DK201970630A1 - A wind speed estimator for a wind turbine - Google Patents

Abstract

The present invention provides a method of estimating a wind speed at a wind turbine. The wind turbine comprises a generator driven by a rotor. Whilst the turbine is in an operational state in which power is not being extracted from the generator the method comprises determining a rotor speed of the rotor; providing a relationship between wind speed and rotor speed for the wind turbine; and estimating the wind speed using the predetermined relationship and the determined rotor speed.

Description

DK 2019 70630 A1 1

A WIND SPEED ESTIMATOR FOR A WIND TURBINE

FIELD OF THE INVENTION The present invention relates to wind turbine control, and in particular to wind speed estimation for wind turbine control.

BACKGROUND OF THE INVENTION Knowledge of local wind speed is an important factor in the control of wind turbines. Wind speed measurements, particularly free stream wind speed measurements, are generally provided by the fusion of two independent signal sources: a direct measurement by the nacelle anemometers and an indirect estimate from other signals, such as power output. This fusion provides cross checks and needed redundancy. This — is crucial, because in absence of a wind signal the turbine control system will generally stop the turbine. The risk of unnecessary wind turbine shutdown is higher when a turbine is idling or in a cut-out state, for the simple reason that while idling the indirect estimate from other signals is disabled, as it is derived from the power produced. Thus measurement of the wind speed during the idling or cut-out phase typically relies on just the direct measurement from the nacelle anemometer. This risks the turbine being stopped while idling because of anemometer failure. Moreover, the nacelle > anemometer signal is generally noisy due to localised wind variations.

SUMMARY OF THE INVENTION A first aspect of the invention provides a method of estimating a wind speed at a wind turbine, the wind turbine comprising a generator driven by a rotor, the method comprising: whilst the turbine is in an operational state in which power is not being extracted from the generator: determining a rotor speed of the rotor; providing a relationship between wind speed and rotor speed for the wind turbine; and

DK 2019 70630 A1 2 estimating the wind speed using the predetermined relationship and the determined rotor speed. The generator may be connected to the rotor via a gearbox. Determining a rotor speed of the rotor may comprise: measuring a generator speed of the generator; and calculating the rotor speed using the generator speed and a gear ratio of the gear box.

In some embodiments, the operational state may be an idling state, or may be a cut- out state. The relationship may be a linear relationship between wind speed and rotor speed. The relationship may be a quadratic relationship between wind speed and rotor speed.

In some embodiments, providing a relationship between wind speed and rotor speed may comprise determining the relationship from a model of expected rotor speeds as a function of wind speeds or from previously recorded measurements. The step of determining the relationship from the model may be based on one or more of: wind turbine type, pitch angle, and air density at the wind turbine.

In some embodiments the method may further comprise comparing the estimated wind speed with a wind speed measured by an anemometer of the wind turbine In some embodiments, the method may further comprise controlling the wind turbine based on the estimated wind speed. For example, in some embodiments the method may comprise switching the wind turbine to a different operational state based on the estimated wind speed.

In some embodiments the method may further comprise, whilst the wind turbine is in a power production operational state, determining an estimate of the wind speed based on power extracted from the generator.

A second aspect of the invention provides a controller configured to receive a measurement of a rotor speed of the wind turbine, wherein the controller is configured to perform the method of any embodiment of the first aspect.

DK 2019 70630 A1 3 A third aspect of the invention provides a wind turbine, the wind turbine comprising: a rotor; a generator driven by the rotor; a tachometer configured to measure a rotor speed of the rotor or a generator speed of the generator; and a wind speed estimator configured to receive measurements from the tachometer and to estimate a wind speed at the wind turbine using the method of any embodiment of the first aspect.

A fourth aspect of the invention provides a computer program comprising instructions which, when the program is executed by a computer, cause the computer to carry out the method of any embodiment of the first aspect.

BRIEF DESCRIPTION OF THE DRAWINGS Embodiments of the invention will now be described with reference to the accompanying drawings, in which: Figure 1 illustrates, in a schematic perspective view, an example of a wind turbine. Figure 2 schematically illustrates an embodiment of a control system together with elements of a wind turbine.

Figure 3 illustrates a flow diagram of transitioning operational states of the control system.

— Figure 4 illustrates a flow diagram of a method for estimating a wind speed at a wind turbine.

Figure 5 illustrates an example of a flow diagram of a method for estimating a wind speed at a wind turbine.

DETAILED DESCRIPTION OF EMBODIMENT(S) Figure 1 illustrates, in a schematic perspective view, an example of a wind turbine 1. The wind turbine 1 includes a tower 2, a nacelle 3 at the apex of the tower, and a rotor 4 operatively coupled to a generator housed inside the nacelle 3. In addition to the generator, the nacelle houses miscellaneous components required for converting wind

DK 2019 70630 A1 4 energy into electrical energy and various components needed to operate, control, and optimize the performance of the wind turbine 1. Positioned on top of the nacelle is a nacelle anemometer 7. The rotor 4 of the wind turbine includes a central hub 5 and a plurality of blades 6 that project outwardly from the central hub 5. In the illustrated embodiment, the rotor 4 includes three blades 6, but the number may vary. Moreover, the wind turbine comprises a control system. The control system may be placed inside the nacelle or distributed at a number of locations inside the turbine and communicatively connected.

The wind turbine 1 may be included among a collection of other wind turbines belonging to a wind power plant, also referred to as a wind farm or wind park, that serve as a power generating plant connected by transmission lines with a power grid. The power grid generally consists of a network of power stations, transmission circuits, and substations coupled by a network of transmission lines that transmit the power to loads inthe form of end users and other customers of electrical utilities.

Figure 2 schematically illustrates an embodiment of a control system 20 together with elements of a wind turbine. The wind turbine comprises rotor blades 21 which are mechanically connected to an electrical generator 22 via gearbox 23. In direct drive systems, and other systems, the gearbox 23 may not be present. The electrical power generated by the generator 22 is injected into a power grid 24 via an electrical converter

25. The electrical generator 22 and the converter 25 may be based on a full scale converter (FSC) architecture or a doubly fed induction generator (DFIG) architecture, but other types may be used. The wind turbine comprises a nacelle anemometer 7 to record wind speed at the nacelle 3.

The control system 20 comprises a number of elements, including at least one main controller 200 with a processor and a memory, so that the processor is capable of executing computing tasks based on instructions stored in the memory. In general, the wind turbine controller ensures that in operation the wind turbine generates a requested power output level. This is obtained by adjusting the pitch angle of the blades 6 and/or the power extraction of the converter 25. To this end, the control system comprises a pitch system including a pitch controller 27 using a pitch reference 28, and a power system including a power controller 29 using a power reference 26. The wind turbine — rotor comprises rotor blades 21 that can be pitched by a pitch mechanism. The rotor

DK 2019 70630 A1 comprises an individual pitch system which is capable of individual pitching of the rotor blades 21, and may comprise a common pitch system which adjusts all pitch angles on all rotor blades at the same time. The control system 20, or elements of the control system 20, may be placed in a power plant controller (not shown) so that the turbine 1 5 may be operated based on externally provided instructions. The control system 20 further comprises wind estimator 30 including an air density sensor. The air density sensor measures and calculates the air density at the nacelle 3 of the wind turbine, which can be used by the wind estimator to calculate an estimate of the wind speed in the rotor plane at the nacelle 3 of the wind turbine. An estimate of the wind speed can be used to alter the turbine operational status, for example changing between operational states such as a power generation state, an idling state, and a cut-out state.

— The wind estimator 30 is configured to receive at least one of: a blade pitch angle; an air density measurement; a generator speed; a power generation; and/or, a localised wind speed measurement/estimate (e.g. from a nacelle anemometer 7).

In the illustrated embodiment, the wind estimator 30 is configured receive inputs from the pitch sensor (i.e. the pitch sensor signal 28b), power sensor (i.e. the power sensor signal 26b), nacelle anemometer 7, tachometer 22a which outputs a generator speed, and/or air density sensor 8. Operation of the wind estimator 30 is described in more detail below.

Alternatively, the wind estimator 30 may comprise an input from the pitch controller 27 instead of the pitch sensor. The wind controller 30 may comprise an input from the power controller 29 instead of the power sensor.

The wind estimator 30 outputs a signal representative of an estimate of the wind speed atawind turbine 1. Specifically, the wind speed can be defined as the free stream wind speed at the wind turbine 1.

In the illustrated embodiment, the wind estimator 30 is shown as a separate component to the main controller 200. In alternative embodiments, the main controller 200 may itself comprise the wind estimator 30.

DK 2019 70630 A1 6 Figure 3 illustrates a basic flow diagram to demonstrate the relationship between three main operational states of the wind turbine control system 20: i) the idling state 40; ii) the power generation state 42; and, iii) the cut-out state 44.

The idling state 40 and the cut out state 44 are both examples of an operational state in which the rotor is rotating but power is not being extracted from the generator. The transition between idling state 40, power state 42, and cut out state 44 occurs when the conditions 46 and 48 have been met. The wind estimator 30 outputs a wind speed estimation which is used for condition 46 when transitioning from idling state 40 to power state 42 and for condition 48 when transitioning from the cut out state 44 to the power state. In these cases the conditions 46 and 48 are first and second wind speed thresholds respectively. The remaining conditions for transitioning from the power state 42 to the states 40, 44 are driven by factors other than the estimated wind speed — signal. As shown in Figure 3, the wind turbine 1 transitions from an idling state 40 to the power generation state 42 when the wind estimator 30 gives an output that is greater than the first wind threshold. If the output from the estimator 30 is less than the first wind threshold then the main controller 200 operates the wind turbine 1 to remain in the idling state 40. When operating in the power generation state 42, the wind turbine 1 transitions to a cut out state 44 if condition 48 is satisfied. If, when operating in the power generation state 42, the conditions 46 and 48 are not satisfied for a transition, then the wind turbine will remain in the power production operational state 42. If condition 46 is satisfied for the operational state to transition to the idling state 40 then it will transition to the idling state 40. If condition 48 is satisfied for the operational state to transition to the cut out state 44 then it will transition to the cut out state 44.

When the main controller 200 operates the wind turbine 1 in the cut out state 44, it will remain in the cut out state 44 as long as the wind speed is above the second wind threshold. When the output of the wind estimator 30 falls below the second wind threshold it will revert to power production operational state 42.

DK 2019 70630 A1 7 It is of note that the second wind speed threshold may also be referred to as a cut-out threshold.

The cut-out state 44 may also be referred to as a second idling state 44. Figure 4 illustrates a method 50 of estimating a wind speed at the wind turbine 1 whilst the wind turbine 1 is in an operational state in which the power is not being extracted from the generator, e.g. an idling state 40 or the cut out state 44. The method starts at step 52, at which the rotor speed of the rotor is determined.

The rotor speed may be determined directly, for example using a tachometer configured to measure the rotational speed of the rotor, or the generator 22 (for direct-drive/gearless turbines). Alternatively, for geared turbines such as the turbine 1 illustrated in figures 1 and 2, the rotor speed may be measured indirectly.

In such cases, the generator 22 is connected to the rotor via a gear box 23. A tachometer 22a is positioned to measure the rotational speed of the generator.

The generator speed determined by the tachometer 22a will represent a multiplication of the generator speed and the gear ratio of the gear box 23. Thus, the rotor speed can be determined using the measured generator speed and the gear ratio of the gear box 23. It may be advantageous to determine the generator speed rather than the rotor speed, as the generator speed will generally be rotating faster than the rotor speed due to the gear ratio.

A higher speed may result in a higher accuracy measurement.

The gear ratio is a known quantity and may be stored locally on a wind turbine 1. In particular embodiments, the gear ratio may be stored on memory of or associated with the wind estimator 30. The calculation of the rotor speed from the generator speed may be performed by the wind estimator 30, or by another component of the wind turbine control system 20, such as the main controller 200. The tachometer 22a may output a signal representative of the rotational speed of a shaft of the generator 22 (or of the rotor, for direct measurements). This signal may be input directly into the wind estimator 30, or may be passed to the main controller 200. The tachometer 22a may be any sensor suitable for monitoring shaft speed, such as, a Hall Effect sensor, an optical encoder, accelerometers, gyros, or any other sensor.

Once the rotor speed has been determined, the method proceeds to step 56. At step 56, a relationship between the wind speed and the rotor speed for the wind turbine 1

DK 2019 70630 A1 8 is provided. As described in more detail below, the relationship may for example be a linear relationship or a quadratic relationship between wind speed and rotor speed. The relationship may already be known, and stored for example in memory associated with the turbine 1. For example, providing the relationship may comprise using known coefficients relating wind speed to rotor speed. Alternatively the method may comprise determining a relationship between wind speed and rotor speed, for example using historical (or recent) measurements of wind speed and rotor speed for the turbine 1. The method 50 then proceeds to step 58. At step 58, the wind speed is estimated using the relationship between the wind speed and rotor speed. As discussed in more detail below, the estimated wind speed may then be used for controlling the wind turbine 1. It is noted that the method 50 comprises determining rotor speed, and using a relationship between wind speed and rotor speed to determine the wind estimate. In geared turbines, the method 50 may equivalently use a measured generator speed, and a relationship between generator speed and wind speed for the turbine, differing from the rotor-wind relationship only by a constant factor equal to the gear ratio. As such, the generator speed may be considered a proxy of the rotor speed, and both relationship options are intended to fall within the scope of method 50.

The relationship between rotor speed and wind speed, as provided at step 56 of method 50, may be estimated with knowledge of at least the wind turbine type or model, and the blade pitch angle. At low wind speeds, i.e. when the operational state is an idling state, the relationship between wind speed and rotor speed may be approximated with alinear relationship. Low wind speeds may for example be 5m/s, 3m/s, 2m/s, 1m/s or less. In reality the relationship between wind speed and rotor speed is complex and can be quadratic or any other algebraic function. However the present inventors have found that a linear approximation of this relationship provides a suitable estimate for a wind speed at low wind speeds. At high wind speeds, e.g. when the operational state — isacutout state, the inventors have found a quadratic relationship between wind speed and rotor speed suitably approximates the relationship between wind speed and rotor speed. Due to the complex relationship between wind speed and rotor speed, previously recorded data or wind/meteorological models and wind turbine models may be used to

DK 2019 70630 A1 9 determine or estimate the relationship of the expected wind speeds as a function of rotor speed.

For example, simulations may be used to simulate the response of the turbine to particular wind speeds.

Any model or data may be used to find the relationship between wind speed and rotor speed using statistical methods, such as regression.

In particular, determining the relationship may comprise determining coefficients of a linear or quadratic relationship that best fit the historical measurements/simulated data.

Inputs to a model for determining the relationship between wind speed and rotor speed may comprise one or more turbine parameters/variables, such as wind turbine type/model, blade pitch, turbine yaw, and air density at the wind turbine 1. These are variables which may affect the rotor speed for a particular wind speed.

As an example, the yaw (i.e. the angle) of the wind turbine 1 to the wind direction affects the rotational power the wind turbine 1 can extract from the wind, with the most power extracted when the yaw is aligned to the wind direction, i.e. the wind turbine 1 faces the direction of the wind front.

To reduce computational power and the need for sensors, the control system 200 may set the pitch to a known value and/or align the yaw of the wind turbine 1 to the wind direction.

The control system 200 may assign the same or different pitch values and/or yaw alignments depending on the operational state.

For example, a fixed pitch angle for a cut-out state may be greater than a fixed pitch angle for the idling state, because it is undesirable for the wind turbine 1 to be rotating at excess speeds.

Some or all of the turbine parameters may be stored and used within the control system 20, or on memory associated with the wind turbine.

Similarly, the determined coefficients of the relationship between wind speed and rotor speed may be stored within the control system 20, for example on the wind estimator 30, or other memory associated with the wind turbine.

As an example, a look-up table may be stored or provided, the look-up table relating one or more turbine parameters to a particular relationship between wind speed and rotor speed (e.g. providing coefficients of a relationship for those parameters). For example, the turbine parameters may be wind turbine type/model; pitch; yaw; and/or air density.

DK 2019 70630 A1 10 At low speeds, where the relationship between wind speed and rotor speed can be approximated as linear, the model/look-up tables may provide a linear coefficient, M, relating wind speed and rotor speed, where M is dependent upon the turbine parameters such as wind turbine mode and pitch. The current wind speed can then be calculated from the determined rotor speed, using the relationship: Speedwina = M + Speedrotor Atlow wind speeds, e.g. in an idle state, the linear coefficient, M, may be independent of the air density measurement.

Once an estimate for the wind speed has been calculated by wind estimator 30 from the rotor speed, the estimated wind speed may be used to control the wind turbine 1.

In some embodiments, the estimated wind speed may be used without reference to a direct wind speed measurement, as measured by the anemometer 7. The anemometer wind speed measurement may be considered a relatively localised wind speed measurement, which can be affected by air turbulence caused by the wind turbine 1 or other factors. In contrast, the estimated wind speed may be considered as an average of the wind speed experienced across the rotor plane. This is less prone to localised wind speed errors due to the large size and inertia of the blades and drive train. The anemometer 7 may also experience calibration errors due to the deployment duration and/or localised wind speeds etc.

In alternative embodiments, both the estimated wind speed and the directly measured wind speed may be used, for example using one measurement type to verify the other measurement type. For example, the direct wind speed measurement may be compared with the estimated wind speed to generate a revised wind speed estimate. The revised wind speed estimate may be more accurate and reliable than either the primary wind speed measurement or the estimated wind speed alone.

Specifically, comparing the estimated wind speed and the direct wind speed measurement may comprise combining the two measurements, for example averaging the two measurements (e.g. taking a weighted-average/ratio of the estimated wind speed and the direct speed measurement, for example this may depend on the relative

DK 2019 70630 A1 11 reliability of each measurement). The estimated wind speed and the direct wind speed measurement may alternatively or additionally be used to cross-check the other measurement, for example such that a flag or error message is produced if the estimated wind speed and the direct wind speed measurement are outside a region of comparability. In other words, the estimated wind speed may be used to verify the direct wind speed measurement and vice versa. If the wind speed has been verified and the estimated wind speed and the direct wind speed measurement are within a comparable range then the wind speed of either the anemometer 7 and/or the wind speed estimator 30 may be assumed to be true, and the wind turbine control system 20 may control the wind turbine 1 based on the output of the wind estimator 30. The measurements may be considered to be in comparable range if, for example, they differ by no more than 20%, or 10%, or 5%. If the estimated wind speed and the direct wind speed measurement are outside of the comparable range then a further wind speed estimation and/or direct wind speed measurement can take place to verify the measurements, or/additionally may raise a maintenance alarm. Alternatively, the direct wind speed measurement and the estimated wind speed may be weighted and combined to produce the wind estimator 30 output if the estimated wind speed and the direct wind speed measurement are within or outside of a comparable range.

As shown in Figure 3 and discussed previously, controlling the wind turbine using the wind speed estimate may comprise comparing the output of the wind estimator 30 to at least one of the first and second wind speed thresholds. If the condition 46 or 48 to transition is satisfied by one of the first and second wind speed thresholds , then the operational state of the wind turbine 1 may be changed (for example by the main controller 200).

When the turbine transitions to the power production operational state 42, the rotor speed becomes dependent upon the power extracted from the turbine 1, as well as the wind speed. The method 50, which relates wind speed to rotor speed independently of power extracted, therefore no longer provides an accurate estimation of wind speed. An alternative method of estimating the wind speed may therefore be used in power production states, in which the wind speed is estimated based on the power extracted from the generator (shown as signal 26b in figure 2).

DK 2019 70630 A1 12 Figure 5 illustrates a flow diagram 60 of a particular example of the calculation and use of wind speed in an operational state in which power is not being extracted from the generator, e.g. the idle state 40 or the cut-off state 44. At step 62 the control system 20 requests an estimate for the wind speed. This may be in response to an expired timer, an internal stimulus, or an external stimulus. Once arequest has been made, the wind estimator 30 determines the blade pitch angle 64 of the wind turbine 1 as actuated by the control system 20. The wind estimator 30 — also determines the wind turbine type/model 66 from a stored look-up table. The yaw of the wind turbine is assumed to be in the wind direction and is thus not accounted for in this example. The wind estimator 30 polls the tachometer 22a and determines the rotor speed 68.

— The relationship 70 between the rotor speed and wind speed is then calculated based on a model, and the operational state of the control system 20. The relationship 70 may be determined using previously recorded data 71, such as previous estimated wind speeds and/or previously revised estimated wind speeds and their corresponding input data, 64, 66, 68, 74.

The estimated wind speed is calculated at step 72 based on the relationship 70 and the rotor speed 68.

The estimated wind speed from step 72 is compared to the direct wind speed measurement 74 from the nacelle anemometer 7 at step 76. If the result from the comparison indicates that there is a calibration error and/or localised wind speed error with the nacelle anemometer 7, then the anemometer 7 can be adaptively corrected with signal 77. A calibration error and/or localised wind speed error may be detected if the difference between the primary wind speed measurement and estimated wind speed is greater than an error threshold. If the results are within the error threshold but the direct wind speed measurement and estimated wind speed are not identical then they are averaged together to generate the revised estimated wind speed.

DK 2019 70630 A1 13 At step 78 the control system 20 receives the revised estimated wind speed and can compare it to either the first and second wind speed threshold to decide whether to transition to the power generation state 42 or not.

Any of the methods described above may be incorporated into a computer program, which, when executed by a processor (e.g. of the main controller 200), cause the processor to perform the steps of the above methods. The steps of the method may be stored on a computer readable medium, for example a non-transitory computer readable medium.

Although the invention has been described above with reference to one or more preferred embodiments, it will be appreciated that various changes or modifications may be made without departing from the scope of the invention as defined in the appended claims.

Claims (14)

DK 2019 70630 A1 14 CLAIMS

1. A method of estimating a wind speed at a wind turbine, the wind turbine comprising a generator driven by a rotor, the method comprising: whilst the turbine is in an operational state in which power is not being extracted from the generator: determining a rotor speed of the rotor; providing a relationship between wind speed and rotor speed for the wind turbine; and estimating the wind speed using the predetermined relationship and the determined rotor speed.

2. The method of claim 1, wherein the generator is connected to the rotor via a gearbox, and wherein determining a rotor speed of the rotor comprises: measuring a generator speed of the generator; and calculating the rotor speed using the generator speed and a gear ratio of the gear box.

3. The method of any preceding claim, wherein the operational state is an idling state.

4. The method of claim 1 or claim 2, wherein the operational state is a cut-out state.

35. The method of any preceding claim, wherein the relationship is a linear relationship between wind speed and rotor speed.

6. The method of any preceding claim, wherein the relationship is a quadratic relationship between wind speed and rotor speed.

7. The method of any preceding claim, wherein providing a relationship between wind speed and rotor speed comprises determining the relationship from a model of expected rotor speeds as a function of wind speeds or from previously recorded measurements, wherein the determining is based on one or more of: wind turbine type, pitch angle, and air density at the wind turbine.

DK 2019 70630 A1 15

8. The method of any preceding claim, further comprising comparing the estimated wind speed with a wind speed measured by an anemometer of the wind turbine

9. The method of any preceding claim, further comprising controlling the wind turbine based on the estimated wind speed.

10. The method of any preceding claim, further comprising switching the wind turbine to a different operational state based on the estimated wind speed.

11. The method of any preceding claim, further comprising: whilst the wind turbine is in a power production operational state, determining an estimate of the wind speed based on power extracted from the generator.

12. A controller for a wind turbine, the controller configured to receive a measurement of a rotor speed of the wind turbine, wherein the controller is configured to perform the method of any of claims 1 to 11.

13. A wind turbine comprising: a rotor; a generator driven by the rotor; a tachometer configured to measure a rotor speed of the rotor or a generator speed of the generator; and a wind speed estimator configured to receive measurements from the tachometer and to estimate a wind speed at the wind turbine using the method of any of claims 1 to 11.

14. A computer program comprising instructions which, when the program is executed by a computer, cause the computer to carry out the method of any of claims 1to 11.