Preventing blade tower strike of wind turbine

Abstract

Preventing blade tower strike of a wind turbine: A method of estimating a position of at least a portion of a rotor blade of a rotor of a wind turbine during operation of the wind turbine is provided. The portion of the rotor blade is a first portion. The rotor blade (103) is deflected due to a deflection movement of the rotor blade towards a tower (104) of the wind turbine (101), and the position is indicative of said deflection. The method (400) comprises measuring a first parameter by means of a first measuring unit (107), wherein the measured first parameter is indicative of an absolute position and / or a relative position of at least a second portion of the rotor blade (103) or of a further rotor blade (102) of the rotor. The method (400) further includes measuring, by one or more second measurement units (108), one or more second parameters, wherein at least one of the one or more measured second parameters is indicative of an absolute position and / or a relative position of at least a third portion of the rotor blade (103) or a further rotor blade (102) of the rotor. The method (400) further comprises estimating a position of at least a first portion of the rotor blade (103), where the estimating comprises employing a state estimator (210) that estimates a state of the rotor blade (103) based at least on the measured first parameter and the one or more measured second parameters, and derives the position from the estimated state of the rotor blade (103).

Description

Field of the Invention

[0001] The present invention relates to a method for estimating the position of at least a first part of a rotor blade of a rotor of a wind turbine during operation of the wind turbine, and to a method for operating such a wind turbine. The present invention also relates to a computer program for implementing such a method, and to a control system configured to execute such a method. Background Art

[0002] A typical wind turbine includes a tower supporting a nacelle, a rotor rotatably mounted horizontally to the nacelle, the rotor including a plurality of rotor blades driven by the wind. During operation of the wind turbine, the wind turbine may be exposed to high loads that cause various components to deflect. For example, when the wind acts on the rotor blades, the rotor blades of the wind turbine may deflect towards the tower. The deflection amplitude of the rotor blades may be so large that the rotor blades collide with the tower when they next pass by the tower, for example due to impact load events such as large gusts or high turbulence winds. Such a collision of the rotor blade with the tower ("blade-tower impact") may cause damage to the wind turbine or at least several of its components.

[0003] Today, the risk of such a collision is reduced by strengthening the rotor blades, tapering the rotor blades, and / or introducing large pre-bends in the rotor blade shape. All these measures reduce the risk of tower impact because the initial distance between the rotor blade and the tower increases. However, all these measures have a negative impact on the power generation capacity of the wind turbine and thus reduce its efficiency. In addition, due to the more complex structure and shape required for the rotor blades, the production, transportation, and assembly work of the wind turbine increases.

[0004] In addition, currently known control methods aim to prevent the rotor blade from colliding with the tower by changing the operating state of the wind turbine (e.g., by reducing the rating of the wind turbine) based on the measured data. Compared with the above non-active methods, such an active method can improve the efficiency of the wind turbine. However, the known active methods may require high-cost hardware (e.g., a laser-based measurement system mounted on the tower), and / or may lack data based on which anti-collision control can be reliably and thus safely implemented.

[0005] Document EP 4047204 A1 describes a method for determining the distance between the tip of a rotor blade of a wind turbine and the tower, wherein strain measurements are used to estimate the distance, and the estimation procedure is calibrated by using distance measurement results obtained from a radar or a laser sensor.

[0006] Document US2011 / 0135466 A1 proposes replacing such strain, laser, and radar sensors with a single GPS sensor mounted on the blade to monitor the deflection of a wind turbine blade. SUMMARY OF THE INVENTION

[0007] Accordingly, it is desirable to mitigate at least some of the disadvantages mentioned above and to provide a more reliable solution for preventing collisions between the rotor blades of a wind turbine and the tower during operation of the wind turbine, which solution has a lesser impact on the efficiency of the wind turbine.

[0008] The features of the independent claims meet this need. The dependent claims describe embodiments of the invention.

[0009] According to one aspect of the invention, there is provided a method of estimating the position of at least a portion of a rotor blade of a rotor of a wind turbine during operation of the wind turbine. This portion of the rotor blade is a first portion. The rotor blade is deflected due to a deflection movement of the rotor blade towards or away from the tower of the wind turbine, and the position indicates said deflection. The method includes measuring a first parameter by a first measurement unit, wherein the measured first parameter indicates the absolute position and / or relative position of at least a second portion of the rotor blade or another rotor blade of the rotor. The method further includes measuring one or more second parameters by one or more second measurement units, wherein at least one of the one or more measured second parameters indicates the absolute position and / or relative position of at least a third portion of the rotor blade or another rotor blade of the rotor. The method further includes estimating the position of at least the first portion of the rotor blade, wherein said estimation includes employing a state estimator that estimates the state of the rotor blade based at least on the measured first parameter and the one or more measured second parameters, and obtaining the position based on the estimated state of the rotor blade.

[0010] Employing state estimation techniques (e.g., prediction / correction algorithms such as, for example, a Kalman filter) based on the measurements provided by multiple measurement units allows for continuously providing / providing at each calculation cycle of the estimator robust data with high accuracy that indicates the estimated position of at least a portion of the rotor blade. Accordingly, robust and accurate data indicating the distance of the position of at least a portion of the rotor blade from the tower can be obtained continuously / at each calculation cycle of the estimator. Accordingly, highly reliable anti-collision control can be provided by making the control based on such estimated data.

[0011] Furthermore, the estimated position is updated based on the model implemented by the state estimator and the measurements obtained at each calculation cycle, such that the position of at least a portion of the rotor blade is available at almost any point in time during rotation of the rotor blade with the rotor (at almost all orientations of the rotor). Accordingly, a controller that controls the operation of the wind turbine based on such estimated position can react in a timely manner when estimating critical positions of at least a portion of the rotor blade and is no longer limited to those points in time when the measurement units provide information.

[0012] In summary, the above methods provide robust data with high accuracy and high continuity / sampling rate. The anti-collision control can be reliably based on this data and is thus safely implemented, minimizing the risk of rotor blade - tower collisions. The effects of employing a state estimator are discussed in more detail below with reference to Figure 3 Figure 3

[0013] It should be clear that one or more first measurement units for measuring one or more first parameters and / or one or more second measurement units for measuring one or more second parameters can be provided. For example, one, two, or more first and / or second measurement units can be provided on the rotor blade or on each rotor blade. It may be particularly advantageous to provide at least a first measurement unit and a second measurement unit on each rotor blade of a wind turbine rotor.

[0014] The wind turbine can include an offshore or onshore wind turbine. In particular, the wind turbine can include a floating wind turbine.

[0015] The measurement units described herein can, for example, include sensors or a sensor system including one or more sensors. In addition to the actual measurement, the measurement step can also include signal pre - processing and post - processing steps, such as filtering.

[0016] The rotor blade can include a blade tip. At least one of the first, second, and third parts of the rotor blade can include a blade tip or be the blade tip. In particular, the blade tip can be the part of the rotor blade that is closest to the tower when the rotor blade deflects towards the tower.

[0017] It should be clear that at least one of the first, second, and third parts can include any single point or section / part on the rotor blade or be any single point or section / part on the rotor blade.

[0018] None, at least two, or all of the first, second, and third parts of the rotor blade can include the same part of the rotor blade or be the same part of the rotor blade. In particular, all of the first, second, and third parts of the rotor blade can include a blade tip or be the blade tip. In the latter case, the first part is the same part as the second and third parts.

[0019] The estimated state of the rotor blade can include at least one of the position, velocity, and acceleration of at least one of the at least first, at least second, and at least third parts of the rotor blade or another part of the rotor blade.

[0020] The estimated state may indicate translational and / or rotational movement of at least a portion of the rotor blade. In particular, the indicated movement may be a movement with six degrees of freedom.

[0021] A state estimator for estimating the state of the rotor blade may include a state observer.

[0022] The method may also include estimating an uncertainty parameter indicative of the uncertainty of the estimated position of at least a first portion of the rotor blade and / or the estimated state of the rotor blade, wherein preferably, estimating the uncertainty includes employing a state estimator. The uncertainty parameter may for example include the variance and / or covariance of the estimated position and / or the estimated state.

[0023] The state estimator may implement a mathematical and / or physical model, based on which the state of the rotor blade and / or the uncertainty parameter is estimated.

[0024] The first parameter may include at least one of acceleration, velocity, and position of at least a second portion of the rotor blade or another rotor blade. When the first parameter indicates a relative position, the first parameter may include the acceleration and / or velocity of at least a second portion of the rotor blade or another rotor blade.

[0025] At least one of the one or more second parameters may include at least one of acceleration, velocity, and position of at least a third portion of the rotor blade or another rotor blade. When at least one of the one or more second parameters indicates a relative position, at least one of the one or more second parameters may include the acceleration and / or velocity of at least a third portion of the rotor blade or another rotor blade.

[0026] In an example, the measured first parameter may indicate only a relative position, and the measured second parameter may indicate only an absolute position or vice versa.

[0027] According to an optional exemplary configuration, the first measurement unit may include an inertial measurement unit. The second measurement unit may include a receiver for receiving global positioning data. The inertial measurement unit may provide measurement results indicative of a relative position more frequently than the receiver for receiving global positioning data provides measurement results indicative of an absolute position. By using both in the state estimator, the position of the blade portion can be estimated frequently at a high repetition rate (i.e., multiple times during a revolution of the wind turbine rotor). At the same time, the absolute position measurement can ensure the accuracy of the position estimation over an extended time period.

[0028] For example, the measurement frequency of the first parameter can be at least 5 times, preferably at least 10 times, the measurement frequency of the second parameter. In addition, the first parameter can be measured multiple times during the revolution of the wind turbine rotor, for example, more than 10 times, 15 times or 20 times. Thus, it is possible to accurately estimate, for example, by using the current measurement result from the first measurement unit, the likelihood that the blade is close to or hits the tower immediately before the blade passes the tower, where the current measurement result from the first measurement unit is obtained, for example, before the blade passes the tower and within the last quarter of the revolution of the blade.

[0029] According to an example, a method of operating a wind turbine is provided. Operating the wind turbine includes implementing any of the methods described herein to estimate the position of at least a portion of a rotor blade of the rotor of the wind turbine during operation of the wind turbine, and determining a distance between a tower of the wind turbine and the rotor blade based on the position of at least a portion of the tower and the estimated position of at least a portion of the rotor blade. Preferably, the wind turbine is operated based on the determined distance.

[0030] Determining the distance can include obtaining a difference between the position of at least a portion of the tower and the estimated position of at least a portion of the rotor blade. Preferably, the obtained distance can be a (multi-dimensional) Euclidean distance.

[0031] According to an example, at least a portion of the tower includes at least a first portion of the tower, and the tower performs a tower movement towards or away from the rotor blade during operation of the wind turbine. Operating the wind turbine includes measuring an additional first parameter by an additional first measurement unit, where the measured additional first parameter indicates an absolute position and / or a relative position of at least a second portion of the tower. Measuring one or more additional second parameters by one or more additional second measurement units, where at least one of the one or more measured additional second parameters indicates an absolute position and / or a relative position of at least a third portion of the tower, and estimating the position of at least a first portion of the tower, where the estimation includes using a state estimator that estimates the state of the tower based at least on the measured additional first parameter and the one or more measured additional second parameters, and obtaining the position according to the estimated state of the tower.

[0032] For the same reasons outlined above with respect to the estimation of the position of the rotor blades, using a state estimator that monitors the movement of the tower allows for providing an estimated position of at least a part of the tower that is highly accurate, robust, and continuously updated / updated at each computational cycle of the estimator. Basing the estimation of the tower-blade distance on this estimated tower position, rather than, for example, a predefined (constant) tower position, further improves the accuracy of the estimated tower-blade distance. Thus, the risk of collision between the rotor blades and the tower can be determined even more reliably. This can be particularly beneficial when the wind turbine is an offshore or floating wind turbine, where the movement of its components (such as the support structure) can significantly affect the global positioning of the blades and the tower, and thus the blade-tower distance.

[0033] The tower can include a traversable portion that is passed by the blade tip during operation of the wind turbine. Preferably, the traversable portion can be the outer wall of the tower.

[0034] At least one of the first, second, and third portions of the tower can include a traversable portion or be a traversable portion.

[0035] It should be clear that at least one of the first, second, and third portions can include any single point or section / portion on the tower, or be any single point or section / portion on the tower.

[0036] None, at least two, or all of the first, second, and third portions can include the same portion of the tower, or be the same portion of the tower. In particular, all of the first, second, and third portions of the tower can include a traversable portion or be a traversable portion. In the latter case, the first portion is the same portion as the second and third portions.

[0037] The estimated state of the tower can include at least one of the position, velocity, and acceleration of at least a part of the tower or preferably at least a part of the tower.

[0038] The estimated state can indicate the translational and / or rotational movement of at least a part of the tower. In particular, the indicated movement can be a movement with six degrees of freedom.

[0039] The state estimator for estimating the state of the tower can include a state observer.

[0040] The method can further include estimating an uncertainty parameter that indicates the uncertainty of the estimated position of at least the first part of the tower and / or the estimated state of the tower, where preferably, estimating the uncertainty includes using a state estimator. The uncertainty parameter can include, for example, the variance and / or covariance of the estimated position and / or the estimated state.

[0041] A state estimator may implement a mathematical and / or physical model and estimate the state and / or uncertainty parameters of the tower based on the mathematical and / or physical model.

[0042] The additional first parameter may include at least one of acceleration, velocity, and position of at least a second part of the tower. When the additional first parameter indicates a relative position, the additional first parameter may include acceleration and / or velocity of at least a second part of the tower.

[0043] At least one of the one or more additional second parameters may include at least one of acceleration, velocity, and position of at least a third part of the tower. When at least one of the one or more additional second parameters indicates a relative position, at least one of the one or more additional second parameters may include acceleration and / or velocity of at least a third part of the tower.

[0044] In an example, the additional first parameter may only indicate a relative position, and at least one of the one or more additional second parameters may only indicate an absolute position or vice versa.

[0045] In an example, at least one of the first measurement unit, the additional first measurement unit, the one or more second measurement units, and the one or more additional second measurement units may include one or more inertial measurement units and / or one or more receivers for receiving global positioning data.

[0046] In particular, the first measurement unit and / or the additional first measurement unit may include one or more inertial measurement units, and / or the second measurement unit and / or the additional second measurement unit may include one or more receivers for receiving global positioning data.

[0047] The estimated state of the rotor blade may be estimated at a time point after the rotor blade has passed the tower and before a future time point when the rotor blade passes the tower again or next time. Obtaining the estimated position of at least a part of the rotor blade may include predicting the position of at least a part of the rotor blade at a future time point based at least on the estimated state of the rotor blade.

[0048] Predicting the position of at least a part of the rotor blade may also be based on one or more previous positions of at least a part of the rotor blade.

[0049] Predicting the position of at least a part of the rotor blade may also be at least based on a (dynamic) model indicating the movement of at least a part of the rotor blade. The model may include, for example, a constant acceleration motion model.

[0050] For example, given the current state (including the acceleration, velocity, and position of at least a portion of the rotor blade) and assuming a constant acceleration motion model, the position of at least a portion of the rotor blade at a future time point can be calculated. Additionally, the prediction can also take into account previously obtained data, such as the previous position of the rotor blade.

[0051] The estimated state of the tower can be estimated at a time point after the rotor blade has passed the tower and before a future time point when the rotor blade passes the tower again or next time. Obtaining the estimated position of at least a portion of the tower can include predicting the position of at least a portion of the tower at a future time point based at least on the estimated state of the tower.

[0052] Predicting the position of at least a portion of the tower can also be based on one or more previous positions of at least a portion of the tower.

[0053] Predicting the position of at least a portion of the tower can also be based on a (dynamic) model indicating the motion of at least a portion of the tower. The model can include, for example, a constant acceleration motion model.

[0054] For example, given the current state (including the acceleration, velocity, and position of at least a portion of the tower) and assuming a constant acceleration motion model, the position of at least a portion of the tower at a future time point can be calculated. Additionally, the prediction can also take into account previously obtained data, such as the previous position of the tower.

[0055] The distance can be the distance at a future time point, which is obtained based on the predicted position of at least a portion of the rotor blade and the position of at least a portion of the tower, and preferably predicts the position of at least a portion of the tower.

[0056] Such a prediction is beneficial because the prediction can allow anti-collision control to anticipate and react, for example, by adjusting the operation of the wind turbine, before a critical rotor blade-to-tower distance occurs. Additionally, when the predicted distance will increase again to an acceptable level before the rotor blade will pass the tower again, the prediction may also allow no reaction, that is, continue the operation of the wind turbine, even though a critical distance has occurred. In this way, anti-collision can operate more reliably / safely and more efficiently.

[0057] In an example, the wind turbine includes one or more additional rotor blades, and the estimation, in particular the prediction, can also be based on or exclusively based on one or more (previous) estimated positions of one or more additional rotor blades and / or one or more (previous) determined distances between the tower and one or more additional rotor blades.

[0058] According to an example, operating a wind turbine includes determining whether the determined distance exceeds a threshold. Alternatively or additionally, operating a wind turbine includes obtaining, at least based on the determined distance between the tower and the rotor blade, the likelihood of the rotor blade colliding with the tower at a future time point when the rotor blade passes the tower, and determining whether the obtained likelihood exceeds a threshold. Preferably, obtaining the likelihood is further based on one or more additional determined distances between the tower and the rotor blade, the one or more additional determined distances being determined at a time point prior to the determined distance.

[0059] According to an example, the method includes adjusting the operation of the wind turbine when it is determined that the threshold is exceeded. Alternatively or additionally, the method includes continuing the operation of the wind turbine or not adjusting the operation of the wind turbine when it is determined that the threshold is not exceeded.

[0060] Adjusting the operation of the wind turbine may include reducing the loads acting on the wind turbine and, in particular, on the rotor blade. The adjustment may include, for example, changing the blade pitch of the rotor blade and / or yawing the nacelle of the wind turbine.

[0061] According to an example, employing a state estimator for estimating the state of the tower and / or a state estimator for estimating the state of the rotor blade includes employing a prediction / correction algorithm, in particular a Kalman filter and / or a Luenberger observer.

[0062] According to one aspect of the invention, there is provided a control system for controlling the operation of a wind turbine. The control system is configured to implement any of the methods described herein.

[0063] According to one aspect of the invention, there is provided a wind turbine. The wind turbine is configured to be controlled by any of the control systems described herein.

[0064] According to one aspect of the invention, there is provided a system for controlling the operation of a wind turbine. The system includes a first measurement unit, one or more second measurement units, and any of the control systems described herein, wherein the control system is communicatively coupled to the wind turbine, the first measurement unit, and the one or more second measurement units. Preferably, the system includes an additional first measurement unit communicatively coupled to the control system, and one or more additional second measurement units communicatively coupled to the control system.

[0065] At least one of the first measurement unit and the one or more second measurement units may be mounted to the rotor blade of the wind turbine. Alternatively or additionally, at least one of the additional first measurement unit and the one or more additional second measurement units may be mounted to the tower of the wind turbine. In a particular example, the measurement unit mounted to the tower may include one or more measurement units mounted to the support structure of the tower.

[0066] The first measurement unit may include at least one of an accelerometer, an angular rate sensor, a gyroscope, and an inertial measurement unit. Alternatively or additionally, one or more second measurement units may at least include a receiver for receiving global positioning data, in particular a GNSS receiver and / or a GPS receiver.

[0067] The additional first measurement unit may include at least one of an accelerometer, an angular rate sensor, a gyroscope, and an inertial measurement unit. Alternatively or additionally, one or more additional second measurement units may at least include a receiver for receiving global positioning data, in particular a GNSS receiver and / or a GPS receiver.

[0068] Using a state estimator for data fusion (i.e., position estimation as described herein) may allow the use of relatively low-cost measurement units (e.g., one or more inertial measurement units and / or one or more receivers for receiving global positioning data) without loss of accuracy and thus without loss of system reliability. Accordingly, the cost of a reliable collision avoidance system can be reduced because high-cost hardware is no longer required.

[0069] According to one aspect of the invention, there is provided a computer program for controlling the operation of a wind turbine. The computer program includes control instructions that, when executed by a processing unit of a control system for controlling the operation of the wind turbine, cause the processing unit to implement any of the methods described herein.

[0070] According to one aspect of the invention, there is provided a computer program for estimating the position of at least a portion of a rotor blade of a rotor of a wind turbine during operation of the wind turbine. The computer program includes control instructions that, when executed by a processing unit, cause the processing unit to implement any of the methods described herein for estimating the position of at least a portion of a rotor blade of a rotor of a wind turbine during operation of the wind turbine.

[0071] According to one aspect of the invention, there is provided a method for estimating the position of at least a part of a tower of a wind turbine during operation of the wind turbine. This part of the tower is the first part. The tower performs tower movement towards the rotor blades during operation of the wind turbine. The method includes measuring an additional first parameter by an additional first measurement unit, wherein the measured additional first parameter indicates the absolute position and / or relative position of at least a second part of the tower. The method further includes measuring one or more additional second parameters by one or more additional second measurement units, wherein at least one of the one or more measured additional second parameters indicates the absolute position and / or relative position of at least a third part of the tower. The method further includes estimating the position of at least the first part of the tower, wherein the estimation includes using a state estimator that estimates the state of the tower based at least on the measured additional first parameter and the one or more measured additional second parameters, and obtaining the position according to the estimated state of the tower.

[0072] According to one aspect of the invention, there is provided a computer program for estimating the position of at least a part of a tower of a wind turbine during operation of the wind turbine. The computer program includes control instructions that, when executed by a processing unit, cause the processing unit to implement any of the methods described herein for estimating the position of at least a part of a tower of a wind turbine during operation of the wind turbine.

[0073] The computer program described herein may be provided on a volatile or non-volatile storage medium or data carrier.

[0074] The processing unit described herein may include, for example, a digital signal processor, an application specific integrated circuit, a field programmable gate array, a microprocessor, etc. The memory unit described herein may include RAM, ROM, flash memory, a hard disk drive, etc.

[0075] It should be understood that the features mentioned above and those not yet explained below can be used not only in the indicated corresponding combinations, but also in other combinations or alone, without departing from the scope of the invention. In particular, unless otherwise stated to the contrary, the features of different aspects and embodiments of the invention can be combined with each other. BRIEF DESCRIPTION OF THE DRAWINGS

[0076] The foregoing and other features and advantages of the invention will become more apparent from the following detailed description read in conjunction with the accompanying drawings. In the drawings, like reference numerals refer to like elements.

[0077] Figure 1 is a schematic diagram illustrating a system for controlling the operation of a wind turbine according to an example.

[0078] Figure 2is a schematic diagram showing a control system and a signal flow diagram illustrating the operation of the control system according to an example.

[0079] Figure 3 is a schematic diagram, which exemplarily includes a first graph illustrating real position data and position data measured by a first measurement unit over time, a second graph illustrating real position data and position data measured by a second measurement unit over time, and a third graph illustrating real position data and estimated position data over time, the estimated position data being estimated based on the measured data of the first and second measurement units.

[0080] Figure 4 is a schematic flow chart illustrating a method of operating a wind turbine according to an example. DETAILED DESCRIPTION

[0081] Hereinafter, embodiments of the present invention will be described in detail with reference to the accompanying drawings. It should be understood that the following description of the embodiments is given for illustrative purposes only and should not be considered as having a limiting meaning. It should be noted that the accompanying drawings should only be considered as schematic representations, and the elements in the accompanying drawings may not be drawn to scale with each other. On the contrary, the representations of various elements are selected so that their functions and general use become apparent to those skilled in the art. As used herein, the singular forms "one", "a" and "described" are also intended to include plural forms, unless the context clearly indicates otherwise. The terms "include", "have", "include" and "comprising" will be interpreted as open terms (i.e., meaning "including, but not limited to"), unless otherwise stated.

[0082] Unless otherwise specified or the context indicates otherwise, a collision of a rotor blade of a wind turbine with a tower may be referred to herein as a "blade-tower strike" or a "tower strike."

[0083] It should be clear that descriptions and explanations herein limited to one or more specific components of a wind turbine may apply to the same or corresponding components of the wind turbine. For example, descriptions and explanations limited to one rotor blade of a wind turbine may apply to each of the remaining rotor blades of the wind turbine. For example, descriptions and explanations limited to a tower of a wind turbine may apply to one rotor blade of a wind turbine, and vice versa.

[0084] Figure 1 is a schematic diagram illustrating a system 100 for controlling operation of a wind turbine 101 according to an example.

[0085] A wind turbine 101 may include a rotor having rotor blades 102, 103 (showing the first and second blades, with the third blade not shown) and a tower 104. The rotor may be driven by the wind to rotate in a direction following an azimuth orientation 123. The wind may follow a wind direction 111. Each of the plurality of rotor blades 102, 103 may be deflected towards the tower 104 due to the incoming wind, thereby reducing the respective distance 116 of each of the rotor blades 102, 103 from the tower 104. Depending on the deflection amplitude, when the distance 116 becomes too small, there may be a risk of a collision between one of the rotor blades 102, 103 and the tower 104.

[0086] The system 100 may include a first measurement unit 107 and a second measurement unit 108. The measurement units 107, 108 may be mounted to a part of the rotor blade 103. In Figure 1 an example, the measurement units 107, 108 are mounted to a part of the rotor blade 103 in a region located at the rotor blade tip. The first measurement unit 107 may be configured to measure a first parameter indicating the relative position of the rotor blade tip, e.g., the acceleration and / or velocity of the rotor blade tip towards and / or away from the tower 104. For example, the first measurement unit 107 may at least include an inertial measurement unit. The second measurement unit 108 may be configured to measure a second parameter indicating the absolute position of the rotor blade tip, e.g., global positioning data, and in particular GNSS and / or GPS data. For example, the second measurement unit 108 may at least include a receiver for receiving global positioning data.

[0087] The system 100 may further include an additional first measurement unit 105 and an additional second measurement unit 106. The measurement units 105, 106 may be mounted to a part of the tower 104. In Figure 1 an example, the measurement units 105, 106 are mounted to a part of the tower 104 that is passed by the blade tip during operation of the wind turbine 101. The additional first measurement unit 105 may be configured to measure an additional first parameter indicating the relative position of this part of the tower, e.g., the acceleration and / or velocity of this part towards or away from the rotor blade 103. For example, the additional first measurement unit 105 may at least include an inertial measurement unit. The additional second measurement unit 106 may be configured to measure an additional second parameter indicating the absolute position of this part of the tower, e.g., global positioning data, and in particular GNSS and / or GPS data. For example, the additional second measurement unit 106 may at least include a receiver for receiving global positioning data.

[0088] System 100 also includes a control system 120, which includes a processing unit 121 and a memory unit 122. The measurement unit is communicatively coupled to the control system 120 to provide the measured parameters to the control system 120. The control system 120 can be configured to determine the distance 116 for each of the rotor blades 102, 103 based on the provided measured parameters. The control system 120 can also be configured to determine whether there is a risk of collision between one of the rotor blades 102, 103 and the tower 104 based on the determined distance, and modify / adjust the operation of the wind turbine 101 when there is a risk. For this purpose, the control system 120 can be communicatively coupled to the wind turbine 101.

[0089] Each rotor blade of the wind turbine 101 can be equipped with a measurement unit, as indicated, for example, by the measurement units 109, 110 mounted to the rotor blade 102. Thus, the position of each existing rotor blade can be monitored individually. Thus, for each blade, the blade-tower distance can be monitored individually.

[0090] It should be clear that the number, location, and type of the measurement units are not limited to the given examples. Any type of measurement unit that directly or indirectly measures parameters indicating the absolute position and / or relative position of at least a part of the tower or at least a part of a rotor blade can be used, for example, strain gauges, laser-based systems, and leaky-wave feeder radars. In addition, it is also possible to arrange additional measurement units on the tower 104 and the rotor blade 108, as exemplarily indicated by the measurement units 112 - 115. It is also possible to use additional measurement units arranged outside the wind turbine 101. When implementing additional measurement units, the operation of the wind turbine 101 can also be controlled based on the parameters measured by such additional measurement units. In this way, due to the increased amount of the provided measured data, the risk of collision between the rotor blades 102, 103 and the tower 104 can be further reduced, which can improve the reliability of the estimation.

[0091] Figure 2 is a schematic diagram showing the control system 120 and a signal flow diagram illustrating the operation of the control system 120 according to an example.

[0092] The additionally measured first parameter and the additionally measured second parameter can be provided by the measuring unit 105 and the measuring unit 106 to the tower state estimation unit 205. The tower state estimation unit 205 can output the estimated state of the tower 104. The estimated tower state can represent the movement currently implemented by the tower 104. Therefore, the estimated tower state can include the current acceleration, speed, and position of the tower 104. The estimated tower state can be generated by using a state estimator based at least on the provided additionally measured first parameter and the provided additionally measured second parameter. The state estimator can include, for example, a prediction / correction algorithm, in particular a Kalman filter and / or a Luenberger observer. In an example, the state estimator can implement a model based on which the estimation is performed. The model can include a constant acceleration motion model. In addition, an uncertainty parameter can be generated, which indicates the uncertainty of the estimated state of the tower 104 (and one or more state parameters included in the estimated state).

[0093] The estimated tower state can be provided to the tower position obtaining unit 215. The obtaining unit 215 can output the estimated position of the tower 104, which preferably includes the uncertainty associated with the estimated position of the tower 104, the estimated tower position, and / or the associated uncertainty obtained from the estimated state of the tower 104.

[0094] In an exemplary embodiment, obtaining can include predicting the tower position at a future time point when the rotor blade 103 passes by the tower 104 again or next time. In such an embodiment, the estimated state of the tower 104 can be estimated at a time point after the rotor blade 103 has passed by the tower 104 and before the rotor blade will pass by the tower 104 again or next time. The prediction can be performed in such a way that starting from the estimated state of the tower and calculating forward in time based on a (dynamic) model (for example, a constant acceleration motion model indicating the tower movement), the expected movement of the tower 104 is simulated.

[0095] The measured first parameter and the measured second parameter can be provided by measurement unit 107 and measurement unit 108 to the rotor blade state estimation unit 210. The rotor blade state estimation unit 210 can output the estimated state of the rotor blade 103. The estimated rotor blade state can represent the motion currently implemented by the rotor blade 103. Therefore, the estimated rotor blade state can include the current acceleration, velocity, and position of the rotor blade 103. The estimated rotor blade state can be generated by using a state estimator based at least on the provided measured first parameter and the provided measured second parameter. The state estimator can include, for example, a prediction / correction algorithm, in particular a Kalman filter and / or a Luenberger observer. In an example, the state estimator can implement a model based on which the estimation is performed. The model can include a constant acceleration motion model. In addition, an uncertainty parameter can be generated, which indicates the uncertainty of the estimated state of the rotor blade 103 (and one or more state parameters included in the estimated state).

[0096] The estimated rotor blade state can be provided to the rotor blade position obtaining unit 220. The obtaining unit 220 can output the estimated position of the rotor blade 103, which preferably includes the uncertainty associated with the estimated position of the rotor blade 103, the estimated rotor blade position, and / or the associated uncertainty obtained based on the estimated state of the rotor blade 103.

[0097] In an exemplary embodiment, obtaining can include predicting the rotor blade position at a future time point when the rotor blade 103 passes the tower 104 again or next time. In such an embodiment, the estimated state of the rotor blade 103 can be estimated at a time point after the rotor blade 103 has passed the tower 104 and before the rotor blade will pass the tower 104 again or next time. The prediction can be performed in such a way that starting from the estimated state of the rotor blade and based on a (dynamic) model (e.g., a constant acceleration motion model indicating the motion of the rotor blade), the time is advanced forward for calculation, thereby simulating the expected motion of the rotor blade 103.

[0098] Based on the estimated tower position and the estimated rotor blade position, the distance between the rotor blade 103 and the tower 104 can be determined at the subtraction point 225, for example, by calculating the difference between the estimated positions, preferably the Euclidean difference. In addition, an uncertainty parameter indicating the uncertainty of the estimated distance can be obtained based on the uncertainty parameters of the estimated tower position and the estimated rotor blade position. The uncertainty parameter associated with the estimated distance can be obtained, for example, according to the teachings of the uncertainty propagation theory on how to calculate the difference between two parameters affected by uncertainty.

[0099] At the threshold exceeding determination unit 230, it may be determined whether the determined distance exceeds a predetermined (e.g., user-set) threshold. Alternatively or additionally, a probability that the rotor blade 103 collides with the tower 104 at a future time point may be obtained, and it may be determined whether the obtained probability exceeds a predetermined (e.g., user-set) threshold. The probability may be obtained, for example, based on an uncertainty parameter of the distance. The determination result may be provided to the operation modification unit 235.

[0100] In an example, the derived likelihood may also be based on one or more further determined distances between the tower and the rotor blade, the one or more further determined distances being determined at a point in time before the distance is determined. In this way, information obtained from historical / empirical data may be taken into account.

[0101] When it is determined that the threshold is exceeded, the operation modification unit 235 may generate and output one or more control commands that adjust the operation of the wind turbine 101. Adjusting the operation may include implementing operations such as increasing the distance between the tower and the rotor blades by reducing the load on the rotor blades. When it is determined that the threshold is not exceeded, the operation of the wind turbine may be continued / not adjusted.

[0102] Figure 3 is a schematic diagram, which exemplarily includes a first graph 310 illustrating real position data 305 and position data 311 measured by a first measuring unit over time, a second graph 320 illustrating real position data 305 and position data 321 measured by a second measuring unit over time, and a third graph 330 illustrating real position data 305 and estimated position data 331 over time, the position data 331 being estimated based on the measured data 311, 321 of the first and second measuring units.

[0103] For example, the first measuring unit may be the measuring unit 105, and the second measuring unit may be the measuring unit 106. Figure 1 . The first measurement unit may, for example, include one or more receivers for receiving global positioning data. Thus, the position data 311 may be global positioning data, i.e., data indicating the absolute position of the tower 104. The second measurement unit may, for example, include one or more inertial measurement units. Thus, the position data 321 may be obtained based on parameters indicating the relative position of the tower, such as acceleration and / or velocity of the tower 104.

[0104] As can be seen from the true position data 305, the tower 104 vibrates / oscillates at a constant frequency. However, since the sampling frequency of the receiver of the global positioning data (position data 311) is lower than the vibration frequency, the true position data cannot be accurately captured because of significant aliasing. In addition, the low sampling frequency inherently limits the update rate of the position data of the tower. In contrast, the position data 321 obtained from the measurements of the inertial measurement unit is obtained at the following sampling frequency: the sampling frequency provides a sufficiently high tower position update rate and is high enough to see the waveform. However, there is drift in the output position signal. For the position data measured by the inertial measurement unit, this drift is typical, such that recording data over a long time period (e.g., more than 0.5 seconds) may lack accuracy.

[0105] By employing a state estimator (e.g., a Kalman filter) that combines both the position data 311 and the position data 321, it is possible to provide the position data 331 over time with sufficient accuracy and a sufficiently high sampling rate, as can be seen in the graph 330.

[0106] In a simplified consideration, by employing a state estimator, the position data 311 is used as an anchor point, i.e., these are labeled as the true positions. The position data between these anchor points is derived from the relative kinematics of the inertial measurement unit. Since only the inertial measurement unit generates position data over a short period, the errors incurred due to drift are within an acceptable error tolerance. Thus, a state estimator that uses both global positioning data and inertial measurement unit measurements can provide highly accurate position data at a high sampling rate / after a short calculation cycle. Thus, downstream anti-collision control can be provided that operates in a more accurate and thus more reliable manner based on such position data.

[0107] It should be clear that reference Figure 3 And the above regarding the position estimation of the tower correspondingly applies to the position estimation of the rotor blade.

[0108] Figure 4 is a schematic flow chart illustrating a method of operating a wind turbine (such as, for example, wind turbine 101) according to an example.

[0109] Figure 4 The order of the method steps in [[ ]] is not limited to the order shown. The method is also not limited to the number of steps shown. Some steps of the method can be replaced, extended, or not performed.

[0110] Operating the wind turbine can include implementing method 410 in order to estimate the position of at least a portion of a rotor blade of the rotor of the wind turbine during operation of the wind turbine. The rotor blade can be deflected due to the deflection movement of the rotor blade towards the tower of the wind turbine. The position can indicate the deflection.

[0111] In step S410, method 400 may include measuring a first parameter by a first measurement unit, wherein the measured first parameter indicates the absolute position and / or relative position of at least a portion of a rotor blade of a wind turbine.

[0112] In step S420, method 400 may include measuring one or more second parameters by one or more second measurement units, wherein at least one of the one or more measured second parameters indicates the absolute position and / or relative position of at least a portion of the rotor blade.

[0113] In step S430, method 400 may include estimating the position of at least a portion of the rotor blade, wherein the estimation includes employing a state estimator that estimates the state of the rotor blade based at least on the measured first parameter and the one or more measured second parameters, and obtaining the position based on the estimated state of the rotor blade.

[0114] The tower may perform tower motion towards the rotor blade during operation of the wind turbine.

[0115] In step S440, method 400 may include measuring an additional first parameter by an additional first measurement unit, wherein the measured additional first parameter indicates the absolute position and / or relative position of at least a portion of a tower of the wind turbine.

[0116] In step S450, method 400 may include measuring one or more additional second parameters by one or more additional second measurement units, wherein at least one of the one or more measured additional second parameters indicates the absolute position and / or relative position of at least a portion of the tower.

[0117] In step S460, method 400 may include estimating the position of at least a portion of the tower, wherein the estimation includes employing a state estimator that estimates the state of the tower based at least on the measured additional first parameter and the one or more measured additional second parameters, and obtaining the position based on the estimated state of the tower.

[0118] In step S470, method 400 may include determining a distance between the tower and the rotor blade based on the estimated position of at least a portion of the tower and the estimated position of at least a portion of the rotor blade.

[0119] In step S480, method 400 may include adjusting the operation of the wind turbine when it is determined that a threshold is exceeded; and / or continuing the operation of the wind turbine when it is determined that the threshold is not exceeded.

[0120] In an example of method 400, at least a portion of the rotor blade can include a first portion, a second portion, and a third portion of the rotor blade, and / or at least a portion of the tower can include a first portion, a second portion, and a third portion of the tower, as discussed above.

[0121] While specific embodiments have been disclosed herein, various changes and modifications can be made without departing from the scope of the invention. The embodiments are to be considered in all respects as illustrative and not restrictive, and all changes which come within the meaning and range of equivalency of the appended claims are intended to be embraced therein.

Claims

1. A method for estimating the position of at least a part of a rotor blade of a rotor of a wind turbine during operation of the wind turbine, the part of the rotor blade being a first part, wherein, the rotor blade (103) is deflected due to a deflection movement of the rotor blade towards or away from a tower (104) of the wind turbine (101), and wherein the position indicates the deflection, and wherein the method comprises: measuring a first parameter by a first measurement unit (107), the first measurement unit (107) comprising an inertial measurement unit, wherein the measured first parameter indicates the relative position of at least a second part of the rotor blade (103) or another rotor blade (102) of the rotor, measuring a second parameter by a second measurement unit (108), the second measurement unit (108) at least comprising a receiver for receiving global positioning data, wherein the measured second parameter indicates the absolute position of at least a third part of the rotor blade (103) or another rotor blade (102) of the rotor, and estimating the position of at least a first part of the rotor blade (103), wherein the estimation comprises employing a state estimator (210), the state estimator (210) estimating the state of the rotor blade (103) based at least on the measured first parameter and the measured second parameter, and obtaining the position according to the estimated state of the rotor blade (103).

2. The method according to claim 1, wherein, the first parameter comprises at least one of acceleration and velocity of at least a second part of the rotor blade (103) or the other rotor blade (102), and / or wherein the second parameter comprises the position of at least a third part of the rotor blade (103) or the other rotor blade (102).

3. A method for operating a wind turbine, wherein, operating the wind turbine comprises: implementing the method according to claim 1 or 2 to estimate the position of at least a part of a rotor blade (103) of a rotor of the wind turbine (101) during operation of the wind turbine, and determining the distance between a tower (104) of the wind turbine (101) and the rotor blade (103) based on the position of at least a part of the tower (104) and the estimated position of at least a part of the rotor blade (103).

4. The method according to claim 3, wherein, at least a part of the tower (104) comprises at least a first part of the tower (104), and wherein the tower (104) undergoes tower movement during operation of the wind turbine (101), and wherein operating the wind turbine (101) comprises: measuring an additional first parameter by an additional first measurement unit (105), wherein the measured additional first parameter indicates the absolute position and / or relative position of at least a second part of the tower (104). Measuring a further second parameter by means of a further second measuring unit (106), wherein the measured further second parameter indicates the absolute and / or relative position of at least a third part of the tower (104), and estimating the position of at least a first part of the tower (104), wherein the estimation includes using a state estimator (205) which estimates the state of the tower (104) based at least on the measured further first parameter and the measured further second parameter, and obtaining the position based on the estimated state of the tower (104).

5. The method according to claim 4, wherein, the further first parameter includes at least one of acceleration, velocity and position of at least a second part of the tower (104), and / or wherein the further second parameter includes at least one of acceleration, velocity and position of at least a third part of the tower (104).

6. The method according to any one of claims 3 to 5, wherein, obtaining the estimated position of at least a part of the rotor blade (103) based on the estimated state of the rotor blade (103), wherein the estimated state of the rotor blade (103) is estimated at a time point after the rotor blade (103) has passed the tower and before a future time point when the rotor blade passes the tower again, and wherein obtaining the estimated position of at least a part of the rotor blade (103) includes: predicting the position of at least a part of the rotor blade at the future time point based at least on the estimated state of the rotor blade, and / or, wherein obtaining the estimated position of at least a part of the tower (104) based on the estimated state of the tower (104), wherein the estimated state of the tower (104) is estimated at a time point after the rotor blade (103) has passed the tower (104) and before a future time point when the rotor blade (103) passes the tower again, and wherein obtaining the estimated position of at least a part of the tower (104) includes: predicting the position of at least a part of the tower (104) at the future time point based at least on the estimated state of the tower.

7. The method according to any one of claims 3 to 6, wherein, operating the wind turbine (101) includes: determining whether the determined distance exceeds a threshold, and / or wherein operating the wind turbine (101) includes: obtaining at least based on the determined distance between the tower and the rotor blade the likelihood of the rotor blade (103) colliding with the tower at a future time point when the rotor blade passes the tower, and determining whether the obtained likelihood exceeds a threshold, wherein preferably the likelihood is also obtained based on one or more further determined distances between the tower (103) and the rotor blade (104), the one or more further determined distances being determined at a time point before the distance is determined.

8. The method according to claim 7, wherein, the method comprises: when it is determined that the threshold is exceeded, adjusting the operation of the wind turbine (101), and / or when it is determined that the threshold is not exceeded, continuing the operation of the wind turbine (101).

9. The method according to any one of the preceding claims, wherein, employing the state estimator comprises employing a prediction / correction algorithm, in particular a Kalman filter and / or a Luenberger observer.

10. A control system for controlling the operation of a wind turbine, wherein, the control system (120) is configured to implement the method according to any one of claims 1-9.

11. A system for controlling the operation of a wind turbine, wherein, the system (100) comprises: a first measurement unit (107), the first measurement unit (107) comprising an inertial measurement unit, a second measurement unit (108), the second measurement unit (108) at least comprising a receiver for receiving global positioning data, and the control system (120) according to claim 10, wherein the control system is communicatively coupled to the wind turbine (101), the first measurement unit and the second measurement unit, and wherein the system preferably comprises: a further first measurement unit (105) communicatively coupled to the control system (120), and a further second measurement unit (106) communicatively coupled to the control system (120).

12. The system according to claim 11, wherein, at least one of the first measurement unit (107) and the second measurement unit (108) is mounted on a rotor blade (103) of the wind turbine (101), and / or wherein at least one of the further first measurement unit (105) and the further second measurement unit (106) is mounted on a tower (104) of the wind turbine (101).

13. The system according to claim 11 or 12, wherein, the first measurement unit (107) comprises at least one of an accelerometer, an angular rate sensor and a gyroscope, and / or wherein the second measurement unit (108) at least comprises a GNSS receiver and / or a GPS receiver.

14. The system according to any one of claims 11 to 13, wherein, the further first measurement unit (105) comprises at least one of an accelerometer, an angular rate sensor, a gyroscope and an inertial measurement unit, and / or wherein the further second measurement unit (106) at least comprises a receiver for receiving global positioning data, in particular a GNSS receiver and / or a GPS receiver.

15. A computer program for controlling the operation of a wind turbine, wherein, the computer program comprises control instructions which, when executed by a processing unit (121) of a control system (120) for controlling the operation of the wind turbine (101), cause the processing unit to implement the method according to any one of claims 1-9.

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