Patent Description:
Generally, a wind turbine includes a tower, a nacelle mounted on the tower, and a rotor coupled to the nacelle. The rotor typically includes a rotatable hub and a plurality of rotor blades coupled to and extending outwardly from the hub. Each rotor blade may be spaced about the hub so as to facilitate rotating the rotor to enable kinetic energy to be transferred from the wind into usable mechanical energy, and subsequently, electrical energy.

Transient wind conditions often present challenges for implementing control strategies to maintain the loads acting on wind turbine rotor blades and other wind turbine components at relatively low levels. See, <CIT>. For example, during extreme wind gusts, the wind speed may increase significantly in a relatively short period of time, leading to a rapid increase in blade loading. This rapid increase initially impacts the outboard portions of the rotor blades (e.g., at the tip) where the blades are more susceptible to increased deflection due to loading, which can result in an increased risk of a tower strike due to excessive tip deflection.

Document <CIT> describes a method of controlling a wind turbine that includes at least one rotor shaft and at least one blade operatively coupled to the rotor shaft that includes measuring a first wind turbine operational condition that is representative of a blade deflection value and generating a first operational condition signal based on that first wind turbine operational condition.

Current control strategies identify transient wind conditions by detecting changes in the rotational speed of the generator. However, due to rotor inertia, changes in generator speed lag behind changes in blade loading. As a result, current control strategies may not be sufficiently responsive in reducing blade loading during extreme transient events.

Accordingly, a system and method for reducing the loads on rotor blades and/or other wind turbine components with improved responsiveness to transient wind conditions would be welcomed in the technology.

Various aspects and advantages of the invention will be set forth in part in the following description, or may be clear from the description, or may be learned through practice of the invention.

Various features, aspects and advantages of the present invention will become better understood with reference to the following description and appended claims. In the drawings:.

In general, the present subject matter is directed to a system and method for reducing the loads acting on rotor blades and/or other wind turbine components in response to transient wind conditions. Specifically, one or more blade sensors are used to detect a blade deflection of one or more of the rotor blades. For example, in several embodiments, one or more Micro Inertial Measurement Units (MIMUs) may be used to detect blade loading and/or blade deflection of one or more of the rotor blades. Such detected blade deflection may then be compared to corresponding predicted blade parameters to identify when transient wind conditions exist. For example, if the detected or actual blade deflection deviate from the predicted blade deflection by a significant amount, it may be an indication that a wind gust or other transient event is occurring. A suitable corrective action may then be performed (e.g., by de-rating the wind turbine) to reduce the amount of loads acting on the wind turbine components.

It should be appreciated that, by monitoring one or more blade deflection directly using the blade sensor(s), the disclosed system and method may be capable of detecting the occurrence of transient wind conditions much faster than conventional control systems/methods that rely on the detection of generator speed changes. Thus, corrective actions may be initiated much quicker to ensure that the loads acting on the rotor blades do not become excessive due to extreme transient conditions (e.g., extreme wind gusts).

Referring now to the drawings, <FIG> illustrates a perspective view of one embodiment of a wind turbine <NUM>. 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 turbine control system or turbine controller <NUM> centralized within the nacelle <NUM>. In general, the controller <NUM> may comprise 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. As such, the controller <NUM> may generally be configured to control the various operating modes (e.g., start-up or shut-down sequences) and/or components of the wind turbine <NUM>. For example, the controller <NUM> may be configured to adjust the blade pitch or pitch angle of each rotor blade <NUM> (i.e., an angle that determines a perspective of the blade <NUM> with respect to the direction of the wind) about its pitch axis <NUM> in order to control the rotational speed of the rotor blade <NUM> and/or the power output generated by the wind turbine <NUM>. For instance, the controller <NUM> may control the pitch angle of the rotor blades <NUM>, either individually or simultaneously, by transmitting suitable control signals directly or indirectly (e.g., via a pitch controller (not shown)) to one or more pitch adjustment mechanisms <NUM> (<FIG>) of the wind turbine <NUM>. During operation of the wind turbine <NUM>, the controller <NUM> may generally control each pitch adjustment mechanism <NUM> in order to alter the pitch angle of each rotor blade <NUM> between <NUM> degrees (i.e., a power position of the rotor blade <NUM>) and <NUM> degrees (i.e., a feathered position of the rotor blade <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>. 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>.

Additionally, the controller <NUM> may also be located 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 (e.g., when the controller <NUM> is configured as a farm controller for controlling a plurality of wind turbines). As is generally understood, 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. For example, as indicated above, the controller <NUM> may be communicatively coupled to each pitch adjustment mechanism <NUM> of the wind turbine <NUM> (one for each rotor blade <NUM>) via a pitch controller to facilitate rotation of each rotor blade <NUM> about its pitch axis <NUM>.

In general, each pitch adjustment mechanism <NUM> may include any suitable components and may have any suitable configuration that allows the pitch adjustment mechanism <NUM> to function as described herein. For example, in several embodiments, each pitch adjustment mechanism <NUM> may include a pitch drive motor <NUM> (e.g., any suitable electric motor), a pitch drive gearbox <NUM>, and a pitch drive pinion <NUM>. In such embodiments, the pitch drive motor <NUM> may be coupled to the pitch drive gearbox <NUM> so that the pitch drive motor <NUM> imparts mechanical force to the pitch drive gearbox <NUM>. Similarly, the pitch drive gearbox <NUM> may be coupled to the pitch drive pinion <NUM> for rotation therewith. The pitch drive pinion <NUM> may, in turn, be in rotational engagement with a pitch bearing <NUM> coupled between the hub <NUM> and a corresponding rotor blade <NUM> such that rotation of the pitch drive pinion <NUM> causes rotation of the pitch bearing <NUM>. Thus, in such embodiments, rotation of the pitch drive motor <NUM> drives the pitch drive gearbox <NUM> and the pitch drive pinion <NUM>, thereby rotating the pitch bearing <NUM> and the rotor blade <NUM> about the pitch axis <NUM>.

In alternative embodiments, it should be appreciated that each pitch adjustment mechanism <NUM> may have any other suitable configuration that facilitates rotation of a rotor blade <NUM> about its pitch axis <NUM>. For instance, pitch adjustment mechanisms <NUM> are known that include a hydraulic or pneumatic driven device (e.g., a hydraulic or pneumatic cylinder) configured to transmit rotational energy to the pitch bearing <NUM>, thereby causing the rotor blade <NUM> to rotate about its pitch axis <NUM>. Thus, in several embodiments, instead of the electric pitch drive motor <NUM> described above, each pitch adjustment mechanism <NUM> may include a hydraulic or pneumatic driven device that utilizes fluid pressure to apply torque to the pitch bearing <NUM>.

In addition, the wind turbine <NUM> includes one or more sensors for monitoring various operating parameters of the wind turbine <NUM>. For example, according to the invention, the wind turbine <NUM> includes one or more blade sensors <NUM> configured to monitor a blade parameter of the wind turbine <NUM>. As used herein, the term "blade parameter" may refer to any suitable operating condition and/or parameter that relates to one or more of the rotor blades <NUM> of the wind turbine <NUM>. Blade parameter, according to the invention, refers to blade deflection. Additionally, blade parameters may include, but are not limited to, blade loading, blade orientation (e.g., blade twisting and/or rotation due to deflection), pitch angle, blade rotational speed, blade vibrations and/or the like. In addition, blade parameters may also include derivatives of any monitored blade parameters (e.g., blade velocity, acceleration, etc.).

In several embodiments, each blade sensor <NUM> may be a Micro Inertial Measurement Unit (MIMU). As is generally understood, MIMUs may include any combination of three-dimensional (<NUM>-D) accelerometers, <NUM>-D gyroscopes and <NUM>-D magnetometers and thus, when mounted on and/or within a rotor blade <NUM>, may be capable of providing various types of blade-related measurements, such as <NUM>-D blade orientation (pitch, roll, yaw) measurements, 3D blade acceleration measurements, <NUM>-D rate of turn measurements, 3D magnetic field measurements and/or the like. As will be described below, such measurements may then be transmitted to the controller <NUM> and subsequently analyzed to determine real-time values for one or more of the blade parameters.

In alternative embodiments, the blade sensors <NUM> may be any other suitable sensors capable of monitoring a blade parameter of one or more of the rotor blades <NUM>. For example, the blade sensors <NUM> may be strain gauges, accelerometers, pressure sensors, angle of attack sensors, vibration sensors, LIDAR sensors, camera systems, fiber optic systems, other optical sensors and/or any other suitable sensors.

As shown in <FIG>, in one embodiment, multiple blade sensors <NUM> may be associated with each rotor blade <NUM>. In such an embodiment, the blade sensors <NUM> may generally be disposed at any suitable location along the length of the rotor blades <NUM>. For example, as shown in <FIG>, one blade sensor <NUM> may be located generally adjacent to a root <NUM> of each rotor blade <NUM> while another blade sensor <NUM> may be located generally adjacent to a tip <NUM> of each rotor blade <NUM>. However, it should be appreciated that, in alternative embodiments, a single blade sensor <NUM> may be associated with each rotor blade <NUM> or a blade sensor(s) <NUM> may be associated with less than all of the rotor blades <NUM>. The blade sensors, according to the invention are mounted along the exterior of the rotor blade(s) <NUM> and/or along the interior of the rotor blade(s) <NUM> (including being embedded within a wall of the rotor blade(s) <NUM>).

Additionally, it should be appreciated that the wind turbine <NUM> may also include various other sensors for monitoring other operating parameters of the wind turbine <NUM>. For example, as shown in <FIG>, the wind turbine <NUM> may include one or more generator sensors <NUM> for monitoring the torque, the rotational speed, the acceleration and/or the power output of the generator <NUM>. Similarly, the wind turbine <NUM> may include one or more wind sensors <NUM> for monitoring the wind speed and/or one or more shaft sensors <NUM> for measuring the loads acting on the rotor shaft <NUM> and/or the rotational speed of the rotor shaft <NUM>. Additionally, the wind turbine <NUM> may include one or more towers sensors <NUM> for measuring the loads transmitted through the tower <NUM> and/or the acceleration of the tower <NUM>. Of course, the wind turbine <NUM> may further include various other suitable sensors for measuring any other suitable operating parameters of the wind turbine <NUM>. For example, the wind turbine <NUM> may also include one or more sensors <NUM> (e.g., accelerometers) for monitoring the acceleration of the gearbox <NUM> and/or the acceleration of one or more structural components of the machine head (e.g., the generator frame, the main frame or bedplate, etc.).

It should be appreciated that, as used herein, the term "monitor" and variations thereof indicates that the various sensors of the wind turbine may be configured to provide a direct measurement of the parameters being monitored or an indirect measurement of such parameters. Thus, the sensors may, for example, be used to generate signals relating to the parameter being monitored, which can then be utilized by the controller <NUM> to determine the actual parameter. For instance, as indicated above, MIMU sensors may be used to monitor one or more blade parameters by providing various <NUM>-D measurements, which may then be correlated to the blade parameter(s).

Referring now to <FIG>, there is illustrated a block diagram of one embodiment of suitable components that may be included within the controller <NUM> in accordance with aspects of the present subject matter. As shown, the controller <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 disclosed herein). 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> to perform various functions including, but not limited to, determining one or more operating parameters of the wind turbine <NUM> based on sensor measurements, transmitting suitable control signals to implement corrective actions in response to the detection of transient wind conditions and various other suitable computer-implemented functions.

Additionally, the controller <NUM> may also include a communications module <NUM> to facilitate communications between the controller <NUM> and the various components of the wind turbine <NUM>. For instance, the communications module <NUM> may serve as an interface to permit the turbine controller <NUM> to transmit control signals to each pitch adjustment mechanism <NUM> for controlling the pitch angle of the rotor blades <NUM>. Moreover, the communications module <NUM> may include a sensor interface <NUM> (e.g., one or more analog-to-digital converters) to permit signals transmitted from the sensors <NUM>, <NUM>, <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>, <NUM>, <NUM> may be communicatively coupled to the communications module <NUM> using any suitable means. For example, as shown in <FIG>, the sensors <NUM>, <NUM>, <NUM>, <NUM>, <NUM> are coupled to the sensor interface <NUM> via a wired connection. However, in other embodiments, the sensors <NUM>, <NUM>, <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.

Referring now to <FIG>, a flow diagram of one embodiment of a method <NUM> for reducing the loads acting on a wind turbine in response to transient wind conditions is illustrated in accordance with aspects of the present subject matter. As shown, the method <NUM> may include determining an actual value for a blade parameter with a first sensor associated with at least one of the rotor blades <NUM>, monitoring a secondary operating parameter of the wind turbine using a second sensor <NUM>, determining a predicted value for the blade parameter based on the secondary operating parameter <NUM>, comparing the actual value to the predicted value <NUM> and performing a corrective action to reduce the loads acting on the wind turbine when the actual value differs from the predicted value by at least a differential threshold <NUM>.

In general, the disclosed method <NUM> may be utilized to reduce wind turbine component loading (e.g., blade loads, tower loads, machine head loads, etc.) in the response to transient wind conditions, such as extreme wind gusts. Specifically, one or more blade parameters, such as blade loading and/or blade deflection, may be monitored using one or more suitable sensors to acquire real-time data relating to the actual operating state of the rotor blades <NUM>. In addition, data relating to the predicted operating state of the rotor blades <NUM> may be obtained by monitoring one or more other operating parameters of the wind turbine <NUM> and subsequently correlating the operating parameter(s) to predicted values for the blade parameter(s). Thereafter, the real-time data for the blade parameter(s) (i.e., the actual, monitored values) may be compared to the predicted data for the blade parameter(s) (i.e., the predicted values) in order to identify when a transient wind condition exists. For example, if the real-time data differs from the predicted data substantially, it may be determined that the wind turbine <NUM> is currently experiencing transient wind conditions. In such instance, a suitable corrective action may be performed to reduce the loads acting on the rotor blades <NUM> and/or other wind turbine components, thereby alleviating the effect of the transient event.

Referring particularly to <FIG>, at <NUM>, an actual value for a blade parameter may be monitored using a sensor associated with at least one of the rotor blades <NUM>. Specifically, as indicated above, one or more blade sensors <NUM> are associated with the rotor blades <NUM> for monitoring various blade parameters. For example, one or more MIMU sensors may be used to allow <NUM>-D blade orientation (pitch, roll, yaw) measurements, <NUM>-D blade acceleration measurements, <NUM>-D rate of turn measurements and/or <NUM>-D magnetic field measurements to be acquired. These measurements may then be transmitted to the controller <NUM> and subsequently analyzed to determine real-time, monitored values for one or more of the blade parameters.

In general, the controller <NUM> may be configured to implement any suitable algorithm that allows for the determination of actual, monitored values for the blade parameter(s) based on the outputs provided by the blade sensor(s) <NUM>. In several embodiments, the controller <NUM> may be configured to implement a model-based estimation algorithm. For example, the mathematical model used to determine the actual values for the blade parameter(s) may be physics-based, such as a model based on static mechanics and/or aerodynamic factors. In another embodiment, the mathematical model may be data-driven and may be based on experimental data from the wind turbine <NUM>, such as by using an artificial neural network to determine the wind turbine parameters. Alternatively, the mathematical model may be a combination of both physics-based and data-driven models. Regardless, the mathematical model may be used as a transfer function in order to derive actual values for the blade parameter(s) based on the outputs received from the blade sensor(s) <NUM>.

In particular embodiments of the present subject matter, a simplified or complex mathematical model of each rotor blade <NUM> may be stored within the controller <NUM> (e.g., in the form of computer-readable instructions) to allow the controller <NUM> to estimate and/or determine actual values for one or more of the blade parameters of the wind turbine <NUM>. For example, in one embodiment, a 3D or finite element mathematical model of each rotor blade <NUM> may be created using suitable modeling software and stored within the controller <NUM>. In such an embodiment, the measurements provided by the blade sensors <NUM> may be analyzed using the mathematical model in order to determine actual values for the blade parameter(s).

In alternative embodiments, the controller <NUM> may be configured to determine actual values for the blade parameter(s) using any other suitable means/methodology. For example, instead of calculating the actual values using a model-based algorithm, the controller <NUM> may simply be configured to utilize look-up tables, charts, data maps and/or any other suitable data compilations to determine the actual values based on the signals provided by the blade sensor(s) <NUM>.

Referring still to <FIG>, at <NUM> and <NUM>, one or more secondary operating parameters of the wind turbine <NUM> may be monitored and subsequently analyzed by the controller <NUM> to determine predicted values for one or more of the blade parameters As used herein, the term "secondary operating parameter" may generally refer to any suitable operating parameter of the wind turbine <NUM>, such as one or more blade parameters (e.g., blade deflection, blade loading, blade twisting, pitch angle, blade rotational speed blade vibrations and/or the like) or one or more non-blade operating parameters (e.g., generator torque, generator speed, power output, shaft loads, tower loads, rotor speed, component vibrations, component accelerations (e.g., tower acceleration, machine head acceleration, gearbox acceleration), yaw angle, wind speed and/or the like). As indicated above, such operating parameters may be monitored using various sensors (e.g., sensors <NUM>, <NUM>, <NUM>, <NUM>, <NUM>) provided on and/or within the wind turbine <NUM>.

In several embodiments, the secondary operating parameter(s) being monitored at <NUM> may differ from the blade parameter(s) being monitored at <NUM>. For example, in a particular embodiment, when the blade sensors <NUM> are being utilized to monitor blade loading and/or blade deflection, the secondary operating parameter(s) may correspond to one or a combination of various other operating parameters, such as a combination of pitch angle and one or more of generator speed, generator torque and power output. As such, the predicted values for the blade parameter may be determined by the controller <NUM> without reference to the actual, monitored values provided by the blade sensors <NUM>.

It should be appreciated that controller <NUM> may be configured to implement any suitable algorithm that permits for the predicted values to be determined using the secondary operating parameter(s) as inputs. For instance, in several embodiments, the controller <NUM> may be configured to implement a model-based estimation algorithm. In such embodiments, the mathematical model may be physics-based, data-driven or a combination of both physics-based and data-driven models. Regardless, the mathematical model may be used as a transfer function in order to derive the predicted values for the blade parameter(s) based on the secondary operating parameter(s).

In several embodiments, a simplified or complex mathematical model of the wind turbine <NUM> may be stored within the controller <NUM> (e.g., in the form of computer-readable instructions) to allow the controller <NUM> to estimate and/or determine predicted values for one or more of the blade parameters. For example, in one embodiment, a 3D or finite element mathematical model of the wind turbine may be created using suitable modeling software and stored within the controller <NUM>. In such an embodiment, the monitored secondary operating parameter(s) may be input into the mathematical model in order to determine the predicted values for the blade parameter(s).

In alternative embodiments, the controller <NUM> may be configured to determine predicted values for the blade parameter(s) using any other suitable means/methodology. For example, instead of calculating the predicted values using a model-based algorithm, the controller <NUM> may simply be configured to utilize look-up tables, charts, data maps and/or any other suitable data compilations to determine the predicted values based on the monitored secondary operating parameter(s).

After determining the predicted values, at <NUM>, the actual and predicted values for the blade parameter(s) are compared. Specifically, for each actual value determined by the controller <NUM>, a corresponding predicted value may also be determined. Thereafter, each actual value may be compared to its corresponding predicted value to determine the error or differential between the two values. If the actual value differs from the predicted value by a given differential threshold, it may be determined that a transient wind condition exists. As will be described below, a suitable corrective action may then be performed to reduce loading on the rotor blades <NUM> and/or other wind turbine components to alleviate the effect of the transient event.

As indicated above, the actual value for the blade parameter(s) may differ from the predicted value at any given instant due, at least in part, to rotor inertia and/or any other operational factors that result in a time lag between changes in blade loading and changes in the loading of the other wind turbine components. For example, <FIG> illustrates a simplified representation of the loads acting on a rotor blade <NUM> (line <NUM>) and a rotor shaft <NUM> (line <NUM>) of the wind turbine <NUM> as a function of time. As shown, at point <NUM>, a loading event (e.g., wind gust) has occurred that causes the loads acting on the rotor blade <NUM> to immediately increase. However, due to rotor inertia and/or other operational factors, the shaft loading may not begin to increase until a later time (e.g., at point <NUM>), thereby creating a time differential <NUM> in the loading response between the rotor blade <NUM> and the rotor shaft <NUM>. As such, in an embodiment in which the predicted value for the blade parameter(s) is based on the loads acting on the rotor shaft <NUM>, the actual value for the blade parameter(s) may differ substantially from the predicted value, at the very least, over the time period defined by time differential <NUM>. Accordingly, the difference between the actual and predicted values may be used to identify the occurrence of certain loading events on the wind turbine <NUM>. It should be appreciated that, although line <NUM> in <FIG> has been described with reference to shaft loading, the line may be representative of the loads acting on any other suitable wind turbine component in which a time lag exists between changes in blade loading and changes in the loading for such component.

It should be appreciated that the differential threshold may generally correspond to any suitable variation amount between the actual and predicted values for a specific blade parameter that may serve as a trigger point for initiating a corrective action. For example, in several embodiments, the differential threshold may be a +/- variation calculated based on the predicted operating state of the rotor blades <NUM> during normal operation. Specifically, based on data gathered during normal wind turbine operation, an average predicted value may be determined for each blade parameter, which may then be used as the basis for defining the differential threshold. For example, in one embodiment, the differential threshold for a specific blade parameter may be defined as +/- two standard deviations from the average predicted value for such blade parameter during normal wind turbine operation. In another embodiment, the differential threshold for a given blade parameter may correspond to a +/- variation amount ranging from about <NUM>% to about <NUM>% of the average predicted value for the blade parameter during normal wind turbine operation, such as from about <NUM>% to about <NUM>% of the average predicted value, or from about <NUM>% to about <NUM>% of the average predicted value and any other subranges therebetween.

For example, <FIG> illustrates a graph depicting example tip deflection data for a rotor blade <NUM>, including both the actual tip deflection values (line <NUM>) determined using the measurements provided by the blade sensors <NUM> and the predicted tip deflection values (line <NUM>) determined based on the secondary operating parameter(s). The graph also illustrates the differential threshold (indicated as the variation <NUM> between the dashed lines and line <NUM>) as a predetermined +/- variation from the predicted deflection values <NUM>. As shown, the actual deflection values <NUM> may be continuously compared to the predicted deflection values <NUM> to determine if the difference between the values exceeds the differential threshold <NUM>, thereby indicating that a transient wind condition exists. For example, in the illustrated embodiment, a wind gust or other transient event has occurred at time T<NUM>, thereby causing the actual deflection values <NUM> to deviate from the predicted deflection values <NUM>. If the deviation between the actual and predicted deflection values <NUM>, <NUM> remains within the differential threshold <NUM>, it may be determined that the transient event is not sufficient to cause an excessive increase in blade loading or other component loading. However, if the actual deflection values <NUM> deviate from the predicted deflection values <NUM> beyond the differential threshold <NUM> (e.g., at time T<NUM>), it may be determined that the transient event may be sufficient to cause a substantial increase in the loads acting on the wind turbine <NUM>. As such, a corrective action may be performed to reduce or otherwise counteract the resulting component loading. For instance, as shown in <FIG>, by performing a corrective action between times T<NUM> and T<NUM>, the variation between the actual and predicted deflection values <NUM>, <NUM> may be reduced to an amount within the differential threshold <NUM>.

Referring back to <FIG>, at <NUM>, a corrective action may be performed to reduce the loads acting on the wind turbine <NUM> when the actual value differs from the predicted value by at least the differential threshold. In general, the corrective action performed may form all or part of any suitable mitigation strategy designed to reduce or otherwise control blade loading and/or any other suitable wind turbine component loading (e.g., loads acting on the hub <NUM>, nacelle <NUM> and/or tower <NUM>). For example, in several embodiments, the corrective action may include temporarily de-rating the wind turbine to permit the loads acting on or more of the wind turbine components to be reduced or otherwise controlled, which may include speed de-rating, torque de-rating or a combination of both. For example, in one embodiment, the wind turbine <NUM> may be temporally de-rated by pitching one or more of the rotor blades <NUM> for a partial or full revolution of the rotor <NUM> to permit the loads acting on the rotor blades <NUM> and/or other wind turbine components to be reduced or otherwise controlled. As described above, the pitch angle of each rotor blade <NUM> may be adjusted by controlling its associated pitch adjustment mechanism <NUM> (<FIG>).

In another embodiment, the wind turbine <NUM> may be temporarily de-rated by modifying the torque demand on the generator <NUM>. In general, the torque demand may be modified using any suitable method, process, structure and/or means known in the art. For instance, in one embodiment, the torque demand on the generator <NUM> may be controlled using the turbine controller <NUM> by transmitting a suitable control signal/command to the generator <NUM> in order to modulate the magnetic flux produced within the generator <NUM>. As is generally understood, by modifying the torque demand on the generator <NUM>, the rotational speed of the rotor blades may be reduced, thereby reducing the aerodynamic loads acting on the blades <NUM> and the reaction loads on various other wind turbine components.

In a further embodiment, the wind turbine <NUM> may be temporarily de-rated by yawing the nacelle <NUM> to change the angle of the nacelle <NUM> relative to the direction of the wind. Specifically, as shown in <FIG>, the wind turbine <NUM> may include one or more yaw drive mechanisms <NUM> communicatively coupled to the controller <NUM>, with each yaw drive mechanism(s) <NUM> being configured to change the angle of the nacelle <NUM> relative to the wind (e.g., by engaging a yaw bearing <NUM> (also referred to as a slewring or tower ring gear) of the wind turbine <NUM>). As is generally understood, the angle of the nacelle <NUM> may be adjusted such that the rotor blades <NUM> are properly angled with respect to the prevailing wind, thereby reducing the loads acting on one or more of the wind turbine components. For example, yawing the nacelle <NUM> such that the leading edge of each rotor blade <NUM> points upwind may reduce loading on the blades <NUM> as they pass the tower <NUM>.

In other embodiments, the corrective action may comprise any other suitable control action that may be utilized to reduce the amount of loads acting on one or more of the wind turbine components as a result of transient wind conditions. For example, in embodiments in which a wind turbine <NUM> includes one or more mechanical brakes (not shown), the controller <NUM> may be configured to actuate the brake(s) in order to reduce the rotational speed of the rotor blades <NUM>, thereby reducing component loading. In even further embodiments, the loads on the wind turbine components may be reduced by performing a combination of two or more corrective actions, such as by altering the pitch angle of one or more of the rotor blades <NUM> together with modifying the torque demand on the generator <NUM>.

According to the invention, it should be appreciated that the type and/or severity of the corrective action performed is varied depending upon the magnitude of the difference between the actual and predicted values. For example, if the difference between the actual and predicted values exceeds the differential threshold by an insignificant amount, it may be desirable to de-rate the wind turbine <NUM> by a relatively small amount (e.g., by an amount less than <NUM> % of the average power output) and/or for a relatively short period of time (e.g., less than <NUM> seconds). However, if the difference between the actual and predicted values exceeds the differential threshold by a significant amount, it may be desirable to de-rate the wind turbine <NUM> by a larger percentage (e.g., by an amount greater than <NUM>% of the average power output) and/or for a longer period of time (e.g., greater than <NUM> seconds) to ensure that the loads acting on one or more of the wind turbine components are sufficiently reduced in response to the transient event.

Claim 1:
A method (<NUM>) for reducing loads acting on a wind turbine (<NUM>) in response to transient wind conditions, the method (<NUM>) comprising the following steps:
determining (<NUM>) an actual value for a blade deflection of a rotor blade (<NUM>) of the wind turbine (<NUM>) using a first sensor (<NUM>) associated with the rotor blade (<NUM>);
monitoring (<NUM>) a secondary operating parameter of the wind turbine (<NUM>) using a second sensor (<NUM>), the secondary operating parameter differing from the blade deflection;
the method being characterized by:
the first sensor (<NUM>) being disposed along the length of the rotor blade (<NUM>);
determining (<NUM>) a predicted value for the blade deflection based on the secondary operating parameter;
comparing (<NUM>) the actual value for the blade deflection to the predicted value for the blade deflection; and
performing (<NUM>) a corrective action to reduce the loads acting on the wind turbine (<NUM>) if the actual value for the blade deflection differs from the predicted value for the blade deflection by at least a differential threshold,
wherein at least one of a type or severity of the corrective action performed is varied depending on a magnitude of the difference between the actual value and the predicted value.