To identify the influence of wind shear and turbulence on wind turbine performance, flat terrain wind profiles are analysed up to a height of 160 m. The profiles' shapes are found to extend from no shear to high wind shear, and on many occasions, local maxima within the profiles are also observed. Assuming a certain turbine hub height, the profiles with hub-height wind speeds between 6 m s −1 and 8 m s −1 are normalized at 7 m s −1 and grouped to a number of mean shear profiles. The energy in the profiles varies considerably for the same hub-height wind speed. These profiles are then used as input to a Blade Element Momentum model that simulates the Siemens 3.6 MW wind turbine. The analysis is carried out as time series simulations where the electrical power is the primary characterization parameter. The results of the simulations indicate that wind speed measurements at different heights over the swept rotor area would allow the determination of the electrical power as a function of an 'equivalent wind speed' where wind shear and turbulence intensity are taken into account. Electrical power is found to correlate significantly better to the equivalent wind speed than to the single point hub-height wind speed. Figure 8. (a): Calculated power curves with fi xed and variable rotational speed. No shear; (b): Calculated power curves with fi xed and variable speed. Extreme shear specifi ed. 246 × 76 mm (500 × 500 DPI) 356 R. Wagner et al. ConclusionsLarge variations have been observed in the wind profi les over a fl at site. The results show that the profi les usually do not follow the logarithmic law; instead, their shape, in the case of fl at terrain, heavily depends upon the atmospheric conditions. These profi les were used as input to a sensitivity analysis concerning the power production as a function of a weighted ('equivalent') wind speed over the whole swept rotor area as compared with the results of the wind speed only at hub height. The results from the simulations indicate that measuring the wind speed at an increased number of points over the whole swept rotor area profi le, would improve the correlation between wind input and power output. These results support the necessity for the introduction of a new defi nition for power performance measurements using a distributed measurement of the wind over the swept rotor area instead of using only the hub-height wind speed.

Power curve measurements are encumbered with large uncertainty as wind measurements take place only at hub height. The wind profile over the turbine rotor is an expression of the kinetic energy available to the wind turbine and the evolution of large rotors prohibits the assumption that the hub height wind speed is representative of the wind speed over the whole rotor. Even in the case where measurements cover the lower half of the turbine rotor and extrapolations are attempted, the uncertainties remain considerable. We argue for that the measurement of the wind speed over the whole rotor height should be the future preferred approach. Such a measurement will minimize the uncertainty in estimating the wind potential of a site and the uncertainty in the power curve measurement method and the AEP calculation of wind turbines. To document this, we present wind speed and power curve results from wind and power measurement campaigns, one in flat terrain suffering an energy deficit and one in complex terrain presenting a surplus. Common for both is the inadequacy of the hub height wind speed measurement to describe the energy contents of the flow. In the flat terrain campaign we use one-year period of data in order to study the wind shear profiles at heights which correspond to an assumed rotor area of a modern multi-MW turbine. The energy flux through the “turbine rotor” is seen to be subject to seasonal variations caused by differences in atmospheric stability which influence the shear profile shape. Considerable deviations occur relative to the flux measured when only the cup anemometer at hub height is used. In the complex terrain campaign, a wind turbine power curve has been measured for a period of eight months in a Midwest (US) site following a site calibration. Wind shear measurements over the lower rotor part were taken throughout this period at three heights (hub, lower tip and midway between the two). Considerable wind shear during nights and well-mixed profiles during days were observed. Large differences in the power curve and the AEP between day and night periods were observed, the power curve and the AEP being better during the night. The data analysis was combined with in-house aeroelastic simulations, over a wide range of wind shear and turbulence intensities values, in order to verify the analysis findings. The combined simulations and data analysis results made it clear that the upper turbine rotor part was influenced by the presence of a low level jet during nighttime. This caused considerable deviations from the expected power curve and AEP, which were not detected either by the site calibration or the lower rotor part rotor speed measurements. We conclude the paper by presenting results from combined cup and LIDAR power curve measurements, and suggest a method which compensates for the wind shear influence on the power curve.

No abstract