Patent Description:
Wind power is considered one of the cleanest, most environmentally friendly energy sources presently available and wind turbines have gained increased attention in this regard. A modern wind turbine typically includes a tower, a generator, a gearbox, a nacelle, and one or more rotor blades. The rotor blades are the primary elements for converting wind energy into electrical energy. The blades typically have the cross-sectional profile of an airfoil such that, during operation, air flows over the blade producing a pressure difference between its sides. Consequently, a lift force, which is directed from the pressure side towards the suction side, acts on the blade. The lift force generates torque on the main rotor shaft, which is connected to a generator for producing electricity that is transferred to a power grid. The power grid transmits electrical energy from generating facilities to end users.

Wind power generation is typically provided by a wind farm, which contains a plurality of wind turbine generators (e.g., often <NUM> or more wind turbines). Typical wind farms have a farm-level controller that regulates the voltage, reactive power, and/or power factor at the wind farm interconnection point (i.e., the point at which the local wind turbine generators are connected to the grid; may also be referred to as the point of common coupling). In such wind farms, the farm-level controller achieves its control objectives by sending reactive power or reactive current commands to the individual wind turbine generators within the wind farm. However, certain constraints of the local wind turbine generators within the wind farm can constrain the capability to supply reactive power. Such constraints, may include, for example, voltage limits, reactive power limits, and/or current limits.

More specifically, when one or more of the wind turbine generators
reaches one of the above constraints, the local turbine-level controllers may not be able to follow the requested reactive power command from the farm-level controller.

In addition, farm-level controllers are often required to have high gains to meet fast voltage regulation requirements. Under normal grid conditions, the high gains may be adequate. However, if the grid strength is reduced significantly as a result of a contingency, then the high gains might adversely affect stable operation.

Accordingly, the present disclosure is directed to a system and method for reducing instability in the reactive power command of an inverter-based resource to improve farm-level volt/VAR control by equipping the farm-level controller with the capability to reduce the gains, such that the wind farm can be stabilized.

<CIT> describes a method for controlling a power system in a wind farm connected to a power grid so as to improve reactive speed-of-response of the wind farm. The method includes receiving a voltage feedback from the power grid and a voltage reference and calculating a linear voltage error as a function of the voltage feedback and the voltage reference. A further step includes generating a first output based on the linear voltage error via a first control path having a first voltage regulator. A further step includes determining a non-linear voltage error based on the linear voltage error via a second control path having a second voltage regulator. A second output is generated via the second control path based on the non-linear voltage error As such, a reactive power command is generated as a function of the first and second outputs.

<CIT> describes a method of damping electromechanical oscillations on a power system.

<CIT> describes a wind power plant with improved rise time.

<CIT> describes a power oscillation damping controller.

The invention is directed to a method for controlling a power system having at least one inverter-based resource connected to an electrical grid, as defined in independent claim <NUM>. The method includes monitoring, via at least one controller of the at least one inverter-based resource, one or more command signals issued by a system-level controller. The method also includes determining, via the at least one controller of the at least one inverter-based resource, whether the one or more command signals issued by the system-level controller includes oscillatory behavior characteristic of an instability. In response to determining that the one or more command signals issued by the system-level controller includes oscillatory behavior characteristic of the instability, the method includes reducing one or more gains of a volt-var regulator of the system-level controller to reduce the instability.

In an embodiment, the command signal(s) may include a reactive power command signal.

The method of the invention includes filtering and analyzing the one or more command signals issued by the system-level controller. More specifically, in an embodiment, the method may include filtering and analyzing the command signal(s) issued by the system-level controller. In such embodiments, filtering the command signal(s) issued by the system-level controller may include filtering the command signal(s) issued by the system-level controller via a plurality of wash-out filters and a lag filter. Also according to the invention, analyzing the command signal(s) issued by the system-level controller further includes determining a magnitude of the filtered command signal(s), amplifying the magnitude of the filtered command signal(s), and comparing the amplified magnitude of the filtered command signal(s) to a magnitude threshold.

Also according to the invention, when the amplified magnitude of the filtered command signal(s) exceeds the magnitude threshold, the method further includes starting a counter for counting a number of times the amplified magnitude crosses zero within a certain time period.

In additional embodiments, determining whether the command signal(s) issued by the system-level controller includes oscillatory behavior characteristic of the instability may include comparing the number of times the amplified magnitude crosses zero within the certain time period with a stability threshold and determining the command signal(s) issued by the system-level controller includes oscillatory behavior characteristic of the instability when the number of times the amplified magnitude crosses zero within the certain time period exceeds the stability threshold.

In several embodiments, the method may include resetting the counter for counting the number of times the amplified magnitude crosses zero within the certain time period after the instability is reduced.

In further embodiments, reducing the one or more gains of the volt-var regulator of the system-level controller to reduce the instability may include incrementally implementing a gain reduction counter for determining how much to reduce the one or more gains of the volt-var regulator of the system-level controller to reduce the instability.

In yet another embodiment, the method may include resetting the one or more gains of the volt-var regulator of the system-level controller after the instability is reduced.

Moreover, in an embodiment, in response to determining that the one or more command signals issued by the system-level controller comprises the oscillatory behavior characteristic of the instability, the method may include also maintaining a power output of the at least one inverter-based resource transmitted to the electrical grid.

In particular embodiments, the system-level controller may include high gains to meet fast-voltage requirements of the electrical grid. In such embodiments, the method may include receiving an indication that a strength of the electrical grid has reduced by a certain amount before determining whether the command signal(s) issued by the system-level controller includes oscillatory behavior characteristic of the instability.

In still another embodiment, the power system may include a plurality of inverter-based resources, the at least one inverter-based resource being one of the plurality of inverter-based resources. Further, in an embodiment, the power system may be a wind farm and the at least one inverter-based resource may be a plurality of wind turbine power systems.

In another aspect, the present disclosure is directed to a system for controlling a wind farm having a plurality of wind turbine generators connected to an electrical grid, as defined in independent system claim <NUM>.

In fact, it will be apparent to those skilled in the art that various modifications and variations can be made in the present invention as long as they do not depart from the scope of the invention as defined by the appended claims. Thus, it is intended that the present invention covers such modifications and variations if they come within the scope of the appended claims.

Generally, the present disclosure is directed to a systems and methods for monitoring the reactive power command issued by a farm-level controller of a wind turbine to a plurality of wind turbines thereof to check for instability based on oscillatory behavior. If there are oscillations in the reactive power command which are characteristic of instability due to large proportional and integral gains in the volt-var control path of the farm-level controller, then these gains are reduced which mitigates the unstable behavior. Once the gains are reduced, the gains can be increased manually by active operator commands. Thus, the present disclosure provides a computer-implemented algorithm configured to analyze the reactive power command to detect whether the command is unstable or not. If unstable, the present disclosure can also determine whether the cause is high gains of the farm-level controller. Thus, in an embodiment, the present disclosure is particularly suitable for wind farms with high gains to obtain a fast speed of response, however, due to sudden change in system conditions such a contingency, these high gains cause instability.

Although the present technology described herein is explained with reference to a wind farm having a plurality of wind turbine generators, it should be understood that the present technology may also be implemented for any suitable application having the ability to rapidly control reactive power. As used herein, inverter-based resources generally refer to electrical devices that can generate or absorb electric power through switching of power-electronic devices. Accordingly, inverter-based resource may include wind turbine generators, solar inverters, energy-storage systems, STATCOMs, or hydro-power systems.

Referring now to the drawings, <FIG> illustrates a perspective view of one embodiment of a wind turbine <NUM> according to the present disclosure. As shown, the wind turbine <NUM> generally includes a tower <NUM> extending from a support surface <NUM>, a nacelle <NUM> mounted on the tower <NUM>, and a rotor <NUM> coupled to the nacelle <NUM>. The rotor <NUM> includes a rotatable hub <NUM> and at least one rotor blade <NUM> coupled to and extending outwardly from the hub <NUM>. For example, in the illustrated embodiment, the rotor <NUM> includes three rotor blades <NUM>. However, in an alternative embodiment, the rotor <NUM> may include more or less than three rotor blades <NUM>. Each rotor blade <NUM> may be spaced about the hub <NUM> to facilitate rotating the rotor <NUM> to enable kinetic energy to be transferred from the wind into usable mechanical energy, and subsequently, electrical energy. For instance, the hub <NUM> may be rotatably coupled to an electric generator <NUM> (<FIG>) positioned within the nacelle <NUM> to permit electrical energy to be produced.

The wind turbine <NUM> may also include a wind turbine controller <NUM> centralized within the nacelle <NUM>. However, in other embodiments, the controller <NUM> may be located within any other component of the wind turbine <NUM> or at a location outside the wind turbine <NUM>. Further, the controller <NUM> may be communicatively coupled to any number of the components of the wind turbine <NUM> in order to control the operation of such components and/or implement a corrective or control action. As such, the controller <NUM> may include a computer or other suitable processing unit. Thus, in several embodiments, the controller <NUM> may include suitable computer-readable instructions that, when implemented, configure the controller <NUM> to perform various different functions, such as receiving, transmitting and/or executing wind turbine control signals. Accordingly, the controller <NUM> may generally be configured to control the various operating modes (e.g., start-up or shut-down sequences), de-rating or up-rating the wind turbine, and/or individual components of the wind turbine <NUM>.

Referring now to <FIG>, a simplified, internal view of one embodiment of the nacelle <NUM> of the wind turbine <NUM> shown in <FIG> is illustrated. As shown, a generator <NUM> may be disposed within the nacelle <NUM> and supported atop a bedplate <NUM>. In general, the generator <NUM> may be coupled to the rotor <NUM> for producing electrical power from the rotational energy generated by the rotor <NUM>. For example, as shown in the illustrated embodiment, the rotor <NUM> may include a rotor shaft <NUM> coupled to the hub <NUM> for rotation therewith. The rotor shaft <NUM> may, in turn, be rotatably coupled to a generator shaft <NUM> of the generator <NUM> through a gearbox <NUM>. As is generally understood, the rotor shaft <NUM> may provide a low speed, high torque input to the gearbox <NUM> in response to rotation of the rotor blades <NUM> and the hub <NUM>. The gearbox <NUM> may then be configured to convert the low speed, high torque input to a high speed, low torque output to drive the generator shaft <NUM> and, thus, the generator <NUM>.

The wind turbine <NUM> may also one or more pitch drive mechanisms <NUM> communicatively coupled to the wind turbine controller <NUM>, with each pitch adjustment mechanism(s) <NUM> being configured to rotate a pitch bearing <NUM> and thus the individual rotor blade(s) <NUM> about its respective pitch axis <NUM>. In addition, as shown, the wind turbine <NUM> may include one or more yaw drive mechanisms <NUM> configured to change the angle of the nacelle <NUM> relative to the wind (e.g., by engaging a yaw bearing <NUM> of the wind turbine <NUM> that is arranged between the nacelle <NUM> and the tower <NUM> of the wind turbine <NUM>).

In addition, the wind turbine <NUM> may also include one or more sensors <NUM>, <NUM> for monitoring various wind conditions of the wind turbine <NUM>. For example, the incoming wind direction <NUM>, wind speed, or any other suitable wind condition near of the wind turbine <NUM> may be measured, such as through use of a suitable weather sensor <NUM>. Suitable weather sensors may include, for example, Light Detection and Ranging ("LIDAR") devices, Sonic Detection and Ranging ("SODAR") devices, anemometers, wind vanes, barometers, radar devices (such as Doppler radar devices) or any other sensing device which can provide wind directional information now known or later developed in the art. Still further sensors <NUM> may be utilized to measure additional operating parameters of the wind turbine <NUM>, such as voltage, current, vibration, etc. as described herein.

Referring now to <FIG>, a schematic diagram of one embodiment of a wind turbine power system <NUM> is illustrated in accordance with aspects of the present disclosure. Although the present disclosure will generally be described herein with reference to the wind turbine <NUM> shown in <FIG>, those of ordinary skill in the art, using the disclosures provided herein, should understand that aspects of the present disclosure may also be applicable in other power generation systems, and, as mentioned above, that the invention is not limited to wind turbine systems.

In the embodiment of <FIG> and as mentioned, the rotor <NUM> of the wind turbine <NUM> (<FIG>) may, optionally, be coupled to the gearbox <NUM>, which is, in turn, coupled to a generator <NUM>, which may be a doubly fed induction generator (DFIG). As shown, the DFIG <NUM> may be connected to a stator bus <NUM>. Further, as shown, a power converter <NUM> may be connected to the DFIG <NUM> via a rotor bus <NUM>, and to the stator bus <NUM> via a line side bus <NUM>. As such, the stator bus <NUM> may provide an output multiphase power (e.g., three-phase power) from a stator of the DFIG <NUM>, and the rotor bus <NUM> may provide an output multiphase power (e.g., three-phase power) from a rotor of the DFIG <NUM>. The power converter <NUM> may also include a rotor-side converter (RSC) <NUM> and a line-side converter (LSC) <NUM>. The DFIG <NUM> is coupled via the rotor bus <NUM> to the rotor-side converter <NUM>. Additionally, the RSC <NUM> is coupled to the LSC <NUM> via a DC link <NUM> across which is a DC link capacitor <NUM>. The LSC <NUM> is, in turn, coupled to the line side bus <NUM>.

The RSC <NUM> and the LSC <NUM> may be configured for normal operating mode in a three-phase, pulse width modulation (PWM) arrangement using one or more switching devices, such as insulated gate bipolar transistor (IGBT) switching elements. In addition, the power converter <NUM> may be coupled to a converter controller <NUM> in order to control the operation of the rotor-side converter <NUM> and/or the line-side converter <NUM> as described herein. It should be noted that the converter controller <NUM> may be configured as an interface between the power converter <NUM> and the turbine controller <NUM> and may include any number of control devices.

In typical configurations, various line contactors and circuit breakers including, for example, a grid breaker <NUM> may also be included for isolating the various components as necessary for normal operation of the DFIG <NUM> during connection to and disconnection from a load, such as the electrical grid <NUM>. For example, a system circuit breaker <NUM> may couple a system bus <NUM> to a transformer <NUM>, which may be coupled to the electrical grid <NUM> via the grid breaker <NUM>. In alternative embodiments, fuses may replace some or all of the circuit breakers.

In operation, alternating current power generated at the DFIG <NUM> by rotating the rotor <NUM> is provided to the electrical grid <NUM> via dual paths defined by the stator bus <NUM> and the rotor bus <NUM>. On the rotor bus <NUM>, sinusoidal multi-phase (e.g., three-phase) alternating current (AC) power is provided to the power converter <NUM>. The rotor-side converter <NUM> converts the AC power provided from the rotor bus <NUM> into direct current (DC) power and provides the DC power to the DC link <NUM>. As is generally understood, switching elements (e.g., IGBTs) used in the bridge circuits of the rotor-side converter <NUM> may be modulated to convert the AC power provided from the rotor bus <NUM> into DC power suitable for the DC link <NUM>.

In addition, the line-side converter <NUM> converts the DC power on the DC link <NUM> into AC output power suitable for the electrical grid <NUM>. In particular, switching elements (e.g., IGBTs) used in bridge circuits of the line-side converter <NUM> can be modulated to convert the DC power on the DC link <NUM> into AC power on the line side bus <NUM>. The AC power from the power converter <NUM> can be constrained with the power from the stator of DFIG <NUM> to provide multi-phase power (e.g., three-phase power) having a frequency maintained substantially at the frequency of the electrical grid <NUM> (e.g., <NUM> or <NUM>).

Additionally, various circuit breakers and switches, such as grid breaker <NUM>, system breaker <NUM>, stator sync switch <NUM>, converter breaker <NUM>, and line contactor <NUM> may be included in the wind turbine power system <NUM> to connect or disconnect corresponding buses, for example, when current flow is excessive and may damage components of the wind turbine power system <NUM> or for other operational considerations. Additional protection components may also be included in the wind turbine power system <NUM>.

Moreover, the power converter <NUM> may receive control signals from, for instance, the local control system <NUM> via the converter controller <NUM>. The control signals may be based, among other things, on sensed states or operating characteristics of the wind turbine power system <NUM>. Typically, the control signals provide for control of the operation of the power converter <NUM>. For example, feedback in the form of a sensed speed of the DFIG <NUM> may be used to control the conversion of the output power from the rotor bus <NUM> to maintain a proper and balanced multi-phase (e.g., three-phase) power supply. Other feedback from other sensors may also be used by the controller(s) <NUM>, <NUM> to control the power converter <NUM>, including, for example, stator and rotor bus voltages and current feedbacks. Using the various forms of feedback information, switching control signals (e.g., gate timing commands for IGBTs), stator synchronizing control signals, and circuit breaker signals may be generated.

The power converter <NUM> also compensates or adjusts the frequency of the three-phase power from the rotor for changes, for example, in the wind speed at the hub <NUM> and the rotor blades <NUM>. Therefore, mechanical and electrical rotor frequencies are decoupled and the electrical stator and rotor frequency matching is facilitated substantially independently of the mechanical rotor speed.

Under some states, the bi-directional characteristics of the power converter <NUM>, and specifically, the bi-directional characteristics of the LSC <NUM> and RSC <NUM>, facilitate feeding back at least some of the generated electrical power into generator rotor. More specifically, electrical power may be transmitted from the stator bus <NUM> to the line side bus <NUM> and subsequently through the line contactor <NUM> and into the power converter <NUM>, specifically the LSC <NUM> which acts as a rectifier and rectifies the sinusoidal, three-phase AC power to DC power. The DC power is transmitted into the DC link <NUM>. The capacitor <NUM> facilitates mitigating DC link voltage amplitude variations by facilitating mitigation of a DC ripple sometimes associated with three-phase AC rectification.

The DC power is subsequently transmitted to the RSC <NUM> that converts the DC electrical power to a three-phase, sinusoidal AC electrical power by adjusting voltages, currents, and frequencies. This conversion is monitored and controlled via the converter controller <NUM>. The converted AC power is transmitted from the RSC <NUM> via the rotor bus <NUM> to the generator rotor. In this manner, generator reactive power control is facilitated by controlling rotor current and voltage.

Referring now to the drawings, <FIG> illustrates a block diagram of a wind farm <NUM> having a plurality of wind turbine generators <NUM> coupled with a transmission grid <NUM>. <FIG> illustrates three wind generators <NUM>; however, any number of wind generators can be included in a wind farm <NUM>. Further, as shown, each of the wind turbine generators <NUM> includes a local controller <NUM> that is responsive to the conditions of the wind turbine generator <NUM> being controlled. In one embodiment, the controller for each wind turbine generator senses only the terminal voltage and current (via potential and current transformers). The sensed voltage and current are used by the local controller to provide an appropriate response to cause the wind turbine generator <NUM> to provide the desired reactive power.

Each wind turbine generator <NUM> is coupled to collector bus <NUM> through generator connection transformers <NUM> to provide real and reactive power (labeled Pwg and Qwg, respectively) to the collector bus <NUM>. Generator connection transformers and collector buses are known in the art.

The wind farm <NUM> provides real and reactive power output (labeled Pwf and Qwf, respectively) via wind farm main transformer <NUM>. The farm-level controller <NUM>, which is communicatively coupled to the turbine-level controllers <NUM>, senses the wind farm output, as well as the voltage at the point of common coupling (PCC) <NUM>, to provide a Q command signal <NUM> (QCMD) that indicates desired reactive power at the generator terminals to ensure a reasonable distribution of reactive power among the wind turbines. In alternate embodiments, the Q command signal (QCMD) <NUM> may be generated as the local or operator level (indicated by the "LOCAL" lines in <FIG>), for example in the event that the wind turbine generator(s) is in manual mode or otherwise not in communication with the wind farm-level controller <NUM>.

Referring now to <FIG>, a block diagram of one embodiment of suitable components that may be included within the turbine-level controllers <NUM> and/or the farm-level controller <NUM> in accordance with aspects of the present disclosure is illustrated. As shown, the controller <NUM>, <NUM> may include one or more processor(s) <NUM> and associated memory device(s) <NUM> configured to perform a variety of computer-implemented functions (e.g., performing the methods, steps, calculations and the like and storing relevant data as disclosed herein). Additionally, the controller <NUM>, <NUM> may also include a communications module <NUM> to facilitate communications between the controller <NUM>, <NUM> and the various components of the wind farm <NUM>. Further, the communications module <NUM> may include a sensor interface <NUM> (e.g., one or more analog-to-digital converters) to permit signals transmitted from one or more sensors <NUM>, <NUM>, <NUM> to be converted into signals that can be understood and processed by the processors <NUM>. It should be appreciated that the sensors <NUM>, <NUM>, <NUM> may be communicatively coupled to the communications module <NUM> using any suitable means. For example, as shown, the sensors <NUM>, <NUM>, <NUM> are coupled to the sensor interface <NUM> via a wired connection. However, in other embodiments, the sensors <NUM>, <NUM>, <NUM> may be coupled to the sensor interface <NUM> via a wireless connection, such as by using any suitable wireless communications protocol known in the art.

As used herein, the term "processor" refers not only to integrated circuits referred to in the art as being included in a computer, but also refers to a controller, a microcontroller, a microcomputer, a programmable logic controller (PLC), an application specific integrated circuit, and other programmable circuits. Additionally, the memory device(s) <NUM> may generally comprise memory element(s) including, but not limited to, computer readable medium (e.g., random access memory (RAM)), computer readable non-volatile medium (e.g., a flash memory), a floppy disk, a compact disc-read only memory (CD-ROM), a magneto-optical disk (MOD), a digital versatile disc (DVD) and/or other suitable memory elements. Such memory device(s) <NUM> may generally be configured to store suitable computer-readable instructions that, when implemented by the processor(s) <NUM>, configure the controller <NUM>, <NUM> to perform various functions as described herein.

The sensors260, <NUM>, <NUM> may include any suitable sensors configured to provide feedback measurements to the farm-level controller <NUM>. In various embodiments, for example, the sensors <NUM>, <NUM>, <NUM> may be any one of or combination of the following: voltage sensors, current sensors, and/or any other suitable sensors.

Referring now to <FIG>, embodiments of various systems and methods for controlling a power system, such as a wind farm, according to the present disclosure are illustrated. In particular, <FIG> illustrates a functional diagram of one embodiment of the farm-level controller <NUM> and the turbine-level controllers <NUM>. <FIG> illustrates a flow diagram of one embodiment of a method <NUM> for controlling a power system, such as a wind farm, according to the present disclosure. <FIG> illustrates another flow diagram of an embodiment of control logic implemented by a controller according to the present disclosure.

Referring particularly to <FIG>, a practical implementation of the system <NUM> for controlling the wind farm <NUM> is illustrated. In particular, as shown, the farm-level controller <NUM> may include a volt-var regulator <NUM> with upper and lower limits (e.g., QLIMHI and QLIMHO). More specifically, as shown, the farm-level controller <NUM> is configured to receive one or more voltage commands of the wind farm (e.g., Vwf_Cmd <NUM>) and one or more voltage feedbacks of the wind farm <NUM> (e.g., Vwf_Fbk <NUM>) that may be used by the volt-var regulator <NUM> for determining a reactive power command signal (e.g., Q_Cmd <NUM>) for the turbine-level controllers <NUM>. Moreover, as shown, each of the turbine-level controllers <NUM> receives the reactive power command signal <NUM> (i.e., via their respective turbine-level volt-var regulators <NUM>). Thus, the turbine-level volt-var regulators <NUM> also receive various other parameters, such as reactive power feedbacks (e.g., Qwtg_Fbk <NUM>) and voltage feedbacks (e.g., Vwtg_Fbk <NUM>) of the individual wind turbines, to determine current commands (e.g., I_Cmd <NUM>) for their respective current regulators <NUM>. Thus, the current regulators <NUM> of the individual wind turbines are configured for generating a rotor current command (e.g., Irq_Cmd) <NUM> for the converter controller.

Referring now to <FIG>, the method <NUM> described herein generally applies to operating the wind farm <NUM> described herein with respect to <FIG> and <FIG>. However, it should be appreciated that the disclosed method <NUM> may be implemented using any other power system that is configured to supply reactive power for application to a load, such as a power grid, such as a solar power system, a hydropower system, an energy storage power system, or combinations thereof. Further, <FIG> depicts steps performed in a particular order for purposes of illustration and discussion. Those of ordinary skill in the art, using the disclosures provided herein, will understand that various steps of any of the methods disclosed herein can be adapted, omitted, rearranged, or expanded in various ways without deviating from the scope of the present disclosure.

As shown at <NUM>, the method <NUM> includes monitoring, via at least one controller of the at least one inverter-based resource, one or more command signals issued by a system-level controller. For example, in an embodiment, the command signals(s) may include the reactive power command signal <NUM>. As shown at <NUM>, the method <NUM> includes determining, via the at least one controller of the at least one inverter-based resource, whether the command signal(s) issued by the system-level controller includes oscillatory behavior characteristic of an instability.

In response to determining that the command signal(s) issued by the system-level controller includes oscillatory behavior characteristic of the instability, as shown at <NUM> and <NUM>, the method <NUM> includes reducing one or more gains of the volt-var regulator <NUM> of the system-level controller (e.g., the farm-level controller <NUM>) to reduce the instability. In particular embodiments, for example, the farm-level controller <NUM> may include high gains to meet fast-voltage requirements of the electrical grid. In such embodiments, the method <NUM> may include receiving an indication that a strength of the electrical grid has reduced by a certain amount before determining whether the command signal(s) issued by the farm-level controller <NUM> includes oscillatory behavior characteristic of the instability.

Referring now to <FIG>, a detailed, flow diagram of one embodiment of control logic <NUM> for instability detection according to the present disclosure is illustrated. In particular, as shown, the control logic implemented by the controller receives the reactive power command signal (e.g., Q_Cmd <NUM>). Further, as shown, the control logic <NUM> may include one or more filters <NUM>, <NUM>, <NUM> for filtering the reactive power command signal <NUM>. In addition, as shown <NUM>, the control logic <NUM> may also be configured to analyze the filtered reactive power command signal <NUM>. Thus, it should be understood that any suitable amount of filtering, analyzing, and/or processing may be applied to the reactive power command signal <NUM>.

In particular embodiments, for example, the control logic <NUM> may include a plurality of wash-out filters <NUM>, <NUM> and a lag filter <NUM>. In addition, as shown at <NUM>, in an embodiment, the control logic <NUM> may analyze the reactive power command signal <NUM> by determining a magnitude of the filtered reactive power command signal <NUM> (e.g., by determining an absolute value of the filtered reactive power command signal <NUM>), amplifying the magnitude of the filtered reactive power command signal <NUM> (e.g., by multiplying the filtered reactive power command signal <NUM> by a factor, such as two), and comparing the amplified magnitude of the filtered reactive power command signal <NUM> to a magnitude threshold (e.g., NSTABMAG).

Still referring to <FIG>, according to the invention, as shown at <NUM>, when the amplified magnitude of the filtered reactive power command signal <NUM> exceeds the magnitude threshold, the control logic <NUM> may include starting one or more timers, such as a zero-crossing timer (e.g., Zcross timer). In addition, as shown at <NUM>, the control logic <NUM> may also reset an oscillatory magnitude time (e.g., OMAG timer). Moreover, as shown at <NUM>, the control logic <NUM> may include starting a counter for counting a number of times (e.g., ZCROSS) the amplified magnitude crosses zero within a certain time period (e.g., ZC timer). Thus, as shown at <NUM>, the control logic <NUM> may include determining whether the reactive power command signal <NUM> includes oscillatory behavior characteristic of the instability by comparing the number of times the amplified magnitude crosses zero within the certain time period with a stability threshold (e.g., NSTAB_TO1). More specifically, the control logic <NUM> is configured to determine the reactive power command signal <NUM> includes oscillatory behavior characteristic of the instability when the number of times the amplified magnitude crosses zero within the certain time period exceeds the stability threshold.

Further, as shown at <NUM>, the control logic <NUM> is configured to determine whether the number of times (e.g., ZCROSS) the amplified magnitude crosses zero within the certain time period exceeds a zero crossing counter limit (e.g., NSTABCTR1). If so, as shown at <NUM>, the control logic <NUM> is configured to check a gain reduction counter. Thus, as shown, if NSTAB_RCT is greater than a gain reduction counter limit (e.g., NSTABCTR2), then the control logic <NUM> continues at <NUM>. If not, as shown at <NUM>, the control logic <NUM> returns to step <NUM>. In particular, as shown at <NUM>, the control logic <NUM> is configured to reset the zero-crossing timer and adds a value (such as <NUM>) to the number of times (e.g., ZCROSS) the amplified magnitude crosses zero within the certain time period.

In contrast, as shown at <NUM>, the control logic <NUM> is configured to set an instability action flag (e.g., NSTAB_ACT) to a certain value, such as <NUM>. Moreover, as shown, the control logic <NUM> is configured to incrementally apply a gain reduction counter and reduce the gain(s) of the volt-var regulator <NUM> of the farm-level controller <NUM> to reduce the instability. More specifically, the control logic <NUM> may include incrementally implementing a gain reduction counter for determining how much to reduce the gain(s) (e.g., KVP and KIV) of the volt-var regulator <NUM> of the farm-level controller <NUM> to reduce the instability. For example, in an embodiment, the gain(s) may be reduced by about half. In further embodiments, the gain(s) may be reduced by any suitable amount to reduce the instability.

In addition, as shown, the control logic <NUM> is configured to reset the zero-crossing counter for counting the number of times the amplified magnitude crosses zero within the certain time period after the instability is reduced. Moreover, in an embodiment, the control logic <NUM> is configured to reset the one or more gains of the volt-var regulator <NUM> of the farm-level controller <NUM> after the instability is reduced. Thus, as shown at <NUM>, the control logic <NUM> is configured to go to the next time step.

Referring still to <FIG>, the control logic <NUM> also includes a control path if, as shown at <NUM>, the instability magnitude does not exceed the magnitude threshold. For example, as shown at <NUM>, the control logic <NUM> is configured to start an oscillatory magnitude timer (e.g., OMAG timer) and set an oscillatory magnitude timer limit (e.g., NSTAB_TO2). Thus, as shown at <NUM> and <NUM>, the control logic <NUM> allows the oscillatory magnitude and the zero-crossing timer to reset. Accordingly, as shown at <NUM>, the control logic <NUM> is configured to reset the instability action flag (e.g., NSTAB_FLAG and NSTAB_ACT) to zero, the number of times (e.g., ZCROSS) the amplified magnitude crosses zero within the certain time period to zero, and the gains (e.g., KVP and KIV) to their original values. In addition, as shown, the control logic <NUM> is configured to reset the zero-crossing timer as well.

In response to determining that the filtered reactive power command signal <NUM> includes the oscillatory behavior characteristic of the instability, the control logic <NUM> may also include maintaining a power output of the wind farm <NUM> transmitted to the electrical grid.

Claim 1:
A method for controlling a power system (<NUM>) having at least one inverter-based resource connected to an electrical grid (<NUM>), the method comprising:
monitoring (<NUM>), via at least one controller of the at least one inverter-based resource (<NUM>), one or more command signals issued by a system-level controller (<NUM>);
determining, via the at least one controller of the at least one inverter-based resource, whether the one or more command signals issued by the system-level controller comprises oscillatory behavior characteristic of an instability (<NUM>); and
in response to determining that the one or more command signals issued by the system-level controller comprises oscillatory behavior characteristic of the instability, reducing one or more gains of a volt-var regulator of the system-level controller to reduce the instability (<NUM>);
further comprising analyzing and filtering the one or more command signals issued by the system-level controller;
wherein analyzing and filtering the one or more command signals issued by the system-level controller further comprises:
determining a magnitude of the filtered one or more command signals;
amplifying the magnitude of the filtered one or more command signals; and
comparing the amplified magnitude of the filtered one or more command signals to a magnitude threshold;
wherein, when the amplified magnitude of the filtered one or more command signals exceeds the magnitude threshold, starting a counter for counting a number of times the amplified magnitude crosses zero within a certain time period.