WO2011157271A2

WO2011157271A2 - A method and control unit for controlling a wind turbine in dependence on loading experienced by the wind turbine

Info

Publication number: WO2011157271A2
Application number: PCT/DK2011/050210
Authority: WO
Inventors: Jesper Sandberg Thomsen; Martin Jørgensen
Original assignee: Vestas Wind Systems A/S
Priority date: 2010-06-14
Filing date: 2011-06-13
Publication date: 2011-12-22
Also published as: WO2011157271A3

Abstract

A method of controlling a wind turbine having a rotor and a generator for producing power, the method comprising the steps of: obtaining an operational parameter, the operational parameter representing the loading experienced by the wind turbine due to a turbulence intensity acting on the rotor of the wind turbine; controlling the wind turbine in dependence on the operational parameter by altering at least one of a rotational speed setpoint of the rotor and a minimum pitch setpoint of a blade of the rotor; wherein the step of obtaining the operational parameter comprises: determining a rotor power produced by the rotor; and calculating a standard deviation of the rotor power over a period of time.

Description

A Method and Control Unit for Controlling a Wind Turbine in Dependence on Loading

Experienced by the Wind Turbine

The present invention relates to a method of controlling a wind turbine which is designed for a specific nominal load, i.e. design load. The invention further relates to a control unit in accordance with the method and to a wind turbine including such a control unit.

A wind turbine obtains power by converting the force of the wind into torque acting on a drive train, i.e. on the rotor blades and thus on the main shaft and thereby typically on an electrical generator rotated by the main shaft directly or through a gearbox. The amount of power which the wind turbine receives and which therefore potentially can be transferred to the drive train depends on several conditions including the wind speed and the density of the air, i.e. the site conditions. Even though a desire to increase productivity requests conversion of the highest possible amount of wind energy to electrical energy, the structural limitations of the wind turbine, i.e. the design loads, define safety limits for the allowed load on the wind turbine. In practice, the wind load depends on various weather conditions including the average wind speed, wind peaks, the density of the air, the turbulence, wind shear, and shift of wind, and the impact of the wind load on the wind turbine and thereby the load on the wind turbine can be adjusted for a current wind condition by changing various settings on the wind turbine.

Even though the loading of a wind turbine is determined by a number of weather conditions and settings on the wind turbine, the wind turbines of today are typically controlled in accordance with a relatively simple and reliable control strategy according to which the turbine is shut down completely at wind speeds above a certain safety value. Though representing a potentially very safe way of operating a wind turbine, the complete shut down represents drawbacks, e.g. due to the fact that any major change in power production may influence the supplied power grid in a negative way.

Improved wind turbine control is desired for several reasons including for providing a more continuous power production even at strong winds or similar difficult weather conditions, for preventing complete power production shut down and thus for improving the performance and thus the economy of the wind turbine.

It is an aim of the present invention to increase the productivity of a wind turbine and reduce the loads acting on a wind turbine by controlling the wind turbine in dependence on a representation of the turbulence to which the wind turbine is subjected.

According to a first aspect of the present invention there is a provided a method of controlling a wind turbine having a rotor and a generator for producing power, the method comprising the steps of: obtaining an operational parameter, the operational parameter representing the loading experienced by the wind turbine due to a turbulence intensity acting on the rotor of the wind turbine; controlling the wind turbine in dependence on the operational parameter by altering at least one of a rotational speed setpoint of the rotor and a minimum pitch setpoint of a blade of the rotor; wherein the step of obtaining the operational parameter comprises: determining a rotor power produced by the rotor and calculating a standard deviation of the rotor power over a period of time.

The turbulence intensity is defined as the standard deviation of the wind velocity, based on a mean value of the wind velocity.

The standard deviation of the rotor power represents the loading experienced by the wind turbine due to a turbulence intensity acting on the rotor of the wind turbine. A high value of the standard deviation of the rotor power indicates a high level of turbulence intensity and a low value of the standard deviation of the rotor power indicates a low level of turbulence intensity. Based on this operational parameter, the turbine is controlled in order to increase the productivity of the turbine and reduce the loads acting on the turbine The standard deviation may be calculated over a time period of 10 minutes with a sample rate of 25Hz for example.

The step of controlling the wind turbine in dependence on the operational parameter may further comprise altering the power or torque produced by the generator. The step of determining the rotor power may comprise estimating the rotor power from the power output of the generator and the rotational speed of the generator.

The step of obtaining the operational parameter may further comprise: determining a load acting on at least one blade of the rotor and calculating a standard deviation of the load acting on the blade over a period of time.

The step of obtaining the operational parameter may further comprise: determining a load acting on a plurality of blades of the rotor; for each blade, calculating a standard deviation of the load acting on the respective blade over a period of time; and selecting the maximum standard deviation of the load acting on a plurality of blades.

The load acting on the at least one blade of the rotor may comprise a blade root flap bending moment.

The step of obtaining the operational parameter may further comprise: determining a weighted average of a standard deviation of the rotor power and the standard deviation of the load acting on the at least one blade. The wind turbine is erected on a location and the method may further comprise the steps of: defining a plurality of sectors each specifying a range of wind directions towards the wind turbine; defining, for each sector, a sector control strategy for controlling the wind turbine; determining a current wind direction; before controlling the wind turbine in dependence on the operational parameter, controlling the wind turbine in accordance with the sector control strategy defined for the sector to which the current wind direction corresponds; and then controlling the wind turbine in dependence on the operational parameter.

The step of controlling the wind turbine may comprise: increasing the rotational speed of the rotor if the operational parameter is higher than a first threshold value; or decreasing the rotational speed of the rotor if the operational parameter is lower than a second threshold value. The step of controlling the wind turbine may comprise: calculating an error value, the error value being the difference between the operational parameter and a threshold value; inputting the error value to a PID controller and outputting from the PID controller, a rotational speed set point of the rotor.

According to a second aspect of the present invention there is provided a control unit for a wind turbine having a rotor and a generator for producing power, the wind turbine being designed for a nominal load, the control unit having a control structure adapted to: obtain an operational parameter, the operational parameter representing the loading experienced by the wind turbine due to a turbulence intensity acting on the rotor of the wind turbine; control the wind turbine in dependence on the operational parameter by altering at least one of a rotational speed setpoint of the rotor and a minimum pitch setpoint of a blade of the rotor; wherein the step of obtaining the operational parameter comprises: determining a rotor power produced by the rotor and calculating a standard deviation of the rotor power over a period of time.

Preferably, the control unit is adapted to carry out the method according to the first aspect of the present invention. According to a third aspect of the present invention there is provided a wind turbine for converting between wind energy and electrical energy, the wind turbine comprising a control unit according to the second aspect of the present invention.

Examples of the invention will be now be described in further detail with reference to the drawings in which:

Figure 1 illustrates a horizontal axis wind turbine;

Figure 2 illustrates a control system for a wind turbine;

Figure 3 illustrates a power curve of a wind turbine;

Figures 4, 5 and 6 illustrate control systems for a wind turbine.

Figure 1 shows a typical horizontal axis wind turbine 10. The turbine comprises a tower 1 1 which supports a nacelle 12. The wind turbine 10 comprises a rotor made up of three blades 14 each having a root end 15 mounted on a hub 16. Each blade 14 can pitch about its own pitch axis which extends longitudinally along the span of the blade, and the nacelle 12, together with the rotor 13, can yaw about a vertical axis aligned with the tower 1 1 , as is well known in the art. The blades 14 may be pitched using hydraulic or electric actuators as is known in the art.

Depending on the control solution, each blade 14 may have a load sensor 17 mounted on the blade at the root end 15. In this example, the load sensor is a strain gauge that measures the blade root flap bending moment. The "flap bending moment" of a blade is the moment when the blade deflects in a direction substantially normal to the plane of the rotor 13. Further strain gauges may be positioned along the longitudinal direction of the blade to measure the load acting on the blades. For example, further strain gauges may be located at 20%, 40%, 50%, 60%, 75% and 80% of the blade radius from the blade root 15. In another example, the load sensor 17 may be in the form of a fibre optic sensor.

Figure 2 shows the drive train of a typical wind turbine 10. The rotor 13 is connected to a gearbox 21 through a low speed shaft 20. A high speed shaft 22 couples the gearbox 21 to the electrical drive train 23. The output of the electrical drive train is to the grid. The electrical drive train comprises a generator which is coupled to an AC-AC converter for connection to the grid. Although a gearbox 21 is shown, the invention is also applicable to gearless direct drive wind turbines.

A control unit 24 provides control signals to components of the wind turbine to regulate the power output from the electrical drive train 23. The control unit 24 comprises a power control unit 25 which is connected to the generator and the converter of the electrical drive train 23. The power control unit 25 provides a power reference to the electrical drive train 23.

The control unit 24 also comprises a pitch control unit 26. The pitch control unit provides a pitch reference to pitch actuators 27 so that the blades are pitched to regulate the power produced by the turbine as is well known in the art. The power control unit 25 and the pitch control unit 26 control the rotational speed or torque to a given set point by adjusting the power reference and the pitch reference. The power produced by the turbine is a result of this control method. As is well known in the art, a wind turbine is operated in a partial load range (also known as part load) until a rated wind speed is reached, at which point the wind turbine is then operated at rated power output in what is known as the full load region. Figure 3 illustrates a power curve of a typical wind turbine plotting wind speed on the x axis against power on the y axis. Curve 40 is the power curve for the wind turbine and defines the power output of the wind turbine generator as a function of wind speed. The wind turbine starts to generate power at a cut in wind speed Vmin. The turbine then operates under partial load conditions until the rated wind speed is reached at point Vr. At the rated wind speed at point Vr the rated generator power is reached (also known as the nominal power). The cut in wind speed in a typical wind turbine is 4 m/s and the rated wind speed is 12 m/s. At point Vmax is the cut out wind speed; this is the highest wind speed at which the wind turbine may be operated while delivering power. At wind speeds equal to and above the cut out wind speed the wind turbine is shutdown for safety reasons, in particular to reduce the loads acting on the wind turbine. When the wind turbine 10 is operating under partial load conditions, the blades 14 are pitched at a pitch setpoint angle about their longitudinal axis in order to maximise the energy capture from the oncoming wind. At the same time the rotational speed and/or torque is controlled by the power control unit 25 by adjusting the power reference. When the wind turbine is operating in the full load region (between Vr and Vmax), the pitch of the blades 14 is controlled so that the rotational speed or torque is kept at a desired reference. At the same time the power control unit 25 keeps the power reference at the nominal set point.

As shown in Figure 3, the turbine 10 is controlled by the control unit 24 such that it can produce more or less power than the typical power curve 40 in both the partial load and the full load regions. The term "over-rating" is understood to mean producing more than the nominal power during full load operation. The term "de-rating" is understood to mean producing less than the nominal power during full load operation. In the invention, the turbine can produce more or less power in both the full load and the partial load regions. Thus the term "over-producing" is used to refer to an increase in power production in both the partial load and the full load region compared to the normal power curve 40; and the term "under-producing" is used to refer to a decrease in power production in both the partial load and the full load region compared to the normal power curve 40. When the turbine is over-producing, the turbine 10 is run more aggressive than normal and the generator has a power output which is higher than the normal power for a given wind speed. The over-producing is shown in Figure 3 as area 41. When the turbine is under-producing, the turbine is run less aggressive than normal and the turbine generator has a power output which is lower than the normal power for a given wind speed. The under-producing is shown in Figure 3 as area 42. It should be noted that the areas 41 and 42 extend into the partial load region as well as the full load region. When the turbine 10 is over-producing the loads acting on the turbine are increased and when the turbine is under-producing the loads acting on the turbine are decreased.

As mentioned above, the power curve 40 is the normal power curve. A wind turbine is conventionally designed to withstand certain loads, such as the rotor blade root flap bending moment, the tower base bending moment and the main shaft design load. These are the "design or nominal loads" which should not be exceeded, and so the turbine has a normal power curve 40, at which the turbine will be operated so that none of the defined loads are exceeded.

As shown in Figure 2, the control unit 24 also comprises an adaptive control unit 28. The adaptive control unit 28 monitors the conditions that the wind turbine 10 is subjected to from the oncoming wind and controls the wind turbine such that it can over-produce or under-produce as shown in Figure 3. The adaptive control unit 28 provides control signals to the pitch control unit 26 and the power control unit 25 to control the output power of the wind turbine.

Figure 4 is a first example of the adaptive control unit 28. The turbine 10 is controlled based on a representation of the turbulence intensity that the turbine experiences. The turbulence intensity in the oncoming wind flow is not estimated through the use of anemometers as this provides a very unreliable indication of the turbulence intensity. Instead, the turbulence intensity is represented by estimating the power of the rotor 13. The power of the rotor "P_rotor" is estimated at 43 from the output power of the generator and the rotational speed of the generator. In this example, P_rotor may be function:

where "P" is the electrical power output of the turbine, "ω" is the rotational speed of the generator or the rotor 13 and "t" is time. The estimated rotor power is input to a calculation unit 44 which calculates the standard deviation of P_rotor, "P_rotor_Std". P_rotor_Std represents the loading experienced by the wind turbine due to the turbulence intensity acting on the rotor of the wind turbine. A high value of P_rotor_Std indicates a high level of turbulence intensity and a low value of P_rotor_Std indicates a low level of turbulence intensity.

The value P_rotor_Std is input to a mode selector unit 45 as an operational parameter. In the mode selector unit 45, it is determined if the turbine 10 should be operated so that it follows the normal power curve 40 (in Figure 3) or if it should over-produce or underproduce. In this example, the mode selector unit 45 comprises a lookup table, and the power setpoint, the rotational speed setpoint and the minimum pitch angle reference (pitch angle reference used in partial load operation) are modified by the level of P_rotor_Std. The mode selector unit 45 provides the control signals to the pitch control unit 26 and the power control unit 25 to control the pitch, speed and power of the wind turbine.

The mode selector unit 45 may also comprise a PID (proportional integral derivative) controller, including a P, I, PI and PD controller. The mode selector unit 45 will contain a reference value for P_rotor_Std called "P_rotor_Std_ref". An error value is calculated as the difference between P_rotor_Std and P_rotor_Std_ref which is then input to the PID controller. The output of the PID controller is the control action that the wind turbine should follow, namely the control signals output to the pitch control unit 26 and output to the power control unit 25.

The mode selector unit controls the output of the turbine 10 by sending signals to the power control unit 25 and the pitch control units 26. The power output of the turbine 10 is the result of the following control strategies: pitch control of the rotor blades about a minimum pitch set point in partial load operation. Normally, the minimum pitch set point is calculated for optimal power production, but when using the mode selector the pitch set point is modified based on the control action; and

· rotational speed control of the rotor about a speed set point by adjusting the pitch reference and the power reference. Normally, the speed set point is calculated for optimal power production and limited to a nominal value, but when using the mode selector the rotational speed set point is modified based on the control action; and

in full load operation feeding the power set point from the mode selector 45 through the power control unit 25 to the electrical drive train.

Figure 5 is a second example of the adaptive control unit 28. In the adaptive control unit 28 of the second example, the rotor power estimator 43 and the calculation unit 44 operate in the same was the first example. However, in the second example, there is a further input to give a representation of the turbulence intensity acting on the rotor 13 of the wind turbine 10. The blade flap bending moment is measured using the sensors 17 located on each blade 14 and results in signals Ma (the flap bending moment for the first blade); Mb (the flap bending moment for the second blade) and; Mc (the flap bending moment for the third blade). Each of Ma, Mb and Mc recorded at each of the three blades 14, is input in to a respective flap moment calculation unit 46a, 46b and 46c. The flap moment calculation units 46a, 46b and 46c calculate the standard deviation of each of Ma, Mb and Mc, referred to as Ma_Std, Mb_Std, Mc_Std.

At 47 the maximum value of Ma_Std, Mb_Std, Mc_Std is determined and will be referred to as "M_max_Std". M_max_Std represents the loading experienced by the wind turbine due to the turbulence intensity acting on the blades 14 of the wind turbine. A high value of M_max_Std indicates a high level of turbulence intensity and a low value of M_max_Std indicates a low level of turbulence intensity. The values of P_rotor_Std and M_max_Std are both input to the mode selector unit 45 and together form an operational parameter. In the mode selector unit 45, it is determined if the turbine 10 should be operated so that it follows the normal power curve 40 (in Figure 3) or if it should over-produce or under-produce. In this example, the mode selector unit 25 comprises a lookup table, and the power output for the turbine is based on the oncoming wind speed and the value of P_rotor_Std and M_max_Std. The mode selector unit 45 may also comprise a PID controller as described above.

The second example shown in Figure 5 provides additional certainty to the first example shown in Figure 4. By using two parameters (namely, P_rotor_Std and M_max_Std) which both represent the turbulence acting on the wind turbine 10, the turbine can be controlled in a more reliable manner. In particular, the mode selector unit 25 can take a weighted average of P_rotor_Std and M_max_Std to determine how to control the turbine.

Figure 6 illustrates a third example of the invention where the adaptive control unit 28 is the same as that shown in the first example of Figure 4, with the additional input of wind direction to the mode selector unit 45. A wind direction sensor 48 on the turbine 10 measures the direction of the oncoming wind to the turbine. The wind direction sensor 48 may not necessarily measure the wind direction directly, it may obtain the direction of the wind from determining in which direction the wind turbine 10 is yawed.

For each location that a wind turbine 10 is erected in, the area around the turbine can be divided up into a number of sectors. For example, the area around the turbine is divided up into twelve sectors, each representing 30 degrees around the compass, although any other numbers of sectors can be used. Before the turbine 10 is erected at a particular site, the turbulence intensity in each sector is measured and stored over a period of time. By way of example, for a particular site, the average turbulence intensity in the sectors 0 to 120 degrees and 180 to 300 degrees can be said to be the average turbulence intensity at that particular site. In the sector 120 to 180 degrees the average turbulence intensity is higher than average turbulence intensity for that site. In the sector 300 to 360 degrees the turbulence intensity is lower than average turbulence intensity for that site.

A turbulence sector determining unit 49 analyses the wind direction and from a lookup table outputs a value representing the turbulence intensity for that sector T_sector. The value T_sector is a predetermined value of the expected turbulence for a particular sector based on measured data before the wind turbine 10 was erected. T_sector may indicate that the rotor 13 of the turbine 10 is pointing towards a sector with known high turbulence intensity or it may indicate that the rotor is pointing towards a sector with known low turbulence intensity.

The value T_sector is input to the mode selector along with the value P_rotor_Std. In the mode selector unit 45, it is determined if the turbine 10 should be operated so that it follows the normal power curve 40 (in Figure 3) or if it should over-produce or underproduce. In this example, the mode selector unit 45 comprises a lookup table, and the power output for the turbine is based on the oncoming wind speed and the value of P_rotor_Std and T_sector.

In this third example shown in Figure 6, mode selector unit 45 first analyses the value of T_sector which is based on a wind sector. For each wind sector, it is preselected how the turbine 10 is controlled. For example, for each sector, the amount the turbine 10 can over-produce or under-produce is limited. In the sector 120 to 180 degrees, the average turbulence intensity is higher than average turbulence intensity for that site and so the mode selector unit will not allow the turbine to over-produce in this sector and the turbine will under-produce in this sector. In the sector 300 to 360 degrees the turbulence intensity is lower than average turbulence intensity for that site and so the turbine 10 is allowed to over-produce in this sector. The mode selector 45 then analyses the value of P_rotor_Std and controls the output power of the wind turbine 10 based on the value of P_rotor_Std, but within the constraints imposed by the sector to which the rotor 13 faces.

As has been described, the values for T_sector are determined before the turbine has been erected. However, in a further implementation, the adaptive control unit may operate for, say, one month and store values of P_rotor_Std for each sector and so update the values of T_sector on the fly, rather than these values being pre-determined when the turbine is erected.

Furthermore, the turbulence sector determining unit 49 may identify, for example, that a sector A has a low level of turbulence intensity and therefore the turbine can overproduce in this sector. The turbulence sector determining unit 49 also identifies that in a sector B the turbulence intensity is high and the turbine should under-produce in this sector B to avoid increasing the loads acting on the turbine. The control algorithms in the rotor power estimator 43 and the calculation unit 44 may be very slow because they need a lot of data over time from the sensors to be able to control the turbine, so when moving from one sector to another it will take a long time for the wind turbine to adapt to the new sector - with the result that the wind turbine may be exposed to critical loads if moving to sector B or the power production will not be optimised if moving to sector A. But, to avoid this time delay problem, if the wind switches from sector A to sector B, the mode selector 45 will "resume" from where it left off the last time the turbine was operating in sector B, i.e. under-producing; and when the wind switches from sector B to sector A the mode selector 45 will '"resume"' from the last setting when the wind turbine was operating in sector A, i.e. over-producing.

In a fourth example, the mode selector unit 45 may takes input from P_rotor_Std, M_max_Std and T_sector, i.e. a combination of examples 1 to 3. By using three parameters (namely, P_rotor_Std, M_max_Std and T_sector) which represent the turbulence acting on the wind turbine 10, the turbine can be controlled in a more reliable manner. In particular, the mode selector unit 45 can take a weighted average of P rotor Std and M max Std to determine how to control the turbine.

Claims

1. A method of controlling a wind turbine having a rotor and a generator for producing power, the method comprising the steps of:

obtaining an operational parameter, the operational parameter representing the loading experienced by the wind turbine due to a turbulence intensity acting on the rotor of the wind turbine;

controlling the wind turbine in dependence on the operational parameter by altering at least one of a rotational speed setpoint of the rotor and a minimum pitch setpoint of a blade of the rotor; wherein the step of obtaining the operational parameter comprises:

determining a rotor power produced by the rotor; and

calculating a standard deviation of the rotor power over a period of time.

2. A method according to claim 1 , wherein the step of controlling the wind turbine in dependence on the operational parameter further comprises altering the power or torque produced by the generator.

3. A method according to claim 1 or claim 2, wherein the step of determining the rotor power comprises estimating the rotor power from the power output of the generator and the rotational speed of the generator.

4. A method according to any one of the preceding claims, wherein the step of obtaining the operational parameter further comprises:

determining a load acting on at least one blade of the rotor;

calculating a standard deviation of the load acting on the blade over a period of time.

5. A method according to any one of claims 1 to 3, wherein the step of obtaining the operational parameter further comprises:

determining a load acting on a plurality of blades of the rotor;

for each blade, calculating a standard deviation of the load acting on the respective blade over a period of time; and selecting the maximum standard deviation of the load acting on a plurality of blades.

6. A method according to claim 4 or claim 5, wherein the load acting on the at least one blade of the rotor comprises a blade root flap bending moment.

7. A method according to any one of claims 4, 5 or 6, wherein the step of obtaining the operational parameter further comprises:

determining a weighted average of a standard deviation of the rotor power and the standard deviation of the load acting on the at least one blade.

8. A method of controlling a wind turbine according to any one of the preceding claims, wherein the wind turbine is erected on a location, the method further comprising the steps of:

defining a plurality of sectors each specifying a range of wind directions towards the wind turbine;

defining, for each sector, a sector control strategy for controlling the wind turbine; determining a current wind direction;

before controlling the wind turbine in dependence on the operational parameter, controlling the wind turbine in accordance with the sector control strategy defined for the sector to which the current wind direction corresponds; and then

controlling the wind turbine in dependence on the operational parameter.

9. A method according to any one of the preceding claims, wherein the step of controlling the wind turbine comprises:

increasing the rotational speed of the rotor if the operational parameter is higher than a first threshold value; or

decreasing the rotational speed of the rotor if the operational parameter is lower than a second threshold value.

10. A method according to any one of claims 1 to 8, wherein the step of controlling the wind turbine comprises:

calculating an error value, the error value being the difference between the operational parameter and a threshold value; inputting the error value to a PID controller;

outputting from the PID controller, a rotational speed set point of the rotor.

1 1 . A control unit for a wind turbine having a rotor and a generator for producing power, the wind turbine being designed for a nominal load, the control unit having a control structure adapted to:

obtain an operational parameter, the operational parameter representing the loading experienced by the wind turbine due to a turbulence intensity acting on the rotor of the wind turbine;

control the wind turbine in dependence on the operational parameter by altering at least one of a rotational speed setpoint of the rotor and a minimum pitch setpoint of a blade of the rotor; wherein the step of obtaining the operational parameter comprises: determining a rotor power produced by the rotor; and

calculating a standard deviation of the rotor power over a period of time.

12. A control unit according to claim 1 1 , wherein the control unit is adapted to carry out the method according to any one of claims 2 to 10.

13. A wind turbine for converting between wind energy and electrical energy, the wind turbine comprising a control unit according to claim 1 1 or claim 12.