Power distribution system fault control apparatus and method

Abstract

A method includes detecting a fault in an electrical grid coupled to a distribution 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) associated with the plurality of DERs; and in response to detecting the fault, determining an error voltage at the RPA, converting the error voltage to an error signal, broadcasting the error signal to the plurality of DERs, and based on the error signal, reducing the error voltage at the RPA by injecting a plurality of currents from the plurality of DERs into the distribution feeder.

Description

[0001] This invention was developed with the support of the U.S. government under Contract No. DE-OE0000896, awarded by the Department of Energy. The U.S. government holds certain rights to this invention. Technical Field

[0002] The present invention generally relates to fault control devices and methods for controlling distributed energy resources in power distribution systems. Background Technology

[0003] The power grid includes conventional power plants such as coal-fired power plants, gas-fired power plants, and nuclear power plants, as well as distributed energy resources (DERs). Conventional power plants are centralized and require the transmission of electricity over long distances. DERs are small, modular, distributed, grid-connected energy systems located in or near energy-consuming loads. DERs and loads form a distributed power network coupled to the power grid.

[0004] During operation, faults may occur at the power grid. Power grid faults can reduce the voltage of the distribution network and cause sensitive tripping of the DER (Distribution Grid Controller). A tripped DER results in significant losses of energy supply over a large geographical area. Unexpected energy supply losses over short periods can lead to more complex consequences, such as overload of the grid's transmission lines and fault-induced delayed voltage recovery (FIDVR). FIDVR refers to the unexpected delay in the voltage returning to its nominal value after a fault is properly cleared. After a fault is cleared, the voltage of the distribution network remains at a significantly reduced level for several seconds before slowly recovering to an acceptable level. To overcome this grid reliability issue, the DER is required to implement fault ride-through functionality.

[0005] Fault ride-through is a requirement designed to prevent the distribution network (DER) from entering tripping mode, enabling the DER to remain connected during faults. DER participation in Dynamic Voltage Support (DVS) is also necessary. Advanced DVS functionality has become possible with recent unprecedented advancements in the flexible control of power converters in the DER. However, effective methods for utilizing this flexibility in a coordinated manner remain an open area of ​​research. Therefore, improvements to DVS control in distribution networks are needed to meet the evolving requirements of power systems. Summary of the Invention

[0006] According to an embodiment, a method includes: detecting a fault in a power grid coupled to a distribution network, the distribution network including a distribution feeder, a plurality of distributed energy sources (DERs) coupled to the distribution feeder, and an applicability reference point (RPA) associated with the plurality of DERs; and 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 based on the error signal by injecting a plurality of currents from the plurality of DERs into the distribution feeder.

[0007] According to another embodiment, a system includes: a distribution network coupled to a power grid, the distribution network including distribution feeders, a plurality of distributed energy sources (DERs) coupled to the distribution feeders, and an applicability reference point (RPA); an RPA controller coupled to the RPA, the RPA controller being programmed to detect faults in the power grid and, in response to detecting a fault, determining an error voltage at the RPA and converting the error voltage into an error signal; a first communication device coupled to the RPA controller, the first communication device being configured to broadcast the error signal to the plurality of DERs; and a plurality of DER controllers coupled to corresponding DERs among the plurality of DERs, wherein, based on the error signal, the plurality of DER controllers are programmed to control the corresponding DERs to reduce the error voltage at the RPA by injecting a plurality of currents into the distribution feeders.

[0008] According to another embodiment, an Applicability Reference Point (RPA) controller includes: a control device coupled to a distribution network, the distribution network including distribution feeders, multiple distributed energy sources (DERs) coupled to the distribution feeders, and the RPA, wherein the control device is directly coupled to the RPA, the control device including: 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, wherein, when the instructions are executed, the processor detects a fault in the grid coupled to the distribution network, and in response to detecting the fault, determines an error voltage at the RPA, converts the error voltage into an error signal, and sends the error signal to the first communication device, wherein the first communication device is configured to broadcast the error signal to the multiple DERs.

[0009] According to another embodiment, a distributed energy source (DER) control system includes: a plurality of DER controllers coupled to a distribution network, the distribution network including distribution feeders, a plurality of distributed energy sources (DERs) coupled to the distribution feeders, and an applicability reference point (RPA), wherein each of the plurality of DER controllers is coupled to a corresponding DER in 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, wherein when the instructions are executed in each of the plurality of DER controllers, the plurality of DER controllers cause the plurality of DER controllers to receive error signals from an RPA controller directly coupled to the RPA, send control signals to the plurality of DERs, one of the control signals being sent to one of the plurality of DERs, and wherein the control signals received by the plurality of DERs are configured to reduce the error voltage at the RPA by injecting a plurality of currents from the plurality of DERs into the distribution feeder.

[0010] The features and technical advantages of this disclosure have been outlined quite extensively above to facilitate a better understanding of the detailed description disclosed below. Additional features and advantages of this disclosure, which form the subject matter of the claims, will be described below. Those skilled in the art will understand that the disclosed concepts and specific embodiments can be readily used as the basis for modifying or designing other structures or processes for carrying out the same purpose of this disclosure. Those skilled in the art will also understand that these equivalent constructions do not depart from the spirit and scope of this disclosure as set forth in the appended claims. Attached Figure Description

[0011] To gain a more complete understanding of this disclosure and its advantages, the following description is now taken in conjunction with the accompanying drawings, in which:

[0012] Figure 1 A block diagram of a distribution network according to various embodiments of the present disclosure is shown;

[0013] Figure 2 The present disclosure illustrates various embodiments of a distribution network DER configured to operate in various operating modes under unbalanced faults;

[0014] Figure 3 Various embodiments according to this disclosure are shown. Figure 1 The simplified model of the DER and distribution feeder is shown in the figure;

[0015] Figure 4 A control system implementing a decoupled dual synchronous reference coordinate system PLL (DDSRF-PLL) control scheme according to various embodiments of the present disclosure is shown;

[0016] Figure 5 Various embodiments according to this disclosure are shown. Figure 1 The block diagram of the RPA controller shown in the figure;

[0017] Figure 6 Various embodiments according to this disclosure are shown. Figure 1 The block diagram of the DER controller is shown below;

[0018] Figure 7 A control system implementing a distributed cooperative dynamic voltage support control scheme according to various embodiments of the present disclosure is shown;

[0019] Figure 8 Various embodiments of the present disclosure are illustrated for controlling Figure 1 The flowchart shown is a method for power distribution networks;

[0020] Figure 9 Block diagrams of systems according to various embodiments of the present disclosure are shown;

[0021] Figure 10 A block diagram of an RPA controller according to various embodiments of the present disclosure is shown;

[0022] Figure 11 Block diagrams of DER control systems according to various embodiments of the present disclosure are shown; and

[0023] Figure 12 A block diagram of a processing system according to various embodiments of the present disclosure is shown.

[0024] Unless otherwise stated, corresponding numbers and symbols in the various figures generally indicate corresponding parts. The figures are drawn to clearly illustrate relevant aspects of the various embodiments, and the figures are not necessarily drawn to scale. Detailed Implementation

[0025] The arrangement and use of the presently preferred embodiments are discussed in detail below. However, it should be understood that this disclosure provides many applicable inventive concepts that can be implemented in various specific contexts. The specific embodiments discussed are merely illustrative of specific ways of arranging and using this disclosure and do not limit the scope of this disclosure.

[0026] This disclosure will be described in a specific context with regard to preferred embodiments, namely, fault control apparatus and methods for controlling distributed energy sources in a distributed power system. However, the invention can also be applied to various power systems. Hereinafter, various embodiments will be described in detail with reference to the accompanying drawings.

[0027] Figure 1 A block diagram of a distribution network according to various embodiments of the present disclosure is shown. Distribution network 100 is coupled to grid 110. Distribution network 100 includes distribution feeder 125. Distribution feeder 125 is coupled to the distribution bus of grid 110 via grid interface 105. Distribution network 100 also includes a plurality of distributed energy sources (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.

[0028] DER 122, 124, and 126 are coupled to distribution feeder 125. For example... Figure 1 As shown, each DER is connected to the distribution feeder 125 via a connection point (POC). Figure 1 As shown, DER 122 is connected to distribution feeder 125 via POC 152. DER 124 is connected to distribution feeder 125 via POC 154. DER 126 is connected to distribution feeder 125 via POC 156. The following will refer to... Figure 3 Describe the detailed structure and operating principle of the DER. Each DER is equipped with a DER controller. For example... Figure 1As shown, DER controller 132 is coupled to DER 122. DER controller 134 is coupled to DER 124. DER controller 136 is coupled to DER 126. The following will refer to... Figure 6 Describe the detailed structure and operating principle of the DER controller.

[0029] The distribution network 100 also includes an Applicability Reference Point (RPA) 107 and an RPA controller 120 coupled to the RPA 107. In IEEE 1547, the Applicability Reference Point (RPA) is defined by the characteristics of the DER circuit, specifically, the aggregated DER capacity and input / output. It can be located at the DER termination or at a point where several DERs are connected to the grid. Regarding... Figure 1 RPA 157 is the connection point between any of DER122, 124, ..., 126 and the power grid 110. RPA 107 may be adjacent to the power grid interface 105. RPA controller 120 is configured to detect faults in the power grid 110. In response to detecting a fault, RPA controller 120 is configured to determine the error voltage at RPA 107 and convert the error voltage into an error signal. Reference will be made below. Figure 5 Describe the detailed structure and operating principle of the RPA controller 120.

[0030] The distribution network 100 also includes a plurality of loads 142, 144, and 146 coupled to the distribution feeder 125. In some embodiments, the loads 142, 144, and 146 may be residential loads, rotating loads (e.g., induction motors), or any combination thereof.

[0031] During operation, faults such as imbalance faults may occur in power grid 110. RPA controller 120 is configured to determine the error voltage at the RPA and convert it into an error signal. At the RPA, RPA controller 120 also separates the positive-sequence component and the negative-sequence component of the error voltage and generates an error signal comprising a first component based on the positive-sequence component and a second component based on both the positive and negative-sequence components. The first component of the error signal includes a value indicating the amplitude increase requirement of distribution network 100 during the fault. The second component of the error signal includes a value indicating the voltage imbalance of distribution network 100 during the fault. In the context of this invention, the first component may be a positive voltage sequence error, and the second component may be a negative voltage sequence error.

[0032] RPA controller 120 broadcasts error signals to multiple DERs. Specifically, RPA controller 120 broadcasts error signals to DERs directly coupled to the RPA via appropriate communication links. DERs directly coupled to the RPA send error signals to DERs indirectly coupled to the RPA.

[0033] In distribution network 100, based on the first component of the error signal, the voltage of the distribution network is increased by applying a positive-sequence current injection control scheme to multiple DERs. Based on the second component of the error signal, the unbalanced voltage of the distribution network can be alleviated by applying a negative-sequence current injection control scheme to multiple DERs.

[0034] A fault is an unbalanced fault occurring in at least one of the three phases of the power grid. The phase in which the fault occurs is the faulty phase. The phases in which the fault does not occur are the non-faulty phases. Dynamic Voltage Support (DVS) control schemes are applied to multiple distribution lines (DERs) to reduce the error voltage at the RPA (Reverse Voltage Arrangement). Applying DVS control involves injecting multiple currents into the distribution feeders to boost the voltage of the faulty phases of multiple DERs and alleviate the unbalanced voltage of the non-faulty phases of multiple DERs.

[0035] In distribution networks, distributed target tracking (DST) schemes are applied to multiple distribution current generators (DERs). Applying DST involves coordinating the injection of current from each DER to determine the multiple currents to be injected under the DST scheme by communicating between the DERs. Based on an error signal, the multiple DERs are coordinated to inject current into the distribution network. This can be achieved through speed matching algorithms, such as coordinating multiple DERs by aligning the current change of one DER with the current changes of the remaining DERs. It can also be achieved through stack-centering algorithms, such as coordinating the voltage of one DER with the voltages of the remaining DERs.

[0036] Figure 2 The diagram illustrates various embodiments of the distribution network DER configured to operate in various operating modes under unbalanced faults. First operating diagram 202 shows the distribution network DER operating in four different modes in response to faults during a cross-passage under a conventional control scheme. Second operating diagram 204 shows the distribution network DER operating in four different modes in response to faults during a cross-passage under the control scheme of this disclosure. Third operating diagram 203 shows a comparison between the phase voltage response of the DER under the conventional control scheme and the phase voltage response of the DER under the control scheme of this disclosure.

[0037] The horizontal axis of the first operation diagram 202, the second operation diagram 204, and the third operation diagram 203 represents the time interval. The unit is seconds. The vertical axis of the first operation diagram 202, the second operation diagram 204, and the third operation diagram 203 represents the voltage of the DER. The voltage is expressed in unit systems. A unit system is a fractional expression of the number of systems as a defined basic unit. The base value of the voltage is the rated voltage of the inverter coupled between the DER and the distribution feeder. The voltage of the DER can also be referred to as the applicable voltage.

[0038] As shown in the first operating diagram 202 and the second operating diagram 204, the DER is designed to operate in four different modes during ride-through in response to abnormal voltage conditions (e.g., voltage disturbances following a fault in the power grid). Each DER can be in one of four operating modes (i.e., continuous operation mode, forced operation mode, momentary stop mode, and trip mode). The trip mode can alternatively be referred to as the shall trip mode.

[0039] In continuous operation mode, the DER remains operational and continues to deliver available active power at least as large as its pre-disturbance level. If the lease phase voltage is lower than the nominal value, the delivered power can be distributed proportionally per unit voltage of the lease phase voltage. In other words, when the applicable voltage is within the specified range (e.g., ... Figure 2 As shown, DER is in a normal state when the value ranges from 0.9 to 1.1.

[0040] In forced operation mode, within specified amplitude and duration limits, the DER is configured to withstand and support the grid until the voltage disturbance ceases. Figure 2 As shown, when the applicable voltage is in the range of 0.5 to 0.9, the DER is configured to operate in forced operation mode for a duration limit of 20 seconds. Once the applicable voltage returns to the voltage range of continuous operation mode, the DER can immediately return to normal operation. On the other hand, after the duration limit (20 seconds) expires, the DER can leave the forced operation mode and enter the trip mode.

[0041] In the momentary stop mode, the DER temporarily stops supplying power to the distribution network. Once the applicable voltage returns to the voltage range of the continuous operation mode, the DER can immediately resume normal operation. Alternatively, the DER can enter tripping mode after the duration limit expires. Figure 2 As shown, when the applicable voltage is in the range of 1.2 to 1.3, the duration is limited to 0.1 seconds. Similarly, when the applicable voltage is in the range of 1.1 to 1.2, the duration is limited to 20 seconds. When the applicable voltage is in the range of 0 to 0.5, the duration is limited to 1 second.

[0042] In trip operation mode, the DER stops supplying power to the distribution network. Alternatively, the DER can be disconnected from the distribution network.

[0043] In operation, an imbalance fault occurs in at least one of the three phases of the power grid. For example, the fault occurs at phase A of the power grid. Due to this fault, phase A is the faulty phase. The other two phases (phases B and C) are non-faulty phases. First operating diagram 202 shows that overvoltages may be introduced into the phases of the DER under conventional control schemes. In response to the fault, the voltages of the three phases of the DER are increased by injecting current into the distribution network. The voltage of the faulty phase (phase A) increases from approximately 0.8 to approximately 0.95. The voltage of one non-faulty phase (phase B) increases from approximately 0.95 to approximately 1.05. The voltage of another non-faulty phase (phase C) increases from approximately 0.95 to approximately 1.15. Phase C introduces an overvoltage and enters a momentary shutdown mode.

[0044] Second operating diagram 204 shows the three phases of the DER remaining in either forced operation mode or continuous operation mode under the control scheme of this disclosure. In response to an unbalanced fault, a dynamic voltage support (DVS) control scheme is applied to multiple DERs. Multiple DERs inject multiple currents into the distribution feeder to reduce the error voltage at the RPA. More specifically, by injecting multiple currents into the distribution feeder, the voltage of the faulted phase of the multiple DERs is boosted, and the unbalanced voltage of the non-faulted phases of the multiple DERs can be mitigated. Boosting the voltage of the faulted phase and mitigating the unbalanced voltage of the non-faulted phases will be further discussed below with reference to equations (11) to (13).

[0045] like Figure 2 As shown, both the faulty and non-faulty phases of multiple DERs are configured to operate in modes including continuous operation mode, forced operation mode, momentary stop mode, and trip mode, as shown in the second operation diagram 204. As shown by dashed line 206, increasing the voltage of the faulty phase of the multiple DERs includes forcing the faulty phase to leave the momentary stop mode and enter the forced operation mode. As shown by dashed line 208, 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. By increasing the voltage of the faulty phases of the multiple DERs and mitigating the unbalanced voltage of the non-faulty phases of the multiple DERs, the control scheme of this disclosure can prevent the faulty and non-faulty phases of the multiple DERs from entering the trip mode.

[0046] As shown in the second operation diagram 204, a potentially advantageous feature of the control scheme of this disclosure is that mitigating the unbalanced voltage of the non-faulty phases of multiple DERs helps reduce the likelihood of introducing overvoltages in the non-faulty phases, thereby reducing the risk of overshoot.

[0047] The third operating diagram 203 shows six voltage curves. Curve 231 represents the voltage response of the faulty phase (e.g., phase A) after a fault occurs and DER is controlled under a conventional control scheme. Curve 232 represents the voltage response of the non-faulty phase (e.g., phase B) after a fault occurs and DER is controlled under a conventional control scheme. Curve 233 represents the voltage response of another non-faulty phase (e.g., phase C) after a fault occurs and DER is controlled under a conventional control scheme. Curve 234 represents the voltage response of the faulty phase (e.g., phase A) after a fault occurs and DER is controlled under the control scheme of this disclosure. Curve 235 represents the voltage response of the non-faulty phase (e.g., phase B) after a fault occurs and DER is controlled under the control scheme of this disclosure. Curve 236 represents the voltage response of another non-faulty phase (e.g., phase C) after a fault occurs and DER is controlled under the control scheme of this disclosure. Figure 2 As shown, under the conventional control scheme, the voltage of a non-faulty phase (e.g., phase C) rises to 1.1. As shown in the first operation diagram 202, phase C leaves the continuous operation mode and enters the forced stop mode. In contrast, under the control scheme of this disclosure, the voltage of the non-faulty phases (e.g., phases C and B) is less than 1.1. Furthermore, the fourth curve 234 and the first curve 231 indicate that the recovery speed of the faulty phase is faster under the control scheme of this disclosure than under the conventional control scheme.

[0048] Figure 3 Various embodiments according to this disclosure are shown. Figure 1 The simplified model of the DER and distribution feeder is shown below. 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 can be implemented as a PV panel. The grid-connected VSC can 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 network at the POC. The distribution feeder is simulated as a series resistor R. L and series impedance Z L A star-delta transformer is placed between the POC and the distribution feeder. A POC voltage sensor is used to detect the voltage (V) at the POC. POC Current sensors are used to detect the current flowing through power distribution feeders (i). g A grid voltage sensor is used to detect the voltage (V) of the power grid. grid ).

[0049] In operation, when an imbalance fault occurs in the power grid, positive-sequence, negative-sequence, and zero-sequence components dominate. The resulting voltage amplitude may differ depending on the fault type. For example, during a 2L-G fault, no significant voltage effect was observed on the non-faulty phases. If voltage support is enabled solely by the positive-sequence component designed to support the faulty phase, the amplitude of the non-faulty phases will exceed a predetermined threshold. To avoid this outcome, voltage support can include both positive-sequence and negative-sequence support simultaneously.

[0050] exist Figure 3 In, POC(V) POC ) and grid voltage (V G The mathematical relationship between them is:

[0051]

[0052] In equation (1), R is the equivalent resistance of the power distribution feeder. L is the equivalent inductance of the power distribution feeder.

[0053] This power converter (e.g., VSC 304) is able to inject positive (I0) + ) and negative (I) - Sequence current. By using the amplitude of the symmetrical component, the positive and negative sequence information can be represented as:

[0054]

[0055]

[0056] Equations (2.1) and (2.2) can be reformulated based on the impedance of the distribution network. If the network impedance is highly inductive, the resistive part of the equations can be ignored. Equations (2.1) and (2.2) can be reformulated as follows:

[0057]

[0058]

[0059] Equations (3.1) and (3.2) show that positive-sequence voltage can be boosted by injecting positive-sequence reactive current into a grid dominated by inductive impedance. On the other hand, injecting negative-sequence reactive current helps alleviate voltage imbalance. Equations (3.1) and (3.2) show that grid voltage support can be achieved in two ways. If only positive-sequence reactive power is injected under imbalance fault conditions, the POC voltage will be boosted equally in each phase compared to the grid voltage. The imbalance voltage at the POC can be compensated by injecting negative-sequence reactive power.

[0060] Imbalance can be mitigated by reducing the voltage amplitude difference between the faulty and non-faulty phases. As a result of mitigating the voltage imbalance, the non-faulty phases can avoid voltage overshoot.

[0061] For low-voltage power grids, equations (2.1) and (2.2) can also be restated because the grid impedance is more resistive. These equations can be restated by neglecting inductive components. Equations (2.1) and (2.2) can be restated as follows:

[0062]

[0063]

[0064] Equations (4.1) and (4.2) show that injecting positive-sequence active power can increase the positive-sequence voltage at the POC, while reducing the amount of negative-sequence active power helps to alleviate the voltage imbalance at the POC of the resistive network.

[0065] To control the power converter (e.g., VSC 304) during unbalanced conditions, equation (1) can be expressed in a dual synchronous reference frame (DSRF). In the stationary reference frame (αβ), equation (1) can be expressed as:

[0066]

[0067] During an unbalanced fault, the voltage variable (V) in the stationary reference coordinate system (αβ) can be decomposed into positive-sequence and negative-sequence components in the (dq) coordinate system:

[0068]

[0069] In equation (6), V αβ The natural quantities abc of V are calculated as follows:

[0070] V αβ =v a e j0 +v b e j2π / 3 +v c e -j2π / 3 (7)

[0071] The decomposed sequence model in the (dq) coordinate system can be obtained by substituting (6) into (5):

[0072]

[0073]

[0074]

[0075]

[0076] In equations (8.1), (8.2), (9.1), and (9.2), Lf is the equivalent inductance of the distribution feeder. Rf is the equivalent resistance of the distribution feeder. For L... f >>R f Conditions for positive-sequence magnitude enhancement and negative-sequence imbalance mitigation can be achieved by controlling... and To directly control it. On the other hand, based on the converter's current limit, it can generate... To meet the requirements for active power delivery.

[0077] In this disclosure, positive-sequence current injection for coordinating voltage magnitude increase and negative-sequence current injection for coordinating unbalanced voltage relief are controlled. and The system addresses the two-dimensional positive-sequence magnitude boosting and negative-sequence imbalance mitigation objectives. To achieve proper power converter control, a phase-locked loop (PLL) algorithm is employed to separately control the positive and negative-sequence components.

[0078] A decoupled dual synchronous reference coordinate system PLL (DDSRF-PLL) control scheme is used to control the positive and negative sequence components separately. DDSRF-PLL is well known in the art and will not be discussed in detail here. After applying the DDSRF-PLL control scheme, the control equation for the power converter (e.g., VSC 304) can be expressed as:

[0079]

[0080]

[0081]

[0082]

[0083] The control equation above is used to control the power converter. This control equation can be implemented in the DER controller. See below for reference. Figure 4 A detailed implementation of the above governing equations is described.

[0084] Following a grid fault, the ride-through requirements include a two-dimensional unbalanced voltage recovery scheme. The first aspect of this scheme is coordinating a positive-sequence current injection for voltage magnitude boost. The second aspect is coordinating a negative-sequence current injection for voltage imbalance mitigation. The requirement at the RPA is broadcast to the distribution network via an error signal. Each power converter (e.g., VSC 304) can interpret this error signal, cooperate with other DERs, and locally generate incremental current injections over a period of time. The voltage change at the RPA can be represented as:

[0085] Δv+，- =Δi Q +，- .t (11)

[0086] Based on the above equations (8.1), (8.2), (9.1) and (9.2), the Δi of equation (11) Q It can be represented as and It is used as the current reference for the power converter. Note that Δi in equation (11) Q Only include I q The distribution network path is an inductive path. Reactive power can boost the voltage of the faulty phase. Therefore, the current I can be ignored. d It should also be noted that if the distribution network has resistive paths, active power can boost the voltage of the faulty phase. q It should be I d Replacement. Furthermore, if the path contains a combination of resistive and inductive elements, then I should be included. q and I d Both.

[0087] The error signal broadcast by RPA includes a first component and a second component. The first component includes a value indicating the amplitude increase requirement of the distribution network during the fault. The second component includes a value indicating the voltage imbalance of the distribution network during the fault. The first component can be expressed as:

[0088]

[0089] At RPA, the RPA voltage (V) RPA The positive-order component (V) RPA + ) and the negative sequence component of the RPA voltage (V RPA - Separation. Equation (12) indicates that the first component of the error signal is based on the positive sequence component of the RPA voltage.

[0090] The second component of the error signal can be expressed as:

[0091]

[0092] Equation (13) indicates that the second component of the error signal is based on both the positive and negative sequence components of the RPA voltage.

[0093] The RPA broadcasts the error signals shown in equations (12) and (13) to the DER of the distribution network. The DER uses the broadcast error signals to generate a current reference for controlling the corresponding power converters.

[0094] Figure 4A control system implementing a decoupled dual synchronous reference coordinate system PLL control scheme according to various embodiments of the present disclosure is shown. The control equations shown in equations (10.1), (10.2), (10.3), and (10.4) are implemented in each DER controller. For simplicity, Figure 4 Only the relevant parts of the DER controller are shown in the diagram. 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., the current and voltage of the inverter coupled to the DER controller). The DDSRF-PLL control scheme is used to process the current reference and the detected operating parameters and generate control signals to control the current injection into the inverter.

[0095] Figure 4 The DER controller shown includes a voltage conversion section 168. In the voltage conversion section 168, the three-phase measured voltage is supplied to a first conversion block 160, which converts V... POC The three-phase signals (line abc) are transformed into their corresponding signals in the dq synchronous reference coordinate system, as understood in the art.

[0096] The dq voltage signal is provided to DDSRF-PLL sequence extraction block 162, where the positive-sequence dq voltage V is calculated. dq + and negative dq voltage V dq - Positive sequence dq voltage V dq + These include positive-sequence DC and quadrature voltage components V, respectively. d + and V q + Negative sequence dq voltage V dq - These include negative-sequence DC and quadrature voltage components V, respectively. d - and V q - Furthermore, DDSRF-PLL sequence extraction block 162 is configured to generate φ + and φ - Signal. φ + and φ - The signals represent voltage V respectively. POC The positive and negative phase angles.

[0097] Inverter measurement current (i f The current and positive sequence phase angle φ are respectively provided to the second converter block 164 and the third converter block 166. + The second transformation block 164 is configured to generate a positive-sequence dq current i dq +Positive sequence dq current i dq + These include positive-sequence DC and quadrature current components i, respectively. d + and i q + Based on the measured current and negative sequence phase angle φ-, the third converter block 166 is configured to generate a negative sequence dq current i. dq + Negative sequence dq current i dq - These include negative-sequence DC and quadrature current components i, respectively. d - and i q - .

[0098] like Figure 4 As shown, the controller includes four current processing branches: positive sequence DC processing branch 191, positive sequence quadrature current processing branch 192, negative sequence DC processing branch 193, and negative sequence quadrature current processing branch 194.

[0099] In the positive sequence DC processing branch 191, the positive sequence DC i d + It is fed into summing unit 181. Summing unit 181 calculates the positive-sequence DC reference current i. d +* and positive sequence DC current i d + The difference between them. This difference can also be called the positive-sequence DC error. It should be noted that the positive-sequence direct reference current i... d +* It is generated based on the error signal broadcast by RPA.

[0100] like Figure 4 As shown, the positive-sequence DC error is fed to a proportional-integral (PI) controller 182. The output of the PI controller 182 is generated based on the sum and integral of the current error values. PI control is well known in the art and will not be discussed further. The output of the PI controller 182 is fed to a summing unit 183. Figure 4 As shown, the summing unit 183 also receives a first cross-coupled signal, which will be described below.

[0101] The first cross-coupled signal received by summing unit 183 is generated as follows: Positive-sequence quadrature current i q + The current is fed to multiplier 185, where the positive-sequence quadrature current is multiplied by ωL. The output of multiplier 185 is equal to i. q +×ωL. The output of multiplier 185 is provided as the first cross-coupled signal to summing unit 183. Summing unit 183 generates the positive-sequence direct reference voltage V. d +* .

[0102] In the positive sequence orthogonal current processing branch 192, the positive sequence orthogonal current i q + It is fed into summing unit 186. Summing unit 186 calculates the positive-sequence quadrature reference current i. q +* and positive sequence orthogonal current i q + The difference between them. This difference can also be referred to as the positive-sequence quadrature current error. It should be noted that the positive-sequence quadrature reference current i q +* It is generated based on the error signal broadcast by RPA.

[0103] like Figure 4 As shown, the positive-sequence quadrature current error is fed to the PI controller 187. The output of the PI controller 187 is generated based on the sum and integral of the current error values. The output of the PI controller 187 is fed to the summing unit 188. Figure 4 As shown, the summing unit 188 also receives the second cross-coupled signal.

[0104] The second cross-coupled signal received by summing unit 188 is generated as follows: Positive sequence DC current i d + The current is fed to multiplier 184, where the positive-sequence DC current is multiplied by ωL. The output of multiplier 184 is equal to i. d + ×ωL. The output of multiplier 184 is provided as a second cross-coupled signal to summing unit 188. Summing unit 188 generates a positive-sequence quadrature reference voltage V. q +* .

[0105] The outputs of summing units 183 and 188 are the positive-sequence DC and quadrature reference voltage V, respectively. d +* and V q +* They are fed to converter block 196, where the positive-sequence DC and quadrature reference voltages are converted into reference voltages in the abc system.

[0106] The negative-sequence DC processing branch 193 is similar to the positive-sequence DC 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. For example... Figure 4As shown, the outputs of the summing unit are the negative-sequence DC and the quadrature reference voltage V, respectively. d -* and V q -* They are fed to converter block 198, where negative-sequence DC and quadrature reference voltages are converted into reference voltages in the abc system.

[0107] The positive-sequence and negative-sequence reference voltages are combined at summing unit 197 to provide the reference voltage signal V. abc +* Reference voltage signal V abc +* It is provided to the pulse width modulation (PWM) controller to generate switching commands for the inverter. The PWM controller can be part of a digital signal processor (DSP).

[0108] Figure 5 Various embodiments according to this disclosure are shown. Figure 1 The block diagram of the RPA controller is shown below. Figure 5 As shown, the RPA controller 120 includes an analog-to-digital converter 502, a memory 504, a digital processor 506, and a communication device 508. For example... Figure 5 As shown, the analog-to-digital converter 502 is configured to receive voltage V. grid The voltage is converted into a digital signal suitable for the digital processor 506. Control instructions are stored in memory 504. The digital processor 506 loads the control instructions from memory 504. The control instructions are executed in the digital processor 506 to process the digital signal from the analog-to-digital converter 502. After the digital signal has been 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 indicating the amplitude increase requirement of the distribution network during a fault in the power grid. The second component includes a value indicating the voltage imbalance of the distribution network during a fault. The error signal is fed to communication device 508. Communication device 508 is configured to broadcast the error signal to the DER.

[0109] In some embodiments, the digital processor 506 is implemented as a high-speed processor, such as a DSP. The DSP enables digital control implementation of the control methods shown in equations (11) and (12). Figure 5 A control method that can be fully implemented in a digital processor is illustrated. This is merely an example and should not unduly limit the scope of the claims. Many variations, alternatives, and modifications will be recognized by those skilled in the art. For example, a portion of the control method can be implemented by any other suitable processing circuitry, such as logic circuitry, analog circuitry, etc.

[0110] Figure 6 Various embodiments according to this disclosure are shown. Figure 1 The block diagram of the DER controller is shown below. Figure 6 As shown, the DER controller 132 includes an analog-to-digital converter 602, a memory 604, a digital processor 606, and a communication device 608. For example... Figure 6 As shown, the analog-to-digital converter 602 is configured to receive multiple operating parameters, including the inverter's output voltage, POC voltage, and POC current. The analog-to-digital converter 602 converts the operating parameters into digital signals suitable for the digital processor 606. The communication device 608 is configured to receive an error signal broadcast by the RPA and feed the error signal to the digital processor 606.

[0111] 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 digital signals from analog-to-digital converter 502 and error signals from communication device 608. After the digital signals and error signals have been processed, digital processor 606 is configured to generate inverter control signals. Inverter control signals are used to control current injection from the DER associated with the DER controller.

[0112] Figure 7 A control system implementing a distributed cooperative dynamic voltage support (DCDVS) ​​control scheme according to various embodiments of the present disclosure is shown. Figure 1 The distribution network shown can be simulated as follows: Figure 7 The multi-agent system is shown. RPA is the primary agent 171. Primary agent 171 may also be referred to as the RPA agent or the main RPA agent. DER are agents 172 to 179 coupled to the primary RPA agent 171.

[0113] In operation, the RPA (agent 171) broadcasts error signals to DERs directly coupled to the RPA (e.g., agents 172, 173, 178, and 179). DERs directly coupled to the RPA send error signals to DERs indirectly coupled to the RPA (e.g., agents 174, 175, 176, and 177).

[0114] In operation, a distributed target tracking control scheme is applied to multiple DERs (agents 172 to 172). Applying the distributed target tracking control scheme involves coordinating the current to be injected under the distributed target tracking control scheme by communicating between the DERs (agents 172 to 172) to coordinate the current to be injected by each of the multiple DERs.

[0115] Agents communicate with each other to achieve a global goal. The global goal of each DER agent is to satisfy a request (e.g., an error signal) from the primary RPA agent. Each DER agent not only implements local response characteristics but also collaborates with other DER agents. This characteristic ensures that the agent has local autonomy while satisfying requests from the primary agent. The RPA (primary agent) can broadcast event-based requests (e.g., error signals after a failure has occurred) to network agents (DERs), requesting them to provide aggregated DCDVS support to implement a specific response at the RPA. This request is in the common interest of all network agents, as RPA connectivity is crucial for keeping the remaining agents online.

[0116] Figure 7 Agents (agents 172 to 179) form a cluster. Within the cluster, agents exhibit local interactions and collective movement to achieve a global goal. Agents can separate, recombine, and form highly ordered, rapidly converging centroids toward the goal. Agents (DERs) can achieve the global goal broadcast by the master agent (RPA) while interacting locally with other neighboring DERs. Three control schemes are employed to manage agent behavior.

[0117] The first control scheme is based on the cluster's speed-matching behavior. Agents attempt to adjust their speed (alignment) with their neighbors. This behavior helps avoid uncontrolled current injection (which could lead to overvoltage).

[0118] The second control scheme is based on the clustering behavior of the cluster. Each agent attempts to stay close to its neighbors (cohesion). This feature helps to maintain a smooth voltage distribution and avoid large differences on the feeders.

[0119] The third control scheme is based on cluster collision avoidance behavior. Agents keep away from colliding (disengaging) with their neighbors. This behavior does not necessarily need to be implemented in the power system domain, as the current injection of each DER can overlap.

[0120] In this disclosure, a first control scheme and a second control scheme are employed to control the DER. Under the first control scheme, multiple DERs are coordinated to inject current into the distribution network based on an error signal. Coordinating the multiple DERs includes aligning the current change of one DER with the current changes of the remaining DERs. In some embodiments, the remaining DERs are adjacent DERs. For example, DER( Figure 7 The current change of agent 174 shown is aligned with the current change of adjacent DERs (agents 172, 173 and 175).

[0121] Under the second control scheme, multiple DERs are coordinated to inject current into the distribution network based on the error signal. Coordinating multiple DERs involves aligning the voltage of one DER with the voltages of the remaining DERs.

[0122] Figure 7 The multi-agent system illustrated functions as a biological network. In this network, the most informed agents tend to modulate their speed with their information. For example, the most informed fish in a school of fish moves faster when they sense danger. Agents need to pay more attention to their fast-moving neighbors and assign them greater weight. When the DCDVS control scheme is applied to the multi-agent system, the behavior of the biological network can be modeled in two ways. The first approach is to correlate acceleration behavior with the observed severity of the fault. The closer an agent is to the fault, the faster it accelerates. The second approach is to consider whether an agent has direct communication with the RPA and can acquire information with less noise, while other agents learn operational models from their neighbors.

[0123] In noisy communication environments, agents possess self-organizing capabilities during and after failure conditions. Constraints and local interactions between DERs include global response patterns to ensure stability after a failure. DERs can adjust the topology in real time by adjusting the weights associated with links in response to the quality of the information received. DERs do not need to converge to the same equilibrium. Instead, the temporal and spatial diversity of data on the network is utilized to allow nodes a degree of individuality in evaluating and assessing the quality of their data.

[0124] During a fault, a grid disturbance occurs. If the RPA's voltage level transitions to a forced operation state (forced operation mode), the RPA broadcasts information including ε to the DER via an unknown network. unbalance and ε mag The error signal is used to track the error signal in the cluster to generate a reference value for controlling the power converters associated with the DER. Specifically, the power converters inject current based on the corresponding reference value.

[0125] According to well-known distributed target tracking theory, each agent is associated with an unknown target location. Agents track and evaluate unknown target locations using a known combine-then-adapt (CTA) strategy. This unknown location tracking method allows information to be received directly from RPA or any other informed agent in the network.

[0126] If any of the agents receives an adjustment signal such as an error signal, then the DER cooperates and according to Δv shown in equation (11). +,- =Δi Q +,-.t generates incremental current injection locally within a certain time period. Based on equations (8.1), (8.2), (9.1), and (9.2), Δi Q It can be represented as and Current reference. and This method is used to determine the current injection rate of the agent. It allows the agent to match the current injection rate to avoid unintentional voltage overshoot and to smooth voltage recovery.

[0127] Figure 8 Various embodiments of the present disclosure are illustrated for controlling Figure 1 The flowchart shown is a method for power distribution networks. Figure 8 The flowchart shown 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, additions, deletions, substitutions, rearrangements, and repetitions may be made. Figure 8 The steps are shown in the diagram.

[0128] The distribution network comprises multiple DERs coupled to distribution feeders. The distributed power network is coupled to the grid. The power supply of each DER is coupled to the distribution feeders via inverters. The distribution network also includes RPAs. An RPA is a node adjacent to the interface between the grid and the distribution network. When a fault occurs in the grid, the RPA can generate an error signal based on the detected voltage at the RPA node. The RPA is equipped with RPA communication equipment. Each DER is equipped with DER communication equipment. The RPA communication equipment is used to broadcast the error signal to multiple DERs via the corresponding DER communication equipment.

[0129] At step 802, a fault in the power grid is detected by the RPA. The RPA is associated with multiple DERs. This has been further described in the various embodiments above, such as in... Figures 2 to 4 middle.

[0130] At step 804, in response to a detected fault, the RPA is configured to determine an error voltage, convert the error voltage into an error signal, and broadcast the error signal to multiple DERs. Based on the error signal, multiple currents from the multiple DERs are injected into the distribution feeder to reduce the error voltage at the RPA. This has been further described in the various embodiments above, for example in... Figures 2 to 4 In step 804, a potentially advantageous feature is that, during a fault, the DER injects current into the distribution feeder based on an error signal. The injected current helps reduce the error voltage at the RPA, thereby maintaining the predetermined voltage distribution at the RPA.

[0131] Figure 9A block diagram of a system according to various embodiments of the present disclosure is shown. Distribution network 100 is coupled to grid 110. Distribution network 100 includes distribution feeder 125, a plurality of distributed energy sources (DERs) 122 to 126 coupled to distribution feeder 125, and applicability reference point (RPA) 121, and RPA controller 120 coupled to RPA 121. RPA controller 120 is programmed to detect faults in grid 110, such as reference to Figure 2 As described above. In response to a detected fault, the RPA controller 120 is programmed to determine the error voltage at RPA 121 and convert the error voltage into an error signal, such as a reference signal. Figure 3 The first communication device 123 is coupled to the RPA controller 120, for example, as described in reference. Figure 5 The first communication device 123 is configured to broadcast error signals, such as reference signals, to a plurality of DERs 122 to 126. Figure 5 As described above. Multiple DER controllers 132 to 136 are coupled to corresponding DERs in multiple DERs 122 to 126, for example, referencing... Figure 1 Based on the error signal, multiple DER controllers 132 to 136 are programmed to control the corresponding DER, thereby reducing the error voltage at RPA 121 by injecting multiple currents into the distribution feeder 125, for example, a reference. Figure 1 As stated above.

[0132] Figure 10 Block diagrams of RPA controllers according to various embodiments of the present disclosure are shown. The RPA controller includes control devices coupled to a distribution network. The distribution network includes distribution feeders, multiple distributed energy sources (DERs) coupled to the distribution feeders, and the RPA. The control devices are directly coupled to the RPA. Figure 10 As shown, the control device includes 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 respectively similar to... Figure 5 The diagram shows a digital processor and communication device. Processor 506 is configured to execute programs. When executed, these instructions cause processor 506 to detect faults in the power grid coupled to the distribution network, such as reference... Figure 2 In response to a detected fault, processor 506 determines the error voltage at the RPA, converts the error voltage into an error signal, and sends the error signal to the first communication device 508, such as a reference. Figures 2 to 4 The first communication device 508 is configured to broadcast error signals to multiple DERs, such as reference signals. Figures 5 to 6 As stated above.

[0133] Figure 11A block diagram of a DER control system according to various embodiments of the present disclosure is shown. The DER control system includes multiple DER controllers, such as... Figure 11 As shown. Multiple DER controllers are coupled to a distribution network, which includes distribution feeders, multiple DERs coupled to the distribution feeders, and RPAs. Each of the multiple DER controllers is coupled to a corresponding DER in the multiple DERs. Each of the multiple 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. When these instructions are executed in each of the multiple DER controllers, they cause the multiple DER controllers to receive error signals from the RPA controller directly coupled to the RPA and send control signals, such as reference signals, to the multiple DERs. Figures 2 to 4 and Figure 7 The control signal is sent to one of the multiple DERs. The control signal received by the multiple DERs is configured to reduce the error voltage at the RPA by injecting multiple currents from the multiple DERs into the distribution feeder, for example, a reference. Figures 1 to 4 As stated above.

[0134] Figure 12 Block diagrams of processing systems according to various embodiments of the present disclosure are shown. Processing system 1200 depicts a general platform, as well as general components and functions, that can be used to implement portions of the distribution network of the embodiments and / or interface with external computers or processing devices. For example, processing system 1200 can be used to implement... Figure 10 This is a portion of the controller shown. In some embodiments, the processing system 1200 can be used to determine and evaluate the operating parameters of the embodiments, and to determine error signals of the distribution network based on the operating parameters.

[0135] The processing system 1200 may include, for example, a central processing unit (CPU) 1202 and a memory 1204 connected to a bus 1208, and may be configured to perform the processing discussed above. If desired or required, the processing system 1200 may also include a display adapter 1210 for providing a connection to a local display 1212, and an input / output (I / O) adapter 1214 for providing input / output interfaces for one or more input / output devices 1216 (such as a mouse, keyboard, flash drive, etc.).

[0136] The processing system 1200 may further include: a network interface 1218, which may be implemented using a network adapter and configured to couple to a wired link, such as a network cable, USB interface, etc.; and / or a wireless / cellular link for communicating with the network 1220. The network interface 1218 may also include suitable receivers and transmitters for wireless communication. It should be noted that the processing system 1200 may include other components. For example, if implemented externally, the processing system 1200 may include hardware components such as power supplies, cables, motherboards, removable storage media, housings, etc. Although not shown, these other components 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 other disclosed system components.

[0137] Exemplary embodiments of the invention are summarized herein. Other embodiments may also be understood from the entire specification and the claims filed herein.

[0138] Reducing the risk of overshoot can be advantageous. To better address this issue, in Example 1 of the present invention, a method is proposed that includes: detecting a fault in a power grid coupled to a distribution network, the distribution network including a distribution feeder, multiple distributed energy sources (DERs) coupled to the distribution feeder, and an applicability reference point (RPA) associated with the multiple DERs. The method includes: in response to detecting a fault, determining an error voltage at the RPA, converting the error voltage into an error signal, broadcasting the error signal to the multiple DERs, and, based on the error signal, reducing the error voltage at the RPA by injecting multiple currents from the multiple DERs into the distribution feeder.

[0139] It may be advantageous to achieve the two-dimensional unbalanced voltage recovery target by separating the positive-sequence component and the negative-sequence component of the error voltage. To better address this issue, in Example 2 of the present invention, according to the method of Example 1, the conversion of the error voltage into an error signal includes: separating the positive-sequence component and the negative-sequence component of the error voltage at the RPA; and generating an error signal at the RPA comprising 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.

[0140] It may be advantageous to achieve coordinated positive-sequence current injection for voltage amplitude enhancement and coordinated negative-sequence current injection for unbalanced voltage mitigation. To better address this issue, in Example 3 of the invention, according to a method of one of Examples 1 or 2, wherein: a first component includes a value indicating the amplitude enhancement requirement of the distribution network during a fault; and a second component includes a value indicating the voltage imbalance of the distribution network during a fault.

[0141] Example 4. According to the method of one of Examples 1 to 3, wherein reducing the error voltage at the RPA includes: based on the first component, increasing the voltage of the distribution network by applying a positive-sequence current injection control scheme to multiple DERs.

[0142] Example 5. According to the method of one of Examples 1 to 4, wherein reducing the error voltage at the RPA includes: mitigating the unbalanced voltage of the distribution network by applying a negative sequence current injection control scheme to multiple DERs based on the second component.

[0143] It may be advantageous to reduce the likelihood of introducing overvoltages in non-faulty phases by mitigating the unbalanced voltages in the non-faulty phases. To better address this issue, in Example 6 of the invention, according to a method of one of Examples 1 to 5, detecting a fault in the power grid includes detecting an unbalanced fault in at least one of the three phases of the power grid, and reducing the error voltage at the RPA includes determining multiple currents to be injected by applying a Dynamic Voltage Support (DVS) control scheme to multiple DERs, and applying the DVS control scheme includes boosting the voltage of the faulty phase of the multiple DERs and mitigating the unbalanced voltages in the non-faulty phases of the multiple DERs by injecting multiple currents into the distribution feeders.

[0144] Example 7. A method according to one of Examples 1 to 6, wherein faulty and non-faulty phases of a plurality of DERs are configured to operate in a mode comprising a continuous operation mode, a forced operation mode, an instantaneous stop mode, and a trip mode, particularly consisting of the continuous operation mode, the forced operation mode, the instantaneous stop mode, and the trip mode, wherein raising the voltage of the faulty phase of the plurality of DERs comprises forcing the faulty phase to leave the instantaneous stop mode and enter the forced operation mode, and wherein mitigating the unbalanced voltage of the non-faulty phases of the plurality of DERs comprises forcing the non-faulty phases to leave the forced operation mode and enter the continuous operation mode.

[0145] Example 8. The method according to any one of Examples 1 to 7 further includes: preventing the faulty and non-faulty phases of the multiple DERs from entering a tripping mode by increasing the voltage of the faulty phases of the multiple DERs and mitigating the unbalanced voltage of the non-faulty phases of the multiple DERs.

[0146] An advantageous feature is that the DERs can be coordinated to avoid uncoordinated current injection through the alignment of current changes. To better address this issue, in Example 9 of the invention, according to a method of one of Examples 1 to 8, reducing the error voltage at the RPA includes: coordinating multiple DERs to inject current into the distribution network based on an error signal, and wherein coordinating the multiple DERs includes, for example, aligning the current change of one DER with the current changes of the remaining DERs in the multiple DERs through a first control scheme and / or speed matching algorithm as described above.

[0147] An advantageous feature is that the voltages of the DERs can be aligned to support the RPA voltage distribution. To better address this issue, in Example 10 of the invention, according to a method of one of Examples 1 to 9, reducing the error voltage at the RPA includes: aligning multiple DERs to inject current into the distribution network based on an error signal, and wherein aligning the multiple DERs includes, for example, aligning the voltage of one DER with the voltages of the remaining DERs, using a second control scheme and / or speed matching algorithm as described above.

[0148] An advantageous feature is that all DERs can reliably receive error signals from the RPA through the following broadcasting mechanism. To better address this issue, in Example 11 of the invention, according to a method of one of Examples 1 to 10, broadcasting the error signal to the plurality of DERs includes: broadcasting the error signal to a first DER among the plurality of DERs, the first DER being directly coupled to the RPA; and transmitting the error signal from the first DER to a second DER among the plurality of DERs, the second DER being indirectly coupled to the RPA.

[0149] An advantageous feature is that, under a distributed target tracking control scheme, the DER can support RPA voltage distribution during and after fault ride-through and avoid uncoordinated current injection through cooperative behavior. To better address this issue, in Example 12 of the invention, according to a method of one of Examples 1 to 11, reducing the error voltage at the RPA includes: applying a distributed target tracking control scheme to multiple DERs, and wherein applying the distributed target tracking control scheme includes determining the multiple currents to be injected under the distributed target tracking control scheme by communicating among the multiple DERs to coordinate the current to be injected by each of the multiple DERs.

[0150] Reducing overshoot risk can be advantageous. To better address this issue, in Example 13 of the invention, a system is proposed comprising: a distribution network coupled to a power grid, the distribution network including distribution feeders, multiple distributed energy sources (DERs) coupled to the distribution feeders, and an applicability reference point (RPA); an RPA controller coupled to the RPA, wherein the RPA controller is programmed to detect faults in the power grid and, in response to detecting a 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, the first communication device being configured to broadcast the error signal to the multiple DERs. The system includes multiple DER controllers coupled to each of the multiple DERs, wherein, based on the error signal, the multiple DER controllers are programmed to control each DER to reduce the error voltage at the RPA by injecting multiple currents into the distribution feeders.

[0151] Example 14. According to the system of Example 13, the RPA controller is programmed to separate the positive-sequence component of the error voltage from the 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 indicating the amplitude increase requirement of the distribution network during the fault; the second component includes a value indicating the voltage imbalance of the distribution network during the fault.

[0152] Example 15. A system according to one of Examples 13 or 14, wherein, based on a first component, multiple DER controllers are programmed to boost the voltage of the distribution network by applying a positive-sequence current injection control scheme to multiple DERs; and based on a second component, multiple DER controllers are programmed to mitigate unbalanced voltage in the distribution network by applying a negative-sequence current injection control scheme to multiple DERs.

[0153] Example 16. A system according to one of Examples 13 to 15, wherein: multiple DER controllers are programmed to control multiple DERs to boost the voltage of the faulty phase of the multiple DERs and alleviate the unbalanced voltage of the non-faulty phase of the multiple DERs.

[0154] Example 17. A system according to one of Examples 13 to 16, wherein: multiple DER controllers are programmed to coordinate multiple DERs to inject current into the distribution network by, for example, aligning the current change of one DER with the current changes of the remaining DERs in the multiple DERs using a first control scheme and / or speed matching algorithm as described above.

[0155] Example 18. A system according to one of Examples 13 to 17, wherein: multiple DER controllers are programmed to coordinate multiple DERs to inject current into the distribution network by, for example, aligning the voltage of one of the multiple DERs with the voltages of the remaining DERs in the multiple DERs using a second control scheme and / or a central aggregation algorithm as described above.

[0156] Example 19. A system according to any one of Examples 13 to 18 further includes: a second communication device coupled to a first DER of a plurality of DERs, wherein the first DER is directly coupled to the RPA; and a third communication device coupled to a second DER of a plurality of DERs, wherein the second DER is indirectly coupled to the RPA, and wherein the second communication device is configured to receive an error signal broadcast by the first communication device and to transmit the error signal to the third communication device.

[0157] Example 20. A system according to one of Examples 13 to 19 further includes: a plurality of inverters, wherein one of the plurality of inverters is coupled between each of the plurality of DERs and the distribution feeder, and wherein, based on an error signal, the plurality of inverters are configured to generate a plurality of currents to be injected into the distribution feeder.

[0158] Reducing the risk of overshoot can be advantageous. To better address this issue, in Example 21 of the present invention, a System Applicability Reference Point (RPA) controller is proposed, comprising: a control device coupled to a distribution network including distribution feeders, multiple distributed energy sources (DERs) coupled to the distribution feeders, and the RPA, wherein the control device is directly coupled to the RPA, the control device 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, wherein, when the instructions are executed, the processor detects a fault in the grid coupled to the distribution network, and in response to detecting the fault, determines an error voltage at the RPA, converts the error voltage into an error signal, and sends the error signal to the first communication device, wherein the first communication device is configured to broadcast the error signal to the multiple DERs.

[0159] Example 22. An RPA controller according to Example 21, wherein: a first DER of a 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, and wherein the second communication device is configured to receive an error signal broadcast by the first communication device and to send the error signal to the third communication device; and the plurality of DERs are coupled to a plurality of DER controllers, wherein, based on the error signal, the plurality of DER controllers are programmed to control the respective DERs to reduce the error voltage at the RPA by injecting multiple currents into the distribution feeder.

[0160] Example 23. An RPA controller according to one of Examples 21 or 22, wherein the processor is programmed to separate the positive-sequence component of the error voltage from the negative-sequence component of the error voltage and generate an error signal comprising 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 indicating the amplitude increase requirement of the distribution network during the fault; and the second component includes a value indicating the voltage imbalance of the distribution network during the fault.

[0161] Reducing the risk of overshoot can be advantageous. To better address this issue, in Example 24 of the present invention, a distributed energy source (DER) control system is proposed, comprising: a plurality of DER controllers coupled to a distribution network including distribution feeders, a plurality of distributed energy sources (DERs) coupled to the distribution feeders, and an applicability reference point (RPA), wherein each of the plurality of DER controllers is coupled to a corresponding DER in the plurality of DERs, each of the plurality of DER controllers including: 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, wherein, when the instructions are executed in each of the plurality of DER controllers, the plurality of DER controllers receive an error signal from an RPA controller directly coupled to the RPA, send control signals to the plurality of DERs, one of the control signals being sent to one of the plurality of DERs, and wherein the control signals received by the plurality of DERs are configured to reduce the error voltage at the RPA by injecting a plurality of currents from the plurality of DERs into the distribution feeders.

[0162] Example 25. According to the DER control system of Example 24, the error voltage includes a positive-sequence component and a negative-sequence component, and 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, wherein: the first component includes a value indicating the amplitude increase requirement of the distribution network during a fault in the grid coupled to the distribution network; and the second component includes a value indicating the voltage imbalance of the distribution network during the fault.

[0163] Example 26. A DER control system according to one of Examples 24 or 25, wherein: based on a first component, a plurality of DER controllers are configured to boost the voltage of the distribution network by executing instructions in each of the plurality of DER controllers to apply a positive-sequence current injection control scheme to the plurality of DERs; and based on a second component, the plurality of DER controllers are configured to mitigate the unbalanced voltage of the distribution network by executing instructions in each of the plurality of DER controllers to apply a negative-sequence current injection control scheme to the plurality of DERs.

[0164] Example 27. A DER control system according to one of Examples 24 to 26, wherein: a plurality of DER controllers are configured to coordinate the plurality of DERs by executing instructions in each of the plurality of DER controllers to inject current into the distribution network by, for example, using a first control scheme and / or speed matching algorithm as described above, aligning the current change of one of the DERs with the current change of the remaining DERs in the plurality of DERs; and the plurality of DER controllers are configured to coordinate the plurality of DERs by executing instructions in each of the plurality of DER controllers to coordinate the plurality of DERs to inject current into the distribution network by, for example, using a second control scheme and / or center aggregation algorithm as described above, aligning the voltage of one of the DERs with the voltage of the remaining DERs in the plurality of DERs.

[0165] Although embodiments of the present disclosure and their advantages have been described in detail, it should be understood that various changes, substitutions and alterations may be made without departing from the spirit and scope of the present disclosure as defined by the appended claims.

[0166] Furthermore, the scope of this application is not intended to be limited to the specific embodiments of the processes, machines, manufactures, material compositions, apparatuses, methods, and steps described in the specification. As will be readily understood by those skilled in the art from the disclosure of this publication, existing or future processes, machines, manufactures, material compositions, apparatuses, methods, or steps that perform substantially the same functions or achieve substantially the same results as the corresponding embodiments described herein can be utilized according to this disclosure. Therefore, the appended claims are intended to include such processes, machines, manufactures, material compositions, apparatuses, methods, or steps within its scope.

Claims

1. A fault control method for a power distribution system, comprising: Detecting faults in a power grid coupled to a distribution network, the distribution network including distribution feeders, multiple distributed energy sources (DERs) coupled to the distribution feeders, and applicability reference points (RPAs) associated with the multiple distributed energy sources (DERs); and In response to the detection of the fault, an error voltage at the applicability reference point RPA is determined, the error voltage is converted into an error signal, the error signal is broadcast to the plurality of distributed energy DERs, and based on the error signal, the error voltage at the applicability reference point RPA is reduced by injecting multiple currents from the plurality of distributed energy DERs into the distribution feeder.

2. The method according to claim 1, wherein, Converting the error voltage into the error signal includes: At the applicability reference point RPA, the positive-sequence component of the error voltage is separated from the negative-sequence component of the error voltage; and At the applicability reference point RPA, an error signal is generated comprising a first component based on the positive-order component and a second component based on both the positive-order component and the negative-order component.

3. The method according to claim 2, wherein: The first component includes a value indicating the amplitude increase requirement of the distribution network during the fault; and The second component includes a value indicating the voltage imbalance of the distribution network during the fault.

4. The method according to claim 3, wherein, Reducing the error voltage at the applicability reference point RPA includes at least one of the following: Based on the first component, the voltage of the distribution network is increased by applying a positive-sequence current injection control scheme to the multiple distributed energy DERs; as well as Based on the second component, the unbalanced voltage of the distribution network is mitigated by applying a negative sequence current injection control scheme to the plurality of distributed energy DERs.

5. The method according to claim 1, wherein, Detecting faults in the power grid includes detecting: An unbalanced fault in at least one of the three phases of the power grid, wherein reducing the error voltage at the applicability reference point RPA includes determining the plurality of currents to be injected by applying a dynamic voltage support DVS control scheme to the plurality of distributed energy DERs, and wherein applying the dynamic voltage support DVS control scheme includes boosting the voltage of the faulted phase of the plurality of distributed energy DERs and mitigating the unbalanced voltage of the non-faulted phases of the plurality of distributed energy DERs by injecting the plurality of currents into the distribution feeder.

6. The method according to claim 5, in, The faulty and non-faulty phases of the plurality of distributed energy DERs are configured to operate in modes including continuous operation mode, forced operation mode, momentary stop mode and trip mode. Specifically, increasing the voltage of the faulty phase of the plurality of distributed energy DERs includes forcing the faulty phase to leave the momentary stop mode and enter the forced operation mode, and The method of mitigating the unbalanced voltage of the non-faulty phases of the plurality of distributed energy DERs includes forcing the non-faulty phases to leave the forced operation mode and enter the continuous operation mode.

7. The method according to claim 6, further comprising: By increasing the voltage of the faulty phase of the plurality of distributed energy DERs and alleviating the unbalanced voltage of the non-faulty phases of the plurality of distributed energy DERs, the faulty phase and the non-faulty phase of the plurality of distributed energy DERs are prevented from entering the tripping mode.

8. The method according to claim 1, wherein, Reducing the error voltage at the applicability reference point RPA includes at least one of the following: Based on the error signal, the plurality of distributed energy DERs are coordinated to inject current into the distribution network, wherein coordinating the plurality of distributed energy DERs includes aligning the current change of one of the plurality of distributed energy DERs with the current changes of the other distributed energy DERs in the plurality of distributed energy DERs. Based on the error signal, the plurality of distributed energy sources (DERs) are coordinated to inject current into the distribution network, wherein coordinating the plurality of DERs includes aligning the voltage of one of the DERs with the voltages of the remaining DERs; and The distributed target tracking control scheme is applied to the plurality of distributed energy DERs, wherein applying the distributed target tracking control scheme includes coordinating the determination of the plurality of currents to be injected under the distributed target tracking control scheme by communicating among the plurality of distributed energy DERs to coordinate the current to be injected by each of the plurality of distributed energy DERs.

9. The method according to claim 1, wherein, Broadcasting the error signal to the plurality of distributed energy DERs includes: The error signal is broadcast to a first distributed energy DER among the plurality of distributed energy DERs, the first distributed energy DER being directly coupled to the applicability reference point RPA, and the error signal is sent from the first distributed energy DER to a second distributed energy DER among the plurality of distributed energy DERs, the second distributed energy DER being indirectly coupled to the applicability reference point RPA.

10. A power distribution system, comprising: A distribution network coupled to a power grid, the distribution network including distribution feeders, multiple distributed energy sources (DERs) coupled to the distribution feeders, and an applicability reference point (RPA); An applicability reference point RPA controller, coupled to the applicability reference point RPA, is programmed to detect faults in the power grid, and In response to the detection of the fault, the error voltage at the applicability reference point RPA is determined and the error voltage is converted into an error signal; A first communication device coupled to the applicability reference point RPA controller, the first communication device being configured to broadcast the error signal to the plurality of distributed energy DERs; as well as Multiple distributed energy DER controllers, coupled to a corresponding distributed energy DER in the multiple distributed energy DERs, wherein, based on the error signal, the multiple distributed energy DER controllers are programmed to control the corresponding distributed energy DER to reduce the error voltage at the applicability reference point RPA by injecting multiple currents into the distribution feeder.

11. The system according to claim 10, wherein: The applicability reference point RPA controller is configured by the program to separate the positive-sequence component of the error voltage from the negative-sequence component of the error voltage, and generate an error signal comprising 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 indicating the amplitude increase requirement of the distribution network during the fault; and The second component includes a value indicating the voltage imbalance of the distribution network during the fault.

12. The system according to claim 11, wherein: Based on the first component, the plurality of distributed energy DER controllers are configured by the programming to boost the voltage of the distribution network by applying a positive-sequence current injection control scheme to the plurality of distributed energy DERs; as well as Based on the second component, the plurality of distributed energy DER controllers are configured by the programming to alleviate the unbalanced voltage of the distribution network by applying a negative sequence current injection control scheme to the plurality of distributed energy DERs.

13. The system according to claim 10, wherein: The plurality of distributed energy DER controllers are configured, through the programming, to control the plurality of distributed energy DERs to increase the voltage of the faulty phases of the plurality of distributed energy DERs and alleviate the unbalanced voltage of the non-faulty phases of the plurality of distributed energy DERs.

14. The system according to claim 10, wherein, Reducing the error voltage at the applicability reference point RPA includes at least one of the following: The plurality of distributed energy DER controllers are programmed to coordinate the plurality of distributed energy DERs to inject current into the distribution network by aligning the current change of one of the plurality of distributed energy DERs with the current changes of the remaining distributed energy DERs; and The plurality of distributed energy DER controllers are programmed to coordinate the plurality of distributed energy DERs to inject current into the distribution network by aligning the voltage of one of the plurality of distributed energy DERs with the voltage of the remaining distributed energy DERs.

15. The system according to claim 10, further comprising: A second communication device, coupled to a first distributed energy DER among the plurality of distributed energy DERs, wherein the first distributed energy DER is directly coupled to the applicability reference point RPA; and A third communication device is coupled to a second distributed energy DER among the plurality of distributed energy DERs, wherein the second distributed energy DER is indirectly coupled to the applicability reference point RPA, and wherein the second communication device is configured to receive the error signal broadcast by the first communication device and transmit the error signal to the third communication device.

16. The system of claim 10, further comprising: A plurality of inverters, wherein one of the plurality of inverters is coupled between each of the plurality of distributed energy DERs and the distribution feeder, and wherein, based on the error signal, the plurality of inverters are configured to generate the plurality of currents to be injected into the distribution feeder.

17. An applicability reference point RPA controller, comprising: A control device coupled to a distribution network, the distribution network including distribution feeders, multiple distributed energy sources (DERs) coupled to the distribution feeders, and an applicability reference point (RPA), wherein the control device is directly coupled to the RPA, and the control device includes: A memory that stores 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, wherein, when the instructions are executed, the processor detects a fault in the power grid coupled to the distribution network, and in response to detecting the fault, determines an error voltage at the applicability reference point RPA, converts the error voltage into an error signal, and sends the error signal to the first communication device, wherein the first communication device is configured to broadcast the error signal to the plurality of distributed energy sources DERs.

18. The applicability reference point RPA controller according to claim 17, wherein: The first distributed energy DER of the plurality of distributed energy DERs is coupled to the second communication device, and the first distributed energy DER is directly coupled to the applicability reference point RPA; A second distributed energy DER of the plurality of distributed energy DERs is coupled to a third communication device, the second distributed energy DER being indirectly coupled to the applicability reference point RPA, and wherein the second communication device is configured to receive the error signal broadcast by the first communication device and transmit the error signal to the third communication device; and The plurality of distributed energy DERs are coupled to a plurality of distributed energy DER controllers, wherein, based on the error signal, the plurality of distributed energy DER controllers are programmed to control the respective distributed energy DERs to reduce the error voltage at the applicability reference point RPA by injecting a plurality of currents into the distribution feeder.

19. The applicability reference point RPA controller according to claim 17, wherein: The processor is configured by the program to separate the positive-sequence component of the error voltage from the negative-sequence component of the error voltage, and to generate an error signal comprising 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 indicating the amplitude increase requirement of the distribution network during the fault; and The second component includes a value indicating the voltage imbalance of the distribution network during the fault.

20. A distributed energy DER control system, comprising: Multiple distributed energy DER controllers are coupled to a distribution network, the distribution network including distribution feeders, multiple distributed energy DERs coupled to the distribution feeders, and an applicability reference point (RPA). Each of the multiple distributed energy DER controllers is coupled to a corresponding distributed energy DER within the multiple distributed energy DERs. Each of the multiple distributed energy DER controllers includes: The memory stores a program including instructions. A processor, coupled to the memory and configured to execute the program, and A communication device coupled to the processor, wherein, when the instructions are executed in each of the plurality of distributed energy DER controllers, the plurality of distributed energy DER controllers cause the plurality of distributed energy DER controllers to receive an error signal from an applicability reference point RPA controller directly coupled to the applicability reference point RPA, send a control signal to the plurality of distributed energy DERs, one of the control signals being sent to one of the plurality of distributed energy DERs, and wherein the control signal received by the plurality of distributed energy DERs is configured to reduce the error voltage at the applicability reference point RPA by injecting a plurality of currents from the plurality of distributed energy DERs into the distribution feeder.

21. The distributed energy DER control system according to claim 20, wherein, The error voltage includes a positive-sequence component and a negative-sequence component, and 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, wherein: The first component includes a value indicating the amplitude boost demand of the distribution network during a fault in the power grid coupled to the distribution network; and The second component includes a value indicating the voltage imbalance of the distribution network during the fault.

22. The distributed energy DER control system according to claim 21, wherein, Reducing the error voltage at the applicability reference point RPA includes at least one of the following: Based on the first component, the plurality of distributed energy DER controllers are configured to boost the voltage of the distribution network by applying a positive-sequence current injection control scheme to the plurality of distributed energy DERs by executing instructions in each of the plurality of distributed energy DER controllers; as well as Based on the second component, the plurality of distributed energy DER controllers are configured to mitigate the unbalanced voltage of the distribution network by applying a negative sequence current injection control scheme to the plurality of distributed energy DERs by executing instructions in each of the plurality of distributed energy DER controllers.

23. The distributed energy DER control system according to claim 20, wherein, Reducing the error voltage at the applicability reference point RPA includes at least one of the following: The plurality of distributed energy DER controllers are configured to coordinate the plurality of distributed energy DERs by executing instructions in each of the plurality of distributed energy DER controllers to inject current into the distribution network by aligning the current change of one of the plurality of distributed energy DERs with the current changes of the remaining distributed energy DERs in the plurality of distributed energy DERs. as well as The plurality of distributed energy DER controllers are configured to coordinate the plurality of distributed energy DERs by executing instructions in each of the plurality of distributed energy DER controllers to inject current into the distribution network by aligning the voltage of one of the plurality of distributed energy DERs with the voltage of the remaining distributed energy DERs in the plurality of distributed energy DERs.

Images