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1Fix the driver behind crashes, sound loss and screen glitches2Clear out junk files and repair common Windows errors3Scan for outdated or missing drivers - takes under a minuteDo not choose turbines from a single average wind-speed figure. Before construction, run a standards-based measurement campaign with a calibrated meteorological mast, primary and backup sensors, and 10-minute records at several heights. The International Electrotechnical Commission’s IEC TS 61400-28:2025 recommends at least six months of measurements, extending to at least 12 months when seasonal variation materially affects the site. Add verified LiDAR or SoDAR when you need hub-height or spatial coverage that a mast cannot provide. Then model conditions at every proposed turbine position, quantify uncertainty, and compare the results with the selected turbine’s certified design limits.
This process answers three separate questions: how much wind energy is available, how the wind changes with direction and height, and whether turbulence, extreme winds, wakes, air density and flow inclination are within the chosen turbine’s design envelope.
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What you must measure before committing to a wind farm
A viable project assessment combines direct observations, quality control, long-term correction and turbine-specific engineering. Mean wind speed is only one output. A credible campaign also produces:
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- Wind-speed frequency distributions and a wind rose showing directional occurrence.
- Air density from temperature, pressure and, where useful, relative-humidity measurements.
- Vertical wind shear and directional veer between measurement levels.
- Turbulence intensity, reported by wind direction and wind-speed range.
- Extreme wind statistics, up-flow or flow inclination, icing indicators and rejected sectors.
- Wake effects from existing or planned turbines and distortion from terrain, trees, buildings and ridgelines.
- An uncertainty budget covering instruments, data recovery, flow modelling, long-term correlation and extrapolation.
There is no universal average-wind-speed or turbulence pass/fail value that applies to every turbine and terrain combination. The final decision uses the measured and modelled site conditions against the selected turbine’s certified site-suitability and design requirements, together with the applicable national implementation of IEC standards and any lender or insurer requirements.
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Start with a site and measurement plan
Map terrain and aerodynamic influences
Before placing equipment, document slopes, ridges, escarpments, valleys, tree lines, buildings, power infrastructure, existing turbines and likely wake directions. Mark sectors in which a mast, tower, nacelle, tree canopy or structure could distort the flow. A mast location should represent the proposed turbine area rather than merely being easy to access.
Use topographic mapping and a field inspection to identify whether one mast can represent the whole project. Complex terrain, rapid elevation changes or multiple ridges often require more than one measurement point or a combination of mast and remote sensing. Record the coordinates and elevations of all candidate turbine positions, because the later flow model will need those exact inputs.
Define the measurement objectives
Write down the hub height and rotor diameter being considered, the number of proposed turbines, the expected dominant wind sectors and the questions the campaign must answer. If the turbine model is not selected, plan for a measurement height near the likely hub height and enough vertical levels to resolve shear. A campaign designed only for a low-level average can leave a developer without the evidence needed to certify a taller machine.
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Choose representative locations
Place a primary mast where its exposure is representative of the project’s wind climate and where sectors can remain unobstructed. A second mast, roaming LiDAR or SoDAR may be needed to capture a separate ridge, a different elevation band or a spatially variable flow field. Keep a site log describing nearby changes such as new construction, forestry work or turbine erection; those changes can invalidate an otherwise clean time series.
Instrumentation: mast, LiDAR and SoDAR
A conventional campaign uses a meteorological mast with calibrated cup anemometers (or another accepted anemometer type), wind-direction vanes, a data logger and mounting hardware. Install primary and backup anemometers so a failed sensor does not create an unmeasured period. Add temperature and pressure sensors, and relative humidity where air-density calculations or icing analysis require them.
Ground-based or roaming LiDAR and SoDAR can complement a mast by measuring several heights, reaching planned hub height directly or sampling multiple turbine locations. Their suitability, calibration or verification method, availability and uncertainty must be demonstrated for the terrain and atmospheric conditions in which they will operate. A remote-sensing unit is not automatically interchangeable with a calibrated mast.
| Criterion | Met mast | LiDAR | SoDAR |
|---|---|---|---|
| Direct hub-height coverage | Requires a sensor mounted at or near hub height; multiple levels are practical on a tall mast. | Can sample several heights, including hub height, from ground level when conditions and device suitability permit. | Can profile several heights from the ground; performance depends on acoustic propagation and atmospheric conditions. |
| Spatial flexibility | Fixed at one location; moving it creates a new campaign and a new reference. | Roaming units can cover multiple proposed positions; fixed units provide continuous profiling at one point. | Can be moved between locations, but each deployment needs its own quality checks. |
| Terrain sensitivity | Mechanical flow distortion, mast shadow and local obstacles must be screened by sector. | Complex terrain, aerosols, precipitation and low signal-to-noise conditions can affect retrievals; suitability must be demonstrated. | Terrain, background noise and atmospheric stability can affect acoustic returns; suitability must be demonstrated. |
| Calibration or verification burden | Use traceable sensor calibration records and inspect alignment, boom geometry and logger settings. | Verify against a suitable reference, normally a calibrated mast or accepted comparison procedure, and document retrieval quality. | Verify against a suitable reference and document operating conditions and rejected data. |
| Uptime and failure modes | Watch for icing, sensor faults, battery or logger failures, cable damage and shadow sectors. | Watch for power loss, precipitation or aerosol limitations, obstructions and periods without valid retrievals. | Watch for acoustic noise, precipitation, power loss and periods without valid retrievals. |
| Campaign cost | Not stated in IEC TS 61400-28:2025 or MEASNET Site Assessment Procedure V2.0; depends on height, access, foundation and service scope. | Not stated in those documents; depends on rental or ownership, verification, transport and deployment duration. | Not stated in those documents; depends on equipment, verification, transport and deployment duration. |
| Uncertainty | Driven by calibration, mounting, flow distortion, data recovery and extrapolation to other positions or heights. | Includes device retrieval uncertainty, verification, atmospheric limitations and model transfer between locations. | Includes acoustic retrieval uncertainty, verification, atmospheric limitations and model transfer between locations. |
Consumer handheld meters are not equivalent to a bankable resource campaign. They generally lack the calibrated, redundant, weather-protected installation and continuous logging needed to produce defensible 10-minute statistics.
How long should measurements run?
IEC TS 61400-28:2025 recommends measurements at 10-minute intervals for at least six months before wind-farm installation. Extend the campaign to at least 12 months when seasonal variation is significant. Six months can support early screening and design work, but it may miss a seasonal regime that changes the wind distribution, turbulence or icing exposure.
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| Campaign length | What it can support | Main limitation |
|---|---|---|
| At least six months | Minimum planning period recommended by IEC TS 61400-28:2025 when the available seasons are representative enough for the project’s decision. | May not contain all seasonal regimes; long-term correlation and uncertainty are more important. |
| At least 12 months | Captures a complete annual cycle. MEASNET notes that 12 complete months means long-term extrapolation is not necessary for turbulence intensity. | One year is still a single realization of weather; energy-yield work may need correlation with a longer reference record. |
| More than 12 months | Improves coverage of unusual seasons, icing periods and extreme-wind observations and can reduce correlation uncertainty. | Additional time and operating cost; it does not remove instrument or flow-model uncertainty. |
If the on-site record is shorter than the long-term reference needed for energy assessment, use a documented measure-correlate-predict procedure. State the reference station or dataset, overlap period, screening rules, regression or other correlation method, and the resulting uncertainty. Do not present a long-term-corrected or modelled hub-height value as if it were a direct observation.
Install sensors at useful heights
Put the primary wind measurement level at least two-thirds of the planned hub height where practicable. Include a sensor at hub height when the equipment and site plan allow it. Multiple levels are essential for estimating vertical shear and detecting whether a local flow profile is being distorted by terrain or obstacles.
Mount paired anemometers at the key levels when possible. A backup channel lets you identify a failed primary sensor and compare the two series. Install wind vanes at appropriate levels and keep their alignment records. Record mast geometry, boom orientation, sensor serial numbers, calibration dates, mounting heights and logger configuration in a permanent installation file.
Set the logger to produce 10-minute summaries, retaining the underlying measurements when the system supports them. Each interval should include mean wind speed, standard deviation, direction statistics and valid-sample counts; the exact fields should be defined before deployment so later processing is consistent.
Collect and quality-check the data
Protect data availability
Check the logger and communications routinely, maintain power and inspect the mast after severe weather. Track missing intervals, flat-lined sensors, implausible jumps, time-stamp errors and disagreement between primary and backup instruments. Keep raw files unchanged and create a separate, versioned processing stream for quality flags and exclusions.
Reject known distortions
Identify mast-shadow sectors from the mast geometry and sensor placement. Flag icing, heavy precipitation, sensor contamination, cable faults and periods in which a remote-sensing device reports poor retrieval quality. A wind-direction sector affected by a tree, building or neighboring turbine should be excluded or corrected only with a documented method. Do not silently fill rejected intervals.
Check calibration and traceability
Keep calibration certificates, laboratory or field comparison records, installation photographs and maintenance logs. For LiDAR or SoDAR, retain the reference comparison, device status files and the criteria used to accept or reject each retrieval. Traceability matters because a precise-looking time series without a defensible calibration chain can still carry large uncertainty.
Calculate wind speed, distribution and turbulence
Mean wind and frequency distribution
Calculate mean wind speed at every measurement level and for each accepted direction sector. Produce a wind rose showing how frequently the wind arrives from each direction. Fit a wind-speed distribution, such as a Weibull representation where appropriate, but preserve the measured histogram as the primary record. Energy production depends on the full distribution and the turbine power curve, not only on the mean.
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Air density, shear and veer
Use temperature and pressure observations to calculate air density for the same intervals as wind speed. Report the vertical shear profile between sensor levels and the change in direction with height (veer). Shear and veer affect rotor loading, wake interaction and the validity of transferring a measurement from one height or location to another.
Turbulence intensity equation
For each 10-minute interval, MEASNET defines turbulence intensity as:
I = σv / Vmean × 100
Here, σv is the standard deviation of wind speed within the 10-minute interval and Vmean is the mean wind speed for that interval. Report the result as a percentage, retain the interval-level inputs and state how calm or invalid intervals were handled. A very small mean speed can make the ratio unstable, so the project’s processing specification should define valid speed ranges and exclusions.
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MEASNET Site Assessment Procedure V2.0 calls for turbulence results by 30-degree wind-direction sectors and 1 m/s wind-speed bins when enough data exist. Build a matrix for each measurement height and, after modelling, for each proposed turbine position at hub height. Include the number of valid intervals in every sector-and-bin cell; sparse cells should be marked as data-limited rather than treated as equally certain.
Include extremes and flow inclination
Estimate extreme wind conditions using the applicable site-assessment method and reference period. Report up-flow or flow inclination where terrain makes it relevant. Include icing exposure, if applicable, because ice can alter measured wind speed, turbulence, power production and component loads. These variables are part of the site-suitability comparison even when the average wind resource appears attractive.
Transfer measurements to every turbine position
Use a documented flow model
The mast and remote-sensing units measure at specific points. A flow model transforms those observations to each proposed turbine coordinate and hub height. Document the model type, terrain and roughness inputs, obstacle treatment, wake assumptions, calibration data, stability treatment where relevant, and the uncertainty assigned to the transfer.
Do not copy one mast’s hub-height value to every turbine. Ridges, slopes, forests and buildings can create speed-up, separation, channeling or directional changes over short distances. The model should be checked against independent measurements whenever possible.
Perform site calibration in complex terrain
IEC 61400-12-1:2017 Annex C describes site calibration for quantifying the relationship between an upwind reference mast or LiDAR and a proposed turbine location. One documented approach combines a short mast at the target location with roaming LiDAR. The calibration period, concurrent data, direction sectors, regression or transfer method and uncertainty must be reported. Site calibration is a way to measure the relationship; it is not a license to hide a poor-quality reference record.
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Separate observation from extrapolation
Label every result as a direct measurement, a height extrapolation, a spatial flow-model output or a long-term-correlated estimate. Carry the corresponding uncertainty into energy-yield and load calculations. This distinction prevents a modelled value from being mistaken for a sensor reading and makes later reviews by engineers, lenders or certification bodies possible.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Compare the site with turbine design conditions
Once the site dataset and model are complete, obtain the selected turbine’s certified site-suitability limits. Compare, for each position:
- Hub-height mean wind and the complete wind-speed distribution against the turbine power and load assumptions.
- Turbulence intensity by direction and speed against the turbine’s turbulence design envelope.
- Extreme wind estimates against the applicable design class and certification limits.
- Vertical shear, veer and flow inclination against the turbine’s allowable conditions.
- Air density, temperature range and icing conditions against operating and structural requirements.
- Wake exposure from existing and proposed turbines, including directional dependence and uncertainty.
A site can have a strong average wind resource and still require a different turbine class, a changed layout, operating restrictions or additional measurement. Conversely, a lower mean wind speed can be viable with a suitable turbine and sound financing assumptions. The pass/fail decision belongs to the turbine-specific certification and project engineering, not to a universal headline number.
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- Screen the area. Map terrain, obstacles, vegetation, existing turbines, likely wakes and flow-distortion sectors. List all proposed turbine coordinates and elevations.
- Choose representative measurement points. Select mast, LiDAR and SoDAR locations that cover the project’s distinct terrain and expected hub heights.
- Specify instruments. Use calibrated primary and backup anemometers, wind vanes, a configured logger and any required temperature, pressure and humidity sensors. Define remote-sensing verification before deployment.
- Install and document. Place the primary level at least two-thirds of planned hub height where practicable, add several levels and include hub-height observations when possible. Record geometry, calibration and serial numbers.
- Configure 10-minute records. Store mean speed, standard deviation, direction, valid counts and status flags. Preserve raw data and synchronized time stamps.
- Operate and inspect. Monitor communications, power, icing, sensor disagreement, mast shadow and remote-sensing retrieval quality. Log every intervention.
- Run quality control. Flag missing, duplicated, implausible or distorted intervals. Apply documented sector and icing rules without overwriting raw files.
- Calculate resource statistics. Produce wind roses, distributions, density, shear, veer, turbulence, extremes, up-flow, wakes and uncertainty.
- Meet the duration target. Operate for at least six months, extending to at least 12 months where seasonal variation is significant. Correlate shorter records with a documented long-term reference.
- Calibrate complex sites. Use IEC 61400-12-1:2017 Annex C methods when a reference-to-target relationship must be established in complex terrain.
- Model every position. Transfer the measurements to hub height and each turbine coordinate, reporting uncertainty and distinguishing model outputs from observations.
- Make the turbine decision. Compare all site conditions with the selected turbine’s certified design and site-suitability limits before final layout, procurement or construction.
Common mistakes and how to correct them
Using one short, low-level reading
Problem: A few weeks from a handheld or low-mounted sensor cannot represent seasonal wind, hub-height shear or turbulence.
Correction: Deploy calibrated, redundant instrumentation, measure at useful heights and meet the six-month minimum, extending to 12 months when seasonal effects matter.
Reporting only an average wind speed
Problem: A single mean hides direction, speed distribution, turbulence, extremes, density and wakes.
Correction: Produce the full variable set and retain sector-and-speed counts so engineers can assess loads and energy separately.
Treating LiDAR or SoDAR as automatically valid
Problem: Remote sensing can lose data or bias results in precipitation, low signal, noise or complex flow.
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Correction: Verify the unit against a suitable reference, document retrieval-quality rules and carry device uncertainty into the flow model.
Ignoring mast shadow and icing
Problem: Distorted sectors or iced sensors can bias wind speed and turbulence.
Correction: Map affected sectors, inspect equipment, flag or reject invalid intervals and explain every correction.
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Presenting modelled values as observations
Problem: Reviewers cannot tell which values were measured and which were extrapolated.
Correction: Label direct, height-transferred, spatially modelled and long-term-correlated results separately, with an uncertainty budget for each.
Applying a universal turbulence limit
Problem: Turbine design classes and certification limits differ, and terrain changes the flow field.
Correction: Compare the site’s 30-degree-sector, 1 m/s-bin turbulence results with the selected turbine’s certified requirements.
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Pre-construction checklist
- Terrain, obstacles, wakes and measurement sectors mapped.
- Representative mast and remote-sensing locations selected.
- Calibration certificates and backup sensors in place.
- Primary level near hub height and multiple vertical levels installed.
- Logger configured for 10-minute summaries with synchronized time.
- Data availability, icing, mast shadow and sensor-failure rules documented.
- At least six months collected, with a 12-month target where seasonal variation is significant.
- Wind rose, distribution, density, shear, veer, turbulence, extremes, inclination and wakes calculated.
- Turbulence reported by 30-degree direction sector and 1 m/s speed bin where data support it.
- Short records correlated to a long-term reference with quantified uncertainty.
- Complex-terrain site calibration completed where needed.
- Flow-model outputs generated for every proposed turbine position and clearly separated from observations.
- Measured and modelled conditions checked against the selected turbine’s certified site limits.
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