Offshore wind production estimates can vary by up to 15 GW depending on turbine design, weather data and wake effects, with major implications for energy planning and investments.
How turbines and climate data reshape offshore wind production forecasts
Offshore wind production can be overestimated or underestimated by as much as 15 GW when models change turbine characteristics, baseline meteorological data and the way wind wakes are simulated.
This is the key finding of a study published in Wind Energy Science, focusing on the North Sea and highlighting how strongly technical parameters influence electricity generation forecasts.
For Europe’s energy system, this issue is strategic. Errors of this magnitude affect investments, grid infrastructure, auctions and industrial planning. The study shows that the largest differences depend on the type of wind turbine installed, while atmospheric conditions and wake interactions between nearby wind farms also play a critical role.
Researchers therefore call for more realistic models to estimate future offshore wind growth, a point increasingly relevant also for emerging markets, including parts of Africa where offshore wind is still at an early stage.
The North Sea study and Europe’s offshore wind targets
The research was conducted by scientists from Helmholtz-Zentrum Hereon and University of Hamburg. It starts from a clear policy benchmark: countries within the North Seas Energy Cooperation aim to increase offshore capacity from 26 GW in 2022 to at least 60 GW by 2030, and up to 300 GW by 2050 in the North Sea region.
Growth on this scale implies new clusters of wind farms, stronger interactions between installations and increasing pressure on forecasting systems.
To assess the impact, researchers used the regional climate model COSMO6.0-CLM, enhanced with a dedicated wind farm module capable of simulating different turbine types, rotor diameters, hub heights and the gradual deployment of installations over time.
Wind turbines account for the largest share of uncertainty
The study finds that combined uncertainty linked to meteorological datasets and turbine type reaches around 15 GW, equal to about 10% of the simulated total capacity of 150 GW.
Of this:
- 11 GW depends on differences between turbines
- 4 GW comes from meteorological conditions used in the model
Researchers compared extreme scenarios with 3.6 MW turbines and next-generation 15 MW turbines. Even with the same total installed capacity, larger turbines generate more electricity.
The reason is twofold:
- fewer machines are needed, reducing mutual interference
- larger rotors and higher hubs capture stronger and more consistent winds
In the simulation, average annual production rises from 62.6 GW with 3.6 MW turbines to 73.7 GW with 15 MW machines.
Capacity factor improves with next-generation offshore wind
The study also evaluates the capacity factor, the ratio between actual output and theoretical installed capacity.
Using ERA5 data:
- it increases from 0.42 with 3.6 MW turbines
- to 0.49 with 15 MW turbines
Without wake effects, values would reach 0.57 and 0.61 respectively.
In practical terms, a significant share of production losses is not due to wind availability but to interactions between wind farms. This directly impacts developers, utilities and grid operators, as it affects expected revenues and integration costs.
Wind wakes can extend up to 50 km
One of the most critical aspects is the wake effect. When a turbine extracts kinetic energy from the wind, it leaves behind a slower, more turbulent airflow.
If another wind farm is located downstream, it receives less available energy.
Simulations and aerial measurements show that wakes in the North Sea can extend beyond 50 km. In analyzed cases:
- wind speed deficits reach about 1 m/s immediately downstream
- vertical reductions reach 2.8–2.9 m/s, up to 45% lower than no-wind-farm scenarios
This makes the geographical layout of wind farms not just a technical variable, but an economic one.
Summer conditions are more critical for offshore wind production
The research highlights how atmospheric conditions significantly affect performance.
In summer:
- average wind speeds are lower
- the atmosphere is more stable
- natural turbulence decreases
As a result, wakes dissipate more slowly, increasing their impact on downstream turbines.
A correction of the turbulence parameter in the model reduces average production by about 2 GW, slightly over 1% of installed capacity. The relative impact is stronger in summer, when winds more often fall below the turbines’ rated power.
Why this matters for grids, auctions and investments
For Europe’s electricity market, the difference between 62 GW and 74 GW of simulated average output is substantial.
It affects:
- project valuation
- revenue forecasts
- storage sizing
- cross-border electricity flows
- grid congestion costs
If offshore wind production is overestimated, business plans may be flawed and flexibility needs underestimated. If underestimated, investments and industrial development may slow down.
This is why researchers stress the need to explicitly include wind farms in both meteorological models and historical reanalysis datasets.
What this study means for Europe and beyond
The growth of offshore wind will not depend only on permits, ports and supply chains. It will also depend on the quality of forecasting models.
With expected capacity reaching 300 GW in the North Sea, even small percentage errors can translate into tens of gigawatts.
For the next phase of the energy transition, choosing the right wind turbines and correctly planning distances between wind farms will be just as critical as installing new capacity.
