Power distribution system fault control device and method

Abstract

The method includes detecting a fault in a grid coupled to an electric power distribution network, the electric power distribution network including a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and a reference point of applicability (RPA) associated with the plurality of DERs; in response to detecting the fault, determining an error voltage at the RPA; converting the error voltage into an error signal; broadcasting the error signal to the plurality of DERs; and reducing the error voltage at the RPA by injecting a plurality of currents from the plurality of DERs into the distribution feeder based on the error signal.

Description

[Technical field]

[0001] This invention was made with United States Government support under Contract No. DE-OE0000896 awarded by the Department of Energy. The United States Government has certain rights in this invention.

[0002] Technical Field The present invention relates generally to a fault control device and method for controlling distributed energy resources in an electrical power distribution system. [Background technology]

[0003] background The power grid comprises traditional power plants, such as coal-fired, gas, and nuclear power plants, and distributed energy resources (DERs). Traditional power plants are centralized and require electrical energy to be transmitted over long distances. DERs are small, modular, decentralized, grid-connected energy systems that are located in or near the loads where the energy is consumed. DERs and loads form a distributed power network that is coupled to the power grid.

[0004] During operation, faults may occur in the power grid. The grid fault may reduce the voltage of the distribution grid, resulting in the sensitive tripping of DERs. The tripped DERs cause a large-scale loss of energy supply over a wide geographical area. An unexpected loss of energy supply over a short period of time may result in more complex consequences such as overloading of the power grid's transmission lines and fault-induced voltage recovery delay (FIDVR). FIDVR refers to an unexpected delay in the recovery of voltage to its nominal value following successful clearing of a fault. After the fault is cleared, the voltage of the distribution grid remains at a significantly reduced level for several seconds and then slowly returns to an acceptable level. To overcome such grid reliability concerns, DERs are required to implement a fault ride-through capability.

[0005] Fault ride-through is one requirement that aims to prevent DERs from going into trip mode so that they can remain connected during a fault. DERs also need to participate in dynamic voltage support (DVS). Now, advanced DVS capabilities are possible due to recent unprecedented advances in the flexible control of DERs' power converters. However, efficient ways to harness this flexibility in a coordinated manner are still an open research area. Therefore, there is a need to improve DVS control in distribution grids to meet the ever-changing requirements of the power system. Summary of the Invention [Means for solving the problem]

[0006] overview According to one embodiment, a method includes detecting a fault in a grid coupled to an electric power distribution network, the electric power distribution network including a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and a reference point of applicability (RPA) associated with the plurality of DERs; in response to detecting the fault, determining an error voltage at the RPA, converting the error voltage into an error signal, broadcasting the error signal to the plurality of DERs, and reducing the error voltage at the RPA by injecting a plurality of currents from the plurality of DERs into the distribution feeder based on the error signal.

[0007] According to another embodiment, a system includes an electric grid coupled to a grid and including a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and a reference point of applicability (RPA); an RPA controller coupled to the RPA and configured by programming to detect a fault in the grid and, in response to detecting the fault, determine an error voltage at the RPA and convert the error voltage into an error signal; a first communications device coupled to the RPA controller and configured to broadcast the error signal to the plurality of DERs; and a plurality of DER controllers coupled to each DER of the plurality of DERs and configured by programming to control each DER to reduce the error voltage at the RPA by injecting a plurality of currents into the distribution feeder based on the error signal.

[0008] According to yet another embodiment, a Reference Point of Applicability (RPA) controller comprises a controller coupled to an electric grid including a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and the RPA, the controller being directly coupled to the RPA, the controller comprising a memory storing a program including instructions, a processor coupled to the memory and configured to execute the program, and a first communications device coupled to the processor, the instructions, when executed, cause the processor to detect a fault in a grid coupled to the electric grid, and in response to detecting the fault, determine an error voltage at the RPA, convert the error voltage into an error signal, and transmit the error signal to the first communications device, the first communications device configured to broadcast the error signal to the plurality of DERs.

[0009] According to yet another embodiment, a distributed energy resource (DER) control system includes a plurality of DER controllers coupled to an electric grid including a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and a reference point of applicability (RPA), each of the plurality of DER controllers coupled to a corresponding DER of the plurality of DERs, each of the plurality of DER controllers comprising a memory storing a program including instructions, a processor coupled to the memory and configured to execute the program, and a communications device coupled to the processor, the instructions, when executed in each of the plurality of DER controllers, cause the plurality of DER controllers to receive an error signal from an RPA controller directly coupled to the RPA and to send control signals to the plurality of DERs, one of the control signals being sent to one of the plurality of DERs, the control signal received by the plurality of DERs being configured to reduce an error voltage at the RPA by injecting a plurality of currents from the plurality of DERs into the distribution feeder.

[0010] The foregoing has outlined rather broadly the features and technical advantages of the present disclosure in order that the detailed description of the disclosure that follows may be better understood. Additional features and advantages of the present disclosure will be described hereinafter which form the subject of the claims of the present disclosure. It should be appreciated by those skilled in the art that the conception and specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures or processes for carrying out the same purposes of the present disclosure. It should also be appreciated by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the present disclosure as set forth in the appended claims.

[0011] BRIEF DESCRIPTION OF THE DRAWINGS For a more complete understanding of the present disclosure and its advantages, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which: [Brief description of the drawings]

[0012] [Figure 1] FIG. 1 is a block diagram of an electrical grid in accordance with various embodiments of the present disclosure. [Diagram 2] FIG. 1 illustrates a diagram showing DERs in an electric grid configured to operate in various operating modes under an unbalance fault according to various embodiments of the present disclosure. [Diagram 3] FIG. 2 illustrates a simplified model of the DERs and distribution feeders shown in FIG. 1 in accordance with various embodiments of the disclosure. [Figure 4] FIG. 1 illustrates a control system implementing a non-coherent dual synchronous reference frame PLL (DDSRF-PLL) control scheme in accordance with various embodiments of the present disclosure. [Diagram 5] FIG. 2 is a block diagram of the RPA controller shown in FIG. 1 in accordance with various embodiments of the present disclosure. [Figure 6] FIG. 2 is a block diagram of a DER controller shown in FIG. 1 in accordance with various embodiments of the present disclosure. [Figure 7] FIG. 1 illustrates a control system implementing a distributed cooperative dynamic voltage support control scheme in accordance with various embodiments of the present disclosure. [Figure 8] 2 is a flowchart of a method for controlling the electrical grid shown in FIG. 1 according to various embodiments of the present disclosure. [Figure 9] FIG. 1 is a block diagram of a system according to various embodiments of the present disclosure. [Figure 10] FIG. 2 is a block diagram of an RPA controller according to various embodiments of the present disclosure. [Figure 11] FIG. 1 is a block diagram of a DER control system according to various embodiments of the present disclosure. [Figure 12] FIG. 1 is a block diagram of a processing system according to various embodiments of the present disclosure. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0013] Corresponding numbers and symbols in the different figures generally refer to corresponding parts unless otherwise indicated. The figures are drawn to clearly illustrate relevant aspects of the various embodiments and are not necessarily drawn to scale.

[0014] DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS The making and use of the presently preferred embodiments are described in detail below. It should be understood, however, that the present disclosure provides many applicable inventive concepts that can be embodied in a wide variety of specific contexts. The specific embodiments described are merely illustrative of specific ways to make and use the disclosure and do not limit the scope of the disclosure.

[0015] The present disclosure is described with respect to preferred embodiments in a particular context, namely, a fault control device and method for controlling distributed energy resources in a power distribution system. However, the present disclosure may also be applied to a variety of power systems. Various embodiments are described in detail below with reference to the accompanying drawings.

[0016] 1 illustrates a block diagram of an electrical grid in accordance with various embodiments of the present disclosure. Electrical grid 100 is connected to a power grid 110. Electrical grid 100 includes a distribution feeder 125. Distribution feeder 125 is a distribution bus that is coupled to grid 110 through a grid interface 105. Electrical grid 100 further includes a number of distributed energy resources (DERs) 122, 124, and 126. In some embodiments, DERs 122, 124, and 126 may be photovoltaic panels, battery energy storage systems, other suitable renewable energy sources, and any combination thereof.

[0017] DERs 122, 124, and 126 are coupled to distribution feeder 125. As shown in FIG. 1, each DER is connected to distribution feeder 125 through a point of connection (POC). As shown in FIG. 1, DER 122 is connected to distribution feeder 125 through POC 152. DER 124 is connected to distribution feeder 125 through POC 154. DER 126 is connected to distribution feeder 125 through POC 156. The detailed structure and operation principle of the DERs are described below with respect to FIG. 3. Each DER is equipped with a DER controller. As shown in FIG. 1, DER controller 132 is coupled to DER 122. DER controller 134 is connected to DER 124. DER controller 136 is connected to DER 126. The detailed structure and operation principle of the DER controller are described below with respect to FIG. 6.

[0018] The power distribution network 100 further comprises a Point of Applicability (RPA) 107 and an RPA controller 120 coupled to the RPA 107. The Point of Applicability (RPA) is defined in IEEE 1547 by the characteristics of the DER circuit, in particular the aggregate DER capacity and import / export. It may be at the DER terminal or at the point where several DERs connect to the power grid. With reference to FIG. 1 , the RPA 157 is a connection point between any of the DERs (122, 124, ... 126) and the power grid (110). The RPA 107 may be adjacent to the grid interface 105. The RPA controller 120 is configured to detect a fault in the power grid 110. In response to detecting the fault, the RPA controller 120 is configured to determine an error voltage at the RPA 107 and convert the error voltage into an error signal. The detailed structure and operation principle of the RPA controller 120 are described below with reference to FIG. 5.

[0019] Electrical distribution network 100 further comprises a number of loads 142, 144, and 146 coupled to electrical distribution feeder 125. In some embodiments, loads 142, 144, and 146 may be residential loads, rotating loads (e.g., induction motors), and any combination thereof.

[0020] During operation, a fault, such as an unbalance fault, may occur in the power grid 110. The RPA controller 120 is configured to determine an error voltage at the RPA and convert the error voltage into an error signal. At the RPA, the PRA controller 120 further separates a positive sequence component of the error voltage from a negative sequence component of the error voltage and generates an error signal including a first component based on the positive sequence component and a second component based on both the positive sequence component and the negative sequence component. The first component of the error signal includes a value indicative of an amplitude boost requirement of the power grid 100 during the fault. The second component of the error signal includes a value indicative of a voltage unbalance of the power grid 100 during the fault. In the context of the present invention, the first component may be a positive voltage sequence error and the second component may be a negative voltage sequence error.

[0021] The RPA controller 120 broadcasts the error signal to multiple DERs. In particular, the RPA controller 120 broadcasts the error signal to DERs that are directly coupled to the RPA through appropriate communication links. The DERs that are directly coupled to the RPA forward the error signal to DERs that are indirectly coupled to the RPA.

[0022] In the electrical grid 100, a positive sequence current injection control scheme is applied to the plurality of DERs based on a first component of the error signal to increase the voltage of the electrical grid. An unbalanced voltage in the electrical grid can be mitigated by applying a negative sequence current injection control scheme to the plurality of DERs based on a second component of the error signal.

[0023] The fault is an unbalanced fault that occurs on at least one of the three phases of the grid. The phase on which the fault occurs is the faulted phase. The phase on which the fault does not occur is the non-faulted phase. A dynamic voltage support (DVS) control scheme is applied to the multiple DERs to reduce the error voltage at the RPA. Applying the DVS control scheme includes increasing the voltage of the faulted phases of the multiple DERs and mitigating the unbalanced voltage of the non-faulted phases of the multiple DERs by injecting multiple currents into the distribution feeder.

[0024] A distributed target tracking control scheme is applied to a plurality of DERs in an electric power distribution network. Applying the distributed target tracking control scheme includes determining a plurality of currents to be injected under the distributed target tracking control scheme by having communication between the DERs coordinate the currents injected by each of the plurality of DERs. Based on the error signal, the plurality of DERs are coordinated to inject currents into the electric power distribution network. This may be achieved by a speed matching algorithm by coordinating the plurality of DERs, including, for example, matching a current variation of one DER of the plurality of DERs with a current variation of the remaining DERs of the plurality of DERs. This may be further achieved by a clustering algorithm by coordinating the plurality of DERs, including, for example, matching a voltage of one DER of the plurality of DERs with a voltage of the remaining DERs of the plurality of DERs.

[0025] FIG. 2 illustrates that under an unbalance fault, DERs of a power grid according to various embodiments of the present disclosure are configured to operate in various operating modes. A first operating chart 202 illustrates that DERs of a power grid operate in four different modes in response to a fault during ride-through under a conventional control scheme. A second operating chart 204 illustrates that DERs of a power grid operate in four different modes in response to a fault during ride-through under a control scheme of the present disclosure. A third operating chart 203 illustrates a comparison between the phase voltage response of a DER under a conventional control scheme and the phase voltage response of a DER under a control scheme of the present disclosure.

[0026] The horizontal axis of the first operating chart 202, the second operating chart 204, and the third operating chart 203 represents a time interval in seconds. The vertical axis of the first operating chart 202, the second operating chart 204, and the third operating chart 203 represents the voltage of the DER. The voltage is expressed in a system of units. A system of units is an expression of a system quantity as a fraction of a defined base unit quantity. The base value of the voltage is the rated voltage of an inverter coupled between the DER and the distribution feeder. The voltage of the DER may alternatively refer to the applicable voltage.

[0027] As shown in the first and second operating charts 202 and 204, the DERs are designed to be capable of operating in four different modes depending on abnormal voltage conditions during ride-through (e.g., voltage perturbations after a grid fault occurs). Each DER can be in one of four operating modes: continuous operation mode, forced operation mode, suspended mode, and trip mode. Trip mode may alternatively be referred to as trip warning mode.

[0028] In the continuous operation mode, the DER remains operational and continues to deliver available active power at least as great as its pre-disturbance level. The delivered power may be prorated by the volts per unit of leased phase voltage if that voltage is less than nominal. In other words, the DER is behaving normally while the available voltage is within the specified limits (0.9 to 1.1 as shown in Figure 2).

[0029] In the forced operation mode, within the prescribed magnitude and duration limits, the DER is configured to withstand and support the grid until the voltage perturbation ends. As shown in Figure 2, the DER is configured to operate in the forced operation mode when the available voltage is 0.5-0.9, within the duration limit of 20 seconds. The DER can return to normal as soon as the available voltage returns to the voltage range of the continuous operation mode. On the other hand, the DER can leave the forced operation mode and enter the trip mode after the duration limit (20 seconds) expires.

[0030] In the Suspend mode, the DER temporarily stops energizing the grid. The DER can return to normal immediately when the applicable voltage returns to the voltage range of the continuous operation mode. Meanwhile, the DER can enter the Trip mode after the duration limit expires. As shown in Figure 2, if the applicable voltage is 1.2-1.3, the duration limit is 0.1 seconds. Similarly, if the applicable voltage is 1.1-1.2, the duration limit is 20 seconds. If the applicable voltage is 0-0.5, the duration limit is 1 second.

[0031] In a tripped mode of operation, the DER stops energizing the grid, or alternatively, the DER may be disconnected from the grid.

[0032] In operation, an unbalance fault occurs in at least one of the three phases of the grid. For example, a fault occurs in phase A of the grid. As a result of having this fault, phase A becomes the faulted phase. The other two phases (phases B and C) are non-faulted phases. A first operational chart 202 shows that under a conventional control scheme, the phases of the DER may introduce overvoltages. In response to the fault, the voltages of the three phases of the DER increase through injecting current into the grid. The voltage of the faulted phase (phase A) increases from about 0.8 to about 0.95. The voltage of one non-faulted phase (phase B) increases from about 0.95 to about 1.05. The voltage of the other non-faulted phase (phase C) increases from about 0.95 to about 1.15. Phase C introduces an overvoltage and goes into a suspension mode.

[0033] The second operating chart 204 illustrates that under the control scheme of the present disclosure, the three phases of the DERs remain in either a forced or continuous operating mode. In response to the unbalance fault, a dynamic voltage support (DVS) control scheme is applied to the multiple DERs. The multiple DERs inject multiple currents into the distribution feeder to reduce error voltages at the RPA. More specifically, by injecting multiple currents into the distribution feeder, voltages of the faulted phases of the multiple DERs may be increased and unbalanced voltages of the non-faulted phases of the multiple DERs may be mitigated. Increasing the voltages of the faulted phases and mitigating the unbalanced voltages of the non-faulted phases are further discussed below with respect to equations (11)-(13).

[0034] 2, both the faulted and non-faulted phases of the multiple DERs are configured to operate in modes including a continuous operation mode, a forced operation mode, a suspend mode, and a trip mode, as shown in a second operation chart 204. Increasing the voltage of the faulted phase of the multiple DERs includes forcing the faulted phase to leave the suspend mode and enter the forced operation mode, as shown by dashed line 206. Mitigating the unbalanced voltage of the non-faulted phase of the multiple DERs includes forcing the non-faulted phase to leave the forced operation mode and enter the continuous operation mode, as shown by dashed line 208. By increasing the voltage of the faulted phase of the multiple DERs and mitigating the unbalanced voltage of the non-faulted phase of the multiple DERs, the control scheme of the present disclosure can prevent the faulted and non-faulted phases of the multiple DERs from entering the trip mode.

[0035] As shown in the second operating chart 204, one potentially advantageous feature of the control scheme of the present disclosure is that it mitigates unbalanced voltages on the non-faulted phases of multiple DERs, helping to reduce the likelihood of introducing overvoltages on the non-faulted phases, thereby reducing the risk of overshoot.

[0036] The third operating chart 203 shows six voltage curves. A first curve 231 represents the voltage response of a faulted phase (e.g., phase A) after a fault occurs and the DER is controlled under a conventional control scheme. A second curve 232 represents the voltage response of a non-faulted phase (e.g., phase B) after a fault occurs and the DER is controlled under a conventional control scheme. A third curve 233 represents the voltage response of another non-faulted phase (e.g., phase C) after a fault occurs and the DER is controlled under a conventional control scheme. A fourth curve 234 represents the voltage response of a faulted phase (e.g., phase A) after a fault occurs and the DER is controlled under the control scheme of the present disclosure. A fifth curve 235 represents the voltage response of a non-faulted phase (e.g., phase B) after a fault occurs and the DER is controlled under the control scheme of the present disclosure. A sixth curve 236 represents the voltage response of another non-faulted phase (e.g., phase C) after a fault occurs and the DER is controlled under the control scheme of the present disclosure. As shown in FIG. 2, under the conventional control scheme, the voltage of one non-faulty phase (e.g., phase C) increases to a maximum of 1.1. As shown in the first operation chart 202, phase C leaves the continuous operation mode and enters the forced shutdown mode. In contrast, under the control scheme of the present disclosure, the voltage of the non-faulty phases (e.g., phase C and phase B) is less than 1.1. Furthermore, the fourth curve 234 and the first curve 231 show that the recovery speed of the faulty phase under the control scheme of the present disclosure is faster than the recovery speed under the conventional control scheme.

[0037] 3 illustrates a simplified model of the DER and distribution feeder shown in FIG. 1 according to various embodiments of the present disclosure. The DER 122 includes a power source 302, an output capacitor Cdc, a grid-connected voltage source converter (VSC), and an LCL filter. The power source 302 may be implemented as a PV panel. The grid-connected VSC may be implemented as an inverter. The LCL filter includes a first inductor Lcf, a capacitor Cf, and a second inductor Lgf. The DER 122 is connected to the distribution grid at the POC. The distribution feeder includes a series resistor R L and series impedance Z L A wye-delta transformer is placed between the POC and the distribution feeder. The POC voltage sensor measures the voltage at the POC (V POC) through the distribution feeder. g ) is used to detect the grinding voltage (V grid ) is used to detect

[0038] During operation, when an unbalanced fault occurs on the grid, positive, negative, and zero sequence components become dominant. Depending on the fault type, the resulting voltage magnitudes may differ. For example, during a 2L-G fault, no significant voltage effect is observed on the non-faulted phases. If voltage support is enabled by only positive sequences with the intention of supporting the faulted phases, the magnitude of the voltage on the non-faulted phases will exceed a certain threshold. To avoid such an outcome, voltage support can incorporate support for positive and negative sequences simultaneously.

[0039] In Figure 3, POC(V POC ) and grid voltage (V G ) is as follows:

[0040]

number

[0041] In equation (1), R is the equivalent resistance of the distribution feeder. L is the equivalent inductance of the distribution feeder.

[0042] This power converter (e.g., VSC304) + ) and negative (I - ) can be injected. By using the magnitude of the symmetrical components, the information of the positive and negative sequences can be expressed as follows:

[0043]

number

[0044] Equations (2.1) and (2.2) can be rewritten based on the impedance of the power grid. If the network impedance is highly inductive, the resistive part of the equation can be neglected. Equations (2.1) and (2.2) can be rewritten as follows:

[0045]

number

[0046] Equations (3.1) and (3.2) suggest that positive sequence voltages can be increased by injecting positive sequence reactive currents into the inductive impedance dominated grid. On the other hand, injecting negative sequence reactive currents can help to mitigate voltage unbalance. Equations (3.1) and (3.2) show that grid voltage support can be realized in two ways. If only positive sequence reactive power is injected under unbalanced faults, POC voltages will rise equally in each phase compared to grid voltages. Unbalanced voltages at POCs can be compensated by injecting negative sequence reactive power.

[0047] The unbalance mitigation can be achieved by reducing the voltage amplitude gap between the faulted and non-faulted phases. As a result of mitigating the unbalanced voltage, the non-faulted phase can avoid voltage overshoot.

[0048] Equations (2.1) and (2.2) can also be rewritten for the low voltage grid since the grid impedance is more resistive. By neglecting the inductive components, the equations can be rewritten as follows:

[0049]

number

[0050] Equations (4.1) and (4.2) suggest that by injecting positive-sequence active power, the positive-sequence voltage at the POC can be increased, while reducing the amount of negative-sequence active power helps to mitigate the POC voltage unbalance of the resistive network.

[0051] To control a power converter (e.g., VSC 304) during unbalanced conditions, equation (1) can be expressed in a double synchronous reference frame (DSRF). In a stationary reference frame (αβ), equation (1) can be expressed as follows:

[0052]

number

[0053] During an unbalance fault, the voltage variable (V) in the stationary reference frame (αβ) can be decomposed into positive and negative sequence components in the (dq) frame.

[0054]

number

[0055] In the formula (6), Vαβ is calculated from the abc natural quantities of V as follows:

[0056]

number

[0057] The decomposition sequence model in the (dq) coordinate system can be obtained by substituting (6) into (5).

[0058]

number

[0059]

number

[0060]

number

[0061] A non-interfering dual synchronous reference frame PLL (DDSRF-PLL) control scheme is used to independently control the positive and negative sequence components. DDSRF-PLL is known in the art and will not be discussed in detail. After the DDSRF-PLL control scheme is applied, the control equation of the power converter (e.g., VSC 304) can be expressed as follows:

[0062]

number

[0063] The above control equations are used to control the power converter. The control equations may be implemented in a DER controller. A detailed implementation of the above control equations is described below with respect to FIG. 4.

[0064] After a grid fault occurs, the ride-through requirement involves a two-dimensional unbalanced voltage recovery scheme. The first aspect of this two-dimensional unbalanced voltage recovery scheme is to coordinate positive sequence current injection for voltage swing increase. The second aspect of this two-dimensional unbalanced voltage recovery scheme is to coordinate negative sequence current injection for voltage unbalance mitigation. The requirement at the RPA is broadcast to the grid through an error signal. Each of the power converters (e.g., VSC 304) can interpret this error signal and cooperate with other DERs to generate incremental current injection locally over a time frame. The voltage change at the RPA can be expressed as:

[0065]

number

[0066]

number

[0067] The error signal broadcast by the RPA includes a first component and a second component. The first component includes a value indicative of the amplitude boost requirement of the grid during the fault. The second component includes a value indicative of the voltage unbalance of the grid during the fault. The first component can be expressed as:

[0068]

number

[0069] In the RPA, the RPA voltage (V RPA ) positive sequence component (V RPA + ) is the negative sequence component of the RPA voltage (V RPA - ) Equation (12) shows that the first component of the error signal is based on the positive sequence component of the RPA voltage.

[0070] The second component of the error signal can be expressed as:

[0071]

number

[0072] Equation (13) shows that the second component of the error signal is based on both the positive and negative sequence components of the RPA voltage.

[0073] The RPA broadcasts the error signals shown in Equations (12) and (13) to the DERs of the power grid. The broadcasted error signals are used by the DERs to generate current references for controlling their respective power converters.

[0074] FIG. 4 illustrates a control system implementing a non-interfering dual synchronous reference frame PLL control scheme according to various embodiments of the present disclosure. The control equations shown in equations (10.1), (10.2), (10.3), and (10.4) are implemented in each DER controller. For simplicity, only the relevant parts of the DER controller are shown in FIG. 4. The DER controller is configured to receive an error signal broadcast by the RPA and generate a current reference based on the error signal. The DER controller also receives operating parameters (e.g., current and voltage of an inverter coupled to the DER controller). The DDSRF-PLL control scheme is utilized to process the current reference and the detected operating parameters and generate a control signal for controlling the current injection of the inverter.

[0075] The DER controller shown in FIG. 4 includes a transformer section 168, where the three-phase measured voltages are transformed to V POC The three-phase signals (lines abc) of are provided to a first transformation block 160 which transforms them into their corresponding signals in the dq synchronous reference frame.

[0076] The dq voltage signal is fed to a DDSRF-PLL sequence extraction block 162, which extracts the positive sequence dq voltage V dq + and negative dq voltage V dq - is calculated. Positive sequence dq voltage V dq + is the positive sequence DC voltage component V d + and positive sequence quadrature voltage component V q + Includes the negative sequence dq voltage V dq - is the negative sequence DC voltage component V d - and the negative sequence quadrature voltage component V q - Furthermore, the DDSRF-PLL sequence extraction block 162 includes φ + and φ - φ+ and φ - The signals have voltages V POC represents the phase angles of the positive and negative sequences of

[0077] Measured inverter current (i f ) are provided to a second transformation block 164 and a third transformation block 166, respectively. + Based on this, the second conversion block 164 converts the positive sequence dq current i dq + It is configured to generate a positive sequence dq current I dq + is the positive sequence DC current component I d + and positive sequence quadrature current component I q + The measured current and the negative sequence phase angle φ - Based on this, the third conversion block 166 converts the negative sequence dq current i dq + It is configured to generate a negative sequence dq current I dq - is the negative sequence DC current component I d - and the negative sequence quadrature current component I q - Includes.

[0078] As shown in FIG. 4, the controller comprises four current processing branches: a positive sequence DC current processing branch 191, a positive sequence Q current processing branch 192, a negative sequence DC current processing branch 193 and a negative sequence Q current processing branch 194.

[0079] In the positive sequence DC current processing branch 191, a positive sequence DC current i d + is fed to a summing unit 181. The summing unit 181 receives a positive sequence DC reference current i d + * and positive sequence DC current i d +This difference may alternatively be referred to as the positive sequence DC current error. d + Note that * is generated based on the error signal broadcast by the RPA.

[0080] As shown in Figure 4, the positive sequence DC current error is provided to a proportional-integral (PI) controller 182. The output of the PI controller 182 is generated based on the sum of the current error values ​​and the integral of the current error values. PI control is well known in the art and therefore will not be discussed. The output of the PI controller 182 is provided to a summing unit 183. As shown in Figure 4, the summing unit 183 also receives a first cross-coupled signal, which will be described below.

[0081] The first cross-coupled signal received by the summing unit 183 is generated as follows: q + is fed to multiplier 185 where it is multiplied by ωL. The output of multiplier 185 is i q + ×ωL. The output of the multiplier 185 is provided as a first cross-coupled signal to the summing unit 183. The summing unit 183 receives a positive sequence DC reference voltage V d + Generate *.

[0082] In the positive sequence quadrature current processing branch 192, the positive sequence quadrature current i q + is provided to a summing unit 186. The summing unit 186 outputs a positive sequence quadrature reference current i q + * and positive sequence quadrature current i q + This difference may alternatively be referred to as the positive sequence quadrature current error. q + Note that * is generated based on the error signal broadcast by the RPA.

[0083] As shown in Figure 4, the positive sequence quadrature current error is provided to a PI controller 187. The output of the PI controller 187 is generated based on a sum of the current error values ​​and an integral of the current error values. The output of the PI controller 187 is provided to a summing unit 188. As shown in Figure 4, the summing unit 188 also receives a second cross-coupled signal.

[0084] The second cross-coupled signal received by the summing unit 188 is generated as follows: d + is provided to multiplier 184 where it is multiplied by ωL. The output of multiplier 184 is i d + ×ωL. The output of multiplier 184 is provided as a second cross-coupled signal to summing unit 188. Summing unit 188 outputs a positive-sequence quadrature reference voltage V q + Generate *.

[0085] The outputs of the summing units 183 and 188 are positive sequence DC reference voltages V d + * and positive sequence quadrature reference voltage V q + *, which are fed to a conversion block 196, where the positive sequence DC and quadrature reference voltages are converted to reference voltages in the abc system.

[0086] The negative sequence DC current processing branch 193 is similar to the positive sequence DC current processing branch 191 and therefore will not be discussed in detail. Similarly, the negative sequence Quadrature current processing branch 194 is similar to the positive sequence Quadrature current processing branch 192 and therefore will not be discussed in detail. As shown in FIG. 4, the outputs of the summing units are respectively the negative sequence DC reference voltage V d - * and the negative sequence quadrature reference voltage V q -*, which are fed to a conversion block 198, where the negative sequence DC reference voltage and the quadrature reference voltage are converted to reference voltages in the abc system.

[0087] The positive-sequence and negative-sequence reference voltages are combined in a summing unit 197 to produce a reference voltage signal V abc + * Provides a reference voltage signal V abc + * is provided to a pulse width modulation (PWM) controller for generating on / off switching commands for the inverter. The PWM controller may be part of a digital signal processor (DSP).

[0088] 5 illustrates a block diagram of the RPA controller shown in FIG. 1 in accordance with various embodiments of the present disclosure. As shown in FIG. 5, the RPA controller 120 includes an analog-to-digital converter 502, a memory 504, a digital processor 506, and a communication device 508. As shown in FIG. 5, the analog-to-digital converter 502 converts a voltage V grid and converts the voltage into a digital signal suitable for the digital processor 506. Control instructions are stored in the memory 504. The digital processor 506 loads the control instructions from the memory 504. The control instructions are executed within the digital processor 506 to process the digital signal from the analog-to-digital converter 502. After the digital signal is processed, the digital processor 506 is configured to generate an error signal. The error signal includes a first component and a second component. The first component includes a value indicative of an amplitude boost requirement of the grid during a fault in the grid. The second component includes a value indicative of a voltage imbalance of the grid during a fault. The error signal is provided to a communication device 508. The communication device 508 is configured to broadcast the error signal to the DERs.

[0089] In some embodiments, the digital processor 506 is implemented as a high-speed processor such as a DSP. The DSP allows for digital control implementation of the control method shown in equations (11) and (12). FIG. 5 shows that the control method may be fully implemented in a digital processor. This is merely an example, and should not unduly limit the scope of the claims. Those skilled in the art will recognize many variations, alternatives, and modifications. For example, parts of the control method may be implemented by any other suitable processing circuitry, such as logic circuits, analog circuits, etc.

[0090] FIG. 6 illustrates a block diagram of the DER controller shown in FIG. 1 according to various embodiments of the present disclosure. As shown in FIG. 6, the DER controller 132 includes an analog-to-digital converter 602, a memory 604, a digital processor 606, and a communication device 608. As shown in FIG. 6, the analog-to-digital converter 602 is configured to receive a number of operating parameters including an inverter output voltage, a POC voltage, and a POC current. The analog-to-digital converter 602 converts the operating parameters into a digital signal suitable for the digital processor 606. The communication device 608 is configured to receive an error signal broadcast by the RPA and provide the error signal to the digital processor 606.

[0091] The control instructions are stored in memory 604. Digital processor 606 loads the control instructions from memory 604. The control instructions are executed in digital processor 606 to process the digital signal from analog-to-digital converter 502 and the error signal from communication device 608. After the digital signal and the error signal are processed, digital processor 606 is configured to generate an inverter control signal. The inverter control signal is used to control current injection from a DER associated with this DER controller.

[0092] 7 is a diagram illustrating a control system implementing a distributed coordinated dynamic voltage support (DCDVS) ​​control scheme according to various embodiments of the present disclosure. The power distribution grid shown in FIG. 1 can be modeled as a multi-agent system as shown in FIG. 7. The RPA is the lead agent 171. The lead agent 171 may alternatively be referred to as an RPA agent or a lead RPA agent. The DERs are agents 172-179 coupled to the lead RPA agent 171.

[0093] In operation, the RPA (agent 171) broadcasts an error signal to the DERs that are directly coupled to the RPA (e.g., agents 172, 173, 178, and 179). The DERs that are directly coupled to the RPA forward the error signal to the DERs that are indirectly coupled to the RPA (e.g., agents 174, 175, 176, and 177).

[0094] In operation, a distributed target tracking control scheme is applied to the multiple DERs (agents 172-172). Applying the distributed target tracking control scheme includes determining the current to be injected under the distributed target tracking control scheme by causing communication between the DERs (agents 172-172) to coordinate the current injected by each of the multiple DERs.

[0095] The agents communicate with each other to achieve an overall goal. The overall goal of each DER agent is to satisfy requirements (e.g., error signals) from the lead RPA agent 171. Each DER agent not only realizes local response characteristics, but also collaborates with other DER agents. This characteristic ensures that the agents have local autonomy while satisfying requests from the lead agent. The RPA (lead agent) can broadcast event-based requests (e.g., error signals after a failure occurs) to the network agents (DERs) to request them to provide aggregate DCDVS support to achieve a specific response in the RPA. This request is a common concern for all network agents, since the connectivity of the RPA is essential for the remaining agents to remain online.

[0096] The agents in Figure 7 (agents 172-179) form a swarm. In a swarm, the agents have local interactions between individual agents and exhibit collective motion to achieve an overall goal. The agents can split, recombine, and form highly ordered and fast convergence of the center of mass towards a target. An agent (DER) can reach an overall goal broadcasted by a leading agent (RPA) while interacting locally with other nearby DERs. Three control schemes are utilized to control the behavior of the agents.

[0097] The first control scheme is based on the speed matching behavior of the swarm: agents try to adjust their speed to match their neighbors (matching). This behavior helps to avoid uncontrolled current injections that can result in overvoltages.

[0098] The second control strategy is based on the herd behavior of the swarm: each agent tries to stay close to its neighbors (cohesion). This feature helps to keep the voltage profile smooth and avoid large differences along the feeder.

[0099] The third control scheme is based on the collision avoidance behavior of the swarm: agents avoid collisions with their neighbors (segregation). This behavior does not necessarily have to be implemented in the power system domain, since the current injections of each DER may overlap.

[0100] In the present disclosure, a first control scheme and a second control scheme are utilized to control DERs. Under the first control scheme, the multiple DERs are coordinated to inject current into the grid based on the error signal. Coordinating the multiple DERs includes matching a current variation of one DER of the multiple DERs with a current variation of the remaining DERs of the multiple DERs. In some embodiments, the remaining DERs of the multiple DERs are neighboring DERs. For example, a current variation of a DER (agent 174 shown in FIG. 7) is matched with a current variation of the neighboring DERs (agents 172, 173, 175).

[0101] Under the second control scheme, the multiple DERs are coordinated to inject current into the grid based on the error signal, where coordinating the multiple DERs includes matching a voltage of one DER of the multiple DERs with voltages of remaining DERs of the multiple DERs.

[0102] The multi-agent system shown in Figure 7 acts as a biological network, where the most informed agents tend to adjust their information to their speed. For example, the most informed fish in a school of fish will move faster when it feels threatened. The agents should pay more attention to their faster-moving neighbors and assign them more weight. When the DCDVS control method is applied to a multi-agent system, the behavior of the biological network can be modeled in two ways. The first is to link the acceleration behavior to the observed severity of the disturbance. If an agent is closer to the disturbance point, this agent will accelerate faster. The second is whether the agents can directly communicate with the RPA and access information with less noise, unlike other agents that learn their behavior model from their neighbors.

[0103] The agents retain the ability to self-organize during and after failure conditions in noisy communication environments. Constrained local interactions between DERs include global response patterns to ensure stability after failures. DERs can adjust the topology in real-time by adapting the weights associated with links depending on the quality of the information received. DERs do not need to converge to the same equilibrium. Instead, the temporal and spatial diversity of data across the network is exploited to allow nodes to have a level of individuality in assessing and evaluating the quality of their data.

[0104] During a fault, a grid perturbation occurs. When the voltage level of the RPA transitions to a forced operation state (forced operation mode), the RPA unbalance and ε mag The DERs in the swarm broadcast an error signal including a value to the DERs across the unknown network. The DERs in the swarm track the error signal to generate reference values ​​for controlling the power converters associated with the DERs. In particular, the power converters inject current based on their respective reference values.

[0105] According to well-known distributed target tracking theory, each agent is associated with an unknown target location. The agents cooperate via a well-known Diffusion Combination-Adaptation (CTA) strategy to track and estimate the unknown target location. This unknown location tracking method can receive information directly from the RPA or any other informed agent in the network.

[0106]

number

[0107] 8 illustrates a flowchart of a method for controlling the power grid shown in FIG. 1 according to various embodiments of the present disclosure. This flowchart illustrated in FIG. 8 is merely an example, which should not unduly limit the scope of the claims. Those skilled in the art will recognize many variations, substitutions, and modifications. For example, various steps illustrated in FIG. 8 may be added, deleted, substituted, rearranged, and repeated.

[0108] The distribution network comprises a plurality of loads coupled to a distribution feeder. The distributed power network is coupled to a grid. A power source of each DER is coupled to the distribution feeder through an inverter. The distribution network further comprises an RPA. The RPA is a node adjacent to an interface between the grid and the distribution network. When a fault occurs in the grid, the RPA can generate an error signal based on a detected voltage on the RPA node. The RPA comprises an RPA communication device. Each DER is equipped with a DER communication device. The RPA communication device is utilized to broadcast the error signal to the plurality of DERs through their respective DER communication devices.

[0109] In step 802, a fault in the grid is detected by an RPA, which is associated with multiple DERs, as further described above in various embodiments, e.g., in Figures 2-4.

[0110] In step 804, in response to detecting the fault, the RPA is configured to determine an error voltage, convert the error voltage into an error signal, and broadcast the error signal to a plurality of DERs. Based on the error signal, a plurality of currents from the plurality of DERs are injected into the distribution feeder to reduce the error voltage at the RPA. This is further described above in various embodiments, e.g., in Figures 2-4. One potentially advantageous feature of having step 804 is that the DERs inject currents into the distribution feeder during the fault based on the error signal. The injected currents help reduce the error voltage at the RPA, thereby maintaining a predetermined voltage profile at the RPA.

[0111] FIG. 9 illustrates a block diagram of a system according to various embodiments of the disclosure. A power distribution network 100 is connected to a grid 110. The power distribution network 100 includes a distribution feeder 125, a plurality of distributed energy resources (DERs) 122-126 coupled to the distribution feeder 125, a reference point of applicability (RPA) 121, and an RPA controller 120 coupled to the RPA 121. The RPA controller 120 is programmatically configured to detect a fault in the grid 110, for example, as described with respect to FIG. 2. In response to detecting the fault, the RPA controller 120 is programmatically configured to determine an error voltage at the RPA 121 and convert the error voltage into an error signal, for example, as described with respect to FIG. 3. A first communication device 123 is coupled to the RPA controller 120, for example, as described with respect to FIG. 5. The first communication device 123 is configured to broadcast an error signal to the plurality of DERs 122-126, for example, as described with respect to FIG. 5. The plurality of DER controllers 132-136 are coupled to respective DERs of the plurality of DERs 122-126, e.g., as described with respect to Figure 1. Based on the error signal, the plurality of DER controllers 132-136 are configured, via programming, to control the respective DERs to reduce the error voltage at the RPA 121 by injecting a plurality of currents into the distribution feeder 125, e.g., as described with respect to Figure 1.

[0112] FIG. 10 illustrates a block diagram of an RPA controller according to various embodiments of the present disclosure. The RPA controller comprises a controller coupled to an electric grid. The electric grid comprises a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and an RPA. The controller is directly coupled to the RPA. As illustrated in FIG. 10, the controller comprises a memory 504 storing a program including instructions, a processor 506 coupled to the memory 504, and a first communication device 508 coupled to the processor 506. The processor 506 and the first communication device 508 are similar to the digital processor and communication device illustrated in FIG. 5, respectively. The processor 506 is configured to execute the program. The instructions, when executed, cause the processor 506 to detect a fault in a grid coupled to the electric grid, for example, as described with respect to FIG. 2. In response to detecting the fault, the processor 506 determines an error voltage at the RPA, converts the error voltage to an error signal, and transmits the error signal to the first communication device 508, e.g., as described with respect to Figures 2-4. The first communication device 508 is configured to broadcast the error signal to multiple DERs, e.g., as described with respect to Figures 5-6.

[0113] FIG. 11 illustrates a block diagram of a DER control system according to various embodiments of the disclosure. The DER control system includes a plurality of DER controllers as shown in FIG. 11. The plurality of DER controllers are coupled to an electric grid including a distribution feeder, a plurality of DERs coupled to the distribution feeder, and an RPA. Each of the plurality of DER controllers is coupled to a corresponding DER of the plurality of DERs. Each of the plurality of DER controllers includes a memory 604 storing a program including instructions, a processor 606 coupled to the memory 604, and a communication device 608 coupled to the processor 606. The processor 606 is configured to execute the program. The instructions, when executed in each of the plurality of DER controllers, cause the plurality of DER controllers to receive an error signal from an RPA controller directly coupled to the RPA and to transmit a control signal to the plurality of DERs, e.g., as described with respect to FIGS. 2-4 and 7. One of the control signals is transmitted to one of the plurality of DERs. The control signals received by the multiple DERs are configured to reduce error voltages at the RPA by injecting multiple currents from the multiple DERs into the distribution feeder, for example, as described with respect to FIGS. 1-4.

[0114] 12 is a block diagram of a processing system according to various embodiments of the present disclosure. Processing system 1200 illustrates a generic platform and general components and functionality that may be used to implement portions of an embodiment of a power grid and / or an external computer or processing device interfaced to an embodiment of a power grid. For example, processing system 1200 may be used to implement portions of the controller illustrated in FIG. 10. In some embodiments, processing system 1200 may be used to determine and evaluate operating parameters of an embodiment and determine an error signal for the power grid based on the operating parameters.

[0115] Processing system 1200 may include, for example, a central processing unit (CPU) 1202 and a memory 1204 coupled to a bus 1208 and may be configured to execute the processes described above. Processing system 1200 may further include, as desired or required, a display adapter 1210 providing a connection to a local display 1212, and an input / output (I / O) adapter 1214 providing an input / output interface for one or more input / output devices 1216, such as a mouse, keyboard, flash drive, etc.

[0116] The processing system 1200 may also include a network interface 1218, which may be implemented using a wired link, such as a network cable, a USB interface, and / or a network adapter configured to be coupled to a wireless / cellular link for communicating with the network 1220. The network interface 1218 may also include a suitable receiver and transmitter for wireless communication. It should be noted that the processing system 1200 may include other components. For example, the processing system 1200 may include hardware components power supply, cables, a motherboard, removable storage media, a case, and the like, if implemented externally. These other components are not shown, but are considered part of the processing system 1200. In some embodiments, the processing system 1200 may be implemented on a single monolithic semiconductor integrated circuit and / or on the same monolithic semiconductor integrated circuit as the other disclosed system components.

[0117] Exemplary embodiments of the present disclosure are summarized here. Other embodiments can be seen throughout the specification and claims appended hereto.

[0118] It may be advantageous to reduce the overshoot risk. To better address this, in a first embodiment of the present invention, a method is presented, which includes detecting a fault in a grid coupled to a distribution network, the distribution network including a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and a reference point of applicability (RPA) associated with the plurality of DERs. The method includes, in response to detecting the fault, determining an error voltage at the RPA, converting the error voltage into an error signal, broadcasting the error signal to the plurality of DERs, and reducing the error voltage at the RPA by injecting a plurality of currents from the plurality of DERs to the distribution feeder based on the error signal.

[0119] It may be advantageous to achieve a two-dimensional unbalanced voltage recovery target based on separating a positive sequence component of an error voltage from a negative sequence component of the error voltage. To better address this, in a second embodiment of the present invention, the method of the first embodiment, wherein converting the error voltage into an error signal includes: separating, in the RPA, a positive sequence component of the error voltage from a negative sequence component of the error voltage; and generating, in the RPA, an error signal including a first component based on the positive sequence component and a second component based on both the positive sequence component and the negative sequence component.

[0120] It may be advantageous to achieve coordinated positive sequence current injection for voltage swing boost and coordinated negative sequence current injection for unbalanced voltage mitigation. To better address this, in the method of one of Example 3, Example 1 or Example 2 of the present invention, the first component includes a value indicative of a swing boost requirement of the grid during the fault, and the second component includes a value indicative of a voltage unbalance of the grid during the fault.

[0121] Example 4. The method of any one of Examples 1-3, wherein reducing the error voltage at the RPA includes increasing a voltage of the power grid by applying a positive sequence current injection control scheme to the plurality of DERs based on the first component.

[0122] Example 5. The method of any one of Examples 1-4, wherein reducing the error voltage at the RPA includes mitigating the unbalanced voltage on the power distribution grid by applying a negative sequence current injection control scheme to the plurality of DERs based on the second component.

[0123] It may be advantageous to reduce the possibility of introducing overvoltages to the non-faulted phase through mitigating the unbalanced voltage of the non-faulted phase. To better address this, in Example 6 of the present invention, the method of any one of Examples 1 to 5, wherein detecting a fault in the grid includes detecting an unbalanced fault in at least one of three phases of the grid, and reducing the error voltage in the RPA includes determining a plurality of currents to be injected by applying a dynamic voltage support (DVS) control scheme to the plurality of DERs, and applying the DVS control scheme includes increasing the voltage of the faulted phase of the plurality of DERs by injecting a plurality of currents into the distribution feeder, and mitigating the unbalanced voltage of the non-faulted phase of the plurality of DERs.

[0124] Example 7 The method of any one of Examples 1 to 6, wherein the faulty and non-faulty phases of the multiple DERs are configured to operate in modes that include, inter alia, a continuous operation mode, a forced operation mode, a suspended mode, and a trip mode, and increasing the voltage of the faulty phases of the multiple DERs includes forcing the faulty phases to leave the suspended mode and enter the forced operation mode, and mitigating the unbalanced voltage of the non-faulty phases of the multiple DERs includes forcing the non-faulty phases to leave the forced operation mode and enter the continuous operation mode.

[0125] Example 8. The method of any one of Examples 1-7, further comprising: preventing the faulted and non-faulted phases of the multiple DERs from entering a trip mode by increasing the voltages of the faulted phases of the multiple DERs and mitigating the unbalanced voltages of the non-faulted phases of the multiple DERs.

[0126] It may be an advantageous feature that the DERs may be coordinated to avoid uncoordinated current injection through matching of current fluctuations. To better address this, in a ninth embodiment of the present invention, the method of any one of the first to eighth embodiments, wherein reducing the error voltage at the RPA includes coordinating the plurality of DERs to inject current into the grid based on the error signal, and coordinating the plurality of DERs includes matching a current fluctuation of one DER of the plurality of DERs with a current fluctuation of the remaining DERs of the plurality of DERs, e.g., by a rate matching algorithm and / or a first control scheme as described above.

[0127] It may be an advantageous feature that the DERs may be coordinated to support the RPA voltage profile by matching the voltages of the DERs. To better address this, in a tenth embodiment of the present invention, the method of any one of the first to ninth embodiments, wherein reducing the error voltage at the RPA includes coordinating the plurality of DERs to inject current into the grid based on the error signal, and coordinating the plurality of DERs includes matching a voltage of one DER of the plurality of DERs with a voltage of the remaining DERs of the plurality of DERs, e.g., by a rate matching algorithm and / or a second control scheme as described above.

[0128] It may be an advantageous feature that all DERs can receive the error signal from the RPA through a broadcast mechanism described below. To better address this, in an eleventh embodiment of the present invention, the method of one of the first to tenth embodiments, wherein broadcasting the error signal to the plurality of DERs includes broadcasting the error signal to a first DER of the plurality of DERs, the first DER being directly coupled to the RPA, and forwarding the error signal from the first DER of the plurality of DERs to a second DER, the second DER being indirectly coupled to the RPA.

[0129] It may be an advantageous feature that under the distributed target tracking control scheme, the DERs can support the RPA voltage profile during and after the fault ridge through cooperative behavior and avoid uncoordinated current injection. To better address this, in a twelfth embodiment of the present invention, the method of any one of the first to eleventh embodiments, wherein reducing the error voltage at the RPA includes applying a distributed target tracking control scheme to a plurality of DERs, and applying the distributed target tracking control scheme to the plurality of DERs includes determining a plurality of currents to be injected under the distributed target tracking control scheme by causing communication between the DERs to coordinate the currents injected by each of the plurality of DERs.

[0130] It may be advantageous to reduce the overshoot risk. To better address this, in a thirteenth embodiment of the present invention, a system is presented, the system includes a distribution grid coupled to a grid, the distribution grid including a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and a reference point of applicability (RPA), an RPA controller coupled to the RPA and configured to programmatically detect a fault in the grid, and in response to detecting the fault, determine an error voltage at the RPA and convert the error voltage into an error signal, and a first communication device coupled to the RPA controller and configured to broadcast the error signal to the plurality of DERs. The system includes a plurality of DER controllers coupled to respective DERs of the plurality of DERs, and based on the error signal, the plurality of DER controllers are configured to programmatically control the respective DERs to reduce the error voltage at the RPA by injecting a plurality of currents into the distribution feeder.

[0131] Example 14. The system of example 13, wherein the RPA controller is configured by a program to separate a positive sequence component of the error voltage from a negative sequence component of the error voltage and generate an error signal including a first component based on the positive sequence component and a second component based on both the positive sequence component and the negative sequence component, the first component including a value indicative of an amplitude rise requirement of the power grid during the fault, and the second component including a value indicative of a voltage imbalance of the power grid during the fault.

[0132] Example 15: The system of one of Examples 13 or 14, wherein the plurality of DER controllers are configured, through programming, to increase a voltage of the power grid by applying a positive sequence current injection control scheme to the plurality of DERs based on a first component, and the plurality of DER controllers are configured, through programming, to mitigate an unbalanced voltage of the power grid by applying a negative sequence current injection control scheme to the plurality of DERs based on a second component.

[0133] Example 16. The system of any one of Examples 13-15, wherein the plurality of DER controllers are configured, through programming, to control the plurality of DERs to increase voltages of faulted phases of the plurality of DERs and mitigate unbalanced voltages of non-faulted phases of the plurality of DERs.

[0134] Example 17. The system of any one of Examples 13-16, wherein the plurality of DER controllers are configured to coordinate the plurality of DERs to inject current into the grid, e.g., by matching a current fluctuation of one DER of the plurality of DERs with a current fluctuation of the remaining DERs of the plurality of DERs, e.g., by a rate matching algorithm and / or a first control scheme as described above.

[0135] Example 18. The system of any one of Examples 13-17, wherein the plurality of DER controllers are configured to coordinate the plurality of DERs to inject current into the grid, e.g., by matching a voltage of one of the plurality of DERs with a voltage of the remaining DERs of the plurality of DERs, e.g., by a clustering algorithm and / or a second control scheme as described above.

[0136] Example 19 The system of one of Examples 13 to 18, further including a second communication device coupled to a first DER of the plurality of DERs, where the first DER is directly coupled to the RPA, and a third communication device coupled to a second DER of the plurality of DERs, where the second DER is indirectly coupled to the RPA, wherein the second communication device is configured to receive an error signal broadcast by the first communication device and forward the error signal to the third communication device.

[0137] Example 20. The system of any one of Examples 13-19, further comprising a plurality of inverters, one of the plurality of inverters coupled between each of the plurality of DERs and the distribution feeder, and wherein based on the error signal, the plurality of inverters are configured to generate a plurality of currents to be injected into the distribution feeder.

[0138] It may be advantageous to reduce the overshoot risk. To better address this, in a twenty-first embodiment of the present invention, a system applicability reference point (RPA) controller is presented, which includes a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and a controller coupled to an electric grid including the RPA, the controller being directly coupled to the RPA, the controller comprising: a memory storing a program including instructions; a processor coupled to the memory and configured to execute the program; and a first communication device coupled to the processor, the instructions, when executed, cause the processor to detect a fault in a grid coupled to the electric grid, and in response to detecting the fault, determine an error voltage in the RPA, convert the error voltage into an error signal, and transmit the error signal to the first communication device, the first communication device being configured to broadcast the error signal to the plurality of DERs.

[0139] Example 22 The RPA controller of Example 21, wherein a first DER of the plurality of DERs is coupled to a second communication device, the first DER is directly coupled to the RPA, a second DER of the plurality of DERs is coupled to a third communication device, and the second DER is indirectly coupled to the RPA, the second communication device is configured to receive an error signal broadcast by the first communication device and forward the error signal to the third communication device, the plurality of DERs are coupled to a plurality of DER controllers, and based on the error signal, the plurality of DER controllers are configured, by programming, to control the respective DERs to reduce an error voltage at the RPA by injecting a plurality of currents into the distribution feeder.

[0140] Example 23. The RPA controller of one of Examples 21 or 22, wherein the processor is configured by a program to separate a positive sequence component of the error voltage from a negative sequence component of the error voltage and generate an error signal including a first component based on the positive sequence component and a second component based on both the positive sequence component and the negative sequence component, wherein the first component includes a value indicative of an amplitude rise requirement of the power distribution network during the fault and the second component includes a value indicative of a voltage imbalance of the power distribution network during the fault.

[0141] It may be advantageous to reduce the overshoot risk. To better address this, in a twenty-fourth embodiment of the present invention, a distributed energy resource (DER) control system is presented, which includes a plurality of DER controllers coupled to a distribution grid including a distribution feeder, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and a reference point of applicability (RPA), each of the plurality of DER controllers is coupled to a corresponding DER of the plurality of DERs, each of the plurality of DER controllers includes a memory storing a program including instructions, a processor coupled to the memory and configured to execute the program, and a communication device coupled to the processor, the instructions, when executed in each of the plurality of DER controllers, cause the plurality of DER controllers to receive an error signal from an RPA controller directly coupled to the RPA and to send a control signal to the plurality of DERs, one of the control signals being sent to one of the plurality of DERs, and the control signal received by the plurality of DERs is configured to reduce an error voltage at the RPA by injecting a plurality of currents from the plurality of DERs into the distribution feeder.

[0142] Example 25. The DER control system of example 24, wherein the error voltage includes a positive sequence component and a negative sequence component, the error signal includes a first component based on the positive sequence component and a second component based on both the positive sequence component and the negative sequence component, the first component includes a value indicative of an amplitude rise requirement of the distribution network during a fault in a grid coupled to the distribution network, and the second component includes a value indicative of a voltage imbalance of the distribution network during the fault.

[0143] Example 26: The DER control system of one of Examples 24 or 25, wherein based on a first component, the multiple DER controllers are configured to increase a voltage of the power grid by applying a positive sequence current injection control scheme to the multiple DERs by executing instructions in each of the multiple DER controllers, and based on a second component, the multiple DER controllers are configured to mitigate an unbalanced voltage of the power grid by applying a negative sequence current injection control scheme to the multiple DERs by executing instructions in each of the multiple DER controllers.

[0144] Example 27: The DER control system of any one of Examples 24-26, wherein the multiple DER controllers are configured to coordinate the multiple DERs to inject current into the grid by executing instructions at each of the multiple DER controllers, e.g., by matching a current fluctuation of one of the multiple DERs with a current fluctuation of the remaining DERs of the multiple DERs, e.g., by a rate matching algorithm and / or a first control scheme as described above, and the multiple DER controllers are configured to coordinate the multiple DERs to inject current into the grid by executing instructions at each of the multiple DER controllers, e.g., by matching a voltage of the one of the multiple DERs with a voltage of the remaining DERs of the multiple DERs, e.g., by a grouping algorithm and / or a second control scheme as described above.

[0145] Although the embodiments of the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions, and alterations can be made therein without departing from the spirit and scope of the present disclosure as defined by the appended claims.

[0146] Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the processes, machines, manufacture, compositions, means, methods, and steps described herein. As one skilled in the art will readily appreciate from the present disclosure, any now existing or later developed processes, machines, manufacture, compositions, means, methods, or steps that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein can be utilized in accordance with the present disclosure. Accordingly, it is intended that the appended claims include within their scope such processes, machines, manufacture, compositions, means, methods, or steps.

Claims

1. Detecting a fault in a grid coupled to an electric power distribution network, the electric power distribution network including a distribution feeder connected to the grid via a grid interface, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and a reference point of applicability (RPA) adjacent the grid interface and associated with the plurality of DERs; responsive to detecting the fault, determining an error voltage at the RPA, converting the error voltage into an error signal, broadcasting the error signal to the plurality of DERs, and reducing the error voltage at the RPA by injecting a plurality of currents from the plurality of DERs into the distribution feeder based on the error signal.

2. converting the error voltage into the error signal; separating, in the RPA, a positive sequence component of the error voltage from a negative sequence component of the error voltage; and generating, in the RPA, the error signal including a first component based on the positive sequence component and a second component based on both the positive sequence component and the negative sequence component.

3. the first component comprises a value indicative of an amplitude rise requirement of the grid during the fault; The method of claim 2 , wherein the second component comprises a value indicative of a voltage imbalance in the electrical grid during the fault.

4. Reducing the error voltage in the RPA increasing a voltage of the grid by applying a positive sequence current injection control scheme to the plurality of DERs based on the first component; and 4. The method of claim 3, comprising at least one of: mitigating an unbalanced voltage on the power grid by applying a negative sequence current injection control scheme to the plurality of DERs based on the second component.

5. Detecting the fault in the grid 2. The method of claim 1, comprising detecting an unbalance fault in at least one of three phases of the grid, wherein reducing the error voltage at the RPA comprises determining the plurality of currents to be injected by applying a dynamic voltage support (DVS) control scheme to the plurality of DERs, and wherein applying the DVS control scheme comprises increasing a voltage of a faulted phase of the plurality of DERs by injecting the plurality of currents into the distribution feeder, and mitigating an unbalance voltage of a non-faulted phase of the plurality of DERs.

6. the faulty and non-faulty phases of the plurality of DERs are configured to operate in modes including a continuous operation mode, a forced operation mode, a pause mode, and a trip mode; increasing the voltage of the faulty phase of the plurality of DERs includes forcing the faulty phase to leave the suspended mode and enter the forced operating mode; 6. The method of claim 5, wherein mitigating the unbalanced voltages of the non-faulted phases of the plurality of DERs comprises forcing the non-faulted phases to leave the forced mode of operation and enter the continuous mode of operation.

7. 7. The method of claim 6, further comprising: preventing the faulted and non-faulted phases of the plurality of DERs from entering the trip mode by increasing the voltage of the faulted phases of the plurality of DERs and mitigating the unbalanced voltages of the non-faulted phases of the plurality of DERs.

8. Reducing the error voltage in the RPA coordinating the plurality of DERs to inject current into the grid based on the error signal, where coordinating the plurality of DERs includes matching a current variation of one DER of the plurality of DERs with a current variation of remaining DERs of the plurality of DERs; coordinating the plurality of DERs to inject current into the grid based on the error signal, where coordinating the plurality of DERs matches a voltage of a DER of the plurality of DERs with a voltage of a remaining DER of the plurality of DERs; 2. The method of claim 1, further comprising: applying a distributed target tracking control scheme to the plurality of DERs, the applying of the distributed target tracking control scheme comprising at least one of determining the plurality of currents injected under the distributed target tracking control scheme by causing communication between the plurality of DERs to coordinate currents injected by each of the plurality of DERs.

9. broadcasting the error signal to the plurality of DERs; 2. The method of claim 1, comprising: broadcasting the error signal to a first DER of the plurality of DERs, the first DER being directly coupled to the RPA; and forwarding the error signal from the first DER of the plurality of DERs to a second DER, the second DER being indirectly coupled to the RPA.

10. an electric grid comprising: a distribution feeder coupled to a grid and connected to the grid through a grid interface; a plurality of distributed energy resources (DERs) coupled to the distribution feeder; and a reference point of applicability (RPA) adjacent to the grid interface; a programmable controller coupled to the RPA for detecting a failure of the grid; an RPA controller configured to, in response to detecting the fault, determine an error voltage across the RPA and convert the error voltage into an error signal; a first communication device coupled to the RPA controller and configured to broadcast the error signal to the plurality of DERs; a plurality of DER controllers coupled to respective DERs of the plurality of DERs and configured by programming to control the respective DERs to reduce the error voltage at the RPA by injecting a plurality of currents into the distribution feeder based on the error signal.

11. the RPA controller is configured by the program to separate a positive sequence component of the error voltage from a negative sequence component of the error voltage and generate an error signal including a first component based on the positive sequence component and a second component based on both the positive sequence component and the negative sequence component; the first component comprises a value indicative of an amplitude rise requirement of the grid during the fault; The system of claim 10 , wherein the second component comprises a value indicative of a voltage imbalance in the electrical grid during the fault.

12. based on the first component, the plurality of DER controllers are configured by the programming to increase a voltage of the grid by applying a positive sequence current injection control scheme to the plurality of DERs; 12. The system of claim 11, wherein based on the second component, the plurality of DER controllers are configured by the programming to mitigate unbalanced voltages on the power distribution grid by applying a negative sequence current injection control scheme to the plurality of DERs.

13. 11. The system of claim 10, wherein the plurality of DER controllers are configured by the programming to control the plurality of DERs to increase voltages of faulted phases of the plurality of DERs and mitigate unbalanced voltages of non-faulted phases of the plurality of DERs.

14. Reducing the error voltage in the RPA the plurality of DER controllers are configured by the programming to coordinate the plurality of DERs to inject current into the grid by matching a current fluctuation of one DER of the plurality of DERs with a current fluctuation of the remaining DERs of the plurality of DERs; and 11. The system of claim 10, wherein the plurality of DER controllers are configured by the programming to at least one of coordinate the plurality of DERs to inject current into the power grid by matching a voltage of one DER of the plurality of DERs with a voltage of remaining DERs of the plurality of DERs.

15. a second communications device coupled to a first DER of the plurality of DERs, the first DER being directly coupled to the RPA; and a third communications device coupled to a second DER of the plurality of DERs, the second DER being indirectly coupled to the RPA; The system of claim 10 , wherein the second communication device is configured to receive the error signal broadcast by the first communication device and forward the error signal to the third communication device.

16. 11. The system of claim 10, further comprising a plurality of inverters, one of the plurality of inverters coupled between each of the plurality of DERs and the distribution feeder, and configured to generate the plurality of currents injected into the distribution feeder based on the error signal.

17. A Reference Point of Applicability (RPA) controller, comprising: a controller coupled to an electric grid comprising a distribution feeder connected to a grid via a grid interface, a plurality of distributed energy resources (DERs) coupled to the distribution feeder, and an RPA adjacent to the grid interface, the controller being directly coupled to the RPA, the controller comprising: a memory for storing a program including instructions; a processor coupled to the memory and configured to execute the program; a first communications device coupled to the processor; An applicability reference point (RPA) controller, wherein the instructions, when executed, are configured to cause the processor to detect a fault in a grid coupled to the electrical grid, and in response to detecting the fault, determine an error voltage at the RPA, convert the error voltage into an error signal, and transmit the error signal to the first communication device, wherein the first communication device is configured to broadcast the error signal to the plurality of DERs.

18. a first DER of the plurality of DERs is coupled to a second communication device, the first DER being directly coupled to the RPA; A second DER of the plurality of DERs is coupled to a third communication device, the second DER being indirectly coupled to the RPA, the second communication device being configured to receive the error signal broadcast by the first communication device and forward the error signal to the third communication device; 20. The RPA controller of claim 17, wherein the plurality of DERs are coupled to a plurality of DER controllers, and based on the error signal, the plurality of DER controllers are configured, via programming, to control respective DERs to reduce the error voltage at the RPA by injecting a plurality of currents into the distribution feeder.

19. the processor is configured by the program to separate a positive sequence component of the error voltage from a negative sequence component of the error voltage to generate an error signal including a first component based on the positive sequence component and a second component based on both the positive sequence component and the negative sequence component; the first component comprises a value indicative of an amplitude rise requirement of the grid during the fault; 20. The RPA controller of claim 17, wherein the second component comprises a value indicative of a voltage imbalance in the electrical grid during the fault.

20. An electric grid comprising: a distribution feeder connected to a grid via a grid interface; a plurality of distributed energy resources (DERs) coupled to the distribution feeder; and a plurality of DER controllers coupled to a distribution grid having a reference point of applicability (RPA) adjacent the grid interface, each of the plurality of DER controllers coupled to a corresponding DER of the plurality of DERs, each of the plurality of DER controllers: a memory for storing a program including instructions; a processor coupled to the memory and configured to execute the program; a communication device coupled to the processor; 11. A distributed energy resource (DER) control system, wherein the instructions, when executed in each of the plurality of DER controllers, cause the plurality of DER controllers to receive an error signal from an RPA controller directly coupled to the RPA and to send control signals to the plurality of DERs, one of the control signals being sent to one of the plurality of DERs, the control signal received by the plurality of DERs being configured to reduce an error voltage at the RPA by injecting a plurality of currents from the plurality of DERs into the distribution feeder.

21. the error voltage includes a positive sequence component and a negative sequence component, the error signal includes a first component based on the positive sequence component and a second component based on both the positive sequence component and the negative sequence component; the first component comprises a value indicative of an amplitude rise requirement of the electrical grid during a fault in a grid coupled to the electrical grid; 21. The DER control system of claim 20, wherein the second component comprises a value indicative of a voltage imbalance on the grid during the fault.

22. Reducing the error voltage in the RPA based on the first component, the plurality of DER controllers are configured to increase a voltage of the grid by applying a positive sequence current injection control scheme to the plurality of DERs by executing the instructions in each of the plurality of DER controllers; and 22. The DER control system of claim 21, further comprising at least one of: applying a negative sequence current injection control scheme to the plurality of DERs by the plurality of DER controllers executing the instructions in each of the plurality of DER controllers based on the second component to mitigate an unbalanced voltage on the power distribution network.

23. Reducing the error voltage in the RPA 21. The DER control system of claim 20, comprising at least one of: the plurality of DER controllers are configured to coordinate the plurality of DERs to inject current into the grid by matching a current fluctuation of one of the plurality of DERs with a current fluctuation of the remaining DERs of the plurality of DERs by executing the instructions in each of the plurality of DER controllers; and the plurality of DER controllers are configured to coordinate the plurality of DERs to inject current into the grid by matching a voltage of one of the plurality of DERs with a voltage of the remaining DERs of the plurality of DERs by executing the instructions in each of the plurality of DER controllers.

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