BACKGROUND
The invention relates to systems and methods for estimating wind conditions for wind turbines.
Recently, wind turbines have received increased attention as environmentally safe and relatively inexpensive alternative energy sources. With this growing interest, considerable efforts have been made to develop wind turbines that are reliable and efficient. Generally, a wind turbine includes a rotor having multiple blades. The rotor is mounted to a housing or nacelle, which is positioned on top of a truss or tubular tower. Blades on these rotors transform wind energy into a rotational torque or force that drives one or more generators that may be rotationally coupled to the rotor through a gearbox. The gearbox steps up the inherently low rotational speed of the turbine rotor for the generator to efficiently convert mechanical energy to electrical energy, which is fed into a utility grid. To maximize the efficacy of power generation and to simplify connection to the utility grid, wind turbines are often located in proximity to one another, which are generally referred to in the pertinent arts as a “wind farm.”
Accurate estimation of wind conditions such as wind speeds and directions is desired to improve wind farm reliability and performance. One method of wind condition estimation for a wind farm is to equip each wind turbine with a measurement system and a control system to enable each wind turbine to independently react to changing wind conditions. However, the effectiveness of these control systems is constrained by limitations on sensor technologies.
Another technique for wind estimation involves the use of a separate meteorological mast (“metmast”). The metmast includes a separate tower associated with measurement sensors. The metmast provides a more accurate measurements of wind conditions at its location, and then a controller extrapolates to provide estimates for individual wind turbines. The accuracy of this technique is constrained by the methodologies used, especially if the wind farm has a complex terrain.
It would be desirable to have an improved method and apparatus for measurement of wind conditions for a wind farm.
BRIEF DESCRIPTION
In accordance with an embodiment disclosed herein, a wind power generation system is provided. The wind power generation system includes a wind turbine at a wind turbine location, a measuring device for providing a wind condition signal at a test location, a sensor for providing a wind condition signal at the wind turbine, and a controller. The controller is configured for receiving the wind condition signals, using a wind correlation database and the wind condition signal at the test location for providing a wind condition estimation at the wind turbine location, obtaining a difference between the wind condition signal at the wind turbine location and the wind condition estimate at the wind turbine location, and using the difference for adjusting the wind condition signal at the wind turbine location.
In accordance with another embodiment disclosed herein, a method includes receiving a wind condition signal at a wind turbine location; receiving a wind condition signal at a test location; using a wind correlation database and the wind condition signal at the test location for providing a wind condition estimation at the wind turbine location; obtaining a difference between the wind condition signal at the wind turbine location and the wind condition estimation at the wind turbine location; and using the difference for adjusting the wind condition signal at the wind turbine location.
In accordance with still another embodiment disclosed herein, a method includes receiving wind condition signals at a wind turbine location and a metmast location, mapping a wind field of a field of interest according to the wind condition signal at the wind turbine location and a terrain parameter of the field of interest, using the wind field to obtain a wind condition estimation at the metmast location, obtaining a difference of the wind condition signal at the metmast location and the wind condition estimation at the metmast location, and using the difference for adjusting the wind condition signal at the wind turbine location.
DRAWINGS
These and other features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:
FIG. 1 illustrates a wind farm configuration.
FIG. 2 illustrates a wind turbine in the wind farm of FIG. 1 according to certain embodiments of the invention.
FIG. 3 is a flow map of wind condition measurement according to one embodiment of the invention.
FIG. 4 is a wind velocity correlation database according to one embodiment of the invention.
FIG. 5 is a wind velocity correlation database according to another embodiment of the invention.
FIG. 6 is a flow map of wind condition measurement according to a second embodiment of the invention.
DETAILED DESCRIPTION
FIG. 1 illustrates an exemplary wind power generation system such as a wind farm 10, which includes two wind turbines 12 operable to supply electrical power to a utility (not shown) such as a power grid. Although two wind turbines 12 are shown in FIG. 1, it should be understood that wind farms can include any number of wind turbines, including only one wind turbine, or multiple wind turbines, that may be similar or different in design and/or power delivery. Wind farm 10 additionally comprises a measuring apparatus for providing a relatively accurate wind condition signal at a test location. The measuring apparatus may comprise, for example, a meteorology station nearby wind farm 10, or a Doppler SODAR in wind farm 10, or a meteorology mast (“metmast”). As with the wind turbines, more than one measuring apparatus may be used if desired. In one exemplary embodiment, the measuring apparatus comprises a metmast 16 at a metmast location in wind farm 10. Wind farm 10 further includes a central controller 18 for communicating with each wind turbine 12 and metmast 16. Central controller 18 may be used for functions such as overall system monitoring and control including, for example, pitch and speed regulation, high-speed shaft and yaw brake application, yaw and pump motor application, fault monitoring, and combinations thereof. Distributed and/or centralized control architectures may be used in some embodiments. Wind turbine 12 and metmast 16 are described in more detail below. As used herein, singular forms such as “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise.
FIG. 2 is a perspective view of wind turbine 12 in accordance with certain embodiments of the invention. The illustrative wind turbine 12 includes a body 20, also referred to as a “nacelle”, and a rotor 22 coupled to nacelle 20 for rotation with respect to body 20 about an axis of rotation 24. Rotor 22 includes a hub 26 and a plurality of blades 28 (sometimes referred to as “airfoils”) extending radially and outwardly from hub 26. In operation, wind impinges on blades 28 and causes the blades 28 to rotate. Mechanical energy generated by rotation of the blades 28 is converted by a system within the nacelle 20 to produce electrical energy.
In the exemplary embodiment, nacelle 20 is mounted on a tower 30. The height of tower 30 may be any suitable height enabling wind turbine 12 to function as described herein. Although rotor 22 is described and illustrated herein as having three blades 28, rotor 22 may have any number of blades 28.
Referring again to FIG. 1, wind turbines 12 each include one or more sensors 32 for real-time measurement of wind conditions at their respective locations. In certain embodiments, the wind condition can be wind direction, or wind speed, or a wind velocity including both wind direction and wind speed information. In one embodiment, measuring sensors 32 are mounted on nacelles 20 of wind turbines 12. In alternative embodiments, wind turbines 12 include one or more sensors coupled to a wind turbine hub, rotor blade, tower, or shaft. In one embodiment, wind speeds and wind directions are respectively measured by different sensors 32. Sensors 32 for measuring wind speeds may comprise anemometers, for example, and sensors 32 for measuring wind directions may comprise anemoscopes and/or windvanes, for example.
As further illustrated in FIG. 1, metmast 16 includes a tower 34 and a plurality of sensors 36. In one embodiment, sensors 36 are mounted on different levels of tower 34 for measurement of wind velocities at different heights. Metmast 36 may or may not have its base at a common elevation level as the wind turbines, and may or may not have a similar height as the wind turbines. When a different elevation level and/or height is present, additional extrapolation may be used by the central controller 18.
FIG. 3 is a flow chart illustrating a method 100 of wind condition measurement according to one embodiment of the invention. At step 102, at least one sensor 32 measures a turbine wind condition at wind turbine 12 and sends a turbine wind condition signal to central controller 18. In one embodiment, the wind condition signal is a turbine wind velocity {right arrow over (V)}tm. The wind velocity {right arrow over (V)}tm includes a turbine wind speed component Stm and a turbine wind direction component Dtm. At step 104, at least one sensor 36 on metmast 16 measures an actual metmast wind velocity {right arrow over (V)}mm. The actual metmast wind velocity {right arrow over (V)}mm includes an actual metmast wind speed component Smm and an actual metmast wind direction component Dmm.
At step 106, central controller 18 searches in a wind correlation database for an approximate wind velocity of metmast 16 which is most close to the measured actual metmast velocity {right arrow over (V)}mm. An exemplary wind correlation database 122 according to a first embodiment is shown in FIG. 4. The correlation database 122 is formulated by simulating the wind blowing to wind farm 10 from a number n of wind directions D with a certain wind speed. The illustrated correlation database 122 includes twelve wind directions D, i.e. n=12, and thus every two adjacent directions are separated by 30 degrees. One example of a certain wind speed is 10 meter per second (“m/s”). At each direction Di with a wind speed of 10 m/s that blows to the wind farm 10, there is a corresponding wind correlation set Mi. Each wind correlation set Mi includes a corresponding wind velocities {right arrow over (V)}mi, and {right arrow over (V)}ti respectively for metmast 16 and wind turbine 12. Each of the wind velocities {right arrow over (V)}mi and {right arrow over (V)}ti includes a wind direction component Di and a wind speed component Si. For a wind farm 10 with a plurality of wind turbines 12, each wind correlation set Mi includes a wind velocity {right arrow over (V)}mi of metmast 16 and wind velocities {right arrow over (V)}ti for each wind turbine 12. In certain embodiments, wind correlation database 122 can be established before the measuring process 100. Wind correlation 122 can be simulated by commercially available software, such as supplied by ANSYS, Inc. and WindSim AS.
Referring to FIGS. 3 and 4, at step 106, database 122 is searched for an approximated wind correlation set Mp which has a wind direction component Dmp for metmast 16 is most close to measured actual wind direction component Dmm. Then the corresponding approximated wind velocity {right arrow over (V)}tp in the same wind correlation set Mp for wind turbine 12 is identified.
Still referring to FIG. 3, at step 108, measured wind velocity {right arrow over (V)}t for wind turbine 12 is adjusted. In one embodiment, an updated wind velocity {right arrow over (V)}t—new for wind turbine 12 includes an updated wind speed component St—new and an updated wind direction component Dt—new. In one embodiment, the updated wind direction component Dt—new is approximated using an iterative method, for example, according to Equation 1:
D
t
—
new
=D
t+γ(Dtp−Dt) Equation 1
wherein Dtp is a direction component of approximated wind velocity {right arrow over (V)}tp; γ is a relaxation factor, and 0<γ≦1. In one embodiment, γ=0.05.
An updated wind speed component St—new may be calculated according to Equation 2:
wherein Smp is a wind speed component of approximated wind velocity {right arrow over (V)}mp for metmast 16, Smm, is the wind speed component of measured actual wind velocity {right arrow over (V)}mm, for metmast 16; Stp is a wind speed component of approximated wind velocity {right arrow over (V)}tp for metmast; γ is a relaxation factor, and 0<γ≦1. In one embodiment, γ=0.05. Whereby, an updated wind velocity Vt—new for wind turbine 12 is obtained.
Since the angle between every two adjacent wind directions in database 122 in FIG. 4 is 30 degrees, a maximum error of the approximation of the wind direction is less than 15 degrees. The error can be decreased by increasing the number of wind directions in the database 122. For example, one may simulate twenty-four wind directions D with a certain wind speed and obtain twenty-four wind velocities for each of metmast 16 and wind turbine 12. In this embodiment, the maximum error for appropriation of wind direction can be reduced to less than 7.5 degrees.
A second embodiment of a wind correlation database 124 for performing step 106 is shown in FIG. 5. The wind correlation database 124 is formulated by simulating a number n of wind directions D and simulating each direction with a number m of wind speeds S, for example twelve wind directions D and ten wind speeds S, from 5 m/s to 14 m/s in each wind direction D, as illustrated. Each data set Aij, which corresponds to one simulated wind direction Di and one wind speed Sj, includes a wind velocity {right arrow over (V)}mij for metmast 16 and a wind velocity {right arrow over (V)}tij for wind turbine 12. In certain embodiments, each data set Aij, includes a wind velocity {right arrow over (V)}mij for metmast 16 and a plurality of wind velocities {right arrow over (V)}mij for a plurality of wind turbines 12. The velocity correlation database 124 can also be simulated by commercially available software, such as CFX® or Fluent® by ANSYS, Inc.
Referring to FIGS. 3 and 5, a second embodiment of step 106 based on the wind correlation database 124 includes a search in the velocity database 124 for a data set Apq, in which the wind velocity {right arrow over (V)}m—pq for metmast 16 is most close to the measured actual wind velocity {right arrow over (V)}mm.
Still referring to FIGS. 3 and 5, a second embodiment of step 108 for adjusting the wind velocity {right arrow over (V)}tm may includes calculating an updated wind velocity {right arrow over (V)}t—new by using an iterative method, for example, according to Equation 3:
{right arrow over (V)}
t
—
new
={right arrow over (V)}
t+γ({right arrow over (V)}t—pq−{right arrow over (V)}t) Equation 3
wherein {right arrow over (V)}t—pq is an approximated wind velocity of wind turbine 12 in the data set At—pq. “γ” is a relaxation factor, and 0<γ≦1. In one embodiment, γ=0.05. For a wind farm with a plurality of wind turbines, each data set Aij includes wind correlation information for metmast 16 and each wind turbine 12, and an updated wind velocity {right arrow over (V)}t—new for each wind turbine 12 can be obtained by similar method.
Referring back to FIG. 3, after an updated wind velocity Vt—new for wind turbine 12 is obtained, a verifying step 110 may be performed. In one embodiment, verifying step 110 includes sub-steps 112-114. At step 112, central controller 18 uses the updated wind velocity Vt—new for wind turbine 12 and terrain parameters of wind farm 10 to map a wind field for wind farm 10. The wind field for wind farm 10 need not cover the entire wind farm 10 and may optionally be a field of interest which includes wind turbine 12 and metmast 16. The mapping can be performed by known methodologies in meteorological arts. An exemplary method may use a diagnostic model, which can generate a wind field utilizing updated wind velocity Vt—new and terrain parameters for the field of interest and which satisfies flow physics. One embodiment includes formulating an initial wind field using updated wind velocity Vt—new by interpolation and extrapolation, considering distance and height differences between interpolation points of wind farm 10 and wind turbine 12, and then using the initial wind field to map an estimated wind field by solving a mass conservation equation that reflects flow physics. A 3-D diagnostic model for wind field adjustment. Journal of Wind Engineering and Industrial Aerodynamics. Vol. 74-76. 249-261. Montero, G. et al. 1998 and Diagnostic Wind Field Modeling for Complex Terrain: Model Development and Testing. Journal of Applied Meteorology. vol. 27. 785-796. Ross, D. G., Smith, I. N., Manins, P. C., Fox, D. G., 1988 describe a number of modeling methods, which are incorporated herein by reference for purposes of example. In one embodiment, one updated wind velocity Vt—new for wind turbine 12 is used to generate the wind field. In another embodiment, a plurality of updated wind velocities Vt—new for a plurality of wind turbines 12 in the field of interest are used to establish the wind field.
Terrain parameters of the field may change with one example being growth of plants in or near the field. In some embodiments, the terrain parameters may be modified as conditions change and/or by month, by quarter, by year, or by any acceptable time period.
With continued reference to FIG. 3, at step 114, wind velocity of metmast 16 is estimated as {right arrow over (V)}me according to the wind field. The estimated wind velocity {right arrow over (V)}me is compared to the measured actual wind velocity {right arrow over (V)}mm of metmast 16 at step 116, and a second difference Δ{right arrow over (V)} is obtained, Δ{right arrow over (V)}={right arrow over (V)}mm−{right arrow over (V)}me. If Δ{right arrow over (V)} is not zero, there is a margin of error for the updated wind velocity {right arrow over (V)}t—new of wind turbine 12. If the difference Δ{right arrow over (V)} is larger than a preset value {right arrow over (V)}0, wind velocities {right arrow over (V)}t—new may need to be further adjusted. In one embodiment, the process starts again at step 102 to perform steps 102-108 for further adjustment. In certain embodiments, steps 102-116 may be repeated, until a minimum Δ{right arrow over (V)} is obtained, or until Δ{right arrow over (V)}≦{right arrow over (V)}0.
FIG. 6 is a flow chart illustrating a method 200 of wind condition measurement according to another embodiment of the invention. At step 202, at least one sensor 32 on wind turbine 12 measures a wind condition at wind turbine 12 and sends a wind condition signal to central controller 18. In one embodiment, the wind condition signal is a wind velocity {right arrow over (V)}t2, which includes a turbine wind speed component St2 and a turbine wind direction component Dt2.
At step 204, central controller 18 uses wind velocity {right arrow over (V)}t2 and terrain parameters of the field of interest of wind farm 10 to map a wind field. The wind field can be established by a similar method as described at step 112 of FIG. 3. Wind velocity of metmast 16 is estimated as {right arrow over (V)}me2 according to the wind field established at step 204, and an actual wind velocity {right arrow over (V)}mm2 of metmast 16 is measured at step 208 which includes an actual wind speed component Smm2 and an actual wind direction component Dmm2. At step 210, the estimated wind velocity {right arrow over (V)}me2 is compared with the measured actual wind velocity {right arrow over (V)}mm2, and a difference Δ{right arrow over (V)}2 is obtained, Δ{right arrow over (V)}2={right arrow over (V)}mm2−{right arrow over (V)}me2. If Δ{right arrow over (V)}2 is not zero, there is a margin of error for the wind field derived from wind velocity {right arrow over (V)}t2 of wind turbine 12. If the difference Δ{right arrow over (V)}2 is larger than a preset value {right arrow over (V)}0, wind velocity {right arrow over (V)}t2 may be adjusted at step 212. At step 212, wind velocity {right arrow over (V)}t2 is adjusted by using the difference Δ{right arrow over (V)}2.
In certain embodiments, the difference Δ{right arrow over (V)}2 includes a wind speed difference component ΔS2 and a wind direction difference component ΔD2. An updated wind turbine velocity {right arrow over (V)}t—new2 of wind turbine 12 includes an updated turbine wind speed component St—new2, and an updated turbine wind direction component Dt—new2. The updated turbine wind speed component St—new2 may be calculated by equation 4:
S
t
—
new2
=S
tm2
+γΔS
2 Equation 4
wherein “γ” is a relaxation factor, and 0<γ≦1. In one embodiment, γ=0.05. The updated turbine wind direction component Dt—new2 may be calculated according to equation 5:
D
t
—
new2
=D
tm 2
+γΔD
2 Equation 5
In certain embodiments, after the wind velocity {right arrow over (V)}t2 of wind turbine 12 is adjusted, the adjusted wind velocity {right arrow over (V)}t—new2 may be verified. In one embodiment, the verifying includes building an updated wind field for the field of interest of wind farm 10 using the updated wind velocity {right arrow over (V)}t—new2 for wind turbine 12 by utilizing the method described at step 204. After an updated wind field is established, an updated estimated wind velocity {right arrow over (V)}me—new2 of metmast 16 is obtained. The updated estimated wind velocity {right arrow over (V)}me—new2 is then compared with the measured wind velocity {right arrow over (V)}mm of metmast 16 to obtain an updated difference Δ{right arrow over (V)}new. If Δ{right arrow over (V)}new<Δ{right arrow over (V)}2, it is verified that the adjustment of wind velocities {right arrow over (V)}t2 is in the right direction. Steps 104 to 114 may be repeated until a smallest Δ{right arrow over (V)} is obtained or until Δ{right arrow over (V)}≦{right arrow over (V)}0. If the updated difference Δ{right arrow over (V)}new>Δ{right arrow over (V)}, it suggests that the measured wind velocities {right arrow over (V)}t2 of wind turbine 12 has already best represented the wind condition at wind turbine 12 and need not be adjusted.
In certain embodiments, at least two metmasts 16 are located in wind farm 10. Wind condition signal of wind turbine 12 is adjusted according to the measured signal condition signal of each metmast 16 using method 100, and at least two updated wind condition signals are obtained. The at least two updated wind condition signals are optimized to obtain a final updated wind condition signal at wind turbine 12.
Central controller 18 is configured to communicate with individual wind turbines 12 and metmast 16 via communication links, which may be implemented in hardware, software, or combinations thereof. In certain embodiments, the communication links may be configured to remotely communicate data signals to and from the central controller 18 in accordance with any wired or wireless communication protocol known to one skilled in the art.
In certain embodiments, each wind turbine 12 includes a turbine controller (not shown) which communicates with central controller 18 and utilizes the adjusted wind velocity to perform yaw control and/or speed regulation, so as to achieve a maximum wind energy capture.
While the invention has been described with reference to an exemplary embodiment, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims.
It is to be understood that not necessarily all such objects or advantages described above may be achieved in accordance with any particular embodiment. Thus, for example, those skilled in the art will recognize that the systems and techniques described herein may be embodied or carried out in a manner that achieves or optimizes one advantage or group of advantages as taught herein without necessarily achieving other objects or advantages as may be taught or suggested herein.
Furthermore, the skilled artisan will recognize the interchangeability of various features from different embodiments. The various features described, as well as other known equivalents for each feature, can be mixed and matched by one of ordinary skill in this art to construct additional systems and techniques in accordance with principles of this disclosure.
Patent Application
20100080703
