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Boost data accuracy at higher levels

With wind blades on taller turbines now spinning at more than twice the height of standard 60-metre meteorological towers, the ability to assess proposed wind plant sites with remote sensing technology is essential. Dan Bernadett explains

cost-effective met towers typically end at 60 metres. As a result, wind resource data above the 60-metre level is often approximated by extrapolating the data available from the lower met towers. This, however, introduces significant uncertainty into energy-production estimates and could affect the ability to secure finance or choose the best turbines for the site.

Remote sensing, which uses light waves or sound waves to measure the conditions via equipment at ground level, is a less expensive way to capture hub-height measurements and has the added advantage of making direct measurements across the rotor plane.

When designing a pre-construction wind resource analysis, a number of important factors need to be

Measuring wind speeds at a proposed site to determine how much electricity will be produced is one of the essential first steps of developing a wind project. But, as the size of modern turbines increases in height and rotor diameter, it is

becoming increasingly complicated to find the right mix of technology to measure the wind resource accurately.

Hub heights of 80 metres were once considered the ceiling for cutting-edge turbines, but they are now reaching 100 metres and beyond. With blade tips reaching 150 metres, the days when two or three 60-metre meteorological (met) towers would be enough to measure potential wind resource are disappearing. But, while larger turbines are delivering economies of scale and value,

Remote sensing Part of a cost-effective way to obtain accurate wind-speed data at greater hub heights a

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Mobile measurement A single remote unit can easily be moved around a site

considered. It must characterise the atmospheric conditions at the site over a range of time scales from seconds to years, and a range of vertical and horizontal distances from metres to kilometres. A full understanding of the uses and limitations of the meteorological instruments available, both fixed and remote sensing, is, of course, essential. Equally important are the location and distribution of the measurements collected at the site.

The general industry rule of thumb is that a minimum of one year of data must be collected to assess seasonal and daily effects. However, the data collected during this short time period must then be corrected to the long-term average. This can be done using an appropriate reference station, such as a nearby airport or other meteorological station, which can provide a set of wind data that can be compared with the site-specific measurements for the proposed wind project. Failure to do this could result in a drastic miscalculation of its energy-generation potential.

The toolkitThe most commonly used instrument for measuring wind speed is the cup anemometer, which looks like a set of spinning cups. Propeller and three-dimensional (3D) ultrasonic anemometers are also used. The wind direction, equally important, is typically captured with a wind vane. The past few years have seen remote sensing grow in popularity and it is now often employed, particularly at sites with complex terrain or wind regimes. While it has yet to become standard best practice, it is proving its value in a wind resource assessment campaign, and using it to

complement traditional wind measurements from met towers is increasingly seen as offering the most comprehensive data set. By combining technologies, a pre-construction wind analysis can be created that far outweighs its cost, as the example below illustrates.

Remote sensing above hub heightsThere are two primary remote sensing technologies available to establish wind conditions: sodar (sonic detection and ranging) and lidar (light detection and ranging). Sodar has been used in the wind industry for ten years or more, while the use of lidar for wind energy applications is more recent. Both devices offer many advantages over traditional met towers and enhance the value of a site’s wind analysis when used in conjunction with tower measurements.

They are capable of measuring across the entire wind turbine rotor plane and providing the speed and 3D direction. The remote sensors are usually portable and can be moved throughout a site by one technician, limiting the number of units required as well as the total cost. A mix of a

As turbine hub heights grow, meteorological (met) masts and installation costs

increase significantly. Met towers higher than 60 metres (200 feet) must also apply for permitting approval from the US Federal Aviation Administration, which can take 90 days to come through and may result in a requirement to install aviation safety lighting — adding further to costs. Other ways to analyse wind must be considered.

Low met towers, lower valueTo provide 14 hub-height met towers for the wind resource assessment of a gigawatt-scale wind farm might cost several million dollars. The developer’s first instinct might be to use only 60-metre towers, saving installation costs of less than half a million dollars. However, this must be balanced against the reduction of the all-important P90 value of the project, which can significantly affect finance.

P90 value is a pre-construction

estimation of a project’s energy production that is 90% sure to be exceeded. P90 and other variations on this figure (P95 or P99) indicate the level of risk of failing to meet debt repayments. They are typically assessed by the investor or lending institution as part of the due-diligence process for the loan. This is similar to the evaluation that a loan officer might make of a proposed business plan when evaluating a small-business loan.

Where there is no data at and above hub heights, the greater uncertainty in pre-construction energy estimates means the P90 value might be reduced by almost 1%, making the wind site appear slightly less attractive to lenders or potential equity investors. This in turn could reduce the value of a gigawatt-scale project by several million dollars and make it harder for the developer to secure finance at an attractive enough rate to construct the project. This is like a small business seeking a loan with a

slightly lower credit score, or a weaker business model, which the banker may view as representing an increased risk or simply not an attractive lending opportunity.

Combined approachA smarter approach would be to combine 60-metre and hub-height met towers with remote sensing. One sonic detection and ranging (sodar) unit can be moved around the site and placed at each of the met towers for a period of four to six weeks. The data from these resources will identify the variation of wind shear with speed and direction across the entire rotor plane throughout the project.

This information is typically able to reduce uncertainty about wind shear above the tower by a factor of two — a developer can be twice as certain of the average wind forces likely to be placed on the upper end of the rotor plane.

A few well-placed hub-height met towers through the site could

confirm the improvement in calculations of wind shear up to the hub height, but only the sodar and lidar (light detection and ranging) units can capture the wind resource variations across the entire rotor plane.

Changing the hub heightRemote sensing also allows the developer to select the turbine hub height after the wind assessment has begun. A site that may have been originally conceived with 80-metre hub heights may be upgraded to a higher-output 100-metre hub height when the site conditions are better understood.

Such a meteorological programme might cost less than a million dollars, but would achieve a P90 similar to a wind resource analysis using only hub-height met towers. The reduction in wind shear uncertainty alone makes sodar cost-effective, as it increases the accuracy of the energy production estimate.

coMbining daTa souRces THe cOST-eFFecTive OPTiOn

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60 metremet mast

Wind speed, metres/second

Height, metres

Extrapolationfrom met mast

Measured data using sodar

Met towers combined data provides greatest accuracy

few hub-height met towers with a greater number of shorter towers, alongside fixed and roving remote sensors, can provide an economic means to reduce the uncertainty in energy-production estimates for today’s larger wind turbines. Careful configurations of this mix of technologies can help to define the 3D wind field at the measurement locations. These measurements can then be used to validate models that predict the 3D wind field at all proposed turbine locations throughout the rotor plane.

Higher turbulenceIt is important to understand not only the horizontal wind characteristics, but the vertical components as well, as they will affect turbine performance and aerodynamic loads. Wind shear — the variation of wind speed with height — can often lead to a large differential in speed between the bottom and top of the rotor. This can result in uneven loading on the rotor and drive train of a turbine.

Wind speeds throughout the rotor plane and the propensity for turbulence at higher elevations are factors to consider when designing a wind project, and the forces at work on a turbine need to be understood as accurately as possible. Remote sensing can help a wind project developer better understand the wind speeds affecting the entire rotor plane, which is often well above where met tower measurements are available.

Accurate measurements across the rotor plane may soon be required to comply with the forthcoming version of the International Electrotechnical Commission standard for power performance measurement techniques. This is likely to define the performance of a turbine by integrating the wind-shear profile across the rotor plane.

An example of the value of remote sensing on energy production and turbine loading can be observed in forested

terrain (see diagram, below left). Met-tower measurements might indicate a very high wind shear value because of the roughness of the land around the project. So, without remote sensing, the energy production might be significantly overestimated. Wind turbine manufacturers use the wind shear value to estimate the physical loads that will be placed on the turbine. If a high shear value is reported, the manufacturer may require a smaller rotor diameter to control the physical loads on the machine, resulting in lower power productivity over a given period of time — a reduced capacity factor. In this case, remote sensing equipment could help prevent significant underperformance at the plant, caused by inappropriate wind resource assessment and turbine choice.

More uncertainty with heightAlthough wind shear is a primary driver for uncertainty in energy-production estimates and turbine loading, other factors come into play as hub heights and rotor diameters grow. These include directional shear (veer), inclined flow, turbulence and extreme winds. It is not just the mean values for these parameters that are important, but also their spatial range and distribution over time periods. Additionally, episodic events, such as low-level jets (a fast-moving ribbon of air in the low atmosphere, common in the Midwest and eastern US), may be the defining design factors for some sites.

Clearly, the entire wind resource assessment process must evolve to keep pace with the move towards larger hub heights, rotor diameters and project sizes. Developers, meteorological consultants and manufacturers need to work closely together to ensure intelligent design of a site’s wind analysis, careful implementation, regular maintenance, sophisticated modelling, and rigorous energy-production estimates and turbine-loading calculations. By collecting high-quality data and using it effectively, the value of each project can be increased and clean energy brought to the customer at the lowest-possible cost.

Daniel Bernadett is chief engineer, Julien Bouget is senior engineer and James Perry is manager of project engineering at AWS Truepower, formerly AWS Truewind

Remote sensing is cleaReRWithin a forested area, the variations in wind speed at tall turbine hub heights are significant; these are not captured from lower-level meteorological mast calculations

“Remote sensing could prevent significant under-performance caused by inappropriate wind resource assessment and turbine choice”

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