WO2016128003A1

WO2016128003A1 - Control system capable of estimating a spatial wind field of a wind turbine system having multiple rotors

Info

Publication number: WO2016128003A1
Application number: PCT/DK2016/050040
Authority: WO
Inventors: Erik Carl Lehnskov Miranda
Original assignee: Vestas Wind Systems A/S
Priority date: 2015-02-12
Filing date: 2016-02-12
Publication date: 2016-08-18

Abstract

A wind turbine system comprising a plurality of wind turbines mounted to a common support 5 structure, wherein each of the plurality of wind turbines includes a rotor and a power generation system driven by the rotor, the wind turbine system further comprising: sensing means arranged to obtain signals indicative of wind speed in at least two spaced locations on or near to the wind turbine system; processing means arranged to process the signals indicative of wind speed to estimate a spatial wind field around the wind turbine system; and 10 control means arranged to adjust operating parameters for each of the wind turbines in response to the estimated spatial wind field.

Description

CONTROL SYSTEM CAPABLE OF ESTIMATING A SPATIAL WIND FIELD OF A WIND TURBINE SYSTEM HAVING MULTIPLE ROTORS

Technical field

The invention relates to a control system of a wind turbine system having multiple rotors and more particularly, but not exclusively, to a control system capable of estimating a spatial wind field around such a wind turbine system. Background to the invention

The most common type of wind turbine is the three-bladed upwind horizontal-axis wind turbine (HAWT), in which the turbine rotor is at the front of the nacelle and facing the wind upstream of its supporting turbine tower.

The spatial wind field can vary considerably over the area covered by the rotor, the spatial wind field representing varying characteristics of the wind, including wind speed, wind veer and wind shear, across a defined area. The rotor and its associated nacelle must be operated according to the wind conditions that it is subjected to, to ensure that the wind turbine operates as close to its rated output as possible, and to minimise stress and vibration in the blades of the rotor.

Before a wind turbine is installed at a new site, measurements are taken to characterise the typical wind conditions at that site. The measurements include wind speed and wind direction, and are taken at various locations around the site at different times. The measurements are then used to generate a predicted wind field that the wind turbine will be subjected to once installed. The wind turbine is then specified and power-rated according to this predicted wind field. Following installation, the wind turbine is controlled dynamically according to instantaneous wind conditions. In conventional wind turbine arrangements, typically wind speed is measured on or near to the nacelle. The measurement is typically low-pass filtered and corrected for wind distortions caused by the nacelle and the rotor. Various operating parameters of the wind turbine such as blade pitch angle and generator power and torque are then optimised according to the measured wind speed, which is assumed to be uniform across the rotor, or to vary in accordance with standardised turbulence models (e.g. Veers or Mann).

l It is noted that the standardised models are based on a small selection of individual site measurements and so are to some extent specific to the characteristics of those sites. The models also do not account for varying atmospheric conditions. So, the estimated wind field may be inaccurate. For example, the actual wind field may have a lower coherence than the standardised model, meaning that there is greater variation in wind speed across the area covered by the rotor than this approach predicts.

It is known to support an array of HAWT units from a common support structure, as described, for example, in EP1483501 B1. Such a configuration achieves economies of scale that can be obtained with a very large single rotor turbine, but avoids the associated drawbacks such as high blade mass, scaled up power electronic components and so on.

However, although such a co-planar multi-rotor wind turbine has its advantages, there are challenges involved in implementing the concept in practice, particularly in controlling the multiple rotors to achieve optimum power production. EP1483501 B1 approaches the control strategy by treating each wind turbine of the system as a separate item that is controlled individually.

Accordingly, to implement dynamic control of each turbine to account for wind speed as described above, a respective sensor attached to each rotor gathers local wind speed measurements, and those measurements are used to optimise control of the rotor to which the sensor is attached. A drawback to this approach is that if one of the sensors fails, the rotor to which it is attached cannot be operated in an optimum manner due to the lack of data, and may even need to be shut down.

It is against this background that the invention has been devised. Summary of the invention According to a first aspect of the invention, there is provided a wind turbine system comprising a plurality of wind turbines mounted to a common support structure. Each of the plurality of wind turbines includes a rotor and a power generation system driven by the rotor. The wind turbine system further comprises sensing means, such as one or more sensors, arranged to obtain signals indicative of wind speed in at least two spaced locations on or near to the wind turbine system, processing means, such as properly programmed processors, arranged to process the signals indicative of wind speed to estimate a spatial wind field around the wind turbine system, and control means, such as one or more controllers, arranged to adjust operating parameters for each of the wind turbines in response to the estimated spatial wind field.

Estimating the spatial wind field around the wind turbine system enables enhanced control of each individual wind turbine to optimise power generation. For example, the pitch of individual blades of each rotor can be tuned to the instantaneous wind speed and direction the blade is subjected to. Accordingly, the control means may be arranged to optimise the power production of each respective wind turbine in relation to the estimated spatial wind field.

In general wind turbine control, the desired operating point of the wind turbine is selected based on the wind field experienced by the rotor(s) of the wind turbine. The operating point being defined as a point in a multidimensional parameter space spanned by two or more of the parameters generator speed, pitch angle, electrical power, electrical torque, wind speed, as well as further parameters used for controlling the wind turbine. In an embodiment, the operating point of each of the plurality of wind turbines is selected based on the estimated spatial wind field.

In some embodiments, at least one of the spaced locations is on or near to one of the wind turbines. In this case, the sensing means may be arranged to obtain signals indicative of wind speed at locations on or near to each wind turbine, and the sensing means may comprise a respective sensor for each wind turbine. Mounting sensors on or near to a wind turbine is a convenient arrangement that also provides direct measurement data at some of the most useful locations.

The sensing means may comprise one or more anemometers. Alternatively, or in addition, the sensing means may comprises at least one load sensor attached to a respective rotor, the or each load sensor being arranged to detect a load applied to its respective rotor. In a further alternative, the sensing means may comprise at least one lidar sensor.

The control means, or elements of the control means, is optionally located remote from the plurality of wind turbines. For example, the control means may be located inside or on the support structure of the wind turbine system. Processing the signals indicative of wind speed may comprise comparing two or more signals indicative of wind speed to calculate wind shear and/or wind veer. The operating parameters adjusted by the control means may comprise one or more of: generator power; generator torque; blade pitch angle; yaw angle.

In some embodiments, the processing means is arranged to estimate a respective spatial wind field for each wind turbine of the system, each spatial wind field estimation being weighted for its respective wind turbine. This approach enables optimised operation of each individual wind turbine, and helps to minimise the impact of inaccuracies in the wind field estimation for locations between measurement locations. The weighing may be a simple weighing which determines a weight based on the distance between the given rotor and the rotor which represent the wind field to be included in the combined wind field of the given rotor. In such embodiments, the estimated wind field of the given rotor is given the highest weight, next highest weight is given to nearest neighbours, etc.

Another aspect of the invention provides a method of controlling a wind turbine system. The wind turbine system comprises a plurality of wind turbines mounted to a common support structure, and each of the plurality of wind turbines includes a rotor and a power generation system driven by the rotor. The method comprises obtaining signals indicative of wind speed in at least two spaced locations on or near to the wind turbine system, processing the signals indicative of wind speed to estimate a spatial wind field around the wind turbine system, and adjusting operating parameters for each of the wind turbines in response to the estimated spatial wind field. Processing the signals indicative of wind speed may comprise interpolating between a pair of signals indicative of wind speed to derive wind speed at locations between the spaced locations at which each of the pair of signals indicative of wind speed were obtained, thereby to estimate the spatial wind field. Alternatively, or in addition, processing the signals indicative of wind speed may comprise comparing two or more signals indicative of wind speed to calculate wind shear and/or wind veer.

It will be appreciated that preferred and/or optional features of the first aspect of the invention may be incorporated alone or in appropriate combination in the second aspect of the invention also.

Brief description of the drawings So that it may be more fully understood, the invention will now be described, by way of example only, with reference to the following drawings, in which:

Figure 1 is a front view of a multi-rotor wind turbine system;

Figure 2 is a top view of the multi-rotor wind turbine system in Figure 1 ;

Figure 3 is a schematic view of an embodiment of a control system for the multi-rotor wind turbine system of Figures 1 and 2;

Figure 4 is a schematic perspective view of the wind turbine system of Figures 1 and 2 in combination with a representative wind field; and

Figure 5 is a flow diagram showing a process for optimising control of the wind turbine system of Figures 1 and 2.

Detailed description of embodiments of the invention

Embodiments of the invention provide apparatus and methods for enabling a dynamic estimation of a spatial wind field around a wind turbine system. This sits in contrast with the conventional approaches described above in which wind speed is typically assumed to be uniform across a wind turbine for the purposes of dynamic control.

In general, this is achieved by gathering wind speed data at various spaced measurement locations around the system, and then processing the data centrally, using the measurements in combination to estimate the spatial wind field across the entire system. For example, interpolation between a pair of measurement points can provide an estimation of the wind speed at locations between the measurement points. Also, wind sheer and wind veer can be calculated from two or more spaced measurements. This may e.g. be done by use of a model of wind shear and/or wind veer and inputting the two or more signals indicative of wind speed and/or load signals into the model to calculate wind shear and/or wind veer.

By estimating the wind field around the entire system, local wind fields around each individual wind turbine can be deduced, enabling enhanced optimisation of the operation of each wind turbine. The more measurement points that are used, the more accurately each wind turbine configuration can be tailored to the wind conditions to which the turbine is subjected. This enables the power curve for each wind turbine to be improved when the turbine is operating below rated power, while minimising loads when operating above rated power. The multiple measurement points enable a dynamic estimation of the wind field within an area bounded by the measurement locations in real-time by interpolating between those measurement points. Indeed, the wind field outside this area can be estimated by extrapolating beyond the measurement locations. Also, the likelihood of gusting can be evaluated, either with reference to the turbulence models or using separate analysis.

Weighted averaging can be applied so that the wind field estimation for each wind turbine is adjusted in accordance with the weight used so the particular wind turbine. In an embodiment, each individual wind turbine prioritises the measurements taken closest to that turbine. Therefore, for a system having, for example, four individual wind turbines, four different wind field estimations may be produced, each being weighted for a respective one of the wind turbines. The weight factors to be applied can be taken from the standardised turbulence models mentioned above. Alternatively, once a sufficient amount of data has been collected the coherence of the estimated wind field can be determined, and the weight factors can be derived accordingly.

As an example, in a four wind turbine configuration, a wind speed for wind turbine /^', could in a simple embodiment be expressed as: v_t = wifiivi) + w_af_a(v_a) + w_bf_b (v_b) + w_cf_c(v_c) meaning that for the /^'th turbine a weight, w, is multiplied to a wind field model function, f, which based on a measured wind speed for that wind turbine calculates an estimated wind speed for that wind turbine, e.g. based on further input such as load measurements. The wind speed calculation is summed together in a weighted sum with contributions from the other wind turbines a, b, c. The wind speed v_h may be expresses as a scalar or a vector field.

In an embodiment, each weight may be determined based on a relative position between of the wind turbines, so that the weights for wind turbines a, b, c are based on these wind turbines relative position with wind turbine /^'. A clear benefit to this approach of using multiple measurement points in a common wind field analysis for the entire system, compared with the earlier described conventional approaches based on operating each turbine wholly independently, is that the wind field locally around each turbine can be estimated. This also applies over the system as a whole. Noting that the wind field can vary considerably over the large area swept by a typical rotor, this approach enables improved power regulation in each wind turbine through more accurate power/torque control and pitch control, to help avoid exceeding the rated power of the turbine. Also, the estimated wind field indicates the prevailing wind direction around the system, and so the yaw angle can be adjusted to account for this.

Additionally, the loss of one of the sensors does not entail a total loss of wind data for the associated wind turbine of the system. Instead, the loss of a sensor merely reduces the accuracy of the estimation; the local wind characteristics around each rotor can still be estimated in order to enable continued optimisation of operation.

Furthermore, wind characteristics such as veer and shear provide an indication of the level of turbulence around the rotors, which influences the load exerted on them and so guides the way in which each rotor and nacelle should be operated. As these parameters are not calculated dynamically in conventional arrangements, embodiments of the invention provide a more complete picture of wind characteristics around the system, and therefore the expected loading on each rotor, enabling enhanced optimisation of turbine operation.

For example, blade pitch control can be enhanced in response to the estimated wind field around each rotor, so that the pitch of each blade of the rotor is controlled individually and continually adjusted to account for the instantaneous wind field that each blade is subjected to as it moves around the swept area of the rotor. The control may be tailored so as to ensure that each blade experiences a similar load at all times, to balance the loads applied to the rotor. Alternatively, the pitch of each blade may be controlled so as to maximise the load applied to it at all times to extract a maximum level of energy from the wind.

Alongside this, each turbine comprises a generator, and the power and torque of the generator can also be adjusted to account for wind conditions. For example, when the wind speed is generally high across the rotor, the generator torque can be raised such that the generator effectively applies braking to the rotor to ensure that the rated output of the wind turbine is not exceeded. Correspondingly, when the wind speed is low, the generator torque is lowered to maximise energy extraction from the wind. Blade pitch control and power/torque control are used in parallel so as to maintain the output of the wind turbine as close as possible to its rated power at all times.

To provide context for the above described invention, an illustrative multi-rotor system that is suitable for use with embodiments of the invention is now described with reference to Figures 1 to 3. It should be appreciated that the system of Figures 1 to 3 is referred to here by way of example only, and it would be possible to implement embodiments of the invention into many different types of wind turbine systems. Referring firstly to Figures 1 and 2, a wind turbine system 2 includes a support structure 4 on which is mounted a plurality of wind turbines 6. In this embodiment, the support structure 4 is a slender tower that is mounted on a foundation embedded in the ground, as is typical with modern wind turbine systems, although it should be appreciated that other support structures are possible, for example frame-like structures. Note that the term 'wind turbine' is used here in the industry-accepted sense to refer mainly to the generating components of the wind turbine system and as being separate to the support structure 4. In general, each wind turbine may be referred to as a wind turbine module 6.

In this embodiment, there are four wind turbines 6 (or modules 6), and these are mounted to the support structure 4 in two pairs, each pair including two wind turbines 6 that are mounted to the support structure 4 by a support arm arrangement 10.

The support arm arrangement 10 comprises a mount portion 12 and first and second arms 13 that extend from the mount portion and carry a respective wind turbine 6. As such, each of the support arms 13 includes an inner end 16 connected to the mount portion 12 and an outer end 18 that is connected to a wind turbine 6.

The support arm arrangement 10 is mounted to the support structure 4 at the mount portion 12 so that the support arm arrangement 10 is able to yaw about the vertical axis of the support structure 4. Suitable yaw gearing (not shown) is provided for this purpose. This movement provides a first degree of freedom for the wind turbine 6 with respect to the support structure, as shown on Figure 2 as 'F1 '. This arrangement may be referred to as a central yaw arrangement. In additional, each wind turbine module may comprise a yaw mechanism.

Each wind turbine 6 includes a rotor 22 that is rotatably mounted to a nacelle 23 in the usual way. The rotor 22 has a set of three blades 24 in this embodiment. Three-bladed rotors are a common rotor configuration, but different numbers of blades are also known; two-bladed configurations are also quite common, for example. Thus, the wind turbines 6 are able to generate power from the flow of wind that passes through the swept area or 'rotor disc' 26 associated with the rotation of the blades.

In this embodiment, a respective wind sensor 27 is mounted to each nacelle 23, the wind sensors 27 being arranged to provide measurements of wind speed and direction at each sensor location, to enable an estimation of the spatial wind field around the entire system 2. From this, local wind fields around each of the rotors 22 of the system 2 can be derived. Placing the sensors 22 on the nacelles 23 is convenient as it mirrors a conventional sensor configuration. As noted above, the sensors could alternatively be distributed around the system in many other ways to achieve the same effect, namely to provide the spaced measurements that are used to estimate the wind field. As an example, wind sensor(s) may be placed at and supported by the tower, a support arm, or other elements of the support structure 4.

The wind sensor 27 may be a conventional anemometer such as would typically be used in known multi-rotor systems. Alternatively, any other sensing means that is capable of providing an indication of wind speed may be used. For example, a lidar sensor could be used. Such sensors direct a laser beam into a target area and then analyse a returning beam that has been reflected by aerosol particles suspended in the air in order to derive wind speed and direction. The analysis may include, for example, interferometry techniques. Conveniently, a single lidar sensor can scan a region of interest to collect measurements from multiple locations in order to estimate the wind field. Such a scanning lidar sensor could be mounted at any convenient location on the system, for example on one of the nacelles 23 or on the support structure 4. Multiple lidar sensors could be used to provide enhanced resolution and accuracy.

A further option is to use load sensors on the rotors 22 to provide an indirect indication of the wind speed, in that the load that the wind applies to each rotor 22 is proportional to the local wind speed when factored for blade pitch angle and wind direction. For example, a strain gauge coupled to a rotor provides an indication of the strain induced in the rotor as a result of the load exerted on the rotor by the wind. Using the known mechanical properties of the rotor, such as the geometry and material strength, this indicated strain can be used to determine the wind load, and in turn the wind speed around the rotor at that location. While this is an indirect measurement and so inherently of lower accuracy than direct measurement approaches, load sensors are generally reliable, inexpensive and readily available, and so this approach may be attractive; even if only alongside other measurement methods, for example for error checking or sensor validation.

A combination of different types of sensors could also be employed in order to enhance the wind field estimation.

Figures 1 and 2 show the main structural components of the wind turbine system 2, although the skilled person would understand that the illustrated embodiment has been simplified to avoid obscuring the invention with unnecessary detail. Further explanation will now be provided on the system component of the wind turbine system 2 with reference also to Figure 3.

On a system level, each wind turbine 6 includes a gearbox 30 that is driven by the rotor 22, and a power generation system including a generator 32 connected to the gearbox 30 and which feeds generated power to a converter system 34 which converts the power into a suitable frequency and voltage for onward transmission. A pitch control system 36 is also provided to control the angle of attack of the blades relative to the wind. The precise configuration of the generator 32 and converter system 34 are not central to the invention and will not be described in detail. However, for present purposes they can be considered to be conventional and, in one embodiment, may be based on a full scale converter (FSC) architecture or a doubly fed induction generator (DFIG) architecture. Furthermore, each of the wind turbines can be considered to be substantially identical, so only one has been labelled fully in Figure 3 for clarity. In the illustrated embodiment, the power output of the converter 34 of each wind turbine 6 is fed to a distribution unit 40 which has a function to receive power inputs 42 from the wind turbines 6 over suitable cabling 44 for onward transmission to a load 46, which is shown here as the electrical grid. The skilled person will appreciate that there are various alternative power transmission systems that could be implemented to take power from several generators to a single grid, and so this embodiment is described for illustrative purposes only.

It should be noted at this point that only a single wind turbine system 2 is described here, but that several such systems may be grouped together to form a wind power plant, also referred to as a wind farm or 'park'. In this case, a power plant control and distribution facility (not shown) would be provided to coordinate and distribute the power outputs from the individual wind turbine systems to the wider grid.

Since the wind turbine system 2 includes a plurality of wind turbines 6, each of which is operable to generate electrical power as the rotor is driven by the wind, the system includes localised control means 49 that is operable to monitor the operation of respective ones of the plurality of wind turbines and to issue commands thereto.

Each control means 49 is also arranged to process signals received from its respective wind sensor 27, to format raw signals received from the sensor 27 appropriately for central processing.

In this embodiment, the localised control means 49 is provided in the form of a plurality of local control modules 50 that are embodied as respective computing devices each of which is dedicated to an associated wind turbine 6.

The responsibility of the local control modules 50 is to monitor the operation of a specific wind turbine 6 and control the operation of its various components to achieve local control objectives. For example, with reference to a single wind turbine 6 for clarity, the local control module may: monitor rotor speed and control the pitch control system 36 in line with a local pitch control strategy as derived from a local power-speed curve that is specific for that particular wind turbine 6 in order to ensure that maximum power is extracted from the wind during below-rated power operating conditions; control the generator 32 in line with a local torque control strategy in order to limit power production in above-rated power operating conditions, as also derived from said local power-speed curve; and monitor wind speed measurements from a respective wind sensor 27 and transmit them to a centralised control means.

In summary, as a group the local control modules 50 are responsible for controlling the functionality of each wind turbine 6 individually in a way that ignores the interaction between the wind turbine 6 and the rest of the multi-rotor wind turbine system 2. So, the localised control modules 50 are specifically directed to optimising the performance of a respective wind turbine 6 in line with the estimated wind field together with an associated set of local control objectives and do not take into account how the operation of the other wind turbines 6 or the support structure 2 may influence how the individual wind turbines should be operated as a wider group. In order to provide a coordinated control strategy, the wind turbine system 2 also includes a centralised control means 51 which is configured to monitor the operation of the wind power system, that is to say the wind turbines 6 and the support structure 4, and to provide centralised control commands to the plurality of wind turbines 6 in order to achieve a set of supervisory control objectives to the wind turbines as a group.

The centralised control means 51 also receives individual wind speed measurements derived from each of the wind sensors 27, and uses those measurements to estimate the spatial wind field around the turbines 6, as described above. This wind field estimation is then used to derive the expected speed and direction of wind striking each blade of each of the rotors 22. This information is used to determine the appropriate blade pitch angle for each blade, as well as the power and torque for the generator 32, to maintain each rotor 22 at a desired point on the local power speed curve. This action can then be implemented in each of the turbines 6 using control commands as described below.

In this embodiment, the centralised control means 51 is provided by a central control module 52 being a computing device incorporated in the central distribution unit 40, although it is noted that in other embodiments the central control module 52 may be separate from the distribution unit 40. Here, the central control module 52 is located on the support structure 4, for example inside the tower or in a housing placed next to the turbine, and includes an integrated wind field processing module 53 that is configured to output an estimated wind field from wind speed measurement inputs. The estimated wind field is output to the central control module, which uses the estimation to produce control commands that will optimise operation of each wind turbine 6 according to the estimated wind field. This may include adjusting the torque of the generator 32, and directing the pitch control system 36 to set the blades to an appropriate angle of attack relative to the wind, or to maintain the required angle of attack according to the local wind direction as derived from the estimated wind field.

The central control module 52 achieves control over each of the wind turbines 6 by providing control commands thereto. As shown in Figure 3, the central control module 52 outputs control commands 54 which are received by each one of the wind turbines 6 and, more particularly, are received by the local control modules 50. The control commands 54 may be of the 'broadcast' type of command in which the same command is sent out to each wind turbine 6, or the commands may be of the 'directed' type of command in which a specific control command is set to a selected one or more, but not all, of the wind turbines 6. It will be noted that Figure 3 is a schematic view, so the way in which the control commands 54 and wind sensor 27 readings are transferred to and from the wind turbines 6 is not depicted explicitly. However, it will be appreciated that suitable cabling may exist in the wind turbine system that interconnects the central control unit 52 to the wind turbines 6, and more specifically to the local control modules 50. The interconnections may be direct or 'point to point' connections, or may be part of a localised area network (LAN) operated under a suitable protocol (CAN-bus or Ethernet for example). Also, it should be appreciated that rather than using cabling, the control commands 54 may be transmitted wirelessly over a suitable wireless network, for example operating under WiFi™ or ZigBee™ standards (IEEE802.11 and 802.15.4 respectively).

The objective of the central control module 52 is to implement a harmonious control strategy for the group of wind turbines 6 so that their interactions between each other, and the interactions between the wind turbines 6 and the support structure 4 are managed in the most effective way, whilst accounting for the estimated wind field around the system 2. Expressed another way, the central control module 52 applies a higher level control strategy to the operation of the wind turbine system 2, whereas the local control modules 50 apply a lower level control strategy to each respective wind turbine 6 individually. However, both 'levels' of the control strategy operate together harmoniously in order to optimise the performance of the wind power system 2, both in terms of absolute power production, production efficiency, and fatigue optimisation.

Moving on to Figure 4, a schematic representation of a wind field within an area of interest 56 upstream of the wind turbine system 2 is illustrated. For clarity, the wind turbine system 2 is shown in simplified form, with only the swept area 26 of each rotor 22 and the support structure 4 shown. The varying wind speed within the area of interest 56 is represented using arrows of varying length. The wind field shown illustrates typical variation of wind speed within such an area, although for simplicity the wind direction is shown as uniform within the area of interest 56. The wind speed may vary significantly throughout the area of interest 56. In general, an uppermost horizontal portion 58 of the area of interest 56 has generally higher wind speed than a lowermost horizontal portion 60 due to wind shear.

Figure 5 shows in schematic form a control flow 62 for estimating the wind field and optimising operation of the wind turbine system 2 accordingly. First, wind sensor measurements are gathered at step 64, for example by the local control modules 50 of the above described wind turbine system 2. The measurements are passed at step 66 to the wind field processing module 53 of the central control module 52 in order to process the measurements to derive an estimation of the wind field. For example, the wind field processing module 53 may interpolate between measurements to derive wind speeds at intermediate positions, or extrapolate beyond measurements, as described above. Once the wind field has been estimated, local wind field estimations are derived at step 68 in order to determine the wind speed and direction incident on each individual blade of the rotors 22. The determined wind speed and direction on each blade is then used to optimise operation of the rotors 22, including controlling the pitch of each blade and the torque of the generator 32. The skilled person will appreciated that modifications may be made to the specific embodiments described above without departing from the inventive concept as defined by the claims.

For example, although in the embodiment of Figure 3 the local control units 50 are shown as being located within the nacelles 23 of the wind turbines 6, this need not be the case, and embodiments are envisaged in which the local control modules are mounted in different locations, for example on the support arms 13 close to the support structure 4. This may provide the local control units 50 in a more convenient position for maintenance access. The responsibilities of processing wind speed measurements, deriving predicted rotor loadings and determining the appropriate action to take may be allocated differently to the manner described above, for example with the local control modules performing a larger proportion of this process. It will be appreciated, though, that the wind field estimation can only be performed by a control module having access to all of the wind speed measurements, although this could be implemented by way of a master local control module that receives measurements from the remaining local control modules and then returns to those remaining modules wind field estimation data.

Furthermore, while the above described system has a single control system, i.e. a single local control module for each turbine connected to a single common centralised control module, the wind field estimation could alternatively be implemented using separate, dedicated apparatus. For example, the output signals from the wind sensors 27 could be transmitted directly to a dedicated central processing unit that is arranged to derive the wind field estimation, without the need for intermediate local control modules or the involvement of a central control module in estimating the wind field. The central processing unit could then determine the appropriate configuration for each rotor of the system in relation to the derived wind characteristics, and deliver this information to a separate control module that issues commands to implement the required action.

Also, it should be appreciated that although the illustrated embodiment includes four wind turbines mounted to the support structure, this is to illustrate the principle of the proposed spatial wind field estimation apparatus which may be applied to wind turbine systems with more than four wind turbines. Moreover, embodiments are envisaged in which the wind turbines are not paired in groups of two, as in the illustrated embodiment, but are arranged differently and not necessarily having a co-planar relationship.

Claims

A wind turbine system comprising a plurality of wind turbines mounted to a common support structure, wherein each of the plurality of wind turbines includes a rotor and a power generation system driven by the rotor, the wind turbine system further comprising: sensing means arranged to obtain signals indicative of wind speed in at least two spaced locations on or near to the wind turbine system; processing means arranged to process the signals indicative of wind speed to estimate a spatial wind field around the wind turbine system; and control means arranged to adjust operating parameters for each of the wind turbines in response to the estimated spatial wind field.

2 The wind turbine system of claim 1 , wherein an operating point of each of the plurality of wind turbines is selected based on the estimated spatial wind field.

3 The wind turbine system of claims 1 or 2, wherein at least one of the spaced locations is on or near to one of the wind turbines.

4 The wind turbine system of claim 2, wherein the sensing means is arranged to obtain signals indicative of wind speed and/or wind direction at locations on or near to each wind turbine.

5 The wind turbine system of claim 4, wherein the sensing means comprises a respective sensor for each wind turbine.

6 The wind turbine system of any preceding claim, wherein the sensing means comprises at least one load sensor attached to a respective rotor, the or each load sensor being arranged to detect a load applied to its respective rotor, at least one or more anemometer and/or at least one lidar sensor.

7. The wind turbine system of any preceding claim, wherein the control means is located remote from the plurality of wind turbines.

8. The wind turbine system of claim 7, wherein the control means is located inside and/or on the support structure of the wind turbine system.

9. The wind turbine system of any preceding claim, wherein the control means is arranged to optimise the power production of each respective wind turbine in relation to the estimated spatial wind field.

10. The wind turbine system of any preceding claim, wherein processing the signals indicative of wind speed comprises comparing two or more signals indicative of wind speed and/or load signals to calculate wind shear and/or wind veer.

11. The wind turbine system of claim 10, wherein the processing means comprises a model of wind shear and/or wind veer, and wherein the signals indicative of wind speed comprises inputting the two or more signals indicative of wind speed and/or load signals into the model to calculate wind shear and/or wind veer.

12. The wind turbine system of any preceding claim, wherein the operating parameters comprise one or more of: generator power; generator torque; blade pitch angle; yaw angle.

13. The wind turbine system of any preceding claim, wherein the processing means is arranged to estimate a respective spatial wind field for each wind turbine of the system, each spatial wind field estimation being weighted for its respective wind turbine.

14. The wind turbine system of claim 13, wherein each weight is determined based on a relative position between of the wind turbines.

15. A method of controlling a wind turbine system, the wind turbine system comprising a plurality of wind turbines mounted to a common support structure, wherein each of the plurality of wind turbines includes a rotor and a power generation system driven by the rotor, the method comprising: obtaining signals indicative of wind speed in at least two spaced locations on or near to the wind turbine system; processing the signals indicative of wind speed to estimate a spatial wind field around the wind turbine system; and adjusting operating parameters for each of the wind turbines in response to the estimated spatial wind field.

The method of claim 15, wherein processing the signals indicative of wind speed comprises interpolating between a pair of signals indicative of wind speed to derive wind speed at locations between the spaced locations at which each of the pair of signals indicative of wind speed were obtained, thereby to estimate the spatial wind field.

The method of claim 15 or claim 16, wherein processing the signals indicative of wind speed comprises comparing two or more signals indicative of wind speed to calculate wind shear and/or wind veer.