Distributed voltage control for power networks

Abstract

Disclosed are systems, methods, techniques and devices for power network control. An exemplary embodiment is a power network comprising a plurality of zones (110, 140), each zone comprising: a plurality of measurement devices (128, 158) structured to measure electrical characteristics of the corresponding zone (110, 140); a zone controller (130, 160) structured to receive measurements from the plurality of measurement devices (128, 158); distributed energy resources (DER) (115, 116); and loads (112-114, 142-144). Each zone controller (130, 160) is structured to receive a set of local measurements from the plurality of measurement devices (128, 158) of the corresponding zone (110, 140), calculate a sensitivity matrix using the received set of local measurements, determine whether a voltage variation has occurred in the corresponding zone (110, 140), determine a DER set point using the received set of local measurements in response to determining that a voltage variation has occurred in the corresponding zone, and transmit the DER set point to the DER (115, 116).

Description

Background Technology

[0001] This disclosure generally relates to distributed control in power networks. As the penetration of distributed energy resources (DERs) in power networks increases, control systems must be able to respond to sudden changes in power generation that cause fluctuations in network voltage. Centralized control systems require the aggregation of large amounts of data, thus reducing responsiveness due to round-trip communication between each controller and the centralized power network control system. Some power networks use distributed control systems where multiple distributed controllers periodically exchange measurements and other data to formulate control strategies for the power network. Existing distributed control systems for power networks suffer from numerous shortcomings and drawbacks. Unmet needs remain, including reducing reliance on external data and other measurements shared by other distributed controllers. For example, a distributed control system may fail if communication channels between controllers fail or if there is insufficient bandwidth to share the data required to compute the control strategy. In another example, some power network control systems must receive prior information about the network topology and node sensitivities before computing the control strategy. Given these and other shortcomings in the art, there is a significant need for the unique devices, methods, systems, and techniques disclosed herein. Summary of the Invention

[0002] For the purpose of clearly, concisely, and accurately describing the non-limiting exemplary embodiments of this disclosure, the ways and processes of making and using them, and to enable the practice, making, and use of these embodiments, reference will now be made to certain exemplary embodiments (including those illustrated in the accompanying drawings), and they will be described using specific language. However, it should be understood that this does not constitute a limitation on the scope of this disclosure, and that this disclosure includes and protects such variations, modifications, and further applications of the exemplary embodiments as would be conceived by those skilled in the art benefiting from this disclosure.

[0003] Exemplary embodiments of this disclosure include unique systems, methods, technologies, and apparatus for power distribution system control. Further embodiments, forms, objectives, features, advantages, aspects, and benefits of this disclosure will become apparent from the following description and accompanying drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0004] Figure 1 This is a circuit diagram illustrating an exemplary power distribution network.

[0005] Figure 2 This is a flowchart illustrating an exemplary network control process.

[0006] Figure 3-7 The diagram is in Figure 2 During the exemplary area control process illustrated in the figure Figure 1 The figure shows a graph illustrating the electrical characteristics of an exemplary power distribution system. DETAILED DESCRIPTION

[0007] refer to Figure 1 An exemplary power distribution network 100 is illustrated, comprising: zone 110, which includes a plurality of loads and DERs, the operation of which is controlled by controller 130; and zone 140, which includes a plurality of loads and DERs, the operation of which is controlled by controller 160. Zones 110 and 140 may be logically defined by the control relationships between their respective controllers 130 and 160 and other zone components, devices, and elements, and may respectively cover different geographical areas as well as common or overlapping geographical areas. It should be understood that network 100 can be implemented in a variety of applications, including public power grids, transmission networks, low-voltage distribution, medium-voltage distribution, and high-voltage distribution, to name just a few. It should be understood that the topology of network 100 is illustrated for illustrative purposes and is not intended to be a limitation of this disclosure. For example, network 100 may include two or more zones interconnected by one or more coupling points. Although network 100 is illustrated as a single-phase power distribution system, network 100 may also be structured to transmit multiphase power.

[0008] Zone 110 includes loads, DERs, and measuring devices, each coupled to one of a plurality of buses, each bus coupled to a portion of distribution line 111. Loads 112, 113, and 114 are coupled to buses 122, 123, and 124, respectively. Each load can be any type of device or system structured to consume power received from the portion of distribution line 111. DERs 115 and 116 are coupled to buses 125 and 126, respectively. Each DER is structured to generate power according to a setpoint received from zone controller 130 and to supply the generated power to the loads of network 100. In some embodiments, each DER may also be structured to receive and store power. Each DER may include a photovoltaic array, a wind turbine, a natural gas generator, or a battery pack, to name just a few.

[0009] Multiple measuring devices 128 are structured to measure electrical characteristics at different nodes of region 110. In the illustrated embodiment, the multiple measuring devices 128 are voltage sensors, structured to measure the bus voltage of each bus in region 110. In some embodiments, the multiple measuring devices may include current sensors, power sensors, voltage transformers, or current transformers, to name just a few. The multiple measuring devices 128 may be structured to measure voltage amplitude, voltage phase angle, current amplitude, current phase angle, power flow, active power, or reactive power, to name just a few. In some embodiments, one or more of the multiple measuring devices may be combined into another device, such as a DER, to name just one.

[0010] The plurality of measuring devices 128, as well as DERs 115 and 116, communicate with the area controller 130 via a plurality of communication channels 127. In some embodiments, the plurality of communication channels 127 form a publish-subscribe agent or agentless data exchange bus. The plurality of measuring devices 128 may publish measured values ​​asynchronously to the data bus. The controller 130 may read the published measured values ​​in real time and use the data bus to transmit commands to DERs 115 and 116. The controller 130 may communicate with the plurality of measuring devices 128, as well as DERs 115 and 116, using area communication protocols such as Message Queuing Telemetry Transport (MQTT), Advanced Message Queuing Protocol (AMQP), Data Distribution Service (DDS), or Open Platform Communications Unified Architecture (OPCUA), to name a few. In some embodiments, one of the devices in area 110 may include an adapter to convert from a utility standard protocol (such as MODBUS, MODBUS TCP, DNP, or IEC 61850) to one of the area communication protocols. Data transfer between controllers 130, DER115 and 116, and the plurality of measuring devices 128 can be guaranteed by message protocol authentication (i.e., MQTT ID and password), transport layer security (i.e., TSL) and Internet Protocol authentication layer.

[0011] The area controller 130 includes an input / output device 131, a processing device 133, and a memory device 135. The area controller 130 can be a standalone device, an embedded system, or multiple devices. The area controller 130 can be an edge device, such as a router, a routing switch, an integrated access device, a wireless gateway device, or another type of access device, to name just a few.

[0012] Input / output device 131 enables area controller 130 to communicate with other devices on network 100. Input / output device 131 is structured to receive measurements from the plurality of measuring devices 128 and transmit commands, including setpoints, to DER 115 and 116. For example, input / output device 131 may be a network adapter, network credential, interface, or port (e.g., USB port, serial port, parallel port, analog port, digital port, VGA, DVI, HDMI, FireWire, CAT 5, Ethernet, fiber optic, or any other type of port or interface), to name just a few. Input / output device 131 may consist of hardware, software, or firmware. Input / output device 131 may include more than one of these adapters, credentials, or ports, such as a first port for receiving data and a second port for transmitting data.

[0013] Processing device 133 may be programmable, dedicated, hardwired state machine, or a combination thereof. For example, device 133 may be an Advanced Reduced Instruction Set Computer (ARM). Device 133 may include multiple processors, arithmetic logic units (ALUs), central processing units (CPUs), digital signal processors (DSPs), field-programmable gate arrays (FPGAs), and a few other examples. For the form of processing device 133 with multiple processing units, distributed, pipelined, or parallel processing may be used. Processing device 133 may be dedicated to performing only the operations described herein or may be utilized in one or more additional applications. In the illustrated form, processing device 133 is programmable, performing processes and processing data according to programming instructions (such as software or firmware) stored in memory device 135. Alternatively or additionally, the programming instructions are defined at least in part by hardwired logic or other hardware. Processing device 133 may consist of one or more components of any type suitable for processing signals received from input / output device 131 or elsewhere and providing a desired output signal. Such components may include digital circuitry, analog circuitry, or a combination of both.

[0014] Memory device 135 can be one or more types, such as solid-state, electromagnetic, optical, or combinations thereof, to name just a few. Furthermore, memory device 135 can be volatile, non-volatile, transient, or a combination thereof, and some or all of memory device 135 can be portable types, such as disks, magnetic tapes, memory sticks, cassette tapes, to name just a few. Additionally, in addition to or in lieu of storing programming instructions, memory device 135 can store data manipulated by processing device 133, such as data representing signals received from or sent to input / output device 131.

[0015] Each area controller in network 100 executes a distributed voltage control algorithm to effectively regulate the voltage of the entire power network. Since each area is controlled by its own area controller, the network is not limited by the number of areas.

[0016] Each area controller in network 100 operates the controllable devices in its corresponding area without using measurements or other data from measuring devices in other areas to generate control strategies. Because each area controller controls the controllable devices in its corresponding area without communicating with other areas, the distributed area controllers of network 100 do not require dedicated inter-controller communication channels and are not subject to the strict communication limitations (such as latency, synchronization, and bandwidth) of other distributed control systems. Furthermore, the lack of communication between area controllers during control strategy generation allows for improved responsiveness of area controllers to voltage variations.

[0017] Unlike distributed control systems (where area controllers use only local measurements and adjust setpoints without considering the influence of neighboring areas), the exemplary area controllers use local measurements to approximate the influence of other areas in network 100. Each area controller uses local measurements to generate and recursively update a sensitivity matrix. The sensitivity matrix is ​​calculated to capture the mutual influence (also known as coupling effect) of other areas on the area controller's area, without requiring measurements or data from other areas. As the sensitivity matrix is ​​recursively updated, the approximate estimate of the matrix's influence on other areas becomes more accurate. Furthermore, since the sensitivity matrix is ​​used to calculate the setpoints for the area's DER, these setpoints will be determined in part based on the approximate estimate of the mutual influence of the sensitivity matrix on other areas.

[0018] Besides not requiring measurements or other data from other area controllers, each area controller also does not need prior information about area sensitivity to generate its area control strategy. Instead, each area controller initializes and recursively updates its sensitivity matrix using measurements from area measurement devices, taking into account the interactions between areas.

[0019] It should be understood that any or all of the aforementioned features of the device in region 110 may also exist in the device in region 140. For example, the aforementioned features of the load, DER, measuring device, and controller in region 140 may also exist in the load, DER, measuring device, and controller in region 140.

[0020] Region 140 includes loads, DERs, and measuring devices coupled to multiple buses coupled to a portion 141 of a power distribution line. Loads 142, 143, and 144 are coupled to buses 152, 153, and 154, respectively. DERs 145 and 146 are coupled to buses 155 and 156, respectively. The plurality of measuring devices 158 are structured to measure the electrical characteristics of region 140. In the illustrated embodiment, the plurality of measuring devices 158 are voltage sensors, structured to measure the bus voltage of each bus in region 140.

[0021] The area controller 160 includes an input / output device 161, a processing device 163, and a memory device 165. The plurality of measuring devices 158 and DERs 145 and 146 communicate with the area controller 160 via a plurality of communication channels 157.

[0022] As explained in more detail below, each area controller of network 100 is configured to respond to voltage changes without using measurements or other data received from another area controller, while still taking into account the coupling effects of other areas. In some embodiments, the area controllers of network 100 can communicate via an inter-controller communication network. For example, a mesh network can be provided to enable area-to-area communication for non-time-sensitive control functions. The latency caused by hops from wireless relay to device means that synchronous communication may be impossible. However, network 100 is less susceptible to limitations in inter-controller communication (such as latency, synchronization, or bandwidth) because it does not use inter-controller communication for time-sensitive control functions, such as responding to voltage changes. This allows for relaxed requirements on any inter-controller communication network, such as infrequent, intermittent, or islanded communication operation modes.

[0023] refer to Figure 2 The illustration depicts an exemplary process 200 for operating a power network comprising multiple interconnected regions, wherein each region of the exemplary network includes at least one load, at least one distributed energy source, multiple measuring devices, and a region controller. Process 200 is implemented by the region controller of each region to produce a convergent effect of network control. It should be further understood that several variations and modifications to process 200 are contemplated, including, for example, omitting one or more aspects of process 200, adding further conditions and operations, reorganizing these operations and conditions, separating one or more operations and conditions into separate processes, or dividing an operation into separate operations.

[0024] Process 200 begins at operation 201, where the area controller initializes communication with the DER and the plurality of measuring devices in the same area.

[0025] Process 200 proceeds to operation 203, in which the area controller receives data corresponding to the electrical characteristics of the area from the plurality of measuring devices.

[0026] Process 200 proceeds to operation 205, where the area controller confirms the data received in operation 203 by determining whether all the data required to perform operation 207 has been received. Process 200 waits at operation 205 until all the required data has been received. During operation 205, the area controller may also determine whether the data includes spurious data.

[0027] Process 200 proceeds to operation 207, where the area controller uses the measurements received in operation 203 to calculate the sensitivity matrix. The area controller does not require prior information, such as network topology or measurements acquired in other areas to calculate the sensitivity matrix. The sensitivity matrix defines the relationship between voltage, phase angle, and real or reactive power measurements acquired at multiple nodes within the area. The sensitivity matrix also captures the effects of mutual coupling between the area controller's area and other areas of the power network.

[0028] A recursive algorithm is used to calculate the sensitivity matrix to reduce computational cost and make operation 207 suitable for execution at the area controller. Each time the area controller executes operation 207, it uses the most recently received measurement from operation 203 to calculate one iteration of the recursive algorithm.

[0029] The sensitivity matrix can be calculated using either ordinary least squares or regularized least squares. The area controller can select either the ordinary least squares or regularized least squares algorithm based on the presence of spurious data determined in operation 205. Regularized least squares requires more computational power than ordinary least squares, but is better suited for managing anomalous data, such as data from malfunctioning or damaged measuring devices.

[0030] If the area controller uses the ordinary least squares algorithm, when the area controller executes operation 207 for the first time, it calculates the sensitivity matrix according to the following initialization equations, where i is the area number, M is the auxiliary matrix, t0 is the initial time, A is the measurement matrix, W is the weighting matrix, Λ is the sensitivity matrix, and D is the voltage measurement matrix.

[0031]

[0032]

[0033] The weighting matrix W is determined by the weights assigned by the user based on the measured age for calculating the sensitivity matrix. The measurement matrix A can be defined as follows, where t is time, i is the region number, ΔP is the change in active power in the region, and ΔQ is the change in reactive power in the region.

[0034]

[0035] Matrix D can be defined as follows, where ΔV is the voltage change, i is the region number, and t is the time.

[0036]

[0037] In the subsequent execution of operation 207, the following set of equations is used to calculate the sensitivity matrix by updating the sensitivity matrix initially calculated using the set of equations (1), where i is the region number, M is the auxiliary matrix, t is the time, α is the vector of the measurement matrix, Λ is the sensitivity matrix, v is the forgetting factor, I is the identity matrix, and Δ 2 It is a second-order difference operator, where P is the active power of the region, Q is the reactive power of the region, and V is the voltage of the region.

[0038]

[0039]

[0040] in

[0041]

[0042] and

[0043]

[0044] If the area controller uses the regularized least squares algorithm, when the area controller executes operation 207 for the first time, it calculates the sensitivity matrix based on the following initialization equations, where i is the area number, M is the auxiliary matrix, t0 is the initial time, A is the measurement matrix, W is the weighting matrix, Π is the constant regularization matrix, and D is the voltage measurement matrix.

[0045]

[0046]

[0047] The weighting matrix W is determined by the weights assigned by the user based on the measured age for calculating the sensitivity matrix. The measurement matrix A can be defined as follows, where t is time, i is the region number, ΔP is the change in active power in the region, and ΔQ is the change in reactive power in the region.

[0048]

[0049] Matrix D can be defined as follows, where ΔV is the voltage change, i is the region number, and t is the time.

[0050]

[0051] In the subsequent execution of operation 207, the following set of equations is used to calculate the sensitivity matrix by updating the sensitivity matrix initially calculated using the set of equations (7), where i is the region number, M is the auxiliary variable, t is the time, α is the vector of the measurement matrix, Λ is the sensitivity matrix, v is the forgetting factor, Π is the constant regularization matrix, I is the identity matrix, and Δ 2 It is a second-order difference operator, where P is the active power of the region, Q is the reactive power of the region, and V is the voltage of the region.

[0052]

[0053]

[0054] in

[0055]

[0056] and

[0057]

[0058] Process 200 proceeds to operation 209, where the area controller receives a reference value from the central controller. In some embodiments, the area controller receives a reactive power reference value or an instruction corresponding to the reference value.

[0059] Process 200 proceeds to condition 211. If the area controller determines that no voltage change has occurred in the area, process 200 proceeds to operation 217, where the area controller does not determine a new setpoint, thus allowing the area's DER to continue operation using the previously determined setpoint. Process 200 then proceeds to operation 219.

[0060] If the area controller determines that a voltage change has occurred at a point in the area, process 200 proceeds from condition 211 to operation 213. At operation 213, the area controller uses the most recently computed iterative and linear programming algorithm of the sensitivity matrix calculated during operation 207 to determine a new setpoint for one or more DERs for the area. As more iterations of the sensitivity matrix are computed, the calculated setpoints become more successful at keeping the constraint variables within limits.

[0061] The new setpoint is determined to effectively minimize the increase in active or reactive power of the DER within constraints. In some embodiments, these constraints may include: 1) the node voltage is within its lower and upper limits; 2) the active and reactive power generated by the DER in the region does not exceed the power consumption of the region load to prevent reverse active power flow; and 3) any increase in power output by the DER does not exceed the DER's capacity. Constraints may be added or removed.

[0062] The setpoint for each DER can be determined based on the type of voltage transformer and the DER's operating mode using one of the following sets of equations. For undervoltage transformers and DERs operating in power factor correction mode, the area controller can use the following set of equations to determine the new DER setpoint, where y is an auxiliary variable, t is time, and V... ι It is the lower bound of the voltage reference value, V μ It is the upper limit of the voltage reference value, Λ VQ,t It is a partition of the sensitivity matrix Λ that correlates voltage changes with reactive power changes, where Q is reactive power and DER is the DER for which the setpoint is being calculated. It is the reactive power setpoint:

[0063] minimize y t

[0064] Make satisfy

[0065]

[0066] For overvoltage transformers and DERs operating in power factor correction mode, the area controller can use the following set of equations to determine the new DER setpoint, where y is an auxiliary variable, t is time, and V... ι It is the lower bound of the voltage reference value, V μ It is the upper limit of the voltage reference value, Λ VQ,t It is a block of the sensitivity matrix Λ that correlates voltage changes with reactive power changes, where Q is reactive power, ER is the DER for which the setpoint is being calculated, and It is the reactive power setpoint:

[0067] Maximize y t

[0068] Make satisfy

[0069]

[0070] For undervoltage transformers and DERs operating in unified mode, the area controller can use the following set of equations to determine the new DER setpoint, where y is an auxiliary variable, t is time, and V... ι It is the lower bound of the voltage reference value, Vμ It is the upper limit of the voltage reference value, Λ VP,t It is a block of the sensitivity matrix Λ that correlates voltage changes with changes in active power, where P is the active power, and DER is the DER for the setpoint being calculated. Active power setpoint:

[0071] minimize y t

[0072] Make satisfy

[0073]

[0074] For overvoltage transformers and DERs operating in unified mode, the regional controller can use the following set of equations to determine the new DER setpoint, where y is an auxiliary variable, t is time, and V... ι It is the lower bound of the voltage reference value, V μ It is the upper limit of the voltage reference value, Λ VP,t It is a block of the sensitivity matrix Λ that correlates voltage changes with active power changes, where P is active power and DER is the DER for which the setpoint is being calculated. Active power setpoint:

[0075] Maximize y t

[0076] Make satisfy

[0077]

[0078] In some embodiments, the time spent executing operation 213 can be monitored. If the time spent executing the operation exceeds a threshold, the region controller, acting as a preprocessor, pushes the execution of operation 213 to a cloud-hosted virtual machine. The virtual machine may reside in a remote data center or on a local (on-premise) server. The result of operation 213 is then transmitted back to the region controller.

[0079] Process 200 proceeds to operation 215, in which the area controller transmits the setpoint to one or more DERs.

[0080] Process 200 proceeds to operation 219, where the area controller then receives new data from the plurality of measuring devices and verifies that the area's DER is operating at the correct setpoint. Once operation 219 is complete, process 200 returns to operation 205. Process 200 uses the new data received during operation 219 in the same manner as using the data received in operation 203.

[0081] refer to Figure 3-7There are graphs that illustrate the performance performed by the area controller 160. Figure 2 During the simulation of the exemplary network control process illustrated in the figure Figure 1 The diagram illustrates the electrical characteristics of region 140 of the exemplary distribution network 100. These graphs also illustrate the characteristics during simulation of a conventional distributed control network (where distributed controllers exchange data in response to voltage transformers). Figure 1 The electrical characteristics of a power network with the same topology as power network 100 in the simulation are shown in these graphs. These graphs also illustrate the electrical characteristics of the power network (where the control system does not respond to voltage transformers) during the simulation. Figure 1 The electrical characteristics of the power network with the same topology as the power network 100 in the example.

[0082] For these simulations, each of the DERs in network 100 is a photovoltaic array operating in PFC mode. Each photovoltaic array has a rated reactive power of 150 kVAR. For each bus in zone 140, the lower voltage limit is 7950 V and the upper voltage limit is 7970 V.

[0083] Throughout the simulation, the active and reactive power consumption of the load varies. At time t0, when the first set of measurements is received by the area controller 160, multiplicative white Gaussian noise with a distribution of N(1,0.1) is used to perturb the reactive power of all DERs in network 100. After t0, the DERs in area 140 are controlled by the area controller 160, but multiplicative white Gaussian noise with a distribution of N(1,0.3) is used to perturb the power output of the DERs in area 110 throughout the remainder of the simulation, with noise sufficient to cause voltage fluctuations in area 140.

[0084] The simulation lasted for 2 hours. The area controller 160 used a distributed regularized recursive least squares algorithm (with a fault tolerance factor of 0.97 and a regularization constant matrix of 0.1×I) to calculate the sensitivity matrix.

[0085] Continue to refer to Figure 3 A graph 300 exists, which illustrates the voltage at bus 152 during simulations of an unregulated power network, an exemplary network control process, and a conventional network control process. Graph 300 includes multiple lines representing: a lower voltage limit 303, an upper voltage limit 301, an unregulated analog voltage 305, a conventional analog voltage 307, and an exemplary analog voltage 309.

[0086] Continue to refer to Figure 4A graph 400 exists, which illustrates the voltage at bus 153 during simulations of an unregulated power network, an exemplary network control process, and a conventional network control process. Graph 400 includes multiple lines representing: a lower voltage limit 403, an upper voltage limit 401, an unregulated analog voltage 405, a conventional analog voltage 407, and an exemplary analog voltage 409.

[0087] Continue to refer to Figure 5 A graph 500 exists, which illustrates the voltage at bus 154 during simulations of an unregulated power network, an exemplary network control process, and a conventional network control process. Graph 500 includes multiple lines representing: a lower voltage limit 503, an upper voltage limit 501, an unregulated analog voltage 505, a conventional analog voltage 507, and an exemplary analog voltage 509.

[0088] Continue to refer to Figure 6 There is a graph 600 that illustrates the reactive power output of DER 145 during simulations of an exemplary network control process and a conventional network control process. Graph 600 includes multiple lines representing exemplary reactive power 609 and conventional reactive power 607.

[0089] Continue to refer to Figure 7 There is a graph 700 that illustrates the reactive power output of DER 146 during simulations of the exemplary network control process and the conventional network control process. Graph 700 includes multiple lines representing the exemplary reactive power 709 and the conventional reactive power 707.

[0090] Further written descriptions of several exemplary embodiments will now be provided. One embodiment is an electric power network comprising: a plurality of zones, each zone including: a plurality of measuring devices structured to measure electrical characteristics of the corresponding zone; a zone controller structured to receive measured values ​​from the plurality of measuring devices; distributed energy resources (DERs); and loads; wherein each zone controller is structured to receive a set of local measured values ​​from the plurality of measuring devices of the corresponding zone, use the received set of local measured values ​​to calculate a sensitivity matrix, determine whether a voltage change has occurred in the corresponding zone, determine a DER setpoint using the received set of local measured values ​​in response to determining that a voltage change has occurred in the corresponding zone, and transmit the DER setpoint to the DER.

[0091] In some forms of the aforementioned power network, each area controller does not use data other than its set of local measurements to calculate the sensitivity matrix, and the calculated sensitivity matrix captures the interactions between other areas within the plurality of areas. In some forms, each area controller determines whether a voltage change has occurred by receiving a reference value from outside the corresponding area and comparing it with the set of local measurements. In some forms, the area controller is structured to receive a second set of local measurements after the DER setpoint is transmitted to the DER, and uses this second set of local measurements to verify that the DER is operating using the DER setpoint. In some forms, the area controller uses the second set of local measurements to update the sensitivity matrix during a recursive least squares algorithm step. In some forms, the area controller uses the following system of equations to calculate the sensitivity matrix, where i is the area number, M is the auxiliary matrix, t0 is the initial time, A is the measurement matrix, W is the weighting matrix, ∏ is the constant regularization matrix, Λ is the sensitivity matrix, and D is the voltage measurement matrix:

[0092]

[0093]

[0094] In some forms, measurement matrices A and D are defined as follows:

[0095]

[0096]

[0097] In some forms, the DER operates in power factor correction mode, where the area controller uses the received reactive power reference value and the following set of equations to determine the DER setpoint, where y is an auxiliary variable, t is time, and V ι It is the lower bound of the voltage reference value, V μ It is the upper limit of the voltage reference value, Λ VQ,t It is a block of the sensitivity matrix Λ that correlates voltage changes with reactive power changes, where Q is reactive power and DER is the DER for the setpoint being calculated. It is the reactive power setpoint:

[0098] Maximize y t (For overvoltage)

[0099] minimize y t (Regarding undervoltage)

[0100] Make satisfy In some forms, DER operates in a unified mode, where the area controller uses the following set of equations to determine the DER setpoint, where y is an auxiliary variable, t is time, and V ι It is the lower bound of the voltage reference value, V μ It is the upper limit of the voltage reference value, Λ VP,t It is a block of the sensitivity matrix Λ that correlates voltage changes with changes in active power, where P is the active power, and DER is the DER for the setpoint being calculated. Active power setpoint:

[0101] minimize y t (Regarding undervoltage)

[0102] Maximize y t (For overvoltage)

[0103] Make satisfy

[0104]

[0105] In some forms, determining the DER setpoint includes the regional controller determining that the time for determining the DER setpoint using the regional controller exceeds a threshold, and wherein, in response to determining that the time for determining the DER setpoint using the regional controller exceeds the threshold, the DER setpoint is determined using a cloud-hosted virtual machine.

[0106] Another exemplary embodiment is a method for operating a power network divided into multiple zones, the method comprising: operating a first zone among the multiple zones using a zone controller, the multiple zones including: a plurality of measuring devices structured to measure electrical characteristics of the first zone; distributed energy resources (DERs); and loads; receiving a set of local measurements from the plurality of measuring devices in the corresponding zone using the zone controller; calculating a sensitivity matrix using the received set of local measurements using the zone controller; determining whether a voltage change has occurred in the corresponding zone using the zone controller; determining a DER setpoint using the received set of local measurements in response to determining that a voltage change has occurred in the corresponding zone; and transmitting the DER setpoint to the DER using the zone controller.

[0107] In some forms of the aforementioned methods, the area controller does not use data other than the set of local measurements to calculate the sensitivity matrix, where the calculated sensitivity matrix captures the interactions between other areas within the plurality of areas. In some forms, the area controller determines whether a voltage change has occurred by receiving a reference value from outside the corresponding area and comparing it with the set of local measurements. In some forms, the area controller is structured to receive a second set of local measurements after the DER setpoint is transmitted to the DER, and uses this second set of local measurements to verify that the DER is operating using the DER setpoint. In some forms, the area controller uses the second set of local measurements to update the sensitivity matrix during a recursive least squares algorithm step. In some forms, the area controller uses the following system of equations to calculate the sensitivity matrix, where i is the area number, M is an auxiliary variable, t0 is the initial time, A is the measurement matrix, W is the weighting matrix, Π is the constant regularization matrix, Λ is the sensitivity matrix, and D is the voltage measurement matrix:

[0108]

[0109]

[0110] In some forms, measurement matrices A and D are defined as follows:

[0111]

[0112]

[0113] In some forms, the DER operates in power factor correction mode, where the area controller uses the received reactive power reference value and the following set of equations to determine the DER setpoint, where y is an auxiliary variable, t is time, and V ι It is the lower bound of the voltage reference value, V μ It is the upper limit of the voltage reference value, Λ VQ,t It is a block of the sensitivity matrix Λ that correlates voltage changes with reactive power changes, where Q is reactive power and DER is the DER for the setpoint being calculated:

[0114] minimize y t (For overvoltage)

[0115] Maximize y t (Regarding undervoltage)

[0116] Make satisfy

[0117]

[0118] In some forms, DER operates in a unified mode, where the area controller uses the following set of equations to determine the DER setpoint, where y is an auxiliary variable, t is time, and V ι It is the lower bound of the voltage reference value, V μ It is the upper limit of the voltage reference value, Λ VP,t It is a block of the sensitivity matrix Λ that correlates voltage changes with changes in active power, where P is the active power, and DER is the DER for the setpoint being calculated. Active power setpoint:

[0119] minimize y t (Regarding undervoltage)

[0120] Maximize y t (For overvoltage)

[0121] Make satisfy

[0122]

[0123] In some forms, determining the DER setpoint includes the regional controller determining that the time for determining the DER setpoint using the regional controller exceeds a threshold, and wherein, in response to determining that the time for determining the DER setpoint using the regional controller exceeds the threshold, the DER setpoint is determined using a cloud-hosted virtual machine.

[0124] It is contemplated that, unless expressly stated otherwise, aspects, features, processes, and operations from the various embodiments may be used in any other embodiment. Some of the illustrated operations may be performed by a computer including processing means that executes a computer program product on a non-transitory computer-readable storage medium, wherein the computer program product includes instructions that cause the processing means to perform one or more operations or issue commands to other means to perform one or more operations.

[0125] Although this disclosure has been illustrated and described in detail in the accompanying drawings and foregoing description, such illustrations and descriptions are to be considered illustrative in nature and not restrictive. It should be understood that only certain exemplary embodiments have been shown and described, and all variations and modifications within the spirit of this disclosure are intended to be protected. It should be understood that while the use of words such as “preferred,” “preferred,” “ideal,” or “more preferred” in the foregoing description indicates that the features so described may be more desirable, it may not be necessary, and embodiments lacking these words may be contemplated as being within the scope of this disclosure, defined by the appended claims. When reading the claims, it is intended that when words such as “a,” “an,” “at least one,” or “at least one part” are used, there is no intention to limit the claims to only one item unless specifically stated otherwise in the claims. The term “of” can mean an association or connection with another item, and an attribution or connection to another item as indicated by the context in which it is used. Unless explicitly indicated otherwise, the terms “coupled to,” “coupled with,” etc., include indirect connection and coupling, and further include but do not require direct coupling or connection. When the language “at least a part” and / or “a part” is used, the item may include a part and / or the whole item unless specifically stated otherwise.

Claims

1. A power network comprising: Multiple areas, each area includes: a plurality of measurement devices structured to measure electrical characteristics of corresponding regions; a zone controller structured to receive measurements from the plurality of measurement devices, Distributed Energy Resources (DER), and load; wherein each regional controller is structured to receive a set of local measurements from the plurality of measurement devices in the corresponding region, calculate a sensitivity matrix using the received set of local measurements, determine whether a voltage variation has occurred in the corresponding region, determine a DER set point using the received set of local measurements in response to determining that the voltage variation has occurred in the corresponding region, the DER set point being determined using the sensitivity matrix, and transmit the DER set point to the DER, wherein each regional controller calculates the sensitivity matrix using no measurements other than the set of local measurements, and wherein the calculated sensitivity matrix captures mutual influences of other regions in the plurality of regions.

2. The power network according to claim 1, wherein: Each zone controller uses the set of local measurements to roughly estimate the impact of other zones in the power network.

3. A power network according to claim 1 or claim 2, wherein: Each zone controller determines whether a voltage surge has occurred by receiving a reference value from outside the corresponding zone and comparing the reference value with the set of local measurement values.

4. The power network according to claim 1 or 2, wherein: The regional controller is structured to receive a second set of local measurements after transmitting the DER setpoint to the DER and to use the second set of local measurements to verify that the DER is operating using the DER setpoint.

5. The power network according to claim 4, wherein: The zone controller uses the second set of local measurements to update the sensitivity matrix in a recursive least squares algorithm step.

6. The power network according to claim 5, wherein: The zone controller calculates the sensitivity matrix using the following set of equations, where i is the zone number, M is the auxiliary matrix, t0 is the initial time, A is the measurement matrix, W is the weighting matrix, Π is the constant regularization matrix, Λ is the sensitivity matrix, D is the voltage measurement matrix, and the superscript T represents the transpose of the corresponding matrix:

7. The power network according to claim 6, wherein: The measurement matrix A and matrix D are defined as follows, where t represents the time, i represents the region number, ΔP is the change in regional active power, ΔQ is the change in regional reactive power, ΔV is the voltage change, and express The lines:

8. The power network according to any one of claims 1-2 and 5-7, wherein: The DER is operated in a power factor correction mode, and wherein the regional controller determines the DER set point using the received reactive power reference and the following system of equations, where y is an auxiliary variable, t is the time, V l is the lower bound of the voltage reference, V μ is the upper bound of the voltage reference value, Λ VQ,t is the block of the sensitivity matrix Λ relating voltage changes to changes in reactive power, Q is the reactive power, DER is the DER for which the set point is being calculated, is the reactive power setpoint, ΔQ is the change in reactive power, the superscript indicates whether the reactive power refers to the load or DER rated power, and the superscript T denotes the transpose of the corresponding matrix: For over-voltage change, Maximize y t Satisfaction For undervoltage transformer, Minimize y t Satisfaction 9. The power network according to any one of claims 1-2 and 5-7, wherein: The DERs are operated in a unified mode, and wherein the zone controllers determine the DER set points using the following system of equations, where y is an auxiliary variable, t is the time, V l is the lower bound of the voltage reference, V μ is the upper bound of the voltage reference value, Λ VP,t is the block of the sensitivity matrix Λ relating voltage changes to changes in active power, P is the active power, and DER is the DER for which the setpoint is being calculated, and is the active power setpoint, ΔP is the change in active power, the superscript indicates whether the active power refers to the load or the DER rated power, and the superscript T denotes the transpose of the corresponding matrix: For undervoltage transformer, Minimize y t Satisfaction For over-voltage change, Maximize y t Satisfaction 10. The power network according to any one of claims 1-2 and 5-7, wherein: Determining the DER setpoint includes determining, by the regional controller, that a time for determining the DER setpoint using the regional controller exceeds a threshold, and wherein, in response to determining that the time for determining the DER setpoint using the regional controller exceeds the threshold, the DER setpoint is determined using a cloud-hosted virtual machine.

11. A method for operating an electric power network divided into a plurality of areas, the method comprising: operating a first zone of the plurality of zones using a zone controller, the plurality of zones comprising: a plurality of measurement devices structured to measure electrical characteristics of the first zone; a distributed energy resource DER; and a load; receiving, with the zone controller, a set of local measurements from the plurality of measurement devices corresponding to a zone; calculating, with the zone controller, a sensitivity matrix using the received set of local measurements; Determining, using the zone controller, whether a voltage change has occurred in the corresponding zone; In response to determining that the voltage voltage transition has occurred in the corresponding zone, determining, with the zone controller, a DER setpoint using the received set of local measurements; and communicating the DER setpoint to the DER using the regional controller, Wherein each zone controller does not use measurements other than the set of local measurements to calculate the sensitivity matrix, wherein the calculated sensitivity matrix captures mutual influences of other zones in the plurality of zones.

12. The method according to claim 11, wherein: Each zone controller uses the set of local measurements to roughly estimate the impact of other zones in the power network.

13. The method according to claim 11 or claim 12, wherein: The zone controller determines whether a voltage variation has occurred by receiving a reference value from outside the corresponding zone and comparing the reference value with the set of local measurement values.

14. The method according to claim 11 or 12, wherein: The regional controller is structured to receive a second set of local measurements after transmitting the DER setpoint to the DER and to use the second set of local measurements to verify that the DER is operating using the DER setpoint.

15. The method according to claim 14, wherein: The zone controller uses the second set of local measurements to update the sensitivity matrix in a recursive least squares algorithm step.

16. The method according to claim 15, wherein: The zone controller calculates the sensitivity matrix using the following set of equations, where i is the zone number, M is the auxiliary variable, t0 is the initial time, A is the measurement matrix, W is the weighting matrix, Π is the constant regularization matrix, Λ is the sensitivity matrix, D is the voltage measurement matrix, and the superscript T represents the transpose of the corresponding matrix:

17. The method according to claim 16, wherein: The measurement matrix A and matrix D are defined as follows, where t represents the time, i represents the region number, ΔP is the change in regional active power, ΔQ is the change in regional reactive power, ΔV is the voltage change, and express The lines:

18. The method according to any one of claims 11-12 and 15-17, wherein: The DER is operated in a power factor correction mode, and wherein the regional controller determines the DER set point using the received reactive power reference and the following system of equations, where y is an auxiliary variable, t is the time, V ι is the lower bound of the voltage reference, V μ is the upper bound of the voltage reference value, Λ VQ,t is the block of the sensitivity matrix Λ relating voltage changes to changes in reactive power, Q is the reactive power, and DER is the DER for which the setpoint is being calculated: For over-voltage change, Maximize y t Satisfaction For undervoltage transformer, Minimize y t Satisfaction 19. The method according to any one of claims 11-12 and 15-17, wherein: The DERs are operated in a unified mode, and wherein the zone controllers determine the DER set points using the following system of equations, where y is an auxiliary variable, t is the time, V ι is the lower bound of the voltage reference, V μ is the upper bound of the voltage reference value, Λ VP,t is the block of the sensitivity matrix Λ relating voltage changes to changes in active power, P is the active power, and DER is the DER for which the setpoint is being calculated, and is the active power setpoint, ΔP is the change in active power, the superscript indicates whether the active power refers to the load or the DER rated power, and the superscript T denotes the transpose of the corresponding matrix: For undervoltage transformer, Minimize y t Satisfaction For over-voltage change, Maximize y t Satisfaction 20. The method according to any one of claims 11-12 and 15-17, wherein: Determining the DER setpoint includes determining, by the regional controller, that a time for determining the DER setpoint using the regional controller exceeds a threshold, and wherein, in response to determining that the time for determining the DER setpoint using the regional controller exceeds the threshold, the DER setpoint is determined using a cloud-hosted virtual machine.

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