Patent Description:
Modern wind turbines are used for supplying electricity to the grid. A wind turbine generally includes a tower with a nacelle supported on top of the tower. A wind turbine rotor comprising a hub and a plurality of wind turbine blades may be rotatably mounted to the nacelle.

The wind turbine blades may be set in motion by wind. The hub of the wind turbine may be operatively coupled with a rotor of a generator. As the hub and blades rotate, the kinetic energy of the wind is converted to kinetic mechanical energy of the wind turbine rotor and ultimately to electrical energy or power in the generator. The generator may typically be arranged inside the nacelle.

The wind turbine rotor may be coupled directly to the generator rotor in so-called direct drive wind turbines. Or the wind turbine rotor may include a main rotor shaft (a so-called "low speed shaft" which leads to a gearbox. A high-speed shaft of the gearbox may then drive the generator. Regardless of the topology of the wind turbine, the electrical power output of the generator may be fed to an electric grid. The connection of the generator to the grid may include e.g. a converter, transformer, medium voltage line and other.

A wind turbine controller may be configured to determine suitable actuator setpoints for the wind turbine based on the prevailing circumstances. The actuator setpoints for modern variable speed wind turbines include e.g. the generator torque and the pitch angle of the blades. Through control of the pitch angle(s) of the blade(s) and the generator torque, the speed of the rotor may be controlled, as well as the electrical power output, aerodynamic thrust and further mechanical loads. The purpose of the control system is generally to maximize electrical power output while at the same time keeping loads in the wind turbine at an acceptable level.

As mentioned before, the actuator setpoints of torque and pitch (but also other actuators such as yaw) may be changed in accordance with circumstances. Important input for the determination of the actuator setpoints include e.g. wind speed, and wind direction. The wind speed may be measured directly or indirectly e.g. through the use of a (generator) rotor speed sensor.

Wind turbines may also comprise load sensors on or in the blades for measuring loads on the blades caused by for example the wind and/or the weight of the blades. Too high loads on the blades can e.g. damage the blades and/or cause undesirable rotational speeds of the rotor which may damage other components of the wind turbine. The blade load sensors permit detecting high loads and make it possible to react, by e.g. acting on the pitch systems in such a way that loads on the blades may be reduced. These adjustments on the blades through the pitch systems may extend the life of the wind turbine and/or reduce the cost of producing power.

Load sensors for measuring loads on wind turbines, and particularly wind turbine blades may include resistive strain gauges, fiber optic strain gauges or any other known strain sensing system.

Different blade loads may be defined for a wind turbine blade, namely edge-wise loads, spanwise loads and flap-wise loads. A spanwise direction refers to a direction along a longitudinal axis of the blade, extending from the blade root towards the blade tip. The edge-wise direction refers to a direction along the chord of a section of the wind turbine blade, i.e. extending from leading edge to trailing edge. The flap-wise direction is perpendicular to both the edge-wise and the spanwise direction.

With respect to a wind turbine rotor, loads may be decomposed as in-plane loads (loads that are tangential to the rotor plane) and out-of-plane loads (loads that are perpendicular to the rotor plane). The rotor plane may herein be defined as a plane perpendicular to the rotor rotational axis and passing through a center of the blades at the blade root.

A further sensor that may be used in wind turbine operation(s) is an azimuth sensor. An azimuth angle indicates the angular position of the wind turbine rotor in the rotor plane. Although any specific reference position may be chosen, in an example, tin the 0º position, one of the blades may be in the <NUM> o'clock position (pointing straight upwards). In a three-bladed rotor, the other two blades may be in the <NUM> o'clock position, and in the <NUM> o'clock position respectively. Maintaining the same reference position, in the <NUM>° position of the rotor, the three blades would be in the <NUM> o'clock position (substantially horizontal), the <NUM> o'clock position and the <NUM> o'clock position respectively.

An azimuth sensor as used throughout the present disclosure is any suitable sensor or sensor system which may be used to measure the azimuth position of the rotor. In an example, the azimuth sensor may be an encoder fixed to the wind turbine rotor shaft, or to the generator rotor.

For wind turbine operation in general, and specific maintenance operations in particular, the correct functioning of the azimuth sensor is thus important. For example, individual blade pitch control may be based on signals from the azimuth sensor. In a rotor locking operation, the wind turbine rotor needs to be positioned precisely in one of a plurality of predefined positions, such that the locking mechanism on the nacelle can engage with the wind turbine rotor (hub) and maintenance can be carried out.

Azimuth sensors can be calibrated in order to preserve their accuracy. Calibration normally comprises establishing correspondence between indications generated by the azimuth sensors and values of reference according to calibration patterns (i.e. particular conditions for calibration). Such a calibration is generally carried out offline (i.e. when the wind turbine is nor in operation) and requires specific conditions (no wind or very low wind speeds). In examples, it may require visual inspection by personnel on the ground to determine when the rotor is in a specific operation.

It is known that azimuth sensors can degrade over time. Particularly, it has been found that azimuth sensors may show a "drift" behaviour in the error, i.e. the difference between the actual angular position of the rotor and the indicated position increases over time. Also, after a maintenance operation it has been found that an offset may be introduced in the system.

Wrong indications from the azimuth sensors can lead to a wrong or suboptimal load control, and/or wrong or suboptimal individual or collective pitch control which in turn can lead to higher (fatigue) loads, and/or reduced energy output. Wrong indications from the azimuth sensors can lead to complications in maintenance operations and increased maintenance time.

Document <CIT> discloses a method of detecting an error in a rotor angle sensing system of a wind turbine. The method comprises generating an estimated blade load signal based at least on the rotor angle signal; comparing the estimated blade load signal with the measured blade load signal to determine a phase difference between them; and identifying an error if the phase difference between the estimated blade load signal and the measured blade load signal exceeds a predetermined threshold.

The present disclosure provides examples of method and systems for determining reliability or correct functioning of azimuth sensors that resolve at least some of the aforementioned disadvantages.

In a first aspect, a method for determining reliability of an azimuth measurement system in a wind turbine is provided. The method comprises, measuring an angular phase of a rotor of the wind turbine by the azimuth measurement system, measuring loads with the load sensors during operation of the wind turbine and determining in-plane moments with rotor rotational speed frequency of one or more blades based on the measured loads. The method then further comprises determining an angular phase of a wind turbine rotor based on the in-plane moments with rotor rotational speed frequency and determining that the azimuth measurement system has reduced reliability if an angular phase of the in-plane moments with rotor rotational speed frequency deviates from an angular phase measured by the azimuth measurement system by more than a first threshold value.

In accordance with this aspect, the reliability or correct functioning of azimuth sensors can be determined during operation of the wind turbine, i.e. the operation of the wind turbine does not need to be interrupted or put in specific conditions in order to be able to determine whether the azimuth measurement system is correctly indicating the azimuth position. The loads measured may be measured as in-plane moments or converted to in-plane moments. The in-plane moments at any given moment during operation will be a combination of aerodynamic loads and loads due to mass of the blades. The mass of the blades will however provide the same moment throughout every rotation of the blade. At a <NUM> o'clock position and at a <NUM> o'clock position, the mass of the blade will not contribute to a bending moment. But at a <NUM> o'clock position and a <NUM> o'clock position, the bending moment due to the mass of the blade will be at a maximum (in one direction, and in the opposite direction respectively). The mass of the blade will have a well-defined contribution with 1p frequency, i.e. the variation of the moment due to the mass will have the same frequency as the rotor rotational speed. The rotor in this respect refers to the wind turbine rotor, not to the generator rotor. The generator rotor may have the same rotational speed in the case of a direct drive wind turbine, but may have a very different speed in the case of a wind turbine with gearbox.

The terms "1p frequency" and "rotor rotational speed frequency" may be used interchangeably throughout this disclosure.

By selecting the in-plane moments with the rotor rotational speed frequency and comparing the angular phase of selected in-plane moments with a measured azimuth phase angle, a deviation between the two indicates a possible malfunctioning of the azimuth measurement system. Once such a possible malfunctioning is detected, different actions can be taken to reduce the risk of a malfunctioning azimuth measurement system.

Each example is provided by way of explanation of the invention, not as a limitation of the invention.

In examples, the rotor blades <NUM> may have a length ranging from about <NUM> meters (m) to about <NUM> or more. Rotor blades <NUM> may have any suitable length that enables the wind turbine <NUM> to function as described herein. For example, non-limiting examples of blade lengths include <NUM> or less, <NUM>, <NUM>, <NUM>, <NUM> or a length that is greater than <NUM>. As wind strikes the rotor blades <NUM> from a wind direction <NUM>, the rotor <NUM> is rotated about a rotor axis <NUM>. As the rotor blades <NUM> are rotated and subjected to centrifugal forces, the rotor blades <NUM> are also subjected to various forces and moments. As such, the rotor blades <NUM> may deflect and/or rotate from a neutral, or non-deflected, position to a deflected position.

In the example, the wind turbine controller <NUM> is shown as being centralized within the nacelle <NUM>, however, the wind turbine controller <NUM> may be a distributed system throughout the wind turbine <NUM>, on the support system <NUM>, within a wind farm, and/or at a remote control center. The wind turbine controller <NUM> includes a processor <NUM> configured to perform the methods and/or steps described herein. Further, many of the other components described herein include a processor.

As used herein, the term "processor" is not limited to integrated circuits referred to in the art as a computer, but broadly refers to a controller, a microcontroller, a microcomputer, a programmable logic controller (PLC), an application specific, integrated circuit, and other programmable circuits, and these terms are used interchangeably herein. It should be understood that a processor and/or a control system can also include memory, input channels, and/or output channels.

<FIG> is an enlarged sectional view of a portion of the wind turbine <NUM>. In the example, the wind turbine <NUM> includes the nacelle <NUM> and the rotor <NUM> that is rotatably coupled to the nacelle <NUM>. More specifically, the hub <NUM> of the rotor <NUM> is rotatably coupled to an electric generator <NUM> positioned within the nacelle <NUM> by the main shaft <NUM>, a gearbox <NUM>, a high-speed shaft <NUM>, and a coupling <NUM>. In the example, the main shaft <NUM> is disposed at least partially coaxial to a longitudinal axis (not shown) of the nacelle <NUM>. A rotation of the main shaft <NUM> drives the gearbox <NUM> that subsequently drives the high-speed shaft <NUM> by translating the relatively slow rotational movement of the rotor <NUM> and of the main shaft <NUM> into a relatively fast rotational movement of the high-speed shaft <NUM>. The latter is connected to the generator <NUM> for generating electrical energy with the help of a coupling <NUM>. Furthermore, a transformer <NUM> and/or suitable electronics, switches, and/or inverters may be arranged in the nacelle <NUM> in order to transform electrical energy generated by the generator <NUM> having a voltage between 400V to <NUM> V into electrical energy having medium voltage (<NUM> - <NUM> KV) or higher voltage, e.g. 66kV. Said electrical energy is conducted via power cables <NUM> from the nacelle <NUM> into the tower <NUM>.

The gearbox <NUM>, generator <NUM> in transformer <NUM> may be supported by a main support structure frame of the nacelle <NUM>, optionally embodied as a main frame <NUM>. The gearbox <NUM> may include a gearbox housing that is connected to the main frame <NUM> by one or more torque arms <NUM>. In the example, the nacelle <NUM> also includes a main forward support bearing <NUM> and a main aft support bearing <NUM>. Furthermore, the generator <NUM> can be mounted to the main frame <NUM> by decoupling support means <NUM>, in particular in order to prevent vibrations of the generator <NUM> to be introduced into the main frame <NUM> and thereby causing a noise emission source.

For positioning the nacelle <NUM> appropriately with respect to the wind direction <NUM>, the nacelle <NUM> may also include at least one meteorological measurement system which may include a wind vane and anemometer. The meteorological measurement system <NUM> can provide information to the wind turbine controller <NUM> that may include wind direction <NUM> and/or wind speed. In the example, the pitch system <NUM> is at least partially arranged as a pitch assembly <NUM> in the hub <NUM>. The pitch assembly <NUM> includes one or more pitch drive systems <NUM> and at least one sensor <NUM>. Each pitch drive system <NUM> is coupled to a respective rotor blade <NUM> (shown in <FIG>) for modulating the pitch angel of a rotor blade <NUM> along the pitch axis <NUM>. Only one of three pitch drive systems <NUM> is shown in <FIG>.

In the example, the pitch assembly <NUM> includes at least one pitch bearing <NUM> coupled to hub <NUM> and to a respective rotor blade <NUM> (shown in <FIG>) for rotating the respective rotor blade <NUM> about the pitch axis <NUM>. The pitch drive system <NUM> includes a pitch drive motor <NUM>, a pitch drive gearbox <NUM>, and a pitch drive pinion <NUM>. The pitch drive motor <NUM> is coupled to the pitch drive gearbox <NUM> such that the pitch drive motor <NUM> imparts mechanical force to the pitch drive gearbox <NUM>. The pitch drive gearbox <NUM> is coupled to the pitch drive pinion <NUM> such that the pitch drive pinion <NUM> is rotated by the pitch drive gearbox <NUM>. The pitch bearing <NUM> is coupled to pitch drive pinion <NUM> such that the rotation of the pitch drive pinion <NUM> causes a rotation of the pitch bearing <NUM>.

Pitch drive system <NUM> is coupled to the wind turbine controller <NUM> for adjusting the pitch angle of a rotor blade <NUM> upon receipt of one or more signals from the wind turbine controller <NUM>. In the example, the pitch drive motor <NUM> is any suitable motor driven by electrical power and/or a hydraulic system that enables pitch assembly <NUM> to function as described herein. Alternatively, the pitch assembly <NUM> may include any suitable structure, configuration, arrangement, and/or components such as, but not limited to, hydraulic cylinders, springs, and/or servomechanisms. In certain embodiments, the pitch drive motor <NUM> is driven by energy extracted from a rotational inertia of hub <NUM> and/or a stored energy source (not shown) that supplies energy to components of the wind turbine <NUM>.

The pitch assembly <NUM> may also include one or more pitch control systems <NUM> for controlling the pitch drive system <NUM> according to control signals from the wind turbine controller <NUM>, in case of specific prioritized situations and/or during rotor <NUM> overspeed. In the example, the pitch assembly <NUM> includes at least one pitch control system <NUM> communicatively coupled to a respective pitch drive system <NUM> for controlling pitch drive system <NUM> independently from the wind turbine controller <NUM>. In the example, the pitch control system <NUM> is coupled to the pitch drive system <NUM> and to a sensor <NUM>. During normal operation of the wind turbine <NUM>, the wind turbine controller <NUM> may control the pitch drive system <NUM> to adjust a pitch angle of rotor blades <NUM>.

According to an embodiment, a power supply <NUM>, for example comprising a battery, electric capacitors hence letter or an electrical generator driven by the rotation of the hub <NUM>, is arranged at or within the hub <NUM> and is coupled to the sensor <NUM>, the pitch control system <NUM>, and to the pitch drive system <NUM> to provide a source of power to these components. In the example, the power supply <NUM> provides a continuing source of power to the pitch assembly <NUM> during operation of the wind turbine <NUM>. In an alternative embodiment, power supply <NUM> provides power to the pitch assembly <NUM> only during an electrical power loss event of the wind turbine <NUM>. The electrical power loss event may include power grid loss or dip, malfunctioning of an electrical system of the wind turbine <NUM>, and/or failure of the wind turbine controller <NUM>. During the electrical power loss event, the power supply <NUM> operates to provide electrical power to the pitch assembly <NUM> such that pitch assembly <NUM> can operate during the electrical power loss event.

In the example, the pitch drive system <NUM>, the sensor <NUM>, the pitch control system <NUM>, cables, and the power supply <NUM> are each positioned in a cavity <NUM> defined by an inner surface <NUM> of hub <NUM>. In an alternative embodiment, said components are positioned with respect to an outer surface of hub <NUM> and may be coupled, directly or indirectly, to outer surface.

<FIG> schematically illustrates an example of a method for determining reliability of an azimuth measurement system in a wind turbine. The method comprises, at block <NUM>, measuring loads with load sensors during operation of the wind turbine. At block <NUM>, in-plane moments based on the measured loads are determined. Then, at block <NUM>, the in-plane moments with 1p frequency are selected.

At block <NUM>, an azimuth angle of a wind turbine rotor is measured. At block <NUM>, the phase angle of the selected in-plane moments may be compared with the phase angle of the theoretical in-plane moments due to a mass of the blades. Then, at block <NUM>, the determination may be made that the azimuth measurement system has reduced reliability if the phase angle of the selected in-plane moments deviates from the phase angle of the theoretical in-plane moments by more than a first threshold value.

In examples, theoretical in-plane moments due to a mass of one or more of the blades derived from the azimuth phase angle may be compared with the phase angle of the selected in-plane moments to determine (reduced) reliability.

In some examples, the measuring loads at block <NUM> may comprise measuring flap-wise and edge-wise moments. Standard wind turbine blades may incorporate suitable load sensors. The load sensors may be strain gauges. Depending on where and how the load sensors are mounted, strains may be measured in different directions. Sensors arranged in the hub, or any other (indirect) blade support may be used to determine loads as well.

Edge-wise and flap-wise loads may be used in control of wind turbines. The edge-wise and flap-wise moments may be converted to in-plane moments and out-of-plane moments based on a pitch angle of the blade at block <NUM>. Only the in-plane moments need to be considered in the present method, since the loads of the mass of the rotor wind turbine blades will be in-plane loads, not out-of-plane loads.

At block <NUM>, the selecting the in-plane moments with rotor rotational speed frequency may comprise filtering the determined in-plane moments using a peak filter. A peak filter is a frequency filter that passes a narrow band of frequencies and is configured to stop all other frequencies. A peak filter in this respect is, in essence, a very narrow band pass filter. The result of the filter may be seen at the top of <FIG>, in which for three blades of a wind turbine, in-plane modes with 1p frequency are shown during a number of complete revolutions of the wind turbine rotor.

From the selected in-plane moments a phase angle of each of the individual blades may be derived. For each of the individual blades, the maximum moment corresponds to the corresponding three o'clock position of the blade, and the minimum moment (or maximum negative moment) corresponds to the nine o'clock position of the blade.

If the azimuth measurement system works correctly, then the moments due to the mass of the blades should correspond to the theoretical moments that would be caused by the mass of the blades in the measured azimuth positions. In other words, if the azimuth measurement system works correctly, then the phase angle of the moments due to the mass of the blades should correspond to the measurement azimuth angle. The measured azimuth angle is shown in the middle of <FIG>.

At the bottom of <FIG>, a phase angle difference is depicted for each of the individual blades. A phase angle difference may be determined continuously, or as in the example of <FIG>, once per full revolution.

In the example of <FIG>, the individual rotor blades shown a mismatch of the measured azimuth angle with the azimuth angle derived from the analysis of the loads, is between -2º and 5º. In this specific example, two different angular thresholds have been defined.

At block <NUM>, the determination may be made that the azimuth measurement has reduced reliability if the phase angle of the selected in-plane moments deviates from the phase angle of the theoretical in-plane moments by more than a first threshold value.

In some examples, the first threshold value may be an angle between <NUM> and 15º, specifically between <NUM> and 15º. In <FIG>, the first threshold value is chosen at 10º.

In some examples, the comparison of the angular difference may be determined for each of the blades individually. Angular difference for individual blades may be compared to an allowable maximum or threshold. In other examples, an average of the phase angle difference for the blades may be compared with the threshold value.

In some examples, the method may further comprise generating a warning signal, or changing operation of the wind turbine when it is determined that the azimuth measurement system has reduced reliability. Changing the operation of the wind turbine may include one or more of the following: derating the wind turbine, deactivating or changing one or more control algorithms that rely on measurements of the azimuth measurement system.

In some examples, the method may further comprise generating a first warning signal if the azimuth measurement system has reduced reliability. A first threshold may be defined which indicates a malfunctioning. If the threshold is passed, different actions may be taken. Maintenance may be planned to substitute or recalibrate sensors. Or the operation of the wind turbine may be downrated, i.e. loads on the wind turbine may consciously be reduced at the expense of electrical power generation, because the measurements of the sensors are not as reliable as they should be. In yet further examples, control algorithms and methods that rely on input from azimuth sensors may be disabled and/or substituted by other algorithms and methods. In other examples, the wind turbine operation may be stopped if the azimuth sensors are determined to be unreliable. In examples, different threshold levels (two or more), and for each threshold different actions may be defined including warning signals, planning maintenance or recalibration, disabling or adapting control functions, control to reduce loads, interrupting of operation and others.

In some examples, as in <FIG>, the method may further comprise determining whether the angular phase of the in-plane moments with rotor rotational speed frequency of the one or more blades deviates from an angular phase of the theoretical in-plane moments by more than a second threshold value, the second threshold value being higher than the first threshold value.

The second threshold value may be between 10º and 20º. In the specific example of <FIG>, the second threshold value is fixed at 15º. In examples, the method may further comprise interrupting the operation of the wind turbine, if the phase angle of the selected in-plane moments of the blades deviates from the phase angle of the theoretical in-plane moments of the blades by more than the second threshold value. In these examples, a first threshold may generate a warning signal (operators are made aware of a potential problem and operation may continue, as normal or with some changes), and the passing of a second threshold indicates a more serious warning (e.g. interruption of the operation, downrating of operation or other).

In a further aspect, a wind turbine system is provided. With reference to <FIG>, the wind turbine system comprises a wind turbine <NUM> including a wind turbine rotor <NUM> with a plurality of blades <NUM>, a plurality of load sensors for measuring loads on the blades <NUM>, and an azimuth measurement system to determine an angular position of the wind turbine rotor <NUM> in a rotor plane.

The wind turbine system further comprises a control system configured to carry out any of the methods illustrated herein.

With reference to <FIG>, in particular, the control system may be configured to receive signals from the load sensors during operation, at block <NUM>. The control system may further, at block <NUM>, determine in-plane moments on one or more of the blades. In particular, at block <NUM>, the in-plane moments with 1p frequency may be determined or selected.

The control system may further be configured, at block <NUM>, to receive azimuth positions from one or more azimuth sensors. The control system may further be configured to compare the compare a phase angle of the selected in-plane moments with a measured azimuth phase angle; and to determine if the phase angle of the selected in-plane moments deviates from the measured azimuth phase angle by more than a predefined threshold. If this determination is made, at block <NUM>, reduced reliability of the azimuth sensors is detected. The control system may further be configured to generate a warning signal if the reduced reliability is detected. As mentioned before, the warning signal may take different forms and may lead to a variety of actions including scheduled maintenance, replacement or recalibration of a sensor, interruption of operation, sending of a warning to a remote operating centre and other. In further examples, input from an azimuth sensor that may still be regarded as reliable may be selected as input (disregarding inputs from other azimuth sensors).

<FIG> and <FIG> schematically illustrate a comparison between measured in-plane moments and theoretical in-plane moments based on a measured azimuth angle.

In the situation of <FIG>, a comparison is made for the three individual blades between the measured in-plane moments (thick lines) and the theoretical in-plane moments based on the measured azimuth angle (interrupted lines indicated upper and lower thresholds). That is, an indirect comparison is made between the phase angle that can be derived from the measured in-plane moments and the phase angle as measured by the azimuth sensor. In the situation of <FIG>, it may be seen (right hand side of the figure) that the difference in phase angle is generally in the range between +5º and -5º. In the specific example, a first threshold is shown to be defined at 10º, and a second threshold at 15º. Differences in the results between individual blades can generally be explained by accuracy or errors in measurements.

In the situation of <FIG>, it may be seen instead that there is a significant difference, around 30º, between the measured azimuth angle, and the angle that can be derived from the load measurements. It may furthermore be seen that the deviation is not only found for an individual blade (which could potentially indicate a problem with measurements of an individual blade), but rather for each of the three blades.

It has been found that even if load sensors may also have reduced reliability at times, such a reduced reliability will generally affect the absolute values of the measurements, but not so much the phase angle. Therefore, examples of the methods provided herein may even be used if the load sensors have a reduced reliability, to some extent.

In some examples, wherein each of the blades may comprise strain gauges. In particular, some of the strain gauges may be arranged to measure flap-wise moments, and other strain gauges may be arranged to measure edge-wise moments. The strain gauges may be located at or near the root of the blade, where the bending moments will be highest. In other examples, the strain gauges may be located at a spanwise position at a distance from the root. The measurements of such strain gauges may be converted to moments at the blade root in some examples. In examples, measurements from load sensors on the blades that are not at the root of the blade may be extrapolated to indicate moments at the root of a blade. In examples, the sensors may be mounted at a suitable location on the hub, instead of the blade.

In other examples, other sensors or systems may be used for measuring stress and strain, and/or to derive bending moments in the blades. Suitable strain gauges may include resistive foil strain gauges. The resistive strain gauges may be attached to the blade with a suitable glue, e.g. epoxy based glue. Other types of strain gauges and sensors may also be used such as e.g. piezoresistors, capacitive strain gauges, or fiber optics to measure strain along an optical fiber, or accelerometers.

In some examples, the azimuth measurement system comprises a rotary encoder. Such a rotary encoder may be arranged with the wind turbine rotor, including the low-speed shaft, or the hub. A rotary encoder may also be arranged with the generator rotor or high-speed shaft. In further examples, the azimuth measurement system may be based on e.g. a capacitance, inductance, magnetic or proximity sensor arranged with the hub. The interaction of the hub with a nacelle mounted element may be measured with such sensors to determine an azimuth angle.

In some examples, the control system may be at a remote location from the wind turbine. The control system may be part of a SCADA system of a wind farm, or may be at a remote operating centre. In some examples, the wind turbine controller itself may incorporate the functions for determining a potential malfunction or loss of reliability of the load sensor. The control system may also form part of the wind turbine controller i.e. the combination of hardware and/or software provided in the wind turbine itself.

<FIG> schematically illustrates another example of a method for determining reliability of a wind turbine azimuth measurement system. <FIG> schematically illustrates a method for on-line determination of correct functioning of azimuth sensors of a wind turbine. "On-line" determination may herein be regarded as a determination that occurs during normal operation of the wind turbine, and substantially in real-time. Therefore, the determination does not require a specific operational sequence or specific operational conditions.

The method comprises measuring edge-wise and flap-wise strains in a wind turbine blade, at block <NUM>. The method them comprises, at block <NUM>, determining edge-wise and flap-wise bending moments in the wind turbine blade based on the measured strains.

At block <NUM>, the determined edge-wise and flap-wise bending moments may be converted to measured in-plane moments and measured out-of-plane moments on the wind turbine blade. The conversion from edge-wise and flap-wise to in-plane and out-of-plane may be based particular on the pitch angle of the individual blade. At block <NUM>, a peak filter may be applied to determine the measured in-plane moments with 1p frequency. And at block <NUM>, a phase angle of the of the in-plane moments with 1p frequency may be determined.

The method comprises, at block <NUM>, measuring an azimuth angle of the rotor blade with the azimuth sensor. Then, at block <NUM>, the phase angle determined based on the measured in-plane moments with 1p frequency may be compared with the measured azimuth angle.

At block <NUM>, the azimuth sensors are determined to function correctly, if an angular phase of the measured in-plane moments with 1p frequency differ less than a threshold phase angle difference from measured azimuth angle. The operation of the wind turbine may continue as normal, as schematically indicated in <FIG>. If the angular difference is above the threshold, an action may be taken to counteract the malfunction of the azimuth sensor, and/or a warning may be generated.

Even though <FIG> illustrates a method for a single blade of a wind turbine, the same method may be applied to multiple blades of the same wind turbine.

In some examples, the method may further comprise interrupting operation of the wind turbine if the warning is generated or downrating the wind turbine if the warning is generated.

The order shown of method steps in <FIG>, <FIG> and <FIG> are not to be regarded as necessarily sequential. In particular, the determination of azimuth angles does not need to occur at any specific moment of time in comparison to the measurement of the loads. The measured loads and azimuth angle only need to be correlated in time to make a meaningful comparison. Also, the methods may be continuously carried out during operation of the wind turbine. Steps may be carried out at a frequency of more than <NUM>, specifically at a frequency of higher than <NUM>.

Throughout the present disclosure a reference has been made to a comparison between the measured azimuthal phase angle and the phase angle that can be derived from in-plane bending moments with 1p frequency (i.e. those moments that theoretically can be attributed to the weight or mass of the blades only). Such a comparison may be made directly in some cases. In other cases, a comparison may be made between the angular phase of the measured in-plane bending moments with 1p frequency and the theoretical moments caused by the mass of the blades, wherein the theoretical moments may be calculated based on the measured azimuth angle.

Throughout the present disclosure, reference has been made to a comparison with a threshold. Such a comparison may be based on a single revolution of a wind turbine rotor. In other examples, a comparison with a threshold (or multiple thresholds) may be made based on a plurality of rotor revolutions, e.g. <NUM> or <NUM> or more.

Examples of the methods disclosed herein may be implemented with hardware, software, firmware and combinations thereof.

Those of skill in the art would further appreciate that the various illustrative logical blocks, modules, circuits, and algorithm steps described in connection with the disclosure herein may be implemented as electronic hardware, computer software, or combinations of both.

The various illustrative logical blocks, modules, and circuits described in connection with the disclosure herein may be implemented or performed with one or more general-purpose processors, a digital signal processor (DSP), cloud computing architecture, an application specific integrated circuit (ASIC), a field programmable gate array (FPGA) or other programmable logic device, discrete gate or transistor logic, discrete hardware components, or any combination thereof designed to perform the functions described herein.

The present disclosure also related to computing systems adapted to carry out any of the methods disclosed herein.

The present disclosure also relates to a computer program or computer program product comprising instructions (code), which when executed, performs any of the methods disclosed herein.

The computer program may be in the form of source code, object code, a code intermediate source and object code such as in partially compiled form, or in any other form suitable for use in the implementation of the processes. The carrier may be any entity or device capable of carrying the computer program.

If implemented in software/firmware, the functions may be stored on or transmitted over as one or more instructions or code on a computer-readable medium. A storage media may be any available media that can be accessed by a general purpose or special purpose computer. By way of example, and not limitation, such computer-readable media can comprise RAM, ROM, EEPROM, CD/DVD or other optical disk storage, magnetic disk storage or other magnetic storage devices, or any other medium that can be used to carry or store desired program code means in the form of instructions or data structures and that can be accessed by a general-purpose or special-purpose computer, or a general-purpose or special-purpose processor. For example, if the software/firmware is transmitted from a website, server, or other remote source using a coaxial cable, fiber optic cable, twisted pair, digital subscriber line (DSL), or wireless technologies such as infrared, radio, and microwave, then the coaxial cable, fiber optic cable, twisted pair, DSL, or wireless technologies such as infrared, radio, and microwave are included in the definition of medium. Disk and disc, as used herein, includes compact disc (CD), laser disc, optical disc, digital versatile disc (DVD), floppy disk and Blu-ray disc where disks usually reproduce data magnetically, while discs reproduce data optically with lasers.

Claim 1:
A method for determining reliability of an azimuth measurement system in a wind turbine, comprising:
measuring an angular phase of a rotor of the wind turbine by the azimuth measurement system;
measuring (<NUM>) loads with load sensors during operation of the wind turbine;
determining (<NUM>) in-plane moments with rotor rotational speed frequency of one or more blades based on the measured loads;
determining (<NUM>) that the azimuth measurement system has reduced reliability if an angular phase of the in-plane moments with rotor rotational speed frequency deviates from the angular phase measured by the azimuth measurement system by more than a first threshold value.