Experimental study of a small wind turbine for low‐ and medium‐wind regimes

The results of an experimental assessment of a small prototype battery charging wind turbine designed for low‐ and medium‐wind regimes are presented. The turbine is based on a newly designed axial flow permanent magnet synchronous generator and a three‐bladed rotor with variable twist and taper blades. Overspeed control is performed by a furling mechanism. The turbine has the unique feature of being capable of operating at either 12, 24 or 48 V system voltage, requiring no load control in any case. In the 48 V configuration, the system is capable of providing 2 kWh day^?1 for an average wind speed as low as 3.5 m s^?1 and an air density of 85% of the standard pressure and temperature value. The experimental assessment has been conducted under field conditions with the turbine mounted on a 20 m guy‐wired tubular tower. The experimental power curves are shown to be in good agreement with a detailed aerodynamical and electromechanical model of the turbine for non‐furling conditions and for wind speeds above the theoretical cut‐in speed. In the case of the rapidly spinning load configurations, a finite power production at wind speeds below the theoretical cut‐in speed can be observed, which can be explained in terms of inertia effects. During the measurement campaigns with high loads, we were able to observe bifurcations of the power curve, which can be explained in terms of instabilities arising in situations of transition from attached to separated flow. A full experimental C_p(λ)‐curve has been constructed by operating the turbine under different load conditions and the findings are in good agreement with a variable Reynolds‐number blade‐element momentum model. The three proposed system configurations have been found to operate with a high aerodynamic efficiency with typical values of the power coefficient in the 0.40–0.45 range. Copyright © 2009 John Wiley & Sons, Ltd.     

Design of a wind turbine rotor for maximum aerodynamic efficiency

The design of a three‐bladed wind turbine rotor is described, where the main focus has been highest possible mechanical power coefficient, CP, at a single operational condition. Structural, as well as off‐design, issues are not considered, leading to a purely theoretical design for investigating maximum aerodynamic efficiency. The rotor is designed assuming constant induction for most of the blade span, but near the tip region, a constant load is assumed instead. The rotor design is obtained using an actuator disc model, and is subsequently verified using both a free‐wake lifting line method and a full three‐dimensional Navier–Stokes solver. Excellent agreement is obtained using the three models. Global CP reaches a value of slightly above 0.51, while global thrust coefficient CT is 0.87. The local power coefficient C_p increases to slightly above the Betz limit on the inner part of the rotor; the local thrust coefficient C_t increases to a value above 1.1. This agrees well with the theory of de Vries, which states that including the effect of the low pressure behind the centre of the rotor stemming from the increased rotation, both C_p and C_t will increase towards the root. Towards the tip, both C_p and C_t decrease due to tip corrections as well as drag. Copyright © 2008 John Wiley & Sons, Ltd.     

Impact of wall roughness and turbulence level on the performance of a horizontal axis wind turbine with the U‐RANS solver THETA

The presented work investigates the impact of different sheared velocity profiles in the atmospheric boundary layer on the characteristics of a wind turbine by modifying the wall roughness coefficients in the logarithmic velocity profile. Moreover, the rotor and wake characteristics in dependence of the turbulence boundary conditions are investigated. In variant I, the turbulence boundary conditions are defined in accordance to the logarithmic velocity profile with different wall roughness lengths. In variant II, the turbulent kinetic energy and turbulent viscosity remain independent of the velocity profile and represent the free‐stream turbulence level. With an increase of the shear in the velocity profile, the amplitudes in the 3/rev characteristics of rotor thrust and rotor torque, induction factors, and effective angles of attack are increased. In variant I, the overall levels of thrust coefficient are hardly affected by the velocity profiles resulting from different wall roughness length values. The power coefficient is reduced about 1%. Conversely, compared with variant II, a difference of 2% in the power coefficient has been detected. Moreover, the wake recovery process strongly depends on the turbulence boundary condition. Simulations are carried out on an industrial 900‐kW wind turbine with the incompressible U‐RANS solver THETA.     

Effects of wind shear on wind turbine rotor loads and planetary bearing reliability

Recent studies suggest that wind shear and the resulting pitch moments increase bearing loads and thereby contribute to premature wind turbine gearbox failure. In this paper, we use momentum‐based modeling approaches to predict the pitch moments from wind shear. The non‐dimensionalized results, which have been validated against accepted aeroelastic results, can be used to determine thrust force, pitch moment and power of a general rotor as a function of the wind shear exponent. Even in extreme wind shear (m = 1), the actual thrust force and power for a typical turbine (R* < 0.5) were within 8% and 20% of the nominal values (those without wind shear), respectively. The mean pitch moment increased monotonically with turbine thrust, rotor radius and wind shear exponent. For extreme wind shear (m = 1) on a typical turbine (R* = 0.5), the mean pitch moment is ~25% the product of thrust force and rotor radius. Analysis of wind shear for a typical 750 kW turbine revealed that wind shear does not significantly affect bearing loads because it counteracts the effects of rotor weight. Furthermore, even though general pitch moments did significantly increase bearing loads, they were found to be unlikely to cause bearing fatigue. Analyses of more common low wind‐speed cases suggest that bearing under‐loading and wear are more likely to contribute to premature bearing failure than overloading and classical surface contact fatigue. Copyright © 2015 John Wiley & Sons, Ltd.     

Power correlation for vertical axis wind turbines with varying geometries

In this paper, a new predictive model that can forecast the performance of a vertical axis wind turbine (VAWT) is presented. The new model includes four primary variables (rotor velocity, wind velocity, air density, and turbine power output) as well as five geometrical variables (rotor radius, turbine height, turbine width, stator spacing, and stator angle). These variables are reduced to include the power coefficient (C_p) and tip speed ratio (TSR). A power coefficient correlation for a novel VAWT (called a Zephyr Vertical axis Wind Turbine (ZVWT)) is developed. The turbine is an adaptation of the Savonius design. The new correlation can predict the turbine's performance for altered stator geometry and varying operating conditions. Numerical simulations with a rotating reference frame are used to predict the operating performance for various turbine geometries. The case study includes 16 different geometries for three different wind directions. The resulting 48 data points provide detailed insight into the turbine performance to develop a general correlation. The model was able to predict the power coefficient with changes in TSR, rotor length, stator spacing, and stator angle, to within 4.4% of the numerical prediction. Furthermore, the power coefficient was predicted with changes in rotor length, stator spacing, and stator angle, to within 3.0% of the numerical simulations. This correlation provides a useful new design tool for improving the ZVWT in the specific conditions and operating requirements specific to this type of wind turbine. Also, the new model can be extended to other conditions that include different VAWT designs. Copyright © 2010 John Wiley & Sons, Ltd.     

Aerodynamic simulations of offshore floating wind turbine in platform‐induced pitching motion

Forfloating offshore wind turbines, rotors are under coupled motions of rotating and platform‐induced motions because of hydrodynamics impacts. Notably, the coupled motion of platform pitching and rotor rotating induces unsteadiness and nonlinear aerodynamics in turbine operations; thus having a strong effect on the rotor performances including thrust and power generation. The present work aims at developing a computational fluid dynamics model for simulations of rotor under floating platform induced motions. The rotor motion is realized using arbitrary mesh interface, and wind flows are modelled by incompressible Navier‐Stokes flow solver appended by the k  ? ω shear stress transport turbulence model to resolve turbulence quantities. In order to investigate the fully coupled motion of floating wind turbine, the six degree of freedom solid body motion solver is extended to couple with multiple motions, especially for the motion of rotor coupled with the prescribed surge‐heave‐pitch motion of floating platform. The detailed methodology of multiple motion coupling is also described and discussed in this work. Both steady and unsteady simulations of offshore floating wind turbine are considered in the present work. The steady aerodynamic simulation of offshore floating wind turbine is implemented by the multiple reference frames approach and for the transient simulation, the rotor motion is realized using arbitrary mesh interface. A rigorous benchmark of the present numerical model is performed by comparing to the reported literatures. The detailed elemental thrust and power comparisons of wind turbine are carried out by comparing with the results from FAST developed by National Renewable Energy Laboratory and various existing numerical data with good agreement. The proposed approach is then applied for simulations of National Renewable Energy Laboratory 5MW turbine in coupled platform motion at various wind speeds under a typical load case scenario. Transient effect of flows over turbines rotor is captured with good prediction of turbine performance as compared with existing data from FAST. Copyright © 2016 John Wiley & Sons, Ltd.     

Assessing atmospheric stability and its impacts on rotor‐disk wind characteristics at an onshore wind farm

As the average hub height and blade diameter of new wind turbine installations continue to increase, turbines typically encounter higher wind speeds, which enable them to extract large amounts of energy, but they also face challenges due to the complex nature of wind flow and turbulence in the planetary boundary layer (PBL). Wind speed and turbulence can vary greatly across a turbine's rotor disk; this variability is partially due to whether the PBL is stable, neutral or convective. To assess the influence of stability on these wind characteristics, we utilize a unique data set including observations from two meteorological towers, a surface flux tower and high‐resolution remote‐sensing sound detection and ranging (SODAR) instrument. We compare several approaches to defining atmospheric stability to the Obukhov length (L). Typical wind farm observations only allow for the calculation of a wind shear exponent (α) or horizontal turbulence intensity (I_U) from cup anemometers, whereas SODAR gives measurements at multiple heights in the rotor disk of turbulence intensity (I) in the latitudinal (I_u), longitudinal (I_v) and vertical (I_w) directions and turbulence kinetic energy (TKE). Two methods for calculating horizontal Ifrom SODAR data are discussed. SODAR stability parameters are in high agreement with the more physically robust L,with TKE exhibiting the best agreement, and show promise for accurate characterizations of stability. Vertical profiles of wind speed and turbulence, which likely affect turbine power performance, are highly correlated with stability regime. At this wind farm, disregarding stability leads to over‐assessments of the wind resource during convective conditions and under‐assessments during stable conditions. Copyright © 2011 John Wiley & Sons, Ltd.     

Horizontal axis wind turbine systems: optimization using genetic algorithms

A method for the optimization of a grid‐connected wind turbine system is presented. The behaviour of the system components is coupled in a non‐linear way, and optimization must take into account technical and economical aspects of the complete system design. The annual electrical energy cost is estimated using a cost model for the wind turbine rotor, nacelle and tower and an energy output model based on the performance envelopes of the power coefficient of the rotor, C_P, on the Weibull parameters k and c and on the power law coefficient α of the wind profile. In this study the site is defined with these three parameters and the extreme wind speed V_max. The model parameters vary within a range of possible values. Other elements of the project (foundation, grid connection, financing cost, etc.) are taken into account through coefficients. The optimal values of the parameters are determined using genetic algorithms, which appear to be efficient for such a problem. These optimal values were found to be very different for a Mediterranean site and a northern European site using our numerical model. Optimal wind turbines at the Mediterranean sites considered in this article have an excellent profitability compared with reference northern European wind turbines. Most of the existing wind turbines appear to be well designed for northern European sites but not for Mediterranean sites. Copyright © 2001 John Wiley & Sons, Ltd.     

The influence of the wind speed profile on wind turbine performance measurements

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. Copyright © 2008 John Wiley & Sons, Ltd.     

Evaluation of the effects of turbulence model enhancements on wind turbine wake predictions

The modelling of wind turbine wakes is investigated in this paper using a Navier–Stokes solver employing the k–ω turbulence model appropriately modified for atmospheric flows. It is common knowledge that even single‐wind turbine wake predictions with computational fluid dynamic methods underestimate the near wake deficit, directly contributing to the overestimation of the power of the downstream turbines. For a single‐wind turbine, alternative modelling enhancements under neutral and stable atmospheric conditions are tested in this paper to account for and eventually correct the turbulence overestimation that is responsible for the faster flow recovery that appears in the numerical predictions. Their effect on the power predictions is evaluated with comparison with existing wake measurements. A second issue addressed in this paper concerns multi‐wake predictions in wind farms, where the estimation of the reference wind speed that is required for the thrust calculation of a turbine located in the wake(s) of other turbines is not obvious. This is overcome by utilizing an induction factor‐based concept: According to it, the definition of the induction factor and its relationship with the thrust coefficient are employed to provide an average wind speed value across the rotor disk for the estimation of the axial force. Application is made on the case of five wind turbines in a row. Copyright © 2010 John Wiley & Sons, Ltd.     

An analytical expression for the power coefficient of an ideal horizontal-axis wind turbine

The paper shows that an analytical evaluation of the power coefficient C_p for an ideal horizontal-axis wind turbine can be made via an expression giving the direct relationship of C_p and the axial induction factor a. The results obtained agree closely with those obtained numerically from the usual integral expression involving several variables.     

Winglet optimization for a model‐scale wind turbine

A winglet optimization method is developed and tested for a model‐scale wind turbine. The best‐performing winglet shape is obtained by constructing a Kriging surrogate model, which is refined using an infill criterion based on expected improvement. The turbine performance is simulated by solving the incompressible Navier‐Stokes equations, and the turbulent flow is predicted using the Spalart‐Allmaras turbulence model. To validate the simulated performance, experiments are performed in the Norwegian University of Science and Technology wind tunnel. According to the simulations, the optimized winglet increases the turbine power and thrust by 7.8% and 6.3%, respectively. The wind tunnel experiments show that the turbine power increases by 8.9%, while the thrust increases by 7.4%. When introducing more turbulence in the wind tunnel to reduce laminar separation, the turbine power and thrust due to the winglet increases by 10.3% and 14.9%, respectively.     

The k‐ϵ‐fP model applied to wind farms

The recently developed k‐?‐f_P eddy‐viscosity model is applied to one on‐shore and two off‐shore wind farms. The results are compared with power measurements and results of the standard k‐? eddy‐viscosity model. In addition, the wind direction uncertainty of the measurements is used to correct the model results with a Gaussian filter. The standard k‐? eddy‐viscosity model underpredicts the power deficit of the first downstream wind turbines, whereas the k‐?‐f_P eddy‐viscosity model shows a good agreement with the measurements. However, the difference in the power deficit predicted by the turbulence models becomes smaller for wind turbines that are located further downstream. Moreover, the difference between the capability of the turbulence models to estimate the wind farm efficiency reduces with increasing wind farm size and wind turbine spacing. Copyright © 2014 John Wiley & Sons, Ltd.     

Interfacing a fixed-pitch-angle wind turbine with a double-output induction generator

We describe the performance of a variable-speed, constant-frequency, double-output induction generator (VSCF—DOIG) that is being driven by a fixed-pitch angle wind turbine. The induction generator is run according to a control strategy that forces the generator to extract more than its rated stator power output from the wind without being overheated. Since, in the steady state, the mechanical power developed by the wind turbine is balanced by the electromechanical power developed by the generator, the interfacing problem may be solved by representing the wind turbine performance curve C_p = f(λ) as a polynomial function of the induction generator slip and wind speed. Using this approach, the induction generator outputs that correspond to a given wind speed can easily be calculated. This procedure is superior to previously used trial and error methods.     

Observations of wind turbine wakes and surface roughness effects on wind flow variability

Wind data collected at nine meteorological towers at the Goodnoe Hills MOD-2 wind turbine site were analyzed to characterize the wind flow over the site both in the absence and presence of wind turbine wakes. Free-flow characteristics examined were the variability of wind speed and turbulence intensity across the site as a function of wind direction and surface roughness. The nine towers' data revealed that scattered areas of trees upwind of the site caused pronounced variations in the wind flow over the site. At two towers that were frequently downwind of an extensive grove of trees, up to 30% reductions in wind speed and a factor of 2 to 3 increase in turbulence intensity were measured. A substantial increase in the magnitude of the wind gusts, as well as a considerable decrease in the mean wind speed, was observed when a tower was downwind of the trees.Wind turbine wake characteristics analyzed included the average velocity deficits, wake turbulence, wake width, wake trajectory, vertical profile of the wake, and the stratification of wake properties as a function of the ambient wind speed and turbulence intensity. The wind turbine rotor disk spanned a height of 15 m to 107 m. The nine towers' data permitted a detailed analysis of the wake behavior at a height of 32 m at various downwind distances from 2 to 10 rotor diameters (D). The relationship between velocity deficit and downwind distance was surprisingly linear, with average maximum deficits ranging from 34% at 2 D to 7% at 10 D. Largest deficits were at low wind speeds and low turbulence intensities. Average wake widths were 2.8 D at a downwind distance of 10 D. Implications for turbine spacing are that, for a wind farm with a 10-D row separation, array losses would be significantly greater for a 2-D than a 3-D spacing because of incremental effects caused by overlapping wakes. Other interesting wake properties observed were the wake turbulence (which was greatest along the flanks of the wake). the vertical variation of deficits (which were greater below hub height than above), and the trajectory of the wake (which was essentially straight).     

Preventing wind turbine overspeed in highly turbulent wind events using disturbance accommodating control and light detection and ranging

Light detection and ranging (LIDAR) systems can be used to provide wind inflow information to a wind turbine controller before the wind reaches the turbine. Both fatigue and extreme load reduction are possible as a result; in this research, we propose a LIDAR‐based controller designed to prevent emergency shutdowns caused by rotor overspeed. This switching controller consists of a disturbance accommodating control (DAC)‐based baseline controller and a different DAC linearized about a reduced generator speed for extreme events, also referred to as an extreme event controller. Switching between the controllers was performed using linear interpolation over various transition times, depending on how early the extreme event could be detected. If a gust of wind is detected using LIDAR measurements evaluated by a one‐sided cumulative summation algorithm, a relatively long transition time can be used. Switching can also be based on a large output estimation error, ε_y, in which case the transition time is shorter. Once the extreme event passed, control is switched from the extreme event controller back to the baseline DAC. This switching controller resulted in fewer overspeeds when compared with the modified baseline controller, which is a gain scheduled DAC. By preventing overspeeds, the switching controller increased the mean power the wind turbine generated over a simulated 10 min period. Copyright © 2014 John Wiley & Sons, Ltd.     

An assessment of the impact of reduced averaging time on small wind turbine power curves,energy capture predictions and turbulence intensity measurements

The effect of varying the averaging time of measured data used to calculate wind turbine power curves is examined. The effects of reducing the averaging time from 10 to 1 min, as recommended for small wind turbines, are investigated using power performance data recorded using a 15 kW wind turbine. Test site data have been processed according to the relevant international standard, IEC 61400‐12‐1, to provide power curves and annual energy yield predictions. A number of issues are explored: the systematic distortion of the power curve that occurs as averaging time is decreased, the errors introduced by the use of 1 min averaged power curves to calculate energy yield and the reduction of turbulence intensity as averaging time is reduced. Recommendations for improved small wind turbine testing and energy yield calculation are given. Copyright © 2012 John Wiley & Sons, Ltd.     

A momentum explanation for the unsatisfactory Betz model prediction in highly loaded wind turbines

The present study attempts to provide a direct explanation for the strong deviation between the predictions of the well‐known Betz model and the actual results for the performance of highly loaded wind turbines. The new model accounts for the inner and outer stream interaction (momentum and energy transfers) by reformulating the relevant one‐dimensional flow equations. This results in a very good prediction of the experimentally measured C_T = f(a) relationship in ‘windmilling propeller’ tests. It is shown that although the maximum power coefficient is near that predicted by Betz, for rotor loadings beyond the ‘optimum’ point, this drops sharply (instead of remaining steady, near the C_P = 0.5 value). Further analysis shows that the main contributor for this ‘efficiency’ degradation is the reduction in the mass flux through the turbine rotor, apparently because of the wake vortices that block its passage in the inner section. Copyright © 2010 John Wiley & Sons, Ltd.