grid system including a primary bus and an island microgrid isolated from a distribution system, the island microgrid forming a branch from the primary bus, the island microgrid including at least one distributed generator (DG), each of the at least one DG including at least one switchable device for isolating a power source of the at least one DG from the power grid, each of the branches including a first terminal sensor located on a near side of the primary bus and a second terminal sensor located on a terminal bus on an opposite side of the branch, the first and second sensors indicating a branch location of each of the branches within the power grid, the system comprising: an interface configured to receive measurement data from each of the branches, the measurement data including the branch position from the first terminal sensor and the second terminal sensor, the measurement data including zero sequence currents of the first terminal sensor and the second terminal sensor, negative sequence currents of the first terminal sensor and the second terminal sensor, and phase currents of the first terminal sensor and the second terminal sensor; a processor configured to perform a computer-implemented method; and and a memory configured to store a method executed by the computer, the method using the processor coupled to the memory having stored thereon instructions implementing the method, the instructions, when executed by the processor, performing steps of the method, the method including: determining that the branches exhibit a fault status between the branches if there is a phase angle difference of approximately 180 degrees between the zero sequence currents, if the magnitude of the difference between the negative sequence currents of the first terminal sensor and the second terminal sensor in a branch is equal to or greater than a threshold, or if the difference in sign of any phase currents as a function of time exhibits a transition between 0 and 2; sending a control command to the at least one switchable device; the at least one switchable device is configured to isolate the determined branch exhibiting the fault status from the at least one DG; the at least one switchable device is determined based on a distance from the at least one switchable device to the determined branch; The control command instructs the switchable device to disconnect the determined branch from the at least one DG.

13. the primary bus is a common coupling point between the island microgrid and the distribution system; The system of claim 12 , wherein a distributed generator is connected to the island microgrid through an ungrounded transformer.

14. The system of claim 12 , wherein each of the island microgrids includes at least one inverter-based distributed generator (IBDG).

15. The system of claim 14 , wherein each of the IBDGs comprises a fault current limiter (FCL).

16. The system of claim 15, wherein one of the IBDGs is operated under a voltage-frequency (VF) control mode and the remaining IBDG is operated under a real-reactive power (PQ) control mode.

17. 13. The system of claim 12, wherein the amount of the difference between the negative sequence currents of the first terminal sensor and the second terminal sensor in the branch is calculable using a magnitude or a phase angle of the negative sequence currents.

18. The system of claim 12 , wherein the threshold value of the difference amount between the negative sequence currents is configurable as a multiple of a maximum difference amount under pre-fault conditions, such as 2.

5.

19. A function DS of the sign difference of the phase currents on the branch between bus M and bus N ｃ (t) is defined as follows: [Equation 2] In the formula, I Ｍ and I Ｎ 13. The system of claim 12, wherein ΘΘ is the current flowing through the two ends of the branch MN.

20. 13. The system of claim 12, wherein the step of determining that the branch exhibits the fault status can be performed centrally by using one central processor for the entire microgrid to locate the faulted branch upon receiving current measurements from all branches.

21. 13. The system of claim 12, wherein the step of determining that the branch exhibits the fault status can be performed in a distributed manner by using one distributed processor for each monitored bus to locate the faulted branch from the branches connected to the bus upon receipt of current measurements from the branches connected to the bus.

22. 13. The system of claim 12, wherein the switches for isolating the branch indicating the fault status are determined as the set of switches located closest to the faulted branch along the path by measuring the distance as a number of switches between two destinations along the path to each of the distributed generators.

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