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Before committing to turbine models, foundations, or grid work, run a standards-based wind-resource campaign at the proposed site. A calibrated meteorological mast with primary and backup anemometers, wind vanes, several measurement heights, and 10-minute records is the normal reference system. Ground-based or roaming LiDAR and SoDAR can add hub-height or spatial coverage when their calibration and uncertainty are demonstrated.
The campaign must do more than produce an average wind speed. It should characterize direction, speed distribution, air density, vertical shear, turbulence, extreme winds, veer, up-flow, wakes, data quality, and uncertainty at every proposed turbine position. Final viability is turbine-specific: compare those conditions with the selected machine’s certified design and site-suitability limits rather than applying a universal wind-speed or turbulence pass/fail number.
What the measurement campaign must establish
A wind-farm decision needs two linked answers. First, what wind conditions actually occur at the measurement locations? Second, how do those conditions change at hub height and at each planned turbine position? A single handheld reading or a short fair-weather survey cannot answer either question reliably.
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- Document terrain, ridges, slopes, trees, buildings, existing turbines, wakes, and sectors likely to distort flow.
- Measure with calibrated instruments, retain calibration certificates, and maintain backup sensors so a single failure does not erase a season.
- Record 10-minute statistics at multiple heights, including a level near planned hub height whenever practical.
- Screen and flag icing, mast shadow, sensor failures, missing records, and other rejected sectors.
- Model the flow from measurement points to every proposed turbine location and report the uncertainty of that transformation.
- Compare measured and modeled conditions with the chosen turbine’s certified limits for turbulence, shear, extreme winds, air density, and flow inclination.
The output is therefore a site-assessment data set and an uncertainty statement, not simply a headline average wind speed.
Plan the site survey before buying equipment
Map the physical influences
Start with a map of the entire project area and its upwind surroundings. Mark ridgelines, escarpments, steep slopes, valleys, forest edges, buildings, transmission structures, existing turbines, and likely wake directions. Note which sectors could accelerate, separate, recirculate, or shade the flow. The map determines whether one mast is representative or whether several masts, remote sensors, or a site-calibration exercise are needed.
Place instruments where they represent turbine positions
A mast should not be chosen merely because it is easy to access. Place it in terrain and exposure that represent the proposed turbine array, while avoiding local obstacles that would make its flow unlike the project area. For a large or complex site, combine representative mast locations with remote sensing or additional short-term deployments so the flow model is constrained across the array.
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Decide whether the campaign is intended to support early screening, turbine selection, financing, or a construction decision. A screening deployment can identify poor areas, but a final investment decision requires calibration records, documented quality control, a modeled value at each turbine, and uncertainty that the project’s lenders and engineers can review.
Met mast, LiDAR, or SoDAR?
No instrument wins every category. The appropriate system depends on terrain, hub height, access, permitting, required spatial coverage, and the uncertainty that the project can accept.
| Criterion | Meteorological mast | Ground-based or roaming LiDAR | SoDAR |
|---|---|---|---|
| Direct hub-height coverage | Direct when a sensor is installed at hub height; otherwise requires vertical extrapolation. | Can sample hub height and several levels without a tall structure, subject to device range and site conditions. | Can provide profiles above ground, but performance depends strongly on atmospheric and acoustic conditions. |
| Spatial flexibility | Fixed point; moving or adding a mast requires physical work. | High flexibility for scanning multiple turbine positions or supplementing a reference mast. | Flexible deployment, with site suitability needing verification. |
| Terrain sensitivity | Terrain can distort flow around the tower and sensors; careful sector screening is required. | Complex terrain, vegetation, precipitation, and atmospheric conditions can affect retrievals. | Terrain, background noise, temperature structure, and wind conditions can affect acoustic returns. |
| Calibration and verification burden | Use traceably calibrated anemometers and vanes, retain records, and check mast and sensor installation. | Verify against a suitable reference and document device configuration, availability, and uncertainty. | Verify against a suitable reference and document the same evidence before relying on the profile. |
| Redundancy and uptime | Primary and backup anemometers, duplicate direction measurements, robust logging, and icing controls improve availability. | Requires power, communications, clear operating conditions, and checks for data dropouts or retrieval flags. | Requires reliable power and acoustic operating conditions; noise and atmospheric effects can reduce usable data. |
| Best use | Reference measurements and long-term traceability. | Adding height or spatial coverage, including roaming surveys. | Supplementary profiling where suitability and uncertainty are demonstrated. |
A mast campaign normally remains the reference for traceability. LiDAR or SoDAR is an accepted complement when its measurements are verified against a suitable reference and its uncertainty is carried into the assessment. A consumer handheld meter is not equivalent to a calibrated, redundant campaign system that produces 10-minute statistics.
Install and calibrate the measurement system
Core mast equipment
Use calibrated cup anemometers or another accepted anemometer type, with at least one backup wind-speed sensor. Install wind-direction vanes at appropriate levels and connect all channels to a data logger configured for 10-minute summaries. Depending on the assessment, add temperature, pressure, and relative-humidity sensors so air-density corrections and weather-related data screening are possible.
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Calibration records and configuration control
Keep the calibration certificate, serial number, calibration date, calibration method, mounting geometry, boom orientation, logger settings, firmware or configuration version, and installation photographs. Record every sensor change in a field log. The evidence should allow an independent reviewer to determine which instrument produced each interval and whether a replacement altered the data series.
Remote-sensing verification
Before using LiDAR or SoDAR values in a turbine decision, verify the device against a suitable reference at the site or in a demonstrably comparable configuration. Check agreement by height and sector, data availability, retrieval flags, and the conditions under which the device fails or becomes biased. Treat the verification result as part of the uncertainty budget rather than as a one-time pass/fail label.
Choose heights, sampling, and campaign duration
Measurement heights
Put the primary measurement level at least two-thirds of the planned hub height where practicable. Include multiple levels to resolve vertical shear, and measure directly at hub height when the equipment and site plan allow it. Multiple heights reveal whether a simple power-law or other flow model is plausible and help identify changing wind profiles between stable and unstable conditions.
Sampling interval
Store 10-minute summaries. Each interval should retain the statistics needed for wind-speed distribution and turbulence analysis, including mean speed and standard deviation, alongside direction and quality flags. Higher-frequency internal sampling may be used by the logger to calculate those summaries, but the project record must preserve the 10-minute products used in the assessment.
How long to measure
IEC TS 61400-28:2025 recommends at least six months of measurements before wind-farm installation. Extend the campaign to at least 12 months when seasonal variation materially affects the site. A complete year captures all seasons directly; MEASNET’s Site Assessment Procedure V2.0 states that 12 complete months means long-term extrapolation is not necessary for turbulence intensity. That statement concerns the turbulence metric, not every long-term energy-yield question.
If the on-site record is shorter than the available long-term reference, use a documented measure-correlate-predict procedure. Explain the reference data, correlation period, exclusions, model, and uncertainty; do not present a long-term-adjusted value as if it were a direct observation.
Quality-control every interval
Raw data are useful only after systematic screening. Build automated checks and review exceptions manually:
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- Calculate data availability by sensor, height, day, month, and direction sector.
- Flag impossible or out-of-range values, flat-lined channels, timestamp errors, logger resets, and communication gaps.
- Identify icing and precipitation effects, especially when anemometers disagree or remain at implausibly low values.
- Apply a documented mast-shadow treatment based on boom geometry and wind direction; do not silently delete sectors.
- Compare primary and backup anemometers for persistent offsets, intermittent failures, and changes after maintenance.
- Check wind-vane alignment, stuck directions, abrupt discontinuities, and disagreement between redundant direction channels.
- Record every rejected sector and the reason for rejection so modeled results can be reproduced.
Do not fill a failed sensor with an unexplained substitute. If a replacement is necessary, mark the transition, preserve both calibration records, and test overlap where possible. Report the resulting availability and explain whether missing data could bias a seasonal or directional result.
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Calculate wind resource and turbulence
Wind-speed statistics
Produce the mean wind speed at each measurement height, a wind-direction frequency plot (wind rose), and a wind-speed distribution. A Weibull fit can summarize that distribution, but retain the measured histogram because a fitted curve can hide directional or multimodal behavior. Calculate air density from the measured atmospheric variables when available, since density affects turbine power and load interpretation.
Vertical and directional flow
Estimate vertical shear from simultaneous levels and examine how it changes by direction and atmospheric condition. Calculate veer, the change in wind direction with height, and up-flow, the vertical inclination of the wind. Identify wake-affected sectors from existing or proposed turbines and keep those sectors separate from free-stream conditions used for turbine suitability.
Turbulence intensity
For each 10-minute interval, MEASNET defines turbulence intensity as:
I = σv / Vmean × 100
Here, σv is the standard deviation of wind speed during the interval and Vmean is its mean wind speed. The result is a percentage. Preserve the underlying interval values and quality flags so unusual turbulence can be traced to a sector, speed range, sensor issue, wake, or weather event.
Extreme conditions
Estimate extreme winds using the project’s accepted method and reference period, and state the assumptions. The extreme-wind result, ordinary turbulence, shear, air density, veer, and up-flow are separate checks; a site with a favorable average wind speed can still exceed a turbine’s load or flow-inclination limits.
Report turbulence by sector and speed
Aggregate turbulence in the resolution needed for turbine comparison. MEASNET specifies 30-degree wind-direction sectors and 1 m/s wind-speed bins when enough observations are available. Report values at the measurement height and at modeled hub height for each proposed turbine position, with the sample count, data availability, rejected sectors, and uncertainty attached to every important result.
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Do not merge all directions into one site-wide turbulence number when terrain or wakes create strong directional differences. A turbine may face a benign free-stream sector for much of the year but experience higher turbulence from a ridge, forest edge, building, or neighboring turbine in another sector. The directional table and wind rose should make those conditions visible to the turbine engineer.
Transform measurements to every turbine position
Flow modeling
Use a documented flow model to convert mast or remote-sensing observations into wind speed, direction, shear, turbulence, and flow inclination at each planned turbine. Describe the terrain model, roughness assumptions, stability treatment if used, wake treatment, calibration points, and the sectors excluded from fitting. Modeled hub-height values are estimates; label them as such rather than calling them observations.
Short campaigns and long-term correlation
When the on-site campaign does not cover the relevant long-term variability, correlate it with a suitable long-term reference. State the concurrent period, reference location, correlation method, filtering, regression or other model, and resulting uncertainty. Test whether the relationship is stable by season and direction. A strong correlation during one weather regime does not automatically prove that the relationship holds for the whole record.
Complex-terrain site calibration
IEC 61400-12-1:2017 Annex C provides a site-calibration approach for quantifying the relationship between an upwind reference mast or LiDAR and a proposed turbine location. One documented arrangement combines a short mast with roaming LiDAR. Use this approach when terrain complexity makes ordinary extrapolation unreliable, and report the calibration residuals and uncertainty rather than only the adjusted wind speed.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Compare the site with the selected turbine
There is no universal average-wind-speed threshold or turbulence percentage that proves every site is viable. Acceptance depends on the turbine type, design class, terrain, wake environment, air density, extreme winds, financing requirements, and the national implementation of applicable IEC standards.
For each candidate turbine, obtain the certified site-suitability and design limits, then compare them with the site assessment:
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| Site quantity | What to compare | Why it matters |
|---|---|---|
| Mean speed and speed distribution | Modeled hub-height distribution and directional frequency versus the turbine power and load assumptions. | Determines expected production and operating exposure; mean speed alone is insufficient. |
| Turbulence intensity | 30-degree sector and 1 m/s bin values against the turbine’s permitted turbulence conditions. | Affects fatigue loads and may vary sharply by direction, speed, terrain, or wake. |
| Vertical shear | Measured multi-level profile and the turbine’s design assumptions. | Changes rotor loading and the relationship between mast height and hub height. |
| Extreme winds | Site extreme-wind estimates against the certified design limits and reference period. | Controls survival and structural load requirements. |
| Air density | Measured or modeled density range against the turbine’s operating and load envelope. | Changes power output and aerodynamic loading. |
| Veer and up-flow | Directional change with height and flow inclination by sector. | Can affect rotor alignment, loads, and the validity of simple flow assumptions. |
| Wakes and complex flow | Wake sectors and terrain-calibration uncertainty against the turbine layout and spacing. | Determines whether a nominally suitable turbine position is exposed to additional turbulence or reduced wind. |
If a condition exceeds a certified limit, the remedy may be a different turbine class, a revised layout, additional site calibration, operational restrictions, or abandoning that position. It is not scientifically defensible to declare the site viable by comparing only its annual mean speed with a generic rule of thumb.
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A practical end-to-end procedure
- Screen the area. Map terrain, roughness, obstacles, existing turbines, wakes, and distorted-flow sectors; mark proposed turbine positions.
- Design the network. Select mast and remote-sensing locations that represent the array and define the heights, redundancy, communications, power, access, and maintenance plan.
- Calibrate and install. Fit calibrated primary and backup anemometers, wind vanes, logger, and needed atmospheric sensors; document geometry, orientation, and certificates.
- Verify remote sensors. Compare LiDAR or SoDAR with a suitable reference and record retrieval flags, availability, sector performance, and uncertainty.
- Collect 10-minute records. Include several heights, with the primary level at least two-thirds of planned hub height where practicable and direct hub-height data when possible.
- Maintain the site. Inspect sensors, icing protection, power, communications, tower hardware, and vegetation or construction changes; log every intervention.
- Quality-control the series. Screen failures, icing, mast shadow, stuck vanes, implausible values, and missing data; preserve rejected records and reasons.
- Compute the resource. Produce mean speed, wind rose, distribution, air density, shear, turbulence, extreme winds, veer, up-flow, wakes, availability, and uncertainty.
- Model every position. Apply a documented flow model and, in complex terrain, consider IEC 61400-12-1:2017 Annex C site calibration.
- Correlate when necessary. Use measure-correlate-predict for short records against a suitable long-term reference and quantify the added uncertainty.
- Check turbine suitability. Compare each modeled position and sector with the selected turbine’s certified turbulence, shear, extreme-wind, density, and flow-inclination limits.
- Issue a decision report. State the usable data fraction, exclusions, assumptions, uncertainty, limitations, and whether more measurement or a layout change is required.
Common mistakes and how to correct them
Using a single sensor without redundancy
A failed anemometer can remove the very season needed to judge the site. Add a backup speed sensor and redundant direction measurement, and compare channels continuously.
Measuring only at 10 meters
A low-level reading may not represent a modern turbine rotor. Add multiple heights and place a primary level near hub height, subject to practical and structural constraints.
Stopping after a few weeks
Short records can miss seasonal regimes and unusual directions. Treat them as screening evidence unless a documented correlation and uncertainty analysis supports a broader conclusion.
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Flow-model outputs at hub height or unsampled turbines contain model uncertainty. Label them as modeled, show calibration evidence, and carry residual uncertainty into the turbine decision.
Reporting one turbulence number
Directional terrain effects and wakes can be hidden by an all-sector average. Use the required direction-sector and speed-bin resolution when data volume permits, and show sample counts.
Ignoring data quality and rejected sectors
Deleting icing, mast-shadow, or failure periods without a log makes the result impossible to audit. Keep an exclusion register and explain how each omission affects representativeness.
Applying a generic viability threshold
Wind speed and turbulence limits belong to a specific turbine design and site condition. Use the certified requirements for the actual machine and include extreme winds, density, shear, veer, up-flow, and wakes.
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What evidence supports a build decision?
A project is ready for final turbine and construction decisions only when the evidence chain is complete: representative measurement locations, calibrated and redundant instruments, adequate duration, 10-minute records, documented quality control, directional turbulence statistics, a transparent flow model, long-term correlation where needed, and uncertainty at every proposed turbine position.
The final engineering review should be able to trace any reported hub-height value back to the measured sensors, rejected sectors, model assumptions, and calibration evidence. If a key season is missing, a remote sensor has not been verified, or complex terrain is uncalibrated, the responsible action is to extend or redesign the campaign rather than infer certainty from an attractive average wind speed.
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