Peder Bay Enevoldsen

Wind Shear and Uncertainties in Power Curve Measurement and Wind Resources

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.

The DAN-AERO MW Experiments

The paper describes the DAN-AERO MW experiments carried out within a collaborative, three years research project between Riso DTU and the industrial partners LM Glasfiber, Siemens Wind Power, Vestas Wind Systems and finally the utility company DONG Energy. The main objective of the project is to establish an experimental data base which can provide new insight into a number of fundamental aerodynamic and aeroacoustic issues, important for the design and operation of MW size turbines. The most important issue is the difference between airfoil characteristics measured under 2D, steady conditions in a wind tunnel and the unsteady 3D flow conditions on a rotor. The different transition characteristics might explain some of the difference between the 2D and 3D airfoil data and the experiments have been set up to provide data on this subject. The overall experimental approach has been to carry out a number of coordinated, innovative measurements on full scale MW size rotors as well as on airfoils for MW size turbines in wind tunnels. Shear and turbulence inflow characteristics were measured on a Siemens 3.6 MW turbine with a five hole pitot tube. Pressure and turbulent inflow characteristics were measured on a 2MW NM80 turbine with an 80 m rotor. One of the LM38.8 m blades on the rotor was replaced with a new LM38.8 m blade where instruments for surface pressure measurements at four radial sections were build into the blade during the blade production process. Additionally, the outmost section on the blade was further instrumented with around 60 microphones for high frequency surface pressure measurements. The surface

3D CFD Quantification of the Performance of a Multi-Megawatt Wind Turbine

This paper presents the results of 3D CFD rotor computations of a Siemens SWT-2.3-93 variable speed wind turbine with 45m blades. In the paper CFD is applied to a rotor at stationary wind conditions without wind shear, using the commercial multi-purpose CFD-solvers ANSYS CFX 10.0 and 11.0. When comparing modelled mechanical effects with findings from other models and measurements, good agreement is obtained. Similarly the computed force distributions compare very well, whereas some discrepancies are found when comparing with an in-house BEM model. By applying the reduced axial velocity method the local angle of attack has been derived from the CFD solutions, and from this knowledge and the computed force distributions, local airfoil profile coefficients have been computed and compared to BEM airfoil coefficients. Finally, the transition model of Langtry and Menter is tested on the rotor, and the results are compared with the results from the fully turbulent setup.

Improving the Accuracy of Wind Turbine Power Curve Validation by the Rotor Equivalent Wind Speed Concept

The measurement of the wind speed at hub height is part of the current IEC standard procedure for the power curve validation of wind turbines. The inherent assumption is thereby made that this measured hub height wind speed sufficiently represents the wind speed across the entire rotor area. It is very questionable, however, whether the hub height wind speed (HHWS) method is appropriate for rotor sizes of commercial state-of-the-art wind turbines. The rotor equivalent wind speed (REWS) concept, in which the wind velocities are measured at several different heights across the rotor area, is deemed to be better suited to represent the wind speed in power curve measurements and thus results in more accurate predictions of the annual energy production (AEP) of the turbine. The present paper compares the estimated AEP, based on HHWS power curves, of two different commercial wind turbines to the AEP that is based on REWS power curves. The REWS was determined by LiDAR measurements of the wind velocities at ten different heights across the rotor area. It is shown that a REWS power curve can, depending on the wind shear profile, result in higher, equal or lower AEP estimations compared to the AEP predicted by a HHWS power curve.