Control for a wind turbine

Abstract

A method of controlling a wind turbine having a nacelle, a rotor, a rotating hub, a first rotor blade and at least a second rotor blade, both rotor blades being mounted to the hub. The method includes measuring the strain in the first rotor blade by a strain measurement device attached to the first rotor blade; and choosing the operational parameters of the wind turbine based on the measured strain such that fatigue damage of the second rotor blade is reduced. A wind turbine is controlled by such a method.

Claims

1. A method of controlling a wind turbine comprising a nacelle, a rotor, a rotating hub, a first rotor blade and at least a second rotor blade, both rotor blades being mounted to the hub, the second rotor blade trailing the first rotor blade in a rotor plane of the wind turbine, the method comprising: measuring a strain in the first rotor blade at a first angular position within the rotor plane using at least one strain measurement device attached to the first rotor blade; calculating a speed of an impinging airflow at the first angular position based at least on the measured strain in the first rotor blade at the first angular position; determining a rotational speed of the rotor; calculating an expected time needed by the second rotor blade to reach the first angular position within the rotor plane, wherein the calculation is carried out based on the determined rotational speed of the rotor and the angle between the first rotor blade and the second rotor blade; and changing an orientation of the second rotor blade to an optimized orientation within the expected time such that the second rotor blade is in the optimized orientation before reaching the first angular position, wherein the optimized orientation is selected based on the calculated speed of the impinging airflow at the first angular position to achieve a goal selected from the group consisting of reducing fatigue damage on the second rotor blade, increasing overall performance of the wind turbine, and combinations thereof.

2. The method according to claim 1, wherein the orientation of the second rotor blade is changed by pitching the second rotor blade.

3. The method according to claim 1, wherein the orientation of the second rotor blade is changed by yawing the nacelle of the wind turbine.

4. The method according to claim 1, further comprising: calculating a second expected time needed by a third rotor blade of the wind turbine to reach the first angular position within the rotor plane, wherein the calculation is carried out based on the determined rotational speed of the rotor and the angle between the first rotor blade and the third rotor blade, and changing an orientation of the third rotor blade to a second optimized orientation within the second expected time such that the third rotor blade is in the second optimized orientation before reaching the first angular position, wherein the second optimized orientation is selected based on the speed of the impinging airflow at the first angular position to achieve a goal selected from the group consisting of reducing fatigue damage on the third rotor blade, increasing overall performance of the wind turbine, and combinations thereof.

5. The method according to claim 1, wherein a plurality of strain measurement devices are arranged along the span of the first rotor blade between the root portion of the first rotor blade and the tip portion of the first rotor blade; and wherein the method comprises obtaining a plurality of strain measurements along the span of the first rotor blade using the plurality of strain measurement devices; calculating a speed distribution of the impinging airflow along the first rotor blade at the first angular position based at least on the plurality of strain measurements; and wherein the optimized orientation is selected based on the calculated speed distribution of the impinging airflow at the first angular position.

6. The method according to claim 1, wherein the strain in all rotor blades of the wind turbine are measured by respective strain measurement devices attached to the respective rotor blades.

7. A wind turbine, comprising: a nacelle; a rotor; a rotating hub; a first rotor blade; at least a second rotor blade, both rotor blades being mounted to the hub, the second rotor blade trailing the first rotor blade in a rotor plane of the wind turbine; at least one strain measurement device attached to the first rotor blade for measuring a strain in the first rotor blade at a first radial position along the first rotor blade and at a first angular position within the rotor plane; and a controller adapted to calculate a speed of an impinging airflow at the first angular position based at least on the measured strain in the first rotor blade at the first angular position; determine a rotational speed of the rotor, to calculate an expected time needed by the second rotor blade to reach the first angular position within the rotor plane, wherein the calculation is carried out based on the determined rotational speed of the rotor and the angle between the first rotor blade and the second rotor blade, and to change an orientation of the second rotor blade to an optimized orientation within the expected time such that the second rotor blade is in the optimized orientation before reaching the first angular position, wherein the optimized orientation is selected based on the calculated speed of the impinging airflow at the first angular position to achieve a goal selected from the group consisting of reducing fatigue damage on the second rotor blade, increasing overall performance of the wind turbine, and combinations thereof.

8. The wind turbine according to claim 7, wherein the strain measurement device is arranged at the root portion of the first rotor blade.

9. The wind turbine according to claim 7, wherein a plurality of strain measurement devices are arranged along the span of the first rotor blade between the root portion of the first rotor blade and the tip portion of the first rotor blade.

10. The wind turbine according to claim 9, wherein the strain measurement devices are connected via optical fibers or wireless with each other.

11. A wind turbine which is controlled by the method according to claim 1.

12. The wind turbine according to claim 11, further comprising a controller adapted to control the wind turbine.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) Embodiments of the invention are now described, by way of example only, with reference to the accompanying drawings, of which:

(2) FIG. 1 shows a wind turbine with a controller for reducing fatigue damage on the rotor blades of the wind turbine;

(3) FIG. 2 shows a rotor blade of a wind turbine;

(4) FIG. 3 shows a wind turbine with a strain measurement device arranged at the root portion of one of the rotor blades and a calculated corresponding wind field;

(5) FIG. 4 shows a rotor blade equipped with a plurality of strain measurement devices arranged along the span of the rotor blade;

(6) FIG. 5 shows a wind turbine with a plurality of strain measurement devices arranged on one of the rotor blades and a calculated corresponding wind field;

(7) FIG. 6 shows two rotor blades being impinged by an airflow with uniform low wind speed;

(8) FIG. 7 shows two rotor blades being impinged by an airflow with uniform high wind speed;

(9) FIG. 8 shows two rotor blades being impinged by an airflow with non-uniform wind speed;

(10) FIG. 9 shows a rotor blade with a strain measurement device in a bent and in an unbent state;

(11) FIG. 10 shows the root bending moment of uniform airflows in Cartesian coordinates;

(12) FIG. 11 shows the root bending moment of uniform airflows in polar coordinates;

(13) FIG. 12 shows the root bending moment of non-uniform airflows in Cartesian coordinates;

(14) FIG. 13 shows the root bending moment of non-uniform airflows in polar coordinates; and

(15) FIG. 14 shows the root bending moment of another non-uniform airflow in polar coordinates.

DETAILED DESCRIPTION OF INVENTION

(16) The illustration in the drawings is in schematic form. It is noted that in different figures, similar or identical elements may be provided with the same reference signs.

(17) In FIG. 1, a wind turbine 10 is shown. The wind turbine 10 comprises a nacelle 12 and a tower 11. The nacelle 12 is mounted at the top of the tower 11. The nacelle 12 is mounted rotatable with regard to the tower 11 by means of a yaw bearing. The axis of rotation of the nacelle 12 with regard to the tower 11 is referred to as the yaw axis.

(18) The wind turbine 10 also comprises a hub 13 with three rotor blades 20 (of which two rotor blades 20 are depicted in FIG. 1). The hub 13 is mounted rotatable with regard to the nacelle 12 by means of a main bearing. The hub 13 is mounted rotatable about a rotor axis of rotation 14.

(19) The wind turbine 10 furthermore comprises a main shaft, which connects the hub 13 with a rotor of a generator 15. The hub 13 is connected directly to the rotor, thus the wind turbine 10 is referred to as a gearless, direct drive wind turbine. As an alternative, the hub 13 may also be connected to the rotor via a gearbox. This type of wind turbine is referred to as a geared wind turbine.

(20) The generator 15 is accommodated within the nacelle 12. It comprises the rotor and a stator. The generator 15 is arranged and prepared for converting the rotational energy from the rotor into electrical energy.

(21) Additionally, the wind turbine 10 comprises a controller 17 which is arranged within the hub 13.

(22) FIG. 2 shows a rotor blade 20 of a wind turbine. The rotor blade 20 comprises a root section 21 with a root 211 and a tip section 22 with a tip 221. The root 211 and the tip 221 are virtually connected by the span 26 which follows the shape of the rotor blade 20.

(23) FIG. 3 shows a wind turbine 10 comprising a first rotor blade 201, a second rotor blade 202 and a third rotor blade 203. All three rotor blades 201, 202, 203 can be pitched about respective pitch axes. These pitch axes coincide substantially with the respective longitudinal axes of the rotor blades. The first rotor blade 201 comprises a strain measurement device 31 at its root section 21. The strain measurement device 31 can be a conventional strain gauge, a fiber-optic strain gauge, or a continuous-medium strain gauge. The strain gauge is capable to measure the strain in the rotor blade. If the rotor blade rotates in the direction of rotation of the rotor 141, the strain in the first rotor blade 201 might change due to the fact that the first rotor blade 201 moves across different areas where different wind speeds are present. Note that the change of the strain that is experienced by the first rotor blade 201 is not due to a time variation of the wind speed, but due to the fact that the wind speed is different at different positions across the swept area of the rotor blades. After one full rotation of the rotor a picture of the wind speeds is obtained by the strain measurements performed on the first rotor blade 201 and subsequent calculation from the strain values into a wind speed distribution. A picture of the wind speed field can also be obtained more quickly (in 1/N rotations) with a plurality of N rotor blades, each of the N rotor blades being equipped with at least one strain measurement device. Note, however, that the wind speed is only obtained retrospectively.

(24) If an anomalous wind, for instance an unusually high wind speed is measured at a certain angular position by the strain measurement device 31, this is an indication of a local variation such as a hot spot in the wind field of the wind turbine. Regarding the optimal angle of attack of the rotor blades, the measurement obtained by the strain measurement device located on the first rotor blade 201 comes too late to change anything for the first rotor blade 201. However, the information about the local variation of the wind field can be used for the second rotor blade 202 and for the third rotor blade 203, and so on for subsequent rotation. Typically, the trailing, or lagging, rotor blade passes the location of the leading rotor blade a few seconds after the leading rotor blade has passed through it. These few seconds, i.e. for example two to five seconds are sufficient that the controller induces a change of the pitch angle of the trailing rotor blade. Thus, a feed-forward control mechanism is obtained for optimizing the performance of the wind turbine.

(25) FIG. 3 shows an example of a wind field 41 as obtained by the proposed measurement method. The height of the illustrated wind speed or signal strength in FIG. 3 describes the level of intensity of the wind speed 34 which is referred to as the angular level of wind speed. Thus, for each direction along the 360 degrees of the rotor plane a specific angular level of wind speed exists.

(26) In the example illustrated in FIG. 3, a hot spot of very high speeds at the east side, i.e. the right-hand side of the swept area of the rotor blades, as seen from the front towards the wind turbine, exists.

(27) FIG. 4 shows another embodiment of the invention wherein a plurality of strain measurement devices 31 is attached along the span of a rotor blade 20. Assuming an inhomogeneous airflow impinging on the rotor blade 20, this leads to different strain values determined by each of the strain measurement devices 31. Taking the input data of the different strain measurement devices 31, different wind speeds are calculated depending on the radial position. The radial position refers to the distance away from the root 211 of the rotor blade 20. In the example of FIG. 4, the wind speed is highest around the shoulder 28 of the rotor blade (cf. value 6 of an arbitrary scale of wind speeds reaching from 1very low wind speedsuntil 7very high wind speeds) and at the tip section 22 (cf. value 7). It can also be seen that in the example of FIG. 4 the wind speed distribution is relatively inhomogeneous along the span of the rotor blade.

(28) Using a similar rotor blade as shown in FIG. 4 in a wind turbine 10 leads to a fine detailed wind speed distribution at the rotor plane of the rotor blades.

(29) FIG. 5 shows a first rotor blade 201 equipped with four strain measurement devices 31 at different radial positions. Alternatively, the second rotor blade 202 and the third rotor blade 203 may also be equipped with strain measurement devices 31.

(30) Note that the information regarding the wind field may directly be used by the controller or another component of the wind turbine to influence and control certain components of the wind turbine such that the overall performance of the wind turbine is optimized. Apart of this, the mere information about the wind field already gives a valuable insight which is otherwise very difficultly, if ever, obtainable at a wind turbine during operation.

(31) In FIG. 5, another way of visualizing the wind field is chosen. The density of the depicted contour lines (in other words: level curves) relate to the level of intensity of the wind speeds. Again, a hot spot 101 of very high wind speeds at the east side, i.e. the right-hand side of the swept area of the rotor blades, as seen from the front towards the wind turbine, exists. Additionally, a second much weaker hot spot 102 in the upper left corner of swept area of the rotor plane is detected.

(32) Compared to the wind field as obtained by one single strain measurement device per rotor blade, the wind field as obtained by a plurality of strain measurement devices situated at different spanwise positions of the rotor blade gives additionally a radial information regarding the determined wind speeds.

(33) Note as well that apart of pitching individually a rotor blade of the wind turbine because of a local variation, also a global anomalous value of the wind speed can be identified. Thus, a principle suboptimal control or suboptimal alignment of the wind turbine can be identified. For instance, a principle yaw error can be identified by the proposed method and can be improved by yawing the nacelle or pitching the rotor blades.

(34) In the following, it is disclosed how calculation from the measured strain values to the wind speeds may be performed and which additional information can be extracted.

(35) FIGS. 6 to 8 show different scenarios how the rotor blades of a wind turbine may exemplarily be bent.

(36) FIG. 6 illustrates a first scenario, where an airflow 35 with low wind speed impinges uniformly on a first rotor blade 201 being connected to a hub 13 of a wind turbine and a second rotor blade 202 being also connected to the hub 13. Consequently, both rotor blades 201, 202 experience only a small thrust force and are only bent away to a negligible extent by the impinging airflow 35.

(37) FIG. 7 illustrates a second scenario, where an airflow 35 with high wind speed impinges uniformly on a first rotor blade 201 being connected to a hub 13 of a wind turbine and a second rotor blade 202 being also connected to the hub 13. Consequently, both rotor blades 201, 202 experience a considerable thrust force and are bent away to a considerable extent by the impinging airflow 35.

(38) FIG. 8 illustrates a third scenario, where an airflow 35 impinges with low wind speed on a first rotor blade 201 being connected to a hub 13 of a wind turbine and with high wind speed on a second rotor blade 202 being connected to the hub 13. Consequently, the first rotor blade 201 experiences only a small thrust force and is only bent away to a negligible extent by the impinging airflow 35, while the second rotor blade 202 experiences a considerable thrust force and is bent away to a considerable extent by the impinging airflow 35.

(39) In all cases, the bending of the rotor blade is measured by a strain measurement device 31, which is located at the root section 21 of the rotor blade.

(40) FIG. 9 illustrates a rotor blade in an unbent state 204, and sketches the same rotor blade in a bent state 205 (in dashed lines). The strain measurement device 31 produces a voltage which is proportional to the bending moment at the root section 21, which is also referred to as the root bending moment.

(41) FIGS. 10 and 11 illustrate how a low wind speed signal and a high wind speed signal translate into respective signals for the root bending moment in Cartesian coordinates and in polar coordinates, respectively.

(42) For both the low wind speed scenario and the high wind speed scenario, an airflow which is uniform across the swept area and which impinges perpendicularly to the rotor plane on the rotor blades is assumed. Additionally, the wind speed is assumed to be constant during the measured time span such that a constant root bending moment is measured.

(43) FIG. 10 illustrates the constant root bending moment in Cartesian coordinates, which is represented by a horizontal straight line. Note that the azimuth 51 is shown in degrees, thus, one full rotation of the rotor is obtained at 360 degrees. The root bending moment 52 is measured in kilo Newton times meter. The values for the root bending moment shown in FIG. 7 represent exemplary values for a three-bladed wind turbine of the Megawatt class.

(44) The curve 521 represents the root bending moment for a low wind speed, while the curve 522 represents the root bending moment for a high wind speed. It is noted that for a stronger wind an increase of the constant root bending moment is translated into a rise of the horizontal line in Cartesian coordinates.

(45) FIG. 11 illustrates the constant root moment in polar coordinates, which is represented by a circle centered at the origin of the polar coordinates.

(46) Again, the curve 521 represents the root bending moment for a low wind speed, while the curve 522 represents the root bending moment for a high wind speed. As the wind speed is assumed to be constant during the observed time, which is at least one full rotation in FIG. 8, the curves 521, 522 have the shape of circles. It is noted that for a stronger wind an increase of the constant root bending moment is translated into an enlargement of the circle in polar coordinates.

(47) FIGS. 9 and 10 illustrate an airflow which is impinging on the swept area 206 of the three rotor blades of a wind turbine 10, and which is non-uniform at this swept area 206. In FIG. 9, a high wind speed at the top 53 and a low wind speed at the bottom 54 of the swept area 206 is assumed, while in FIG. 10, a low wind speed at the left-hand side 54 and a high wind speed at the right-hand side 53 of the swept area 206 is assumed. Descriptively speaking, this results in a vertical or horizontal push-pull effect, respectively.

(48) FIG. 12 shows the root bending moment 52 depending on the azimuth 51 for two scenarios of an airflow with non-uniform wind speeds. The curve 523 represents a scenario with a high wind speed at the top and a low wind speed at the bottom of the swept area 206 of the rotor blades. The curve 524 represents a scenario with a low wind speed at the left-hand side and a high wind speed at the right-hand side of the swept area 206 of the rotor blades. It is noted that the curve 523 can be described by a cosine function, while the curve 523 can be described by a sine function.

(49) FIG. 13 shows both curves 523, 524 in polar coordinates. A vertical push-pull effect produces a vertically-offset circle 523 in polar coordinates (cf. the vertical offset Y of the origin), while a horizontal push-pull effect produces a horizontally-offset circle 524 in polar coordinates (cf. the horizontal offset X of the origin).

(50) A scenario for an arbitrary airflow impingement upon the swept area of the rotor blades is illustrated in FIG. 14.

(51) The swept area of a wind turbine with a first rotor blade, a second rotor blade and a third rotor blade is impinged by an airflow which is non-uniform across the swept area. Note, however, that the airflow is assumed to be constant during the observation time, i.e. during at least one full rotation of rotor.

(52) FIG. 14 shows the resulting signal 525 of the root bending moment in polar coordinates. The resulting signal is a circle comprising a radius R, which can be associated with the size of the root-bending moment, a horizontal offset X, which can be associated with a horizontal push-pull pull effect, and a vertical offset Y, which can be associated with a vertical push-pull effect.

(53) If each of the three rotor blades were equipped with a respective strain measurement device at the root section of the respective rotor blade, a simultaneous measurement of the root bending moments of the rotor blades could be obtained. This has the advantage that at any time three measurement values for the root bending moment are obtained, wherein the first measurement value 91 relates to the first rotor blade, the second measurement value 92 relates to the second rotor blade and the third measurement value 93 relates to the third rotor blade. Each measurement value is separated by one hundred and twenty degrees from each other, thus the definition of a circle is possible, whose parameters R, X and Y can subsequently be extracted.

(54) In order to extract concrete values for the wind speed based on the obtained values for the root bending moment, simulations were performed with the simulation tool BHawC. A uniform inflow of wind, i.e. without any turbulences, has been assumed and many systematic asymmetries, such as gravity, tower shadow, main shaft tilt, etc. have been disregarded. Thus, the only variables that were changed from simulation to simulation were (1) wind speed v, (2) yaw misalignment , and (3) wind shear power-law exponent .

(55) The results of those simulations show that in the variable-speed region of the wind turbine's operation, i.e. wind speeds between 5 m/s and 10 m/s, a single-valued function can describe the average root bending moment for all wind speeds in this region. This means that for any measured root bending moment, one could back-calculate the wind speed as it is single-valued. This negligible impact of the wind shear and the yaw misalignment on the average root bending moment in the mentioned range of wind speeds has been observed for wind shear power-law exponents between 0 and 0.3, and for yaw misalignments between 10 degrees and 10 degrees.

(56) Once the wind speed has been established, the other two signals, namely X and Y, relating to the wind shear and the yaw misalignment can be extracted.

(57) For each curve and for all wind speeds between 5 m/s and 10 m/s, the following equations are valid:
Y=m.sub.Y+n.sub.Y
X=m.sub.X+n.sub.X
where the m values and n values above are constants. Written in matrix form, this results in:

(58) $.Math.\begin{array}{c}Y\\ X\end{array}.Math.=.Math.\begin{array}{cc}{m}_Y& n_Y\\ m_X& n_X\end{array}.Math..Math.\begin{array}{c}\\ \end{array}.Math.$

(59) Thus, for a known wind speed, a measurement of X and Y can yield a yaw misalignment and wind shear value from matrix inversion and multiplication.

(60) The m and n values have to be obtained once for each wind speed, for instance via the simulation tool BHawC, such that a lookup table can be generated. In this way, measurements of X, Y, and R produce values for wind speed, yaw misalignment, and wind shear.