Determining wind speed at wind turbine

Abstract

The invention relates to determining a wind speed at a wind turbine comprising a rotor and a plurality of rotor blades. The invention relates to receiving a rotor speed signal indicative of a current speed of a rotor and receiving a pitch angle signal indicative of a current pitch angle of a rotor blade. For each of a plurality of wind speeds, a first thrust on the rotor is obtained based on the received rotor speed and pitch angle signals. The invention relates to receiving a blade flapping load signal indicative of a measured flapping load on the rotor blade from a blade flapping load sensor of each of the rotor blades, and obtaining a second thrust on the rotor using the defined blade unit model and the received blade flapping load signals. The first thrust is compared to the second thrust, and a wind speed is determined based on the comparison.

Description

Technical Field

[0001] The present invention relates to determining wind speed at a wind turbine. In particular, the present invention uses an estimate of the thrust on a rotor of a wind turbine based on measurements of flapping loads on the rotor blades of the wind turbine in order to determine the wind speed. Background Art

[0002] Wind turbines typically include one or more controllers for controlling various components of the wind turbine. For example, a wind turbine controller may be used to control the pitch angle of the wind turbine's rotor blades and / or the speed of the wind turbine's generator. The wind turbine controller may control the components with the goal of maximizing the power production / energy captured by the wind turbine from the wind and / or minimizing the loads experienced by the various wind turbine components during operation.

[0003] Wind turbine controllers typically determine control actions or set points for components based on various operating parameters associated with the operation of the wind turbine. In particular, wind turbine controllers often use knowledge of the current wind speed near the wind turbine to determine appropriate control actions.

[0004] There are various known ways to obtain the wind speed flowing through a wind turbine. For example, direct measurement of the wind speed can be performed. In particular, for this purpose, one or more sensors (e.g., anemometers) can be positioned on or near the wind turbine, for example, mounted to the nacelle of the wind turbine. Such wind speed measurements may suffer from the disadvantages of having a relatively high level of noise and being unreliable. Moreover, in many cases, what is desired is the "rotor-effective" wind speed - that is, the wind speed representing the wind speed over the entire rotor area of the wind turbine (the wind speed experienced by the rotor), rather than at a single measurement point - which is of interest for use in wind turbine controllers. Therefore, another option is to estimate the wind speed flowing through the wind turbine. There are various ways to achieve this. In one example, the wind speed can be estimated based on the rotational speed of the wind turbine rotor, the (collective) pitch angle of the wind turbine rotor blades, and the rotor power output.

[0005] In both cases, measurement or estimation filtering can be applied to remove high-frequency noise. This can be achieved directly by applying a low-pass filter to the measurement signal or the input and / or output signal of the wind speed estimator. Alternatively, some typical wind speed estimation methods used (e.g., integration-based methods) act as a low-pass filter as part of the estimation.

[0006] One problem is that some wind turbine controllers need to react to relatively rapid changes in wind speed, i.e., provide appropriate control actions. For example, a controller for limiting the thrust loads experienced by a wind turbine rotor needs to react to gusts (i.e., relatively rapid increases in wind speed with significant magnitude). However, filtering out high-frequency components from a wind speed measurement or estimate as described above may not only result in high-frequency noise being removed as desired, but may also result in these faster (i.e., shorter timescale) wind speed variations being filtered out of the measurement or estimate. In some wind speed estimator methods that act as a low-pass filter, there is a lag in the high-frequency components in the estimated wind speed. In either case, this may result in suboptimal performance of a controller that relies on wind speed determinations that include these shorter timescale variations.

[0007] The present invention is set against this background. Summary of the Invention

[0008] According to one aspect of the present invention, a method for determining wind speed at a wind turbine comprising a rotor and a plurality of rotor blades is provided. The method includes receiving a rotor speed signal indicating a current speed of the rotor. The method includes receiving a pitch angle signal indicating a current pitch angle of the rotor blades. The method includes, for each of a plurality of wind speeds, obtaining a first thrust on the rotor based on the received rotor speed signal and the received pitch angle signal. The method includes receiving a blade flapping load signal indicating a measured flapping load on the rotor blade from a blade flapping load sensor of each of the rotor blades. The method includes obtaining a second thrust on the rotor using a defined blade unit model and the received blade flapping load signal. The method includes comparing the first thrust to the second thrust and determining the wind speed based on the comparison.

[0009] The determined wind speed may be a wind speed corresponding to the first thrust that is closest to the second thrust.

[0010] Comparing the first thrust to the second thrust may include performing an interpolation of the first thrust to obtain an interpolation function describing a relationship between thrust and wind speed. The determined wind speed may be the wind speed at which the interpolation function equals the second thrust.

[0011] Each of the plurality of wind speeds may be within a defined range of wind speeds and may have defined increments within the defined range. Optionally, the defined increments may be between 0.1 m / s and 2 m / s. Further optionally, the defined increments may be 0.1 m / s, 0.2 m / s, 0.5 m / s, 1 m / s, or 2 m / s. Alternatively, the lower limit of the defined range may be between 0 m / s and 5 m / s. Further optionally, the lower limit may be 0.5 m / s, 1 m / s, 2 m / s, 3 m / s, 4 m / s, or 5 m / s. Alternatively, the upper limit of the defined range may be between 20 m / s and 40 m / s. Further optionally, the upper limit may be 25 m / s, 30 m / s, 35 m / s, or 40 m / s.

[0012] The method may include obtaining a first wind speed signal, wherein the first wind speed signal may be obtained by estimating the wind speed based on one or more received operating parameter signals indicating current operating parameters of the wind turbine or by measuring the wind speed using one or more wind speed sensors of the wind turbine. The first wind speed signal may be a filtered signal that retains low-frequency components.

[0013] The method may comprise obtaining a second wind speed signal, wherein obtaining the second wind speed signal may comprise determining the wind speed according to the method of any preceding claim.The second wind speed signal may be a filtered signal retaining high frequency components.

[0014] The method may include combining the first wind speed signal and the second wind speed correction signal to determine the wind speed.

[0015] Combining the first wind speed signal and the second wind speed signal may include adding the first wind speed signal and the second wind speed signal.

[0016] Obtaining the second wind speed signal may include applying a high pass filter to the wind speed obtained from the comparison of the first thrust and the second thrust.

[0017] The first wind speed signal may be obtained by measuring wind speed using one or more wind speed sensors of the wind turbine.The method may include applying a low pass filter to the measured wind speed to obtain the first wind speed signal.

[0018] The first wind speed signal may be obtained by estimating the wind speed based on one or more received operating parameter signals indicating current operating parameters of the wind turbine. The operating parameters may include a current rotor speed and a current pitch angle. The filtering to preserve low-frequency components may be achieved by one or more of: applying a low-pass filter to the one or more received operating parameter signals; and applying a low-pass filter to the estimate of wind speed.

[0019] The first wind speed signal may be obtained by estimating the wind speed based on one or more received operating parameter signals indicating current operating parameters of the wind turbine. The wind speed estimate may be based on an estimated rotor power of the wind turbine. The estimated rotor power may be estimated based on one or more operating parameters of the wind turbine. The wind speed estimate may be obtained using an integral controller and the estimated rotor power.

[0020] Using the integrating controller may include receiving a measured rotor power indicative of output power and power loss of the wind turbine; determining an error between the measured rotor power and an estimated rotor power; and integrating the error over time to obtain a first wind speed signal.

[0021] According to another aspect of the present invention, there is provided a non-transitory computer-readable storage medium having stored thereon instructions which, when executed by one or more computer processors, cause the one or more computer processors to perform the method defined above.

[0022] According to another aspect of the present invention, a controller for determining a wind speed at a wind turbine comprising a rotor and a plurality of rotor blades is provided. The controller is configured to receive a rotor speed signal indicating a current speed of the rotor. The controller is configured to receive a pitch angle signal indicating a current pitch angle of the rotor blades. The controller is configured to, for each of a plurality of wind speeds, obtain a first thrust on the rotor based on the received rotor speed signal and the received pitch angle signal. The controller is configured to receive a blade flapping load signal indicating a measured flapping load on the rotor blade from a blade flapping load sensor of each of the rotor blades. The controller is configured to obtain a second thrust on the rotor using a defined blade unit model and the received blade flapping load signal. The controller is configured to compare the first thrust with the second thrust and determine the wind speed based on the comparison.

[0023] According to another aspect of the invention, there is provided a wind turbine comprising a controller as defined above. BRIEF DESCRIPTION OF THE DRAWINGS

[0024] Examples of the present invention will now be described with reference to the accompanying drawings, in which:

[0025] Figure 1 schematically illustrates a wind turbine according to an aspect of the present invention;

[0026] Figure 2 shows the determination according to one aspect of the present invention Figure 1 The method steps of determining the wind speed at a wind turbine;

[0027] Figure 3 Shown according to Figure 2 The method of determining the Figure 1 A graph showing the thrust on a rotor of a wind turbine;

[0028] Figure 4 The control module device for determining wind speed is schematically illustrated. Figure 1 The wind turbine controller is implemented and used Figure 2 methods; and

[0029] Figure 5 Schematically illustrates the Figure 4 The device implements the integral controller module. DETAILED DESCRIPTION

[0030] Examples of the present invention advantageously provide for determining wind speed at a wind turbine, wherein relatively rapid changes in wind speed, such as due to gusts, are captured in the determination, but the determination is not subject to significant levels of high-frequency noise. The determined wind speed can be used as a standalone determination of overall wind speed, or can be used to correct wind speed obtained from a different source to include high-frequency components, i.e., shorter timescale variations.

[0031] Examples of the present invention exploit the fact that the effects of relatively rapid changes in wind speed are initially experienced by the rotor blades of a wind turbine. Therefore, examples of the present invention use measurements of the loads experienced by the rotor blades as part of the wind speed determination to capture shorter timescale variations in wind speed via the measurement or estimation of rotor thrust, as described in more detail below. The measured blade load signal includes less noise than some other methods of measuring or estimating wind speed.

[0032] Figure 1 An example of a wind turbine 10 is illustrated in a schematic diagram. Wind turbine 10 includes a tower 102, a nacelle 103 disposed at the apex or top of tower 102, and a rotor 104 operably coupled to a generator housed within nacelle 103. In addition to the generator, nacelle 103 houses other components required to convert wind energy into electrical energy, as well as various components required to operate, control, and optimize the performance of wind turbine 10. The rotor 104 of wind turbine 10 includes a central hub 105 and three rotor blades 106 projecting outwardly from the central hub 105. Rotor blades 106 are pitch-adjustable. Rotor blades 106 can be adjusted according to a collective pitch setting, in which each blade is set to the same pitch value. Rotor blades 106 can also be adjusted according to individual pitch settings, in which each blade 106 can be provided with an individual pitch set point.

[0033] Wind turbine 10 includes blade load sensors positioned at or near the root 109 of each blade in such a manner that the sensors detect the load in blade 106. Blade load signals from such sensors can be used to determine how to adjust the pitch of each of blades 106. Depending on the placement and type of sensors, loads can be detected in the flapping (in-plane / out-of-plane) direction or the edgewise (edgewise) direction (in-plane). For example, such sensors can be strain gauge sensors or optical Bragg sensors.

[0034] A method for determining the wind speed at wind turbine 10 according to an example of the present invention will now be described. The determined wind speed can be considered the speed of the wind near wind turbine 10, or the rotor effective wind speed, i.e., a wind speed representing the wind speed across the swept area of rotor blades 106, for example. The method can be implemented by a controller or other processing module associated with wind turbine 10. In an example, the controller or processing module can be located within wind turbine 10, such as within nacelle 103, within tower 102, or distributed at multiple locations within turbine 10 and communicatively connected to each other. Alternatively, the controller (or portions thereof) can be located external to wind turbine 10. The controller can be in the form of any suitable computing device, such as one or more functional units or modules implemented on one or more computer processors. Such functional units can be provided by suitable software running on any suitable computing substrate using conventional or custom processors and memory. One or more functional units can use a common computing substrate (e.g., they can run on the same server) or separate substrates, or one or both substrates can themselves be distributed among multiple computing devices. The computer memory may store instructions for executing the method performed by the controller, and the processor may execute the stored instructions to perform the method.

[0035] The described method utilizes different methods for estimating or measuring the thrust experienced by a wind turbine rotor 104, i.e. the total (aerodynamic) force acting on the rotor 104 in a direction along the axis of rotation of the rotor 104. In particular, results from a first method for determining the rotor thrust that is dependent on the wind speed are compared with results from a second method for determining the rotor thrust that is independent of the wind speed, wherein the determination of the wind speed is performed based on this comparison.

[0036] An example of a model or equation for rotor thrust according to the first approach (ie, where the rotor thrust determination depends on wind speed) is:

[0037]

[0038] Among them F tis the thrust, ρ is the air density, R is the radius of the rotor 104, V is the wind speed, θ is the pitch angle of the rotor blades 106, ω is the rotational speed of the rotor 104, and the thrust coefficient C t is a defining function of the pitch angle θ and the tip speed ratio ωR / V.

[0039] The thrust coefficient function may typically be in the form of a lookup table calculated off-line and stored in a memory accessible to a controller implementing the method. In particular, the lookup table may include a plurality of thrust coefficient values, each thrust coefficient value corresponding to a respective pair of pitch angle and tip speed ratio values.

[0040] Note that rearranging the above equation into an expression for wind speed, i.e. rearranging the above equation to isolate V, will require the thrust coefficient C t Different expressions for the relationship between and wind speed V.

[0041] Instead, the described example provides a different way of solving the above equation for wind speed V. In particular, as described above, the described example uses another second method to obtain an estimate or measurement of rotor thrust. In particular, rotor thrust is determined using a defined blade element model and measured flapping loads experienced by rotor blades 106. The measured flapping loads (i.e., the load in the flapping direction of the blades) are obtained from blade load sensors, for example, by combining (e.g., averaging) measured flapping load signals obtained from sensors for each rotor blade 106. Alternatively, the measured flapping loads may be based on a flapping load signal from only one of the blade load sensors. The blade flapping load measurements indicate a bending moment at the root 109 of rotor blade 106.

[0042] As is known in the art, a blade element model (or blade element momentum model) decomposes a rotor blade into several small components / elements (along its span) and then determines the forces on each of these elements. These forces are then integrated over the entire blade and over one rotor rotation of the blade to obtain the forces and moments experienced by the rotor blade. In this context, the blade element model provides a signal that can map the sum of the measured flapping loads (moments / torques) in Nm to rotor thrust in N, i.e., a mapping signal in 1 / m. Specifically, the BEM can calculate the forces and moments on the rotor blade 106 based on the lift and drag curves of the rotor 104. The forces and moments are expressed at the intersection of the center of the rotor hub / rotor blade 106; however, as described above, the blade load sensors are located at the root of the rotor blade 106, which is a certain radius or distance from the center of the rotor hub. This is used to derive the rotor thrust from the blade flapping loads measured by the blade load sensors of the rotor blade 106.

[0043] More formally, in one example, the following relationship may be used to obtain rotor thrust using blade load measurements.

[0044] M HC =r c F HC

[0045] Among them, M HC is the moment at the hub center, F HC is the force at the hub center, and r c is the radius of the pressure center. Assume that the moment is given by a uniform distribution about the radius of the pressure center:

[0046]

[0047] where r m is the measuring radius, M meas is the measured blade torque, and C = r c / (r c -r m ) is the correction factor. Then,

[0048]

[0049] And the sum of the flapping moment to the thrust coefficient can be defined as K = C / r c (Unit is 1 / m).

[0050] Figure 2 The steps of a method 20 for determining wind speed according to an example of the present invention are schematically illustrated. Referring back to the thrust F above t From the equations for ω, it is clear that values for the rotor speed ω and the pitch angle θ are required to evaluate the thrust equation (note that both the air density ρ and the rotor radius R are known constant values). Therefore, step 201 of method 20 involves obtaining signals indicative of the current rotor speed and the current pitch angle (which may also be collectively referred to as the current operating point of the wind turbine 10). In particular, the received rotor speed signal may indicate a measured rotational speed of the rotor. This may be performed in any suitable manner. For example, the rotor speed signal may be received from a suitable sensor for measuring the rotor speed (e.g., an encoder). The received pitch angle signal may indicate a collective pitch angle setting of the rotor blades 106 of the wind turbine 10. For example, the wind turbine 10 may include a pitch controller for transmitting a collective pitch reference (to a pitch actuator system of the wind turbine 10) according to which the pitch angles of the rotor blades 106 are to be controlled. Therefore, the received pitch angle signal may be a collective pitch reference from such a pitch controller.

[0051] The wind speed is unknown, and the thrust F tThe equation for ω R / V cannot be rearranged as an expression for wind speed V. Instead, at step 202 of method 20, the above equation is evaluated to obtain a thrust value for each of a plurality of (possible) wind speeds. Each of these obtained thrusts may be referred to as a first thrust. In particular, for a given possible wind speed, the tip speed ratio ω R / V is determined (using the rotor speed signal), and then the thrust coefficient C is determined based on the received pitch angle signal and the determined tip speed ratio, for example, via a lookup table. t The thrust F corresponding to this given wind speed is then obtained by evaluating the above equation t .

[0052] Thrust can be obtained as described above for any appropriately defined multiple wind speeds. For example, thrust can be obtained at wind speeds within a defined range in defined increments. In one example, thrust can be obtained in increments of 1 m / s within a range of 2 m / s to 35 m / s. More generally, the defined increments can be between 0.1 m / s and 2 m / s. For example, the defined increments can be 0.1 m / s, 0.2 m / s, 0.5 m / s, 1 m / s, or 2 m / s. In different examples, the wind speed at which thrust is obtained may not have a constant value increment. For example, thrust can be obtained for a larger number of possible wind speeds within a wind speed range that is considered more likely to correspond to the actual wind speed. The lower limit of the wind speed range considered can be between 0 m / s and 5 m / s. For example, the lower limit can be 0.5 m / s, 1 m / s, 2 m / s, 3 m / s, 4 m / s, or 5 m / s. The upper limit of the wind speed range considered can be between 20 m / s and 40 m / s. For example, the upper limit may be 25 m / s, 30 m / s, 35 m / s or 40 m / s. It should be understood that the values provided above are merely exemplary.

[0053] At step 203 of method 20, a blade flapping load signal is received. Specifically, a measured flapping load on rotor blade 106 is obtained from one or more blade load sensors of rotor blade 106. If measurements from more than one blade load sensor are obtained, the received signals may be combined in any suitable manner to obtain the measured blade flapping load. At step 204, method 20 involves using the received blade flapping load signal and the defined blade element model to obtain a rotor thrust value. This thrust value may be referred to as a second thrust.

[0054] Steps 201 and 202 of method 20 may be performed in parallel with steps 203 and 204 , or steps 201 and 202 may be performed before or after steps 203 and 204 .

[0055] At step 205, method 20 involves comparing the plurality of first thrusts (obtained in step 202) with the second thrust (obtained in step 204). This comparison is then used to determine the wind speed at wind turbine 10. The comparison and determination can be performed in various ways. In one example, a specific first thrust (from the plurality of first thrusts) having a value closest to the value of the second thrust (i.e., the first thrust that minimizes the difference between the first thrust and the second thrust) is identified, and the wind speed is determined as the wind speed corresponding to the specific thrust. In another example, the plurality of first thrusts is interpolated to obtain a function that describes the relationship between thrust and wind speed. The wind speed at which the interpolated function value equals the second thrust is then identified as the determined wind speed.

[0056] Figure 3 Graph 30 shows a curve 301 describing a plurality of first thrusts at corresponding wind speeds for a current operating point determined for an example according to the present invention. In the illustrated example, the (first) thrusts are determined in increments of 1 m / s between 2 m / s and 35 m / s, and curve 301 is determined based on these discrete evaluation points. Figure 3 Also shown is the value of the (second) thrust 302 obtained via the measured blade flapping load signal as described above. In the illustrated example, curve 301 and value 302 intersect at approximately 10 m / s, and thus the wind speed at the wind turbine is determined to be 10 m / s.

[0057] While the described methods can be used to obtain an overall determination of wind speed, in examples of the present invention, the described methods for determining wind speed can be used to capture wind speed variations caused by high-frequency components, and then combine this determination with another determination of wind speed that includes low-frequency components. This can be advantageous because, while the above methods benefit from including high-frequency components in the wind speed determination, other methods can provide more accurate wind speed determinations for low-frequency components. This will be described in more detail below.

[0058] Figure 4 A schematic diagram illustrates a processing or control module arrangement 40 that may be implemented by a controller of a wind turbine 10 according to an example of the present invention. Specifically, a first wind speed signal 411 is obtained from a first processing or control module 41, and a second wind speed signal 421 is obtained from a second processing or control module 42. The first wind speed signal 411 and the second wind speed signal 421 are then combined to obtain a signal 431 that provides an overall determination of the wind speed at the wind turbine 10. The second wind speed signal 421 can be considered a correction signal because it is combined with the first wind speed signal 411 to correct the wind speed according to the first wind speed signal 411 to include the effects of high-frequency components, i.e., to recover some of the faster variations in wind speed that may have been filtered out by the method used to obtain the first wind speed signal 411.

[0059] The first processing module 41 determines the wind speed at the wind turbine 10 for low frequency components. This can be performed in any suitable manner. In one example, the first processing module 41 receives a measured wind speed signal and applies a low pass filter to remove high frequency components (including high frequency noise).

[0060] In another example, the first processing module 41 is a wind speed estimator that uses a balance of power (particularly between rotor power and electrical power generated by the wind turbine 10) to take into account power losses due to connection to the grid and other transmission systems. The power balance can be expressed as:

[0061] P rot =P out +P loss +P acc

[0062] Among them, P rot is the rotor power, P out is the electrical power, P loss is the power loss, and P acc It is the power required to accelerate and decelerate the rotor 104 .

[0063] The power balance equation can be reformulated as:

[0064]

[0065] Among them, P meas =P out +P loss , the power coefficient is a defining function of the pitch angle θ and the tip speed ratio λ, A is the rotor swept area, V is the wind speed, ω is the rotor speed, and J is the rotor moment of inertia.

[0066] The wind speed estimate may then be estimated as the wind speed that will generate a power approximately equal to the power output by wind turbine 10. In particular, this may be determined via a feedback loop that integrates the error between the measured rotor power and the estimated rotor power. Such a feedback loop is Figure 5 , which provides as output a first wind speed signal 411. In particular, it should be noted that estimating the wind speed according to this integrator method acts as a low-pass filter (there is a hysteresis on the high frequency components) on the resulting output signal.

[0067] When using Figure 5 The illustrated (power-based) wind speed estimator uses the power-based wind speed estimator to determine the first wind speed signal 411. Figure 4 An advantage of determining the wind speed using the method outlined in is that the wind speed estimator does not need to be tuned for high frequency components (as this is provided via the second wind speed signal 421 ), but can be optimized for low frequency components.

[0068] The second processing module 42 determines the wind speed variation at the wind turbine 10 caused by the high-frequency component. In particular, the second processing module 42 performs this determination according to the above-described method for determining wind speed based on estimated or measured thrust. However, in order for the second wind speed signal 421 to include only wind speed variations that are a result of the high-frequency component, the second processing module 42 needs to apply filtering to remove the low-frequency component (as provided by the first wind speed signal 411) from the determination.

[0069] The filtering may be performed in any suitable manner. For example, the wind speed may be determined based on the thrust obtained as described above, and the determined wind speed signal may be high-pass filtered to remove low-frequency components and obtain the second wind speed signal 421 .

[0070] The high-frequency component can be defined in any suitable manner. As a purely illustrative example, a high-frequency component can be a component greater than 0.5 Hz. Similarly, the low-frequency component can be defined in any suitable manner. As a purely illustrative example, a low-frequency component can be a component less than 0.1 Hz. In some examples, the high-pass filter can be tuned to pass components near the first eigenfrequency of the rotor blades, which will vary depending on the specific size of the rotor and the length of the rotor blades.

[0071] The first wind speed signal 411 and the second wind speed signal 421 may be combined in any suitable manner to obtain the (overall) wind speed signal 431. For example, the first wind speed signal 411 and the second wind speed signal 421 may be added together. If the determinations from one of the first processing module 41 and the second processing module 42 are to be weighted compared to the other, a coefficient may be applied to one of the first wind speed signal 411 and the second wind speed signal 421 before they are combined.

[0072] Output signal 431 indicating the determined wind speed can be used as an input to one or more wind turbine controllers that determine control actions based on the current wind speed. In particular, output signal 431 can be used as an input to one or more wind turbine controllers that determine control actions in response to relatively rapid changes in wind speed. An example of such a controller may be a thrust limiter controller, in which the rotor blade pitch angle is controlled to ensure that the loads experienced by wind turbine rotor 104 remain below a maximum thrust level (thereby reducing fatigue of one or more wind turbine components). Because gusts of wind can cause relatively rapid increases in thrust loads, determining the current wind speed with minimal delay, including high-frequency components (i.e., including wind speed variations on a shorter timescale (e.g., less than a few seconds, such as less than two seconds), ensures better or optimal performance of such a thrust limiter controller.

[0073] Since the second wind speed signal 421 is intended to capture relatively rapid changes in wind speed, the second wind speed signal 421 can be updated relatively frequently or substantially continuously to ensure that such changes are captured when determining the current wind speed. The blade flapping load and operating point can be sampled at a defined sampling rate of the controller. The method for obtaining the second wind speed signal can be performed for each set of sampled data (blade load and operating point), that is, at each time step. Alternatively, the second wind speed signal 421 can be updated at a defined time step (that is, at a defined time interval). The first wind speed signal 411 can be updated at the same rate as the second wind speed signal 421, or can be updated less frequently than the second wind speed signal 421. The (overall) signal 431 indicating the determined wind speed can be updated at the same rate as the second wind speed signal 421.

[0074] Many modifications may be made to the examples described without departing from the scope of the appended claims.

[0075] It will be appreciated that differently defined thrust models or equations (which are dependent on wind speed) than those used in the above examples may alternatively be used in different examples in accordance with the present invention.

Claims

1. A method of determining wind speed at a wind turbine comprising a rotor and a plurality of rotor blades, the method comprising: receiving a rotor speed signal indicating a current speed of the rotor; receiving a pitch angle signal indicating a current pitch angle of the rotor blade; obtaining a first thrust on the rotor based on the received rotor speed signal and the received pitch angle signal for each of a plurality of wind speeds; receiving a blade flapping load signal indicative of a measured flapping load on the rotor blade from a blade flapping load sensor of each of the rotor blades; obtaining a second thrust on the rotor using a defined blade element model and a received blade flapping load signal; The first thrust is compared to the second thrust, and a wind speed is determined based on the comparison.

2. The method according to claim 1, wherein The determined wind speed is the wind speed corresponding to the first thrust that is closest to the second thrust.

3. The method according to claim 1, wherein Comparing the first thrust to the second thrust includes performing an interpolation of the first thrust to obtain an interpolation function describing a relationship between thrust and wind speed, wherein the determined wind speed is the wind speed at which the interpolation function equals the second thrust.

4. A method according to any preceding claim, wherein: Each of the plurality of wind speeds is within a defined range of wind speeds and has a defined increment within the defined range; Optionally, the defined increment is between 0.1 m / s and 2 m / s; further optionally, the defined increment is 0.1 m / s, 0.2 m / s, 0.5 m / s, 1 m / s or 2 m / s; Optionally, the lower limit of the defined range is between 0 m / s and 5 m / s; further optionally, the lower limit is 0.5 m / s, 1 m / s, 2 m / s, 3 m / s, 4 m / s or 5 m / s; Optionally, the upper limit of the defined range is between 20 m / s and 40 m / s; further optionally, the upper limit is 25 m / s, 30 m / s, 35 m / s or 40 m / s.

5. A method according to any preceding claim, comprising: obtaining a first wind speed signal, wherein the first wind speed signal is obtained by estimating the wind speed based on one or more received operating parameter signals indicating current operating parameters of the wind turbine or by measuring the wind speed using one or more wind speed sensors of the wind turbine, wherein the first wind speed signal is a filtered signal that retains low frequency components; obtaining a second wind speed signal, wherein obtaining the second wind speed signal comprises determining the wind speed according to the method of any preceding claim, and wherein the second wind speed signal is a filtered signal that retains high frequency components; and The first wind speed signal and the second wind speed correction signal are combined to determine the wind speed.

6. The method according to claim 5, wherein: Combining the first wind speed signal and the second wind speed signal includes adding the first wind speed signal and the second wind speed signal.

7. The method according to claim 5 or claim 6, wherein: Obtaining the second wind speed signal includes applying a high pass filter to the wind speed obtained from the comparison of the first thrust and the second thrust.

8. The method according to any one of claims 5 to 7, wherein The first wind speed signal is obtained by measuring wind speed using one or more wind speed sensors of the wind turbine, and wherein the method comprises applying a low pass filter to the measured wind speed to obtain the first wind speed signal.

9. The method according to any one of claims 5 to 8, wherein The first wind speed signal is obtained by estimating the wind speed based on one or more received operating parameter signals indicative of current operating parameters of the wind turbine, wherein the operating parameters include a current rotor speed and a current pitch angle, and wherein filtering to preserve low frequency components is achieved by one or more of: applying a low pass filter to the one or more received operating parameter signals; and A low-pass filter is applied to the estimate of wind speed.

10. The method according to any one of claims 5 to 9, wherein The first wind speed signal is obtained by estimating the wind speed based on one or more received operating parameter signals indicative of current operating parameters of the wind turbine, wherein the estimate of the wind speed is based on an estimated rotor power of the wind turbine, the estimated rotor power being estimated based on one or more operating parameters of the wind turbine, and wherein the estimate of the wind speed is obtained using an integral controller and the estimated rotor power.

11. The method according to claim 10, wherein: Using the integral controller includes: receiving a measured rotor power indicative of an output power and a power loss of the wind turbine; determining an error between the measured rotor power and the estimated rotor power; and The error is integrated over time to obtain the first wind speed signal.

12. A non-transitory computer-readable storage medium having stored thereon instructions which, when executed by one or more processors, cause the one or more processors to perform the method according to any preceding claim.

13. A controller for determining wind speed at a wind turbine comprising a rotor and a plurality of rotor blades, the controller being configured to: receiving a rotor speed signal indicating a current speed of the rotor; receiving a pitch angle signal indicating a current pitch angle of the rotor blade; obtaining a first thrust on the rotor based on the received rotor speed signal and the received pitch angle signal for each of a plurality of wind speeds; receiving a blade flapping load signal indicative of a measured flapping load on the rotor blade from a blade flapping load sensor of each of the rotor blades; obtaining a second thrust on the rotor using a defined blade element model and a received blade flapping load signal; The first thrust is compared to the second thrust, and a wind speed is determined based on the comparison.

14. A wind turbine comprising a controller according to claim 13.

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