METHOD FOR CONTROLLING A WIND POWER PLANT AND WIND POWER PLANT

Description

[0001] The present invention relates to a method for controlling a wind turbine and a corresponding wind turbine.

[0002] In particular, the present invention relates to a method for controlling a wind turbine, wherein the wind turbine is operated according to an operating point. The operating point is determined at least by a pitch angle and a tip speed ratio, wherein one of the operating points corresponds to a maximum power coefficient. The wind turbine is operated in a partial load range at an operating point that deviates from the operating point with the maximum power coefficient.

[0003] The partial load range is the operating range of a wind turbine in which the wind is not strong enough to achieve the rated wind power output. Typically, a wind turbine is operated in a partial load range such that the tip speed ratio λ, i.e., the ratio between the peripheral speed of the rotor and the wind speed, remains virtually constant throughout the entire partial load range by flexibly adjusting the turbine's speed. The pitch angle γ is generally not changed in the partial load range.

[0004] In Figuren 2a und 2b are schematic curves of the tip speed ratio λ, cf. Figur 2a , and the pitch angle γ, cf. Figur 2b , plotted against the wind speed v. In a partial load range 200, both the tip speed ratio λ and the pitch angle γ are independent of the wind speed v. In these examples, in a full load range 210, the tip speed ratio λ decreases with increasing wind speed v, while the pitch angle γ increases with increasing wind speed v. In the full load range 210, the wind turbine finally reaches the rated power. It should be noted that in the schematic Figuren 2a und 2b no extreme winds, which could lead to a shutdown of the wind turbine, for example, are outlined.

[0005] It is known that for a certain value of the tip speed ratio λ at a constant pitch angle γ, an optimal power coefficient cp can be achieved. The curve of the power coefficient cp over the tip speed ratio λ at a constant pitch angle γ is shown schematically in Figur 3 shown. A specific value of the tip speed ratio λ can now be selected as the operating point of the wind turbine, whereby maximizing the achievable power is generally desired. However, an operating point 310 at which the optimal power coefficient cp is achieved is generally not selected, but rather an operating point 320 shifted to the right by a tip speed ratio Δλ, i.e., toward higher tip speed ratios.

[0006] It should be noted that this choice of operating point depends on the rotor blade design and the turbine's operating mode and is particularly feasible for high-wind turbines with large blade chords. Even for low-wind turbines with small blade chords, operation at operating point 320 may be possible if there are no noise restrictions in the partial load range, since with such rotor blades, the maximum power coefficient shifts to higher tip speed ratios, and therefore, operating at tip speed ratios to the right of the maximum can be expected to result in higher overall noise.

[0007] By operating the turbine not at the optimum power coefficient, i.e., operating point 310, but around the tip speed ratio Δλ to the right of it at a higher tip speed ratio, turbulence in the approach flow is taken into account. Turbulence describes fluctuations in wind speed around an average wind speed in the approach flow and can be quantitatively expressed as turbulence intensity. Such variations in the approach wind speed on a timescale significantly shorter than the duration of one rotor revolution are not perceived by the rotor due to the inertia of the turbine control system, so that the variations in wind speed are reflected in a variation in the tip speed ratio, since the rotational speed or blade tip speed does not change on the timescale of the variations in the approach wind speed.Accordingly, the tip-speed ratio decreases as a consequence of a gust that leads to an increase in wind speed. It is therefore known that the turbine is operated on the right, i.e., at higher tip-speed ratios, so that gusts with resulting reduced tip-speed ratios are associated with an improved power coefficient close to the optimum. The key idea is that the angle of attack due to the gust does not increase to such an extent that it could cause a flow separation on the rotor blade, which would have significantly adverse consequences for the energy yield.

[0008] The German Patent and Trademark Office has searched the following prior art in the priority application for the present application: DE 10 2013 100 387 A1, GB 2 542 343 A, US 2009 / 0295160 A1, US 2012 / 0165996 A1, US 2014 / 0193254 A1, US 2015 / 0176569 A1, WO 2011 / 157271 A2, WO 2017 / 000953 A1.

[0009] WO 2011 / 150931 A2 describes a method for operating a wind turbine, wherein the wind turbine comprises a rotor with a set of wind turbine blades, where said rotor is mounted on a tower, and wherein the method comprises the following steps: providing a curve defining the optimal tilt angle as a function of the tip speed ratio of the rotor blades of the wind turbine or as a function of the wind speed, wherein the optimal tilt angle is the tilt angle that results in the highest possible output power or power coefficient CP for the wind turbine under specific wind conditions, modifying only a part of said optimal tilt angle curve by applying a safety buffer and thereby obtaining a safety tilt angle curve, wherein the safety buffer is applied to prevent stall at the rotor blade and / or overloading of one or more components of the wind turbine,Operating the wind turbine according to the safety tilt angle curve, during operation of the wind turbine, measuring one or more parameters to obtain information about the wind conditions and / or loads on one or more components of the wind turbine, adjusting the safety buffer based on said measurements and thereby obtaining an adjusted tilt angle curve, and operating the wind turbine according to the adjusted tilt angle curve.

[0010] Against this background of known control strategies of wind turbines, one object of the present invention was to further optimize the power yield in the partial load range.

[0011] According to a first aspect, the object is achieved according to the invention in a method of the type mentioned at the outset by the features of claim 1.

[0012] By not keeping the distance between the operating point and the operating point with the maximum power coefficient constant, but rather adjusting it as a function of a turbulence measure, it is possible to prevent an unnecessarily large distance from the operating point with the maximum power coefficient. The distance between the selected operating point and the operating point with the maximum power coefficient can therefore be as small as necessary to enable safe operation of the wind turbine with maximum power output. Furthermore, this is not a merely simulated turbulence measure, but rather, by being measured, reflects the actual condition of the wind turbine. The adjustment of the distance is therefore carried out taking into account the actual prevailing conditions.

[0013] The core of the invention is therefore that the operating point in the partial load range, in particular the selection of the tip speed ratio and the pitch angle in the partial load range, is adjusted depending on the measured turbulence level. The wind turbine preferably has a corresponding measuring system for this purpose, which is capable of determining the turbulence level, in particular in real time, and of controlling the wind turbine accordingly in real time based on the measured turbulence level.

[0014] Turbulence intensity is considered as a measure of turbulence.

[0015] The turbulence of the wind can be described by the turbulence intensity TI: TI = σ u U ‾ .

[0016] The standard deviation σ u is defined as follows: σ u = 1 T ∫ 0 T u − U ‾ 2 dt , with the over the period T average wind speed U : U ‾ = 1 T ∫ 0 T u dt .

[0017] To describe unsteady flows u, the average velocity is usually superimposed by the fluctuation ũ: u = U ‾ + u ˜

[0018] The turbulence intensity thus represents the standard deviation of the wind speed relative to the wind speed averaged over a longer period, for example, 10 minutes. This provides a measure of the magnitude of the superimposed fluctuation in wind speed. This turbulence intensity is therefore also a measure of the strength of the wind fluctuations, which can represent an additional load on the wind turbine.

[0019] In addition to turbulence intensity, other measurable turbulence measures can of course also be used alternatively or additionally.

[0020] In a preferred embodiment, a larger measured turbulence measure corresponds to a larger distance of the operating point from the operating point with maximum power coefficient.

[0021] The greater the measured turbulence level, the stronger the effects of gusts or similar winds. Accordingly, in this embodiment, a greater distance, i.e., greater safety, is proposed for a larger measured turbulence level. Accordingly, a lower measured turbulence level does not require such a large distance, so even smaller gusts are sufficient to bring the tip speed ratio close to the operating point with the maximum power coefficient.

[0022] In other embodiments, however, a larger measured turbulence level can also mean, conversely, a smaller absolute value of the distance between the operating point and the operating point with the maximum power coefficient. This is particularly suitable for the case where the wind turbine is operated to the left of the operating point with the maximum power coefficient, i.e., particularly at lower tip speed ratios. As a result, with a larger turbulence level, a higher tip speed ratio is selected, with the advantages mentioned above. This type of operation is used, for example, with narrow rotor blades.

[0023] It should be noted that, within the scope of this disclosure, the distance is generally to be understood as the absolute value of the distance. If a sign convention is explicitly used, a distance is considered positive if the operating point lies to the right of the operating point with the maximum power coefficient. Similarly, negative distances exist if the operating point lies to the left of the maximum.

[0024] If, in one embodiment, the wind turbine is operated to the left of the operating point with the maximum power coefficient, i.e., with a negative distance, increasing the distance can also result in the wind turbine ultimately being operated at or even to the right of the operating point with the maximum power coefficient, given a correspondingly large measured turbulence level. The invention is not limited to the examples in this regard, and other relationships between the selected distance and the measured turbulence level must also be explicitly considered.

[0025] According to the invention, the distance of the operating point to the operating point with maximum power coefficient is further adjusted depending on a degree of rotor blade contamination.

[0026] It is also a finding of the present invention that the position and movement of the operating point with maximum power coefficient strongly depend on the degree of rotor blade contamination. Accordingly, a further increase in yield is possible by taking the degree of rotor blade contamination into account when adjusting the distance.

[0027] In a preferred embodiment, the pitch angle and / or the tip speed ratio of the operating point are increased compared to the operating point with maximum power coefficient.

[0028] Accordingly, with reference to the already discussed Fig. 3 The operating point is set to the right of the operating point with the maximum power coefficient. This allows the occurrence of a gust to lead to a reduction in the tip speed ratio due to the rotor's inertia, thus allowing operation closer to the optimal operating point without the risk of stall.

[0029] Likewise, in other preferred embodiments, it is provided to reduce the pitch angle and / or the tip speed ratio of the operating point compared to the operating point with the maximum power coefficient. Accordingly, in these embodiments, the wind turbine is operated to the left of the operating point with the maximum power coefficient. The choice is preferably made depending on the rotor blade geometry, with operation to the left of the operating point with the maximum power coefficient having proven advantageous, particularly for narrow rotor blades. Also, due to noise restrictions and / or generally in low-wind turbines, operation may only be possible to the left of the operating point with the maximum power coefficient.

[0030] In a preferred embodiment, the tip speed ratio is controlled by controlling the speed and / or the torque.

[0031] Controlling the tip speed ratio by controlling the speed and / or torque is, of course, only one of the possible ways to control the tip speed ratio. Other ways to influence the tip speed ratio can be used just as advantageously.

[0032] In a preferred embodiment, the power coefficient improves when a gust hits.

[0033] By improving the power coefficient when a gust occurs, the instantaneous yield and thus also the annual energy yield can be improved. At the same time, by improving the power coefficient and thus being closer to the optimal power coefficient, the loads on the wind turbine are kept as low as possible.

[0034] In a preferred embodiment, the turbulence measure is measured substantially in real time.

[0035] Because the turbulence level is measured essentially in real time, it is possible for the wind turbine to adjust to the measured turbulence level. Suitable measurement systems, such as the Blade Vision system, are preferably provided for this purpose, although other systems suitable for measuring turbulence levels can also be used.

[0036] In a preferred embodiment, 15-second averages of the turbulence measure are provided substantially in real time.

[0037] 15-second averages have proven to be a useful tool for suppressing high-frequency and less relevant fluctuations, while simultaneously failing to take into account general changes in wind conditions, such as wind pick-ups. 15-second averages are particularly useful for assessing the strength of gusts. Of course, longer or shorter durations of the turbulence measure can also be determined.

[0038] In a preferred embodiment, the method further comprises controlling the wind turbine as a function of a measured wind shear.

[0039] Wind shear refers to different wind directions or wind speeds at different points or areas, particularly on the rotor. Vertical wind shear is particularly prominent and generally indicates that wind is stronger at altitude than nearby and under the influence of the ground. High wind shear, i.e. strongly varying wind situations at different positions of the rotor blades over the rotor revolution, can lead to high turbine loads and also carries the risk of the rotor blade stalling due to excessively high angles of attack. Wind shear can be measured and determined, for example, based on the loads occurring around the rotor circumference or by wind sensors that measure the wind at different areas of the rotor plane.

[0040] In a preferred embodiment, the wind turbine is controlled as a function of the measured wind shear and the measured turbulence level, taking into account a time of day.

[0041] It is known that day and night influence both turbulence and wind shear. However, the effect is diametrically opposed. While turbulence intensity is generally greater during the day than at night, this is generally reversed for wind shear. This means that wind shear is generally greater at night than during the day. Therefore, a wind turbine, which is controlled based on the time of day in addition to the turbulence and wind shear, can better assess the prevailing situation and thus operate closer to an optimal value.

[0042] In a preferred embodiment, the turbulence measure is measured spatially resolved over the rotor.

[0043] In a preferred embodiment, the operating point is further adjusted taking into account acoustic boundary conditions.

[0044] The object is further achieved according to the invention by a wind turbine according to claim 12.

[0045] In particular, the wind turbine according to the invention thus makes it possible to achieve all of the advantages described with reference to the method described above. Likewise, the wind turbine according to this aspect can be combined with all of the preferred embodiments of the method according to the invention.

[0046] The turbulence sensor can be implemented as any suitable sensor capable of providing a measure indicative of the turbulence on the rotor blade. For example, the turbulence sensor can measure and provide the turbulence measure directly based on the measured wind or indirectly based on deflections or loads on the rotor blade.

[0047] The invention is explained in more detail below using exemplary embodiments with reference to the accompanying figures. Figure 1 shows a wind turbine in a schematic representation. Figure 2a shows a schematic representation of the relationship between tip speed ratio λ and wind speed v. Figure 2b shows a schematic representation of the relationship between pitch angle γ and wind speed v. Figure 3 shows a schematic representation of the relationship between power coefficient cp and tip speed ratio λ at a constant pitch angle γ. Figure 4 shows a schematic representation of various power coefficient relationships as a function of a turbulence level. Figure 5a shows a schematic representation of the relationship between tip speed ratio λ and wind speed v with increasing turbulence level. Figure 5b shows a schematic representation of the relationship between pitch angle γ and wind speed v with increasing turbulence level. Figure 6a shows a schematic representation of the influence of blade fouling at low inflow turbulence. Figure 6b shows a schematic representation of the influence of blade fouling at higher inflow turbulence.

[0048] Figur 1 shows a wind turbine 100 with a tower 102 and a nacelle 104. A rotor 106 with three rotor blades 108 and a spinner 110 is arranged on the nacelle 104. During operation, the rotor 106 is set into rotation by the wind and thereby drives a generator in the nacelle 104.

[0049] The wind turbine 100 has a measuring system that is suitable for determining a measure of the inflow turbulence in real time and for controlling the wind turbine 100 accordingly in real time according to the measured values.

[0050] The core of the present invention is, as already mentioned, the adjustment of the operating point in the partial load range 200°C, i.e., the selection of the tip speed ratio and the pitch angle in the partial load range 200°C, depending on the turbulence intensity of the incoming flow. In the following, the turbulence intensity Ti defined above is described as an example as a turbulence measure. However, this is of course only an example, and other variables that allow a statement about the extent of the turbulence of the incoming flow are also conceivable.

[0051] In Fig. 4 For three different turbulence intensities Ti 1 , Ti 2 and Ti 3 , curves of the power coefficient cp over the tip speed ratio λ are shown, each corresponding to a different choice of the pitch angle γ 1 , γ 2 and γ 3 . It is important, however, that for each of the curves with different turbulence intensities, different tip speed ratios λ with maximum power coefficient cp 411, 412 and 413 result. The operating point at which the wind turbine 100 is operated at the different turbulence intensities Ti 1 , Ti 2 and Ti 3 is the operating point 421, 422 or 423, which are each operated at a tip speed ratio λ that is higher by a difference Δλ 1 , Δλ 2 , Δλ 3 than the tip speed ratio belonging to the maximum power coefficient.

[0052] The core of the invention is precisely that the selection of the distance or deviation from the operating point with the maximum power coefficient, in this example Δλ 1 , Δλ 2 , Δλ 3 , is dependent on the measured turbulence level and is not constant. In this example, Ti 1 < Ti 2 < Ti 3 and, accordingly, Δλ 1 , < Δλ 2 < Δλ 3 . In other words, the greater the measured turbulence level, the greater the deviation from the operating point with the maximum power coefficient.

[0053] With reference to Fig. 4 Three effects that play a significant role in the selection of the adjusted operating point are described below.

[0054] Firstly, the distance of the operating point to the optimum of the power coefficient Δλ should be a function of the turbulence intensity because, if there were no inflow turbulence, the operating point could be placed directly on the optimum, i.e. Δλ=0, since then there would be no variation in the tip speed ratio λ.

[0055] Secondly, it must be taken into account that the optimum power coefficient of the rotor blade generally shifts towards higher tip speed ratios and pitch angles under the influence of the inflow turbulence. This is Fig. 4 expressed by the fact that the points with maximum power coefficient cp 411, 412 and 413 shift to the right with increasing turbulence intensity Ti.

[0056] Thirdly, at very high turbulence intensities Ti, flow separation can occur even in the part-load range of 200°C, since the effective angle of attack increases due to the reduction of the tip-speed ratio λ. These flow separations lead to significant performance losses, which must therefore be avoided. This is again achieved, according to the invention, by increasing the pitch angle and / or the tip-speed ratio.

[0057] All the described effects now lead to an adjustment of the tip speed ratio and the pitch angle in the part-load range depending on the turbulence intensity of the incoming flow determined in real time, preferably in such a way that the tip speed ratio λ and / or the pitch angle γ are adjusted at part-load with increasing turbulence intensity, in particular, as in Fig. 5a und 5b This is particularly evident in Fig. 5a und 5b indicated by the upward arrow in the partial load range 200, while in the full load range 210 no adjustment dependent on the specific turbulence level takes place.

[0058] In Fig. 6a and 6b The curves of the power coefficient over the tip speed ratio are shown schematically and exemplarily for different pitch angles, with the values ​​of a clean rotor blade being shown with solid lines and those of a dirty rotor blade being shown with dashed lines. Fig. 6a the curves for a low turbulence intensity are shown, while in Fig. 6b In comparison, the curves for a higher turbulence intensity are shown.

[0059] It can be seen that the maximum power coefficients for contaminated blades are, of course, significantly lower than those for uncontaminated rotor blades, regardless of the turbulence intensity.

[0060] However, it has been shown that the difference in tip speed ratios at which optimum performance is achieved between a clean and a contaminated rotor blade depends on the turbulence intensity. While this difference is significant at low turbulence intensity, cf. Fig. 6a , is rather large, it will be larger with a greater turbulence intensity, cf. Fig. 6b , significantly lower. It has also been shown that the optimum performance shifts to higher tip speed ratios and pitch angles with increasing inflow turbulence. Preferably, all of these findings, in particular including rotor blade contamination, are used by the wind turbine 100 for control purposes in order to achieve optimal operation of the turbine.

Claims

1. A method for controlling a wind turbine (100), wherein the wind turbine (100) is operated according to an operating point, wherein the operating point is determined at least by a pitch angle (γ) and a tip speed ratio (λ), wherein one of the operating points (411, 412, 413) corresponds to a maximum power coefficient, wherein, in a partial load range (200), the wind turbine (100) is operated at an operating point (421, 422, 423) which differs from the operating point (411, 412, 413) with the maximum power coefficient, wherein the distance (Δλ) of the operating point (421, 422, 423) from the operating point (411, 412, 413) with the maximum power coefficient is set in accordance with a measured turbulence measure (Ti), wherein the turbulence measure (Ti) comprises a turbulence intensity, characterized in that the distance (Δλ) of the operating point (421, 422, 423) from the operating point (411, 412, 413) with the maximum power coefficient is also set in accordance with a degree of rotor blade soiling.

2. The method as claimed in claim 1, wherein a relatively large measured turbulence measure (Ti) corresponds to a relatively large distance (Δλ) of the operating point (421, 422, 423) from the operating point (411, 412, 413) with the maximum power coefficient.

3. The method as claimed in one of the preceding claims, wherein the pitch angle (γ) and / or the tip speed ratio (λ) of the operating point (421, 422, 423) is increased with respect to the operating point (411, 412, 413) with the maximum power coefficient.

4. The method as claimed in claim 3, wherein the tip speed ratio (λ) is controlled by controlling the rotational speed and / or the torque.

5. The method as claimed in one of the preceding claims, wherein the power coefficient improves when a gust of wind occurs.

6. The method as claimed in one of the preceding claims, wherein the turbulence measure is measured essentially in real time.

7. The method as claimed in claim 6, wherein 15-second mean values of the turbulence measure are made available essentially in real time.

8. Method according to one of the preceding claims, which also comprises controlling the wind turbine (100) in accordance with a measured wind shear.

9. The method as claimed in claim 8, wherein the wind turbine (100) is controlled in accordance with the measured wind shear and the measured turbulence measure (Ti) taking into account the time of day.

10. The method as claimed in one of the preceding claims, wherein the turbulence measure (Ti) is measured with spatial resolution over the rotor.

11. The method as claimed in one of the preceding claims, wherein the operating point (421, 422, 423) is also set taking into account acoustic boundary conditions.

12. A wind turbine, wherein the wind turbine is a pitch-controlled wind turbine with a variable rotational speed, wherein the wind turbine (100) has: - a turbulence sensor for measuring a turbulence measure (Ti), in particular a turbulence intensity, and - a controller for controlling the wind turbine, wherein the controller is configured to operate the wind turbine (100) according to an operating point, wherein the operating point is determined at least by a pitch angle (γ) and a tip speed ratio (λ), wherein one of the operating points (411, 412, 413) corresponds to a maximum power coefficient, wherein, in a partial load range (200), the controller is configured to operate the wind turbine (100) at an operating point (421, 422, 423) which differs from the operating point (411, 412, 413) with the maximum power coefficient, wherein the controller is configured to set the distance (Δλ) of the operating point (421, 422, 423) from the operating point (411, 412, 413) with the maximum power coefficient in accordance with the turbulence measure (Ti) which is measured by the turbulence sensor, wherein the turbulence measure (Ti) comprises a turbulence intensity, characterized in that the controller is configured to also set the distance (Δλ) of the operating point (421, 422, 423) from the operating point (411, 412, 413) with the maximum power coefficient in accordance with a degree of rotor blade soiling.