The North Sea will play a key role in providing clean and secure energy for Europe. This not only requires the development of new offshore wind farms, but also their successful integration into the onshore system. In this work we analyze and compare three key integration options and their preferred siting (onshore vs. offshore): grid expansions, electricity storage, and the production, storage and transport of low-carbon hydrogen. We focus on their potential to reduce emissions and energy system costs – individually and in combination with each other. Additionally, we study the consequences of constraints on their implementation. We analyze the years 2030 and 2040, starting from the projections of installed energy infrastructure and demand from the Ten Year Network Development Plan (TYNDP) 2022 of the European Network of Transmission System Operators (ENTSO-E). Results show that cross-border electricity grid expansions across the North Sea are a no-regret measure, resulting in significant reductions in system costs and emissions compared to national grid expansions. By comparison, the production, storage and transport of hydrogen have a lower cost and emission reduction potential. In both the short and long term (2030 and 2040), electricity storage can help to reduce emissions, but it is not cost competitive unless emission reduction targets are enforced. Combining the three integration measures at optimal capacities provides additional benefits. Overall, the highest emission reductions can be achieved by combining electricity storage with an expansion of the grid, while the highest economic benefits can be achieved with a combination of grid expansions and hydrogen production for direct use in industry.
Floating offshore wind (FOW) pre-feasibility studies typically separate resource-based siting from operation and maintenance (O&M) assessment. This study tests whether candidate-site attractiveness changes when uncertainty in data-driven ranking and metocean-limited serviceability is propagated from spatial screening to maintenance routing while service workload is held constant. An auditable screening-to-operations framework is evaluated across 20 Spanish coastal areas, combining constrained geospatial screening, spatial out-of-fold surrogate validation, and metocean-aware routing; relative fatigue demand is retained only as an uncalibrated screening proxy. Across 60 area–layout cases, loss-adjusted net annual energy production (AEP) ranged from 0.087 to 2.169 TWh/yr, with gross-to-net reductions of 11.1–41.6%. Under the uniform eight-sector directional weighting adopted for screening, energy/wake-aware layouts achieved the highest mean net AEP (1.302 TWh/yr), whereas O&M-friendly layouts reduced mean turbine-to-port distance to 58.63 km, indicating an energy–maintainability trade-off under the adopted directional reference. ExtraTrees and LightGBM achieved median spatial out-of-fold R2 values of 0.944 and 0.926 for capacity factor, respectively, while the median Top-30 overlap between direct-raster and surrogate rankings was 0.20, showing that predictive accuracy does not ensure shortlist stability. Routing did not reduce service coverage; instead, weather-limited accessibility governed serviceability. Under the baseline uniform wave-height sampler, serviceability decreased from 91.82% in calm conditions to 50.79% in stormy conditions, while a mean-matched Rayleigh-type sensitivity showed that the assumed wave-height distribution can change expected serviceability by at most 8.61 percentage points. These findings show that spatial ranking robustness and weather-limited maintainability materially affect early FOW screening and should be considered before detailed design and operational planning.
