Method and system for automatic voltage regulation of renewable energy plants

Abstract

A method for regulating voltage of electric power provided by an energy plant coupled to an electric power grid, the energy plant having at least one inverter-based resource ("IBR") coupled to the electric power grid via at least one inverter, the method comprising: using a control system communicatively coupled to an inverter of an IBR, implementing an automatic voltage regulator ("AVR") in the control system, the AVR having selectable control modes including a voltage control mode, a reactive power control mode, and a power factor control mode; receiving one or more command messages at the AVR for selecting a control mode; generating one or more command messages for controlling operations of the inverter; and, transmitting the one or more command messages for controlling operations of the inverter from the AVR to the inverter of the IBR for controlling operations of the inverter in accordance with the control mode selected.

Description

METHOD AND SYSTEM FOR AUTOMATIC VOLTAGE REGULATION OF RENEWABLE ENERGY PLANTS

[0001] This application claims priority from and the benefit of the filing date of United States Provisional Patent Application No. 63 / 617,191, filed January 3, 2024, and the entire content of such application is incorporated herein by reference.FIELD OF THE APPLICATION

[0002] This application relates to the field of control systems, and more specifically, to a method and system for automatic voltage regulation of renewable energy plants, and the like.BACKGROUND OF THE APPLICATION

[0003] The ability of a power system to comply with reactive power requirements and maintain grid voltage within a safe range is crucial for stability and reliability of transmission systems. (See “UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Order No. 827 Reactive Power Requirements for Non-Synchronous Generation”; https: / / www.ferc.gov / sites / default / files / 2020-06 / RM16-l-000.pdf; accessed March 15, 2023; and incorporated herein by reference.)

[0004] FIG. 1 is a block diagram illustrating an example PV power (or energy) plant 100 in accordance with the prior art. (See "WECC Solar Plant Dynamic Modeling Guidelines"; https: / / www.wecc.biz / Reliability / WECC%20Solar%20Plant%20Dynamic%20Modeling%20 Guidelines.pdf; accessed March 15, 2023; and, incorporated herein by reference.) Typical grid- connected inverter-based generators (“IBG”) may include battery energy storage systems (“BESS”) and renewable energy plants such as photovoltaic (“PV”) plants and wind plants, and their hybrids. The power plant 100 includes PV arrays 110 which supply DC power to inverters 120. AC current injected by the inverters 120 is stepped-up to medium voltage by PV inverter transformers 130 and transmitted by a medium voltage PV feeder 140. Further upstream, the medium voltage is stepped up by a substation transformer 150 which typically is equipped with an on-load tap changer (“OLTC”). The substation transformer 150 is connected via an interconnection line 160 to an electric energy transmission network (e.g., the bulk-power system, an electric power grid, etc.) 170 at a point-of-interconnection (“POT’) 175. Plant reactive compensation devices 180, if present, are connected at the plant medium voltage bus190. The power plant control system, which is necessary to maintain grid reliability, includes inverter controls (or inverter control systems) located inside the inverters 120, a PV plant supervisory control system (or controller) 200, and other controls and relay protection devices omitted in FIG. 1 for clarity. The above-mentioned control devices typically communicate with each other using a power plant communication network. The PV plant supervisory control system 200 typically acquires electrical properties 201 from the POI 175 and communicates with a plant fleet remote operations center 210 and a utility system operations center 220.

[0005] FIG. 2 is a block diagram illustrating a control system (e.g., the PV plant supervisory control system 200 of FIG. 1) for a renewable energy plant 100 in accordance with the prior art. (See “Guideline for PSSE Stability Modeling of Inverter-Based DER > 5 MW to Meet National Grid SRD for Western RI DER ASO 3”;accessedMarch 15, 2023; and incorporated herein by reference). The control system 200 typically includes the following components and functions. First, a closed-loop automatic voltage regulator (“AVR”) controlling voltage at a user-designated bus (e.g., 190). A voltage feedback signal 402 has provisions for line drop compensation, voltage droop response, and a usersettable deadband on a voltage error signal. Second, AVR closed-loop reactive power regulation on a user-designated branch 403 with user-selectable deadband on a reactive power error signal. Third, AVR closed-loop power factor control. Fourth, a plant-level governor acting on a signal which derives from frequency deviation 407 at a user-designated bus (e.g., 190). A frequency droop response is applied to active power flow on a user-designated branch 406 (e.g., 140). The frequency deviation applied to the droop gain is typically subject to a usersettable deadband.

[0006] One problem with such existing plant supervisory control systems 200 is that they typically do not limit injected and absorbed reactive power beyond required amounts which may decrease power generation.

[0007] Another problem with the inverter control systems of such existing plant supervisory control systems 200 is that they typically do not optimally distribute commands among the inverters 120 which may also decrease power generation.

[0008] A further problem with the inverter control systems of such existing plant supervisory control systems 200 is that they typically do not provide smooth, bumpless transitions betweencontrol modes which may result in a bumpy controlled process.

[0009] A need therefore exists for an improved method and system for automatic voltage regulation of renewable energy plants. Accordingly, a solution that addresses, at least in part, the above and other shortcomings is desired.SUMMARY OF THE APPLCIATION

[0010] According to one aspect of the application, there is provided a method for regulating voltage of electric power provided by an energy plant coupled to an electric power grid, the energy plant having at least one inverter-based resource (“IBR”) coupled to the electric power grid via at least one inverter, the method comprising: using a control system communicatively coupled to an inverter of an IBR, implementing an automatic voltage regulator (“AVR”) in the control system, the AVR having one or more selectable control modes, the control modes including a voltage control mode, a reactive power control mode, and a power factor control mode; receiving one or more command messages at the AVR for selecting a control mode; while the voltage control mode is selected: continuously updating a reactive power reference value with a measured reactive power value to prevent abrupt changes in reactive power when transferring between the voltage control mode and the reactive power control mode; continuously updating a power factor reference value with a measured power factor value to prevent abrupt changes in power factor when transferring between the voltage control mode and the power factor control mode; generating one or more command messages for controlling operations of the inverter using the reactive power reference value and the power factor reference value; while the reactive power control mode is selected: continuously updating a power factor reference value with a measured power factor value to prevent abrupt changes in power factor when transferring between the reactive power control mode and the power factor control mode; generating one or more command messages for controlling operations of the inverter using the power factor reference value; while the power factor control mode is selected: continuously updating a reactive power reference value with a measured reactive power value to prevent abrupt changes in reactive power when transferring between the power factor control mode and the reactive power control mode; generating one or more command messages for controlling operations of the inverter using the reactive power reference value; and, transmitting the one or more command messages for controlling operations of the inverter from the AVR to the inverter of the IBR for controlling operations of the inverter in accordance withthe control mode selected to thereby regulate voltage of the electric power provided by the energy plant.

[0011] In accordance with further aspects of the application, there is provided an apparatus such as an information system, a controller, a control system, a computer system, etc., a method for adapting these, as well as articles of manufacture such as a computer readable medium or product and computer program product or software product (e.g., comprising a non-transitory medium) having program instructions recorded thereon for practicing the method of the application.BRIEF DESCRIPTION OF THE DRAWINGS

[0012] Further features and advantages of the embodiments of the present application will become apparent from the following detailed description, taken in combination with the appended drawings, in which:

[0013] FIG. 1 is a block diagram illustrating an example PV power plant in accordance with the prior art;

[0014] FIG. 2 is a block diagram illustrating a control system for a renewable energy plant in accordance with the prior art;

[0015] FIG. 3 is a block diagram illustrating an information system in accordance with an embodiment of the application;

[0016] FIG. 4 is a graph illustrating renewable energy plant reactive capability requirements versus POI voltage in accordance with an embodiment of the application;

[0017] FIG. 5 is a graph illustrating renewable energy plant reactive capability requirements versus POI active power in accordance with an embodiment of the application;

[0018] FIG. 6 is a graph illustrating inverter active-reactive capability in accordance with an embodiment of the application;

[0019] FIG. 7 is a block diagram illustrating AVR feedforward control in accordance with an embodiment of the application;

[0020] FIG. 8 is a graph illustrating the calculation of Wext in accordance with an embodimentof the application;

[0021] FIG. 9 is graph illustrating reactive power at the POI as displayed at a control system in accordance with an embodiment of the invention;

[0022] FIG. 10 is a flowchart illustrating operations of a shunt controller in accordance with an embodiment of the application;

[0023] FIG. 11 is a graph illustrating a control system performing capacitor connection in accordance with the prior art; and,

[0024] FIG. 12 is a flow chart illustrating operations of modules within an information system for regulating voltage of electric power provided by an energy plant coupled to an electric power grid, the energy plant having at least one inverter-based resource (“IBR”) coupled to the electric power grid via at least one inverter, in accordance with an embodiment of the application.

[0025] It will be noted that throughout the appended drawings, like features are identified by like reference numerals.DETAILED DESCRIPTION OF THE EXAMPLE EMBODIMENTS

[0026] In the following description, details are set forth to provide an understanding of the application. In some instances, certain software, circuits, structures and methods have not been described or shown in detail in order not to obscure the application. The term “information system” or “system” is used herein to refer to any machine for processing data, including the control systems, supervisory control systems, controllers, energy management systems, supervisory control and data acquisition (“SCADA”) systems, computer systems, and network arrangements described herein. The present application may be implemented in any computer programming language provided that the operating system of the data processing system provides the facilities that may support the requirements of the present application. Any limitations presented would be a result of a particular type of operating system or computer programming language and would not be a limitation of the present application. The present application may also be implemented in hardware or in a combination of hardware and software.

[0027] According to one embodiment of the application, there is provided an improved method and system (e.g., 200) for providing automatic voltage regulation for a renewable energy plant 100 coupled to an electric power grid 170, the renewable energy plant 100 having an intermittent energy source (e.g., PV arrays 110). Advantageously, and as further described below, the method and system for automatic voltage regulation of renewable energy plants of the present application may provide one or more of the following: a bumpless transfer between AVR voltage / reactive / power factor control modes; AVR feedforward control; AVR PI loop scheduling and bumpless loop tuning; AVR auto / manual control modes and a bumpless transfer between these mode; plant reactive capability with reactive and power factor limit control; a voltage limit control mode; reactive command distribution between inverters; and, plant reactive compensation. The method and system 200 for automatic voltage regulation of renewable energy plants of the present application provides one or more improvements to existing methods and systems such as those shown in FIGS. 1 and 2.

[0028] FIG. 3 is a block diagram illustrating an information system 1000 in accordance with an embodiment of the application. The information system 1000 is suitable for performing as a supervisory control system (e.g., 200), control system, controller, supervisory control and data acquisition (“SCADA”) system, energy management system (“EMS”), or the like. The information system 1000 may be implemented as a virtual machine. The information system 1000 may be a client and / or a server in a client-server configuration. As an example, the information system 1000 may be a server and / or a personal computer, microcontroller, etc. The information system 1000 may be a distributed system deployed on multiple processors or hosts.

[0029] The information system 1000 includes a display 1100, a processor or CPU 1200, an input device 1300, memory 1400, and an interface device 1600. The display 1100 may include a computer screen or a television screen. The CPU 1200 is coupled to memory 1400 that stores an operating system 1420 to manage the information system 1000. The CPU 1200 is operatively coupled to an input device 1300 for receiving user commands and to the display 1100 for displaying the results of these commands to a user. These commands may also be received over a network 1700 via the interface device 1600. The CPU 1200 may operate in association with dedicated co-processors, memory devices, or other hardware modules 1500. The input device 1300 may include a keyboard, mouse, touchpad, or the like. The memory 1400 may include a plurality of storage devices including internal memory and an external storage device. For example, the memory 1400 may include databases, random access memory,read-only memory, flash drives, solid state drives, and / or hard disk devices. The information system 1000 may include a database management system and a database 1410 that may be stored in the memory 1400 of the information system 1000. The interface device 1600 may include one or more network connections. The information system 1000 may be adapted to communicate with other information systems (e.g., 1000, 200, 210, 220) over a network 1700 via the interface device 1600. For example, the interface device 1600 may include an interface to a network 1700 such as the Internet, a wireless network, a wired network, a serial communications network, etc. Thus, the interface 1600 may include suitable transmitters, receivers, connectors, and the like. The information system 1000 may be associated with other information systems (e.g., 1000, 200, 210, 220) over the network 1700. Of course, the information system 1000 may include additional software and hardware, the description of which is not necessary for understanding the application.

[0030] The information system 1000 includes programmed computer-executable instructions to implement the embodiments of the present application. The instructions may be embodied in one or more hardware modules 1500 or program (software) modules (e.g., 1420) resident in the memory 1400 of the information system 1000. Alternatively, programmed instructions may be embodied on a machine-readable medium or product such as one or more DVDs, CDs, etc.

[0031] A user may interact with the information system 1000 using a user interface (“U ’) 1120 such as a graphical user interface. The UI 1120 may be used for monitoring, managing, and accessing the information system 1000. Typically, a UI is used to display information to and receive commands from users and includes a variety of controls including icons, dropdown menus, toolbars, text, buttons, and the like. A user interacts with the UI 1120 presented on a display 1100 by using an input device 1300 to position a pointer or cursor 1122 over a graphical object, for example, an icon, menu, etc. 1121 and by selecting the object 1121. Typically, UI elements are presented in at least one window 1110, that is, a rectangular area within the display 1100. A window 1110 may be open, closed, displayed full screen, reduced in size, or moved to different areas of the display 1100.

[0032] According to one embodiment of the application, the method and system 200 for automatic voltage regulation of renewable energy plants 100 provides a bumpless transfer between AVR voltage / reactive / power factor control modes. Referring to FIG. 2, the AVR may operate in mutually exclusive voltage, reactive power, or power factor control modes formaintaining voltage, reactive power, or power factor, respectively. To prevent abrupt voltage and power flow changes for an inverter-based resource (“IBR”), the AVR implements a bumpless transfer between control modes when switching the reference flag 413 into a desired position.

[0033] For voltage control mode, the reference flag 413 is set to position " 1 ". In this mode, the reactive power reference 404 is continuously updated with measured reactive power 403 to prevent abrupt changes in reactive power when the AVR control mode is transferred from voltage mode to reactive power mode. Also, the power factor reference 412 is continuously updated with the measured power factor to prevent abrupt changes in power factor when the AVR control mode is transferred from voltage mode to power factor control mode.

[0034] For reactive power mode, the reference flag 413 is set to position "0". In this mode, the power factor reference 412 is continuously updated with the measured power factor to prevent abrupt changes in power factor when the AVR control mode is transferred from reactive mode to power factor control mode.

[0035] In the following, the prevention of abrupt changes when the AVR is transferred from reactive mode to voltage control mode is described.

[0036] If the droop flag for voltage control 414 is set to position "0" for reactive droop compensation, voltage reference (Vref) 409 is continuously updated with the following value:

[0037] Vref = Vt + Ibranch*Kc, where: [1]

[0038] Vt is the bus voltage (p.u.);

[0039] Ibranch is the branch current (p.u.); and,

[0040] Kc is reactive droop (p.u.).

[0041] Note that in equation [1], the branch current may be replaced with branch reactive power. In addition, per unit (p.u.) values in equation [1] may be replaced with engineering unit calculations.

[0042] If the droop flag for voltage control 414 is set to position " 1 " for current compensation, voltage reference (Vref) 409 is continuously updated with the following value:

[0043] Vref = Vt - (Rc + Xc)*Ibranch, where: [2]

[0044] Vt is the bus voltage (p.u.);

[0045] Rc is the line drop compensation resistance (p.u.);

[0046] Xc is the line drop compensation reactance (p.u.); and,

[0047] Ibranch is the branch current (p.u.).

[0048] For power factor mode, the reference flag 413 is set to position "2". In this mode, the reactive power reference (Qref) 404 is continuously updated with the measured reactive power (Qbranch) 403 to prevent abrupt changes in reactive power when the AVR control mode is transferred from power factor mode to reactive power control mode.

[0049] To prevent abrupt AVR changes when the control mode is transferred from power factor mode to voltage control mode, voltage reference tracking is provided as described above.

[0050] According to one embodiment of the application, the method and system 200 for automatic voltage regulation of renewable energy plants 100 provides AVR feedforward control. Feed forward is important for obtaining the desired response to references such as voltage reference Vref 409 or reactive reference Qref 404 as shown in FIG. 2.

[0051] FIG. 7 is a block diagram illustrating AVR feedforward control in accordance with an embodiment of the application. The desired response may include requirements for rise time, settling time, and overshoot, among other requirements for changing the references. The rise time tr is typically defined as the transition time between initial and final steady state values, for example 10% and 90%. The settling time ts is the time until the transient response stays within, typically 2% of the steady state value. The “overshoot” is the ratio of the difference between the first peak and stationary value.

[0052] The control signal Wext 410 consists of feedback proportional Kp and integral Ki components and a feedforward component Kff from a measurement disturbance or setpoint Qref 404 as shown in FIGS. 2 and 7.

[0053] To avoid integrator windup, anti-windup provisions act on the final control signal Wexp410. As an example of anti-windup provisions, in FIGS. 2 and 7, the control signal limits Qmin415 and Qmax 416 preventing a feedback integrator increase when the control signal reaches Qmax limit 418 and a feedback integrator decrease when the control signal drops to Qmin limit 417

[0054] According to one embodiment of the application, the method and system 200 for automatic voltage regulation of renewable energy plants 100 provides AVR PI loop scheduling and bumpless loop tuning. Referring to FIG. 2, the voltage regulator may have Kp proportional gain 419 and Ki integral gain 420 separately for voltage and for reactive and power factor control modes. The gain values are assigned to Kp and Ki prior to changing the reference flag 413 position.

[0055] The gain values may have different values based on operating conditions such as voltage, power, and reactive power. For example, Kp proportional gain 419 and Ki integral gain 420 points may have one set of values for a range of lower voltages Vt 402 and another set of gains for the higher range.

[0056] To prevent abrupt changes in controlled variables when tuning the Kp proportional gain 419 and Ki integral gain 420 or transitioning between operating conditions, the PI controller s2 417 may be implemented as a velocity controller. One example equation for the controller 200 is as follows:

[0057] Out = OutPrev + Kp*(E-El) + BOOL TO REAL (NOT Freeze) *Ki*E*deltaT + (Tr - OutPrev) *Kt*deltaT, where: [3]

[0058] OutPrev is the previous cycle output;

[0059] Kp is the proportional gain 419;

[0060] E is the controller error, i.e., difference between controller setpoint and process variable (e.g., for voltage control mode, Vref 409 and Vt 402);

[0061] El is the previous cycle error E;

[0062] BOOL TO REAL is the conversion of logical value to floating point value;

[0063] Freeze is the controller freeze state 418;

[0064] Ki is the integral gain 416;

[0065] detaT is the time between last and previous cycles;

[0066] Tr is the tracking signal; and,

[0067] Kt is the tracking gain.

[0068] Note that the tracking signal and gain serving as a controller anti-windup provision are described in more detail in United States Patent No. 11,451,062 B2, issued September 20, 2022, and incorporated herein by reference.

[0069] According to one embodiment of the application, the method and system 200 for automatic voltage regulation of renewable energy plants 100 provides AVR auto / manual control modes and a bumpless transfer between these modes. In a normal operating mode, the AVR operates in an automatic closed-loop control as shown in FIG. 2. To provide allow the control system (e.g., 200 in FIGS. 1 and 2) to temporarily operate the energy plant 100 while repairing faulty equipment such as power metering or communications between the power meter and the control system 200, the AVR may implement an open-loop control mode.

[0070] The AVR may automatically transition to the open-loop control mode after measurement 201 failure. These measurements 201 (See FIG. 1) may include active or reactive power, voltage, power factor, and system frequency. The transition may be caused by a malfunction of the power meters or a loss of communication between the power meters and the control system 200. The failure may be identified by comparing a measurement value with a required range, or monitoring measurement quality as set by the power meter, or any other method. The transition may be performed immediately after measurement failure, or after a configurable timeout. Of course, the transition does not occur if the measurement is restored within the timeout. The AVR’s transition to the open-loop control mode may also be initiated by an operator command.

[0071] In the open-loop mode, the AVR does not use measurements 201 as feedback to determine whether the output has achieved the desired setpoints. Therefore, in the open-loop control mode, the control system 200 cannot correct control errors and compensate for disturbances in the power system (e.g., 100, 170).

[0072] The control system 200 may provide a smooth transition from the open-loop control mode to the closed-loop control mode and vice versa. To provide bumpless transfer, the AVRsetpoints are backtracked as described herein with respect to the bumpless transfer between AVR voltage / reactive / power factor control modes. Since measurements are not available when switching to the open-loop control mode, the AVR may also transfer to reactive power mode from the voltage or power factor control modes.

[0073] When going backward from an open-loop control mode to a closed-loop control mode, the AVR may maintain the reactive power control mode until the operator changes it to the voltage or power factor control mode. Alternatively, prior to the transition to the open-loop control mode, the control system 200 may save the control mode. After going backward from the open-loop control mode to the closed-loop control mode, the AVR may transition back to the previously saved control mode.

[0074] After measurements 201 are made available for the control system 200, an operator may initiate a transition from the open-loop control mode back to the closed-loop voltage, reactive, or power factor control mode if valid measurement data is available for the control system 200. Alternatively, the control system 200 may automatically initiate the transition from the open loop control mode to the closed loop control mode when the measurements 201 become available for the control system 200.

[0075] According to another embodiment as illustrated in FIG. 8, the AVR transitions from the closed-loop voltage control mode to the open-loop voltage control mode. During this transition, measured voltage Vt 402 is stored in the memory 1400 of the control system 200. This value does not change until the control mode is switched back to the closed-loop control mode. The stored value is used in the calculation of Wext 410 where the stored Vt value is subtracted from voltage reference Vref 409 and proceeds through the V-Q curve to define reactive injection / absorption Wext 410.

[0076] According to one embodiment of the application, the method and system 200 for automatic voltage regulation of renewable energy plants 100 provides plant reactive capability with reactive and power factor limit control. FIG. 5 is a graph illustrating renewable energy plant 100 reactive capability requirements versus POI 175 active power in accordance with an embodiment of the application. In particular, FIG. 5 illustrates exemplary plant reactive capability requirements 3000 as a function of active power. The reactive requirements as a function of active power are typically specified by grid codes at a high side of the station transformer 190 or the POI 175 as shown in FIG. 2. Reactive power capability can have a coneshape 3010, a rectangular shape 3020, or their combination as illustrated in FIG. 5.

[0077] FIG. 4 is a graph illustrating renewable energy plant 100 reactive capability requirements versus POI 175 voltage in accordance with an embodiment of the application. In particular, FIG. 4 illustrates an exemplary plant reactive capability requirement 4000 as a function of voltage at the high side of the substation transformer 190 or the POI 175 as specified in the grid codes. FIG. 4 shows the required reactive capability with the x-axis relating to voltage and the y-axis relating to reactive power.

[0078] Injected or absorbed reactive power for a given POI 175 active power and voltage is limited beyond the capability requirements 3000 and 4000 by a reactive high limit Qmax 416 and low limit Qmin 415 (see FIG. 2). The limits Qmin 415 and Qmax 416 are defined by characteristics 3000 and 4000 accounting for a specified reliability margin and reactive power loss.

[0079] The reactive power loss between the inverter terminals (e.g., 120) and POI 175 may be modeled using well known methods. The reliability margin ensures that the plant reactive capability is in compliance with the abovementioned requirements.

[0080] According to one embodiment of the application, the method and system 200 for automatic voltage regulation of renewable energy plants 100 provides a voltage limit control mode. Voltage limit control is important when the AVR is operating in either the power factor or reactive power control modes. Referring to FIG. 4, the AVR maintains reactive power between low limit 4002 and high limit 4001 while the voltage low limit 4003 and high limit 4004 are not violated. Otherwise, to prevent over- and under-voltage conditions, the AVR may maintain the operating point within the voltage limits. In the power factor mode, the AVR maintains a power factor similar to reactive power.

[0081] Referring again to FIG. 4, the AVR initially operates in reactive power control mode with unity power factor and close to nominal voltage (operating point 4005). When the grid voltage increases, the operating point moves closer to the maximum voltage limit (operating point 4006). As soon as one of the voltage limit 4004 is violated, the control system 200 overrides the reactive power reference, keeping the voltage within the specified range. In the example shown in FIG. 4, the AVR begins to absorb reactive power by moving the operating point along the maximum voltage limit to operating point 4007. Note that since the AVR isoperating in voltage control mode, the reactive power increases and is not controlled by the AVR.

[0082] Reducing the voltage leads to a decrease in reactive power absorption, and therefore the operating point moves back until the reactive power reaches its reference at operating point 4006. At this point, the voltage limit is not violated, and the AVR maintains the target reactive power. Timeout and hysteresis may be applied to the voltage limits preventing the AVR voltage to reactive mode from transitioning back and forth near the operating point. If the power system voltage continues to decrease, the operating point moves away from the maximum limit to operating point 4005.

[0083] According to one embodiment of the application, the method and system 200 for automatic voltage regulation of renewable energy plants 100 provides reactive command distribution between inverters 120 (see FIG. 1). Optimization of reactive power command Wext 410 (see FIG. 2) distribution among the solar PV inverters 120 is described in the following.

[0084] FIG. 6 is a graph illustrating inverter active-reactive capability in accordance with an embodiment of the application. In particular, FIG. 6 illustrates a PV inverter P-Q graph 2000. The graph 2000 is characterized by a circular shaped PQ curve 2002, a rated power Pmax 2001 achieved at unity power factor, a maximum reactive power Qmax 2003, and a minimum reactive power -Qmax 2004.

[0085] To comply with plant reactive capability requirements, the inverters 120 typically have reactive power priority set over active power. When the inverter P-Q operating point defined by control system 200 commands Pext 411 and Wext 410 (see FIG. 2) resides outside of the capability curve 2002, the inverter 120 satisfies reactive command and then active commands positioning the operating point at the capability curve 2002.

[0086] During cloudy conditions, inverters 120 with shaded PV arrays 110 may inject or absorb more reactive power without sacrificing active power when compared to inverters 120 with non-shaded PV arrays 110. Note that the reactive capability curve is a function of ambient temperature, terminal voltage, and other parameters.

[0087] Reactive command Wext 410 distribution among the individual inverters 120 has thegoal of maximizing the energy plant's power generation. To minimize transportation losses for the inverters 120 operating inside of the capability chart area, the reactive command should be evenly distributed among the inverters 120. For those inverters 120 running at the maximum power point (“MPP”), their operating points are situated on the vertical line 2006 shown in FIG. 6. All other inverters 120 are commanded to operate along capability curve 2005 between unity power factor and the line 2006.

[0088] The reactive command Wext 410 distribution algorithm (or method) among the individual inverters 120 includes the following steps.

[0089] First, reactive losses between the inverters 120 and the point of interconnection (POI) 175 is estimated using, for example, the following equation:

[0090] Qloss = Il sign*Il_mag*Il_mag*Xc / mbase, where: [4]

[0091] Qloss is the reactive power loss in p.u.;

[0092] Il sign is the current direction;

[0093] Ilmag is the current magnitude in p.u.;

[0094] Xc is the line drop compensation reactance; and,

[0095] mbase is the MVA base.

[0096] Second, the reactive command is compensated with reactive loss as follows:

[0097] Qextl = Qext + Qloss [5]

[0098] Third, line 2006 (see FIG. 6) is defined iteratively. All inverters 120 operating at the MPP with active power below the point of intersection between the line 2006 and the capability curve 2002 will have the Qcmd of line 2006. The operating points of all other inverters 120 will reside along the capability curve 2005. The sum of all inverters’ reactive injection or absorption should be equal to Qextl.

[0099] According to one embodiment of the application, the method and system 200 for automatic voltage regulation of renewable energy plants 100 provides plant reactive compensation. Referring to FIG. 1, plant reactive compensation 180 such as shunt capacitorsand / or reactors are intended to supplement reactive injection, or absorption, of the plant inverters 120. In the case of a voltage excursion, the control system 200 may calculate the reactive power to compensate for it. The control system 200 may send a reactive power command to fast-reacting inverters 120 for changing reactive injection or absorption.

[0100] FIG. 10 is a flowchart illustrating operations 10000 of a shunt controller (e.g., 200) in accordance with an embodiment of the application. To increase active power generation by reducing reactive power injection from the inverters 120, to conserve inverters’ reactive power allowing for a wider control range and faster response to voltage excursions, and to reduce power losses within the power plant 100, the shunt controller coordinates capacitors and inverters, substituting dynamic inverters’ reactive power with static VARs provided by capacitors and / or reactors. The shunt controller may be included in or implemented by the PV plant supervisory control or control system 200.

[0101] At step 10001, a reactive command Wext 410 is received by the shunt control’s input Qbr.

[0102] At step 10002, for a positive (capacitive) Wext (410 in FIG. 2) value, to minimize the number of switching operations, the capacitive command is compared with a high limit Qhi at step 10003 and a timer LimitTime is started at step 10004. The control system 200 stores the number of switching operations individually for each capacitor or reactor (or inductor). After the timer expires at step 10005, the control system 200 selects an available reactor at step 10006 with the lowest number of switching operations (step 10007). If no reactors are currently available, the control system 200 selects an available capacitor (step 10008) with the smallest number of switching operations (step 10009). The timer is reset and the operations 10000 start over if Wext drops below the limit Qhi or an operation error occurs (step 10010).

[0103] At step 10002, for a negative (inductive) Wext value, the value is compared with a low limit Qlow (step 10020) and a timer LimitTime is started (step 10021). After the timer expires (step 10024), the control system 200 selects an available capacitor (step 10025) with the lowest number of switching operations (step 10026). If capacitors are currently unavailable, the control system 200 selects an available reactor (step 10027) with the smallest number of switching operations (step 10028). The timer is reset and the operations 10000 start over if Wext increases above the limit Qlow or an operation error occurs (step 10022).

[0104] Advantageously, the control system 200 reduces voltage excursions caused by engaging or tripping capacitors or reactors. Solutions have been proposed for minimizing the transient effect of capacitor switching in plant control. For example, see Jorge Martinez Garcia, Aalborg University; "Voltage Control in Wind Power Plants with Doubly Fed Generators”; available at https: / / vbn.aau.dk / en / publications / voltage-control-in-wind-power-plants-with- doubly-fed-generators; accessed March 15, 2023; and incorporated herein by reference. The plant control performing capacitor connection described therein is shown in prior art FIG. 11 where it " . . . starts decreasing / increasing the Q reference in a value equal to the Q supplied to the capacitor step (Qmsc), before it is connected / disconnected, thus, this feed-forward action minimizes the Q impact of the connect! on / disconnecti on." However, this proposed solution does not consider voltage protection limits.

[0105] To prevent possible energy plant 100 and individual inverters’ over- and undervoltage trips, the control system 200 prior to connecting or tripping capacitors or reactors considers the inverters’ terminal voltages after a switching operation to define Qsh. The value Qsh is added to the AVR command prior to operation to ramp up or down reactive VARs to reduce the transient effect and under- or over-voltage conditions.

[0106] Voltages may be defined by an energy (or power) plant dynamic model. The control system 200 operation shown in FIG 9 illustrates reactive power at the POI 175. For example, reactive power increases reaching 20 MV AR are shown at operating point 5001. The control system 200 issues a freeze 418 AVR command (see FIG. 2) and decreases the AVR command by Qsh. Plant reactive power ramps down reaching approximately 0 MV AR at operating point 5002. The control system 200 engages capacitors increasing the reactive power to 27 MV AR at operating point 5003. The control system 200 then unfreezes the AVR outputs reaching operating point 5004. Note that Qsh is selected to minimize voltage transients while keeping the operating point 5003 below the high voltage limit.

[0107] Referring again to FIG. 10, the control system 200 freezes AVR output 410 (step 10050), adds to the output Qsh value to ramp up or down dynamic VARS, and starts the RampTime timer (step 10051). After the time expires (step 10052), a shunt close (step 10061) or trip (step 10062) operation is initiated. Close (step 10071) or trip (step 10072) fault timers are used to monitor and reset faulty operation. At step 10080, the timer stops (expires) and the operations 10000 start over.

[0108] The embodiments described herein may contribute to an improved method and system 200 for automatic voltage regulation of renewable energy plants 100 and may provide one or more advantages. First, the method and system of the present invention improves the operation of existing methods and system for automatic volage regulation of renewable energy plants 100.

[0109] Aspects of the methods and systems described herein may be illustrated with the aid of a flowchart.

[0110] FIG. 12 is a flow chart illustrating operations 12000 of modules (e.g., 1420, 1500) within an information system (e.g., 1000, 200, 210, 220) for regulating voltage of electric power provided by an energy plant 100 coupled to an electric power grid 170, the energy plant 100 having at least one inverter-based resource (“IBR”) 110 coupled to the electric power grid 170 via at least one inverter 120, in accordance with an embodiment of the application.

[0111] At step 12001, the operations 12000 start.

[0112] At step 12002, using a control system 200 communicatively coupled to an inverter 120 of an IBR 110, implementing an automatic voltage regulator (“AVR”) in the control system 200, the AVR having one or more selectable control modes, the control modes including a voltage control mode, a reactive power control mode, and a power factor control mode.

[0113] At step 12003, receiving one or more command messages at the AVR for selecting a control mode.

[0114] At step 12004, while the voltage control mode is selected: continuously updating a reactive power reference value with a measured reactive power value to prevent abrupt changes in reactive power when transferring between the voltage control mode and the reactive power control mode; continuously updating a power factor reference value with a measured power factor value to prevent abrupt changes in power factor when transferring between the voltage control mode and the power factor control mode; and, generating one or more command messages for controlling operations of the inverter 120 using the reactive power reference value and the power factor reference value.

[0115] At step 12005, while the reactive power control mode is selected: continuouslyupdating a power factor reference value with a measured power factor value to prevent abrupt changes in power factor when transferring between the reactive power control mode and the power factor control mode; and, generating one or more command messages for controlling operations of the inverter 120 using the power factor reference value.

[0116] At step 12006, while the power factor control mode is selected: continuously updating a reactive power reference value with a measured reactive power value to prevent abrupt changes in reactive power when transferring between the power factor control mode and the reactive power control mode; and, generating one or more command messages for controlling operations of the inverter 120 using the reactive power reference value.

[0117] At step 12007, transmitting the one or more command messages for controlling operations of the inverter from the AVR to the inverter 120 of the IBR 110 for controlling operations of the inverter 120 in accordance with the control mode selected to thereby regulate voltage of the electric power provided by the energy plant 100.

[0118] At step 12008, the operations 12000 end.

[0119] The above method may further include, while the power factor control mode is selected, to prevent abrupt changes in voltage when transferring between the power factor control mode and the volage control mode: receiving one or more command messages at the AVR for selecting between a reactive droop compensation mode and a current compensation mode; while the reactive droop compensation mode is selected: determining a voltage reference value (Vref) as a sum of a bus voltage (Vt) of the energy plant 100 and a branch current (Ibranch) of the IBR 110, the branch current (Ibranch) being scaled by a reactive droop value (Kc); and, generating the one or more command messages for controlling operations of the inverter 120 using the voltage reference value (Vref); and, while the current compensation mode is selected: determining the voltage reference value (Vref) as a difference between the bus voltage (Vt) of the energy plant 100 and the branch current (Ibranch) of the IBR 100, the branch current (Ibranch) being scaled by a sum of a line drop compensation resistance value (Rc) and a line drop compensation reactance value (Xc); and, generating the one or more command messages for controlling operations of the inverter 120 using the voltage reference value (Vref).

[0120] The above method may further include, while the reactive control mode isselected, to prevent abrupt changes in voltage when transferring between the reactive control mode and the volage control mode: receiving one or more command messages at the AVR for selecting between a reactive droop compensation mode and a current compensation mode; while the reactive droop compensation mode is selected: determining a voltage reference value (Vref) as a sum of a bus voltage (Vt) of the energy plant and a branch current (Ibranch) of the IBR, the branch current (Ibranch) being scaled by a reactive droop value (Kc); and, generating the one or more command messages for controlling operations of the inverter using the voltage reference value (Vref); and, while the current compensation mode is selected: determining the voltage reference value (Vref) as a difference between the bus voltage (Vt) of the energy plant and the branch current (Ibranch) of the IBR, the branch current (Ibranch) being scaled by a sum of a line drop compensation resistance value (Rc) and a line drop compensation reactance value (Xc); and, generating the one or more command messages for controlling operations of the inverter 120 using the voltage reference value (Vref).

[0121] In the above method, the energy plant may be a renewable energy plant 100. The energy plant may be a PV energy plant 100. The control system may be a plant supervisory control system 200. The one or more command messages for selecting a control mode may be received from one or more of a remote operations center 210 and a utility system operations center 220. The control system 200 may be communicatively coupled to one or more of the remote operations center 210 and the utility system operations center 220 over a network 1700. The IBR may be an intermittent energy source 110. And, the intermittent energy source may be a PV array 110.

[0122] According to one embodiment, each of the above steps 12001-12008 may be implemented by a respective software module 1420. According to another embodiment, each of the above steps 12001-12008 may be implemented by a respective hardware module 1500 (e.g., application-specific hardware 1500). According to another embodiment, each of the above steps 12001-12008 may be implemented by a combination of software 1420 and hardware modules 1500. For example, FIG. 12 may represent a block diagram illustrating the interconnection of specific hardware modules 12001-12008 (collectively 12000) within the information system or systems 1000, each hardware module 12001-12008 adapted or configured to implement a respective step of the method of the application.

[0123] According to one embodiment, one or more of the software 1420 and hardwaremodules 1500 (or to components referred to as a "module" herein) may be implemented by one or more information systems 1000 or components thereof.

[0124] According to one embodiment, certain implementations of the functionality of the present application are sufficiently mathematically, computationally, or technically complex that application-specific hardware (e.g., 1500) or one or more physical computing devices (e.g., 1000, 200, 210, 220) (using appropriate executable instructions (e.g., 1420)) may be necessary or essential to perform that functionality, for example, due to the volume or complexity of the calculations involved and / or to provide results substantially in real-time.

[0125] While this application is primarily discussed as a method, a person of ordinary skill in the art will understand that the apparatus discussed above with reference to an information system 1000 may be programmed to enable the practice of the method of the application. Moreover, an article of manufacture for use with an information system 1000, such as a pre-recorded storage device or other similar computer readable medium or computer program product including program instructions recorded thereon, may direct the information system 1000 to facilitate the practice of the method of the application. It is understood that such apparatus, products, and articles of manufacture also come within the scope of the application.

[0126] In particular, the sequences of instructions which when executed cause the method described herein to be performed by the information system 1000 may be contained in a data carrier product according to one embodiment of the application. This data carrier product may be loaded into and run by the information system 1000. In addition, the sequences of instructions which when executed cause the method described herein to be performed by the information system 1000 may be contained in a computer software product or computer program product (e.g., comprising a non-transitory medium) according to one embodiment of the application. This computer software product or computer program product may be loaded into and run by the information system 1000. Moreover, the sequences of instructions which when executed cause the method described herein to be performed by the information system 1000 may be contained in an integrated circuit product (e.g., a hardware module or modules 1420, 1500) which may include a coprocessor or memory according to one embodiment of the application. This integrated circuit product may be installed in the information system 1000.

[0127] The embodiments of the application described above are intended to be examples only. Those skilled in the art will understand that various modifications of detail maybe made to these embodiments, all of which come within the scope of the application.

Claims

WHAT IS CLAIMED IS:

1. A method for regulating voltage of electric power provided by an energy plant coupled to an electric power grid, the energy plant having at least one inverter-based resource (“IBR”) coupled to the electric power grid via at least one inverter, the method comprising: using a control system communicatively coupled to an inverter of an IBR, implementing an automatic voltage regulator (“AVR”) in the control system, the AVR having one or more selectable control modes, the control modes including a voltage control mode, a reactive power control mode, and a power factor control mode; receiving one or more command messages at the AVR for selecting a control mode; while the voltage control mode is selected: continuously updating a reactive power reference value with a measured reactive power value to prevent abrupt changes in reactive power when transferring between the voltage control mode and the reactive power control mode; continuously updating a power factor reference value with a measured power factor value to prevent abrupt changes in power factor when transferring between the voltage control mode and the power factor control mode; generating one or more command messages for controlling operations of the inverter using the reactive power reference value and the power factor reference value; while the reactive power control mode is selected: continuously updating a power factor reference value with a measured power factor value to prevent abrupt changes in power factor when transferring between the reactive power control mode and the power factor control mode; generating one or more command messages for controlling operations of the inverter using the power factor reference value; while the power factor control mode is selected: continuously updating a reactive power reference value with a measured reactive power value to prevent abrupt changes in reactive power when transferring between the power factor control mode and the reactive power control mode; generating one or more command messages for controlling operations of theinverter using the reactive power reference value; and, transmitting the one or more command messages for controlling operations of the inverter from the AVR to the inverter of the IBR for controlling operations of the inverter in accordance with the control mode selected to thereby regulate voltage of the electric power provided by the energy plant.

2. The method of claim 1, further comprising, while the power factor control mode is selected, to prevent abrupt changes in voltage when transferring between the power factor control mode and the vol age control mode: receiving one or more command messages at the AVR for selecting between a reactive droop compensation mode and a current compensation mode; while the reactive droop compensation mode is selected: determining a voltage reference value (Vref) as a sum of a bus voltage (Vt) of the energy plant and a branch current (Ibranch) of the IBR, the branch current (Ibranch) being scaled by a reactive droop value (Kc); and, generating the one or more command messages for controlling operations of the inverter using the voltage reference value (Vref); and, while the current compensation mode is selected: determining the voltage reference value (Vref) as a difference between the bus voltage (Vt) of the energy plant and the branch current (Ibranch) of the IBR, the branch current (Ibranch) being scaled by a sum of a line drop compensation resistance value (Rc) and a line drop compensation reactance value (Xc); and, generating the one or more command messages for controlling operations of the inverter using the voltage reference value (Vref).

3. The method of claim 1, further comprising, while the reactive control mode is selected, to prevent abrupt changes in voltage when transferring between the reactive control mode and the volage control mode: receiving one or more command messages at the AVR for selecting between a reactive droop compensation mode and a current compensation mode; while the reactive droop compensation mode is selected:determining a voltage reference value (Vref) as a sum of a bus voltage (Vt) of the energy plant and a branch current (Ibranch) of the IBR, the branch current (Ibranch) being scaled by a reactive droop value (Kc); and, generating the one or more command messages for controlling operations of the inverter using the voltage reference value (Vref); and, while the current compensation mode is selected: determining the voltage reference value (Vref) as a difference between the bus voltage (Vt) of the energy plant and the branch current (Ibranch) of the IBR, the branch current (Ibranch) being scaled by a sum of a line drop compensation resistance value (Rc) and a line drop compensation reactance value (Xc); and, generating the one or more command messages for controlling operations of the inverter using the voltage reference value (Vref).

4. The method of claim 1, wherein the energy plant is a renewable energy plant.

5. The method of claim 1, wherein the energy plant is a PV energy plant.

6. The method of claim 1, wherein the control system is a plant supervisory control system.

7. The method of claim 1, wherein the one or more command messages for selecting a control mode are received from one or more of a remote operations center and a utility system operations center.

8. The method of claim 7, wherein the control system is communicatively coupled to one or more of the remote operations center and the utility system operations center over a network.

9. The method of claim 1, wherein the IBR is an intermittent energy source.

10. The method of claim 9, wherein the intermittent energy source is a PV array.

11. A control system for regulating voltage of electric power provided by an energy plant coupled to an electric power grid, the control system comprising: a processor coupled to memory and an interface to a network; and, at least one of hardware and software modules within the memory and controlled or executed by the processor, the modules including computer readable instructions executable by the processor for causing the control system to implement the method of any one of claims 1 to 10.

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