Integrating Offshore Wind and Green Hydrogen: A Systematic Review of Technological Progress and System-Level Challenges

Abstract

Offshore wind energy is emerging as a vital component of the global transition to renewable energy, leveraging consistent wind conditions and higher power density compared to onshore systems. Integrating variable offshore wind power with hydrogen production via electrolysis provides a strategic pathway to convert surplus electricity into a storable and transportable energy carrier, thereby mitigating grid congestion, curtailment, and variability challenges. This review systematically examines the integration of offshore wind farms and hydrogen production technologies. Key components of the review include a comparative analysis of electrolyzer technologies, their suitability for offshore deployment, and the implications for energy storage and transport. The analysis employs a multi-step framework: (1) extensive search of the literature in scientific databases, (2) qualitative and quantitative assessment of system performance, and (3) synthesis of findings to identify trends and research gaps, enabling a thorough examination of technical challenges in the marine environment, and economic and policy barriers. The review highlights recent advancements, technical challenges, and economic considerations related to deployment of offshore wind-to-hydrogen systems. This review provides a comprehensive understanding of the current state of offshore hydrogen production, identifies research gaps, and outlines policy recommendations to accelerate its deployment. Offshore wind-powered hydrogen emerges as a cornerstone of a resilient, low-carbon energy future. The systematic approach ensures actionable insights and robust conclusions, facilitating the alignment of technological advancements with global decarbonization goals.

1. Introduction

1.1. Background and Significance

The urgency of addressing climate change and transitioning to sustainable energy has spurred intense exploration of renewable power sources and clean energy carriers [1]. Offshore wind has emerged as a leading clean power source due to consistently strong marine winds yielding higher capacity factors than onshore turbines (often >40% in mature markets) [2]. This high availability makes offshore wind especially well-suited to continuous processes like hydrogen production. In parallel, green hydrogen, hydrogen produced via water electrolysis using renewable electricity, has gained prominence as a versatile energy carrier for energy storage and for decarbonizing hard-to-abate sectors such as transportation, heavy industry, and power generation [3,4]. By coupling abundant offshore wind resources with electrolysis, variable wind power can be converted into storable fuel (hydrogen) [5], effectively turning intermittent wind into a dispatchable energy source [6]. The escalating demand for clean energy and the pressing need to decarbonize diverse sectors have spurred significant interest in green hydrogen production [7]. Indeed, global hydrogen use is around 150 Mtons per year, yet only around 1% is produced via renewables [8].

1.2. Global Context of Offshore Wind-to-Hydrogen

Offshore wind power deployment is growing rapidly worldwide, laying the groundwork for large-scale hydrogen production at sea. The global share of installed offshore wind power capacity is dominated by China, accounting for 49% in 2022. Other significant contributors include the United Kingdom (25%), Germany (14%), and the Netherlands (5%) [9]. Global analyses highlight that heavy industries (steel, cement, chemicals) and long-distance transport (aviation, maritime, heavy trucking) account for a large share of emissions and lack easy zero-carbon alternatives [10]. The IEA similarly notes that low-emissions hydrogen can decarbonize these sectors and provide seasonal energy storage [11]. Since batteries are impractical for very long-range or high-temperature applications, green H₂ (or its carriers) offers a viable path. By linking offshore wind-to-hydrogen production, a supply of carbon-free fuel for such industries can be created, while also leveraging renewable baseload power.

Major policy initiatives in leading markets reflect this momentum. For instance, the EU has set an ambitious Offshore Renewable Energy Strategy (2020) that calls for 300 GW of offshore wind by 2050 (111 GW by 2030) [12]. Concurrently, EU climate plans aim for 10 Mt/yr of domestic renewable hydrogen production by 2030 (rising to 33 Mt by 2040) to decarbonize industry and transportation. Achieving these goals requires vast new clean power, for which offshore wind is viewed as a key ally since it can supply large additional clean power without land-use constraints. As of 2021, Europe had 25 GW of offshore wind installed [13], with many multi-GW projects under development. First-of-a-kind offshore wind–hydrogen pilots are also emerging. For instance, the HOPE project in the North Sea, with a 10 MW offshore PEM electrolyzer capacity, off Belgium, which by 2026 aims to produce 4 tons of green H₂ per day, sending it ashore via pipeline [14]. The Sealhyfe prototype has already demonstrated a 1 MW floating wind turbine with integrated hydrogen production (since 2022) [15]. Other North Sea initiatives, like Germany’s AquaVentus [16] and the proposed North Sea Wind Power Hub, similarly envision large-scale offshore H₂ “energy islands”. In sum, the EU combines high-level targets (300 GW offshore wind by 2050; 10 Mt H₂ by 2030) with pilot projects to catalyze offshore wind–hydrogen (OW2H) deployment.

Several individual countries have announced ambitious programs linking offshore wind and hydrogen. Germany is among the most active countries linking offshore wind with hydrogen, targeting 5 GW electrolyzer by 2030, doubling by 2035 [17] and has several flagship pilots, including Siemens Energy/Gamesa’s H2Mare initiative, a fully integrated Offshore Wind–Hydrogen System (OWHS) by 2026 [18]. The AquaVentus consortium plans up to 10 GW of offshore electrolyzers by 2035. Its sub-project, AquaPrimus, will integrate a 15 MW electrolyzer into the base of a 15 MW turbine at Heligoland (with hydrogen piped ashore) as a commercial-scale pilot [16]. The Netherlands plans for 3–4 GW of electrolyzer capacity by 2030 [19]. Shell’s Holland Hydrogen I (HH1) project will build a 200 MW electrolyzer near Rotterdam, fully powered by a new offshore wind farm, to produce 60,000 kg H₂ per day, which would make it Europe’s largest green hydrogen facility [20]. Meanwhile, RWE and Neptune Energy’s proposed H₂opZee project (Dutch North Sea) with 300–500 MW of offshore wind-powered electrolyzers on platforms, with all power dedicated to hydrogen production [21]. The UK’s North Sea resources and hydrogen goals have driven pioneering trials. The ERM Dolphyn consortium deployed the world’s first floating wind-to-hydrogen demonstrator off Scotland, a 2 MW floating wind turbine with onboard electrolyzer and desalination, which first produced hydrogen in mid-2024 [22], supported by UK government funding (Net Zero Innovation Portfolio) [23]. The UK’s offshore wind capacity (15 GW in 2024, targeting 50 GW by 2030 [23]) and the national Hydrogen Strategy (targeting 5 GW electrolyzers by 2030) create strong drivers for OW2H, even as these projects remain at pilot scale.

The U.S. targets 30 GW of offshore wind by 2030 [24]. Notably, the Atlantic Shores offshore wind farm (New Jersey, 1.5 GW) plans to include a 10 MW green hydrogen pilot electrolyzer to demonstrate pairing offshore wind with H₂ production [25], indicating U.S. plans to integrate offshore hydrogen pilots alongside new wind farms. Figure 1 provides an illustrative overview of the global distribution of planned and operational offshore wind-to-hydrogen projects.

In 2025, China commissioned the world’s first self-contained offshore hydrogen platform off Shandong province [26]. This large platform integrates wind (and solar) power with three electrolyzers, including a direct seawater electrolyzer to produce green hydrogen and convert it on-site into ammonia and methanol. Japan has aggressive offshore wind targets (10 GW by 2030, 45 GW by 2040) [27] and aims to expand hydrogen use (targeting 10 Mt H₂ by 2030 in its Basic Hydrogen Strategy), given a vast offshore wind potential of 9000 TWh/yr [28] and strong national carbon-neutral goals. South Korea is also rapidly scaling offshore wind (targeting 14 GW by 2030 [29]) and has a hydrogen roadmap (6.2 Mt H₂ by 2030). Australia has very strong hydrogen ambitions (seeking to become a major H₂ exporter) and is opening its waters to wind farms. In 2024, Australia approved its first offshore wind zones (12 GW capacity) [30]. The 2030 Hydrogen Strategy targets up to 15 Mt/yr H₂ (mostly for export) [31]. However, current projects focus on onshore renewables [32]. Offshore wind farms could play a big role given Australia’s excellent wind resources and export plans.

Several other countries have ambitious targets, such as Norway, with its enormous offshore wind potential of 30 GW [33] and its R&D agreements with the UK to explore offshore H₂ [34]. Similarly, Denmark and Belgium are pioneering “Power-to-X” projects combining offshore wind with hydrogen. The Bornholm Energy Island in the Baltic will connect 2–3 GW of offshore wind to 1.3 GW of onshore electrolysis for green fuel production by 2030 [35]. In 2024, Denmark approved one of Europe’s first GW-scale green hydrogen hubs (Esbjerg project) to use 2 GW of offshore wind to produce up to 100,000 tons of H₂ per year by 2025 [36]. In the Middle East, Saudi Arabia is planning massive green hydrogen facilities (the NEOM project) [37], though these rely on onshore solar/wind, as offshore wind in the region is nascent.

Despite many national targets and announcements, fully commercial OW2H systems are largely at pilot or planning stages. The IEA notes that only a small fraction of announced hydrogen projects have reached a final investment decision due to cost and regulatory uncertainties [38]. Cumulatively, the projects reviewed represent on the order of 10²–10³ MW of electrolyzer capacity linked to offshore wind in the near-term pipeline, primarily within the R&D and pilot phases through the late 2020s. Looking ahead, several initiatives indicate multi-gigawatt ambitions emerging in the early 2030s, Figure 2, consistent with a transition toward commercial-scale deployment [39]. This trajectory reflects a staged development pathway in which innovation and pilot projects scale up, supported by enabling policy frameworks. However, progress along this timeline will depend on continued cost reductions and mitigation of technical, economic and environmental impacts, particularly during the demonstration phase.

1.3. Offshore Wind Energy and Hydrogen in Decarbonization

Offshore wind-to-hydrogen (OW2H) integration sits at the intersection of two major decarbonization strategies: renewable power expansion and clean fuels production. Coupling abundant offshore wind power with electrolyzers allows intermittent wind generation to be stored as hydrogen fuel. This P2G approach means surplus wind electricity (during high-wind periods) can be diverted to produce hydrogen, which can then be used later (via fuel cells or combustion) to generate power or provide heat/fuel, effectively smoothing energy supply over daily to seasonal timescales [40]. In addition to balancing the grid, hydrogen serves as a crucial decarbonization vector for the hard-to-abate sectors that are difficult to electrify [41]. Heavy industries (steel, cement, chemicals) and long-distance transport (shipping, aviation, heavy trucking) collectively contribute a large share of global emissions and have limited alternatives to fossil fuels [10]. Green hydrogen or its derivatives (like ammonia) can decarbonize these sectors by replacing coal, natural gas, or oil-based fuels in high-heat or long-range applications. In essence, offshore wind provides a new pathway to extend decarbonization beyond the power sector by producing a clean fuel that can be used across the energy system.

However, these benefits are counterbalanced by significant challenges introduced by the marine environment and the nascent state of offshore hydrogen infrastructure. Salt spray, waves, and high humidity accelerate corrosion and equipment wear offshore. Electrolyzers and power electronics must handle rapid fluctuations as wind power varies, and platforms at sea face complex engineering and maintenance issues. Producing hydrogen offshore also necessitates desalination (or direct seawater electrolysis), and safely handling hydrogen on isolated platforms, introducing new technical hurdles.

1.4. Motivation and Scope of the Review

Several comprehensive reviews of offshore wind-to-hydrogen systems have appeared in recent years. For example, Niblett et al. (2024) [5] provide an overview of next-generation offshore electrolysis technologies, and Ramakrishnan et al. (2024) [42] offer a critical assessment of offshore green hydrogen production costs and technical barriers. Rodriguez et al. (2023) [40] focus on the engineering challenges of offshore structures for hydrogen production and storage. Mudhafar et al. (2025) [43] provide a detailed review of offshore wind–hydrogen production systems, focusing on challenges, techno-economic analyses, and environmental implications. Jiang et al. (2026) [44] focus on three technical routes (offshore distributed, offshore centralized, onshore) and identify challenges like limited electrolyzer adaptability, high life-cycle costs, and storage bottlenecks.

Some earlier studies have examined specific feasibility aspects, for example, Luo et al. (2022) [45] modeled offshore wind–hydrogen production in South China, and Ishaq et al. [46] review hydrogen production methods, both conventional and renewable (blue and green) routes, and discuss key technological developments and utilization pathways in the hydrogen sector. These works, however, typically focus on isolated technologies or case studies and do not provide a unified, system-level synthesis. In contrast, the present review adopts a broader and more systematic approach by integrating technological, economic, environmental, and policy dimensions within a single analytical framework. It distinguishes itself by offering an up-to-date comparative evaluation of electrolysis technologies specifically for offshore applications, including explicit suitability rankings for different platform concepts, alongside a dedicated examination of operational control and system integration strategies that have been only marginally addressed in earlier reviews. In addition, the review incorporates evidence from real pilot projects and regulatory contexts, enabling the identification of emerging trends, actionable insights, and priority research gaps, and culminating in a forward-looking roadmap to guide OW2H research and deployment over the coming decade.

By synthesizing findings across these dimensions, the review aims to highlight prevailing challenges and outline potential pathways to accelerate the adoption of offshore wind-powered hydrogen. In line with the above scope, the review addresses the following key research questions:

• What are the recent advancements in the integration of offshore wind energy with hydrogen production technologies?
• What are the major technical and economic challenges limiting the development of OW2H Systems?
• What opportunities, strategies, and innovations could facilitate the large-scale deployment of offshore wind-to-hydrogen solutions as part of global decarbonization efforts?

2. Methodology

Systematic Review Protocol

This review followed a transparent, predefined strategy for the literature search in line with PRISMA guidelines [47]. The details of PRISMA checklist is provided in Supplementary Materials. Searches were conducted in Web of Science, Scopus, ScienceDirect, IEEE Xplore, and Google Scholar using the Boolean string “(offshore wind OR floating wind) AND (hydrogen OR electrolysis OR electrolyzer) AND (system OR integration OR transport)”. Filters were applied to restrict results to peer-reviewed journals, conference papers, and authoritative reports in English for the period 2015–2025, capturing the period of significant growth in offshore wind-to-hydrogen systems. Broad yet focused query strings were used (such as “offshore wind” AND (hydrogen OR electrolysis OR electrolyzer) AND (system OR integration)) in order to retrieve a wide range of relevant peer-reviewed articles, conference papers, and major technical reports. The multi-database strategy ensured coverage of both foundational studies and recent developments. Following the approach of Wiegner et al. [48], keyword filters and subject area refinements were applied to eliminate off-topic results, ensuring the remaining literature was squarely focused on renewable OW2H systems. All retrieved references were exported, and duplicates were removed. The number of studies at each stage (identification, screening, eligibility, inclusion) was recorded following a PRISMA flow approach, Figure 3, to ensure transparency in study selection.

Clear inclusion and exclusion criteria were applied to filter the literature. Inclusion criteria included the following: (i) studies addressing integration of offshore wind energy with hydrogen production or storage; (ii) case studies, techno-economic analyses, or reviews of OW2H systems; (iii) English-language peer-reviewed articles, conference papers, or authoritative government/industry reports (e.g., IEA, DOE). Exclusion criteria: (i) studies focusing solely on onshore wind–hydrogen systems or fossil-based hydrogen production; (ii) papers where “hydrogen” or “offshore” appear only peripherally; (iii) non-peer-reviewed blogs, magazines, or consultancy articles; and (iv) studies focusing purely on onshore wind-to-hydrogen systems or other unrelated energy topics, as well as those dealing with fossil-based hydrogen production in offshore settings (e.g., steam methane reforming on oil/gas platforms) were excluded.

Following the PRISMA 2020 guidelines [47], the literature selection process was documented in detail to ensure transparency and reproducibility, as summarized in Figure 3. The initial database search yielded 320 records across Web of Science, Scopus, ScienceDirect, IEEE Xplore, and Google Scholar. After the removal of 30 duplicate records, a total of 290 unique studies remained for screening. The titles and abstracts of these 290 studies were screened against the defined inclusion and exclusion criteria. During this stage, 246 records were excluded, primarily because they were not directly related to offshore wind-to-hydrogen integration, focused exclusively on onshore systems, or mentioned hydrogen or offshore wind only tangentially. As a result, 44 studies were deemed potentially relevant and were sought for full-text retrieval. All 44 full-text articles were successfully retrieved and assessed for eligibility. During the full-text review, 23 studies were excluded for the following reasons: 10 studies did not specifically address offshore wind–hydrogen systems, 7 studies lacked sufficient technical or quantitative detail to support comparative analysis, and 6 studies were policy-focused without substantive system-level or techno-economic evaluation. Ultimately, 21 studies met all inclusion criteria and were included in the final qualitative synthesis and comparative analysis. These studies form the core evidence base of this systematic review, covering offshore wind-powered hydrogen production technologies, system integration configurations, techno-economic performance, and deployment challenges. This rigorous screening,

Table 1. Summary of the literature identification, screening, and inclusion by source database following the PRISMA methodology for offshore wind-to-hydrogen studies.

Source Database	Records Found	After Duplicates	Excluded at Screening	Full-Text Excluded	Final Included
Web of Science	80	72	61	6	5
Scopus	90	82	69	7	6
ScienceDirect	65	59	50	5	4
IEEE Xplore	45	41	35	3	3
Google Scholar (top results)	40	36	31	2	3
Total	320	290	246	23	21

, ensured that only the most pertinent and high-quality studies were retained for analysis. The final literature pool, consisting of several dozen sources, provides a robust foundation for qualitative and quantitative assessment of the State of the Art in OW2H.

3. Offshore Wind-to-Hydrogen System Architecture Overview

An offshore wind-to-hydrogen (OW2H) system mainly couples a wind farm, electrolysis, and hydrogen handling equipment on an offshore platform. Electricity from offshore turbines (fixed or floating) is routed through transformers and power converters to stabilize the variable output. A seawater purification unit is used to produce high-purity water for the electrolyzer. The purified water feeds the electrolyzers on the platform, which split water into hydrogen and oxygen [49]. Auxiliary systems such as battery energy storage smooth wind-power fluctuations and enable continuous operation of critical equipment, while heat exchangers recover waste heat from electrolysis for desalination or heating. The generated hydrogen is either compressed and stored for delivery to shore via subsea pipelines or liquefied and loaded onto specialized tankers. The choice between compressed-gas pipelines and liquefied-hydrogen shipping depends on distance, scale, and integration with existing infrastructure. This integrated approach allows offshore wind resources to be converted directly into green hydrogen, reducing onshore transmission requirements and enabling deployment far from existing grids.

Offshore Wind Turbine Technologies and Foundation Concepts

Offshore wind technology has bifurcated into fixed-bottom turbines (attached to the seabed by monopile, jacket, or other fixed foundations) and floating turbines (mounted on buoyant platforms anchored in deep water). Fixed-bottom turbines have been deployed for decades in water depths up to 50 m, using monopile foundations in shallow seas and jacket or tripod structures for intermediate depths [43], Figure 4.

Floating wind turbines, by contrast, are an emerging solution enabling wind farm deployment in deep waters (>60 m) where fixed foundations are impractical [43]. Floating platforms (spar buoys, semi-submersibles, tension-leg platforms, (Figure 5) support the turbine and are moored to the seabed with cables. In recent years, prototypes and small arrays of floating turbines have demonstrated capacity factors on par with fixed turbines, often exceeding 50%, thanks to excellent wind resources far offshore. These successes show that floating wind can unlock vast new areas for wind power development by overcoming depth limitations.

As countries like Japan, France, and Norway invest in floating wind, this technology is poised to greatly expand the exploitable offshore wind resource area beyond the limits of continental shelves.

Table 2. Comparison of offshore wind turbine foundation types and their attributes (material, typical weight, cost range, installation depth, TRL, and other considerations). Sources: [3,4,24,28,40,49].

Foundation Type	Material	Weight Range (tons)	Cost per kW (USD)	Install Depth (m)	TRL	Characteristics
Monopile	Steel	200–2000	USD 15–30	up to 30–35	9	Simplest and most common for shallow waters. Susceptible to seabed scour (may require protection).
Gravity Base (GBS)	Concrete/Steel + Ballast	1000–8000+	USD 20–40	up to 30	9	Very large/heavy. Stable in shallow water but needs a strong seabed and installation of ballast.
Jacket (Lattice)	Steel	500–2500	USD 30–50	30–60	9	Three or four-legged lattice, stable for mid-depths. Higher fabrication/installation complexity than monopiles; requires pile driving for each leg.
Tripod	Steel	600–2800	USD 35–55	30–60	8	Three-legged base improves stability over monopile. Less common; dynamic analysis needed to handle loads.
Suction Caisson (Bucket)	Steel	300–1500	USD 25–45	15–40	7–8	Hollow “bucket” anchor installed by suction can be removed/reused. Suitable for various soils. Needs testing for seismic stability.
Floating Platforms (spar, semi-sub, TLP)	Steel or Concrete	5000–15,000+	USD 50–100+	60+ (deep water)	6–8	Enables deep-water wind farms. Requires complex moorings and dynamic cables. More expensive but allows access to superior wind resources.

compares the common offshore wind turbine foundation types, including monopile, gravity base, jacket, tripod, suction caisson, and floating platforms, highlighting their typical characteristics. Each foundation type offers advantages for certain site conditions and depth ranges, while posing specific engineering and cost challenges.

Turbine rated capacities have grown dramatically; current State-of-the-Art offshore turbines are in the 12–15 MW class, with prototypes of 15–20 MW under development [49]. These larger machines have longer blades (often >100 m) and taller towers, sweeping more area to capture more energy. The scale-up improves the economics by delivering higher output per turbine (reducing the number of units needed for a given farm size) and accessing stronger, steadier winds at greater heights [3,4]. Alongside upsizing, there have been significant design improvements: lightweight composite blades to reduce stress, advanced control systems that adjust blade pitch in real time to mitigate fatigue, and enhanced drivetrains (including direct-drive generators) to boost efficiency and reliability. Another key advance is power transmission: as offshore wind farms are built farther from shore, high-voltage DC (HVDC) transmission is being adopted, and offshore energy hubs are created to efficiently deliver power to shore [24]. These grid innovations facilitate very large offshore projects and lay the groundwork for directly integrating offshore hydrogen production (for instance, an “energy island” where wind power is routed either to electrolyzers or to HVDC export). Overall, the trend in offshore wind is toward greater scale and efficiency, with some projects now achieving capacity factors above 50% and improved durability for harsh marine conditions (longer maintenance intervals, anti-corrosion designs) [40]. These advancements benefit OW2H systems by providing more powerful and reliable electricity generation, which improves electrolyzer utilization and lowers the unit cost of hydrogen.

Table 3. Representative large-scale offshore wind turbine models (capacity, dimensions, typical deployment, and key considerations) compiled from sources [3,4,24,28,40,49].

Turbine Model	Manufacture.	Capacity (MW)	Rotor Diameter (m)	Hub Height (m)	Deployment	Key Characteristics
Siemens Gamesa SG 14-222 DD	Siemens Gamesa	14 (up to 15 MW)	222	110–130	North Sea, Baltic, Asia-Pacific	Direct-drive (gearless) turbine; features 108 m blades designed for high CF.
Vestas V236-15.0 MW	Vestas	15	236	120–140	North Sea (planned globally)	One of the largest to date; up to 80 GWh/year, very long blades (115 m).
GE Haliade-X 13 MW	GE Renewable	12–14 (prototype 13)	220	100–130	North Sea, U.S. Atlantic	First to exceed 12 MW; 107 m blades, high output even at moderate wind speeds.
MHI Vestas V164 (V174)	MHI Vestas (now Vestas)	9.5–10	164 (174 for variant)	90–110	North Sea, European coasts	Proven turbine (widely deployed 2016–2020). Robust design with gearless drive and strong performance.
Goldwind 171-8 MW	Goldwind (China)	8	171	90–100	China Sea	Designed for Chinese offshore conditions. geared design; focuses on local climate resilience, including typhoon resistance.
MingYang MySE 16-260	MingYang (China)	16 (prototype)	260	120–140	China Sea (planned)	Among the world’s largest (16 MW); 126 m blades. Typhoon-resistant design for South China Sea.
Adwen AD 8-180	Adwen (Gamesa)	8	180	120	North Sea (planned, never mass-produced)	Developed for offshore with large 180 m rotor; merged into Siemens Gamesa portfolio.

illustrates several large-scale offshore turbine models and their key characteristics, showcasing the State of the Art in turbine technology.

4. Offshore Hydrogen Production Technologies (Electrolysis)

Water electrolysis is the primary technology for hydrogen production in OW2H systems. Several electrolyzer types are available or in development, each with different operating principles and suited to different conditions:

4.1. Alkaline Electrolyzers (AEL)

The most mature and historically common type. They use a liquid alkaline electrolyte (KOH or NaOH solution) and operate at 60–80 °C. AELs have a relatively simple design and low capital cost (no precious metals required), making them attractive for large-scale installations. However, they have lower current density and slower response to load changes compared to newer types [50]. In offshore use, the presence of liquid electrolytes raises concerns about leakage and maintenance on a moving platform.

4.2. Proton Exchange Membrane Electrolyzers (PEMEL)

These use a solid polymer proton-exchange membrane as the electrolyte and typically operate at 50–80 °C [51]. PEM electrolyzers can handle high current densities and ramp output quickly, which is advantageous for variable wind power. They produce high-purity hydrogen and have a compact, modular design. The main downsides are higher cost (due to platinum-group metal catalysts) and sensitivity to water purity (requiring deionized water). Their fast response and solid-state design make PEMEL a promising choice for offshore applications where space is limited and power fluctuates.

4.3. Anion Exchange Membrane Electrolyzers (AEMEL)

A newer, developing technology that, like PEM, uses a solid membrane but conducts hydroxide ions (OH⁻) rather than protons. AEM electrolyzers operate around 40–60 °C and aim to combine some advantages of both alkaline and PEM, potentially lower materials cost (no noble metals) while still having a solid electrolyte [52]. AEMELs are still at the pilot stage, with ongoing research into long-term stability. If durability issues are resolved, they could offer a cost-effective alternative for offshore systems by eliminating liquid electrolyte handling while maintaining good dynamic response.

4.4. Solid Oxide Electrolyzers (SOEC)

High-temperature electrolyzers that operate at 600–850 °C using a ceramic solid oxide electrolyte. SOECs can achieve very high electrical efficiencies (75–85%) by leveraging heat input. They are best suited for continuous operation and potentially integrating with waste heat sources [53]. However, their high-temperature requirement and fragile ceramic cells make offshore deployment challenging (managing an 800 °C system on an unmanned platform is complex). Currently, SOECs have lower technology readiness for marine use and would require significant innovation to be viable offshore.

Table 4. Comparison of major electrolyzer types for offshore hydrogen production (AEL, PEMEL, AEMEL, SOEC).

Attribute	AEL	PEMEL	AEMEL	SOEC
Operating Principle	Electrolysis in liquid alkaline solution (KOH/NaOH) [50]	Electrolysis with a solid polymer proton-exchange membrane [51]	Electrolysis with a solid hydroxide-conducting membrane [52]	High-temperature electrolysis using a ceramic oxide electrolyte (steam electrolysis) [53,54]
Typical Operating Temperature	60–80 °C [55]	50–80 °C [56]	40–60 °C [57]	600–850 °C [53,57]
Electrolyte	Aqueous KOH/NaOH (liquid)	Solid polymer membrane (Nafion)	Solid anion-exchange membrane	Solid oxide ceramic (e.g., YSZ)
Current Density	0.2–0.6 A/cm2 [56]	1.0–2.5 A/cm2 [58]	0.4–1.0 A/cm2 [59]	0.3–1.0 A/cm2 [53]
Efficiency (LHV)	50–60% [58]	55–70% [60]	55–65% [59]	75–85% [61]
Stack Lifetime	60,000–90,000 h [62]	40,000–60,000 h [60]	Up to 60,000 h (projected, emerging technology) [63]	10,000–40,000 [52]
Key Advantages	Mature technology; low cost; readily available materials.	High power density; compact; handles dynamic operation well.	Potentially lower cost than PEM; solid electrolyte (no liquid handling).	Very high efficiency; can utilize waste heat; lower electricity use per kg H2.
Key Disadvantages	Lower dynamic response; risk of electrolyte leakage; larger footprint.	Higher cost (uses precious metal catalysts); acidic membrane can degrade.	New technology—durability not fully proven; performance degradation needs study.	Requires high heat input; complex thermal management; material degradation at high T.

provides a comparison of the major electrolyzer types (alkaline, PEM, AEM, SOEC) across key characteristics relevant to offshore use.

Each electrolyzer type must be evaluated for how well it can integrate with the characteristics of offshore wind power. PEM electrolyzers, with their compact and solid-state design, are currently favored for offshore pilots (the Dolphyn project [64] uses PEM) because they tolerate motion, have fast load response, and are easier to package in modular containers (possibly even within turbine towers). The main needs for PEM offshore are a reliable supply of very pure water (implying robust desalination and water purification units on-site) and managing the replacement of catalyst materials in a remote environment. AEM electrolyzers, if durability improves, could become competitive due to lower cost (no noble metals) and solid electrolyte; in the future they may offer a middle ground, but at present AEM is still at the pilot stage. Alkaline electrolyzers (AEL), while proven and low-cost onshore, are less ideal offshore; on fixed platforms they are technically viable but pose challenges. With marine deployment, the liquid electrolyte can slosh or leak on a moving platform and maintaining large alkaline systems at sea would require careful design of enclosures and seals. AEL could be utilized on large, fixed installations if spill containment and maintenance are well-managed, but generally PEM is favored even on fixed platforms for its quicker load-following and easier enclosure. On floating systems, ranking is clear: PEMEL is the most suitable, followed by AEMEL (once proven), whereas AEL is not recommended due to sloshing electrolyte and dynamic instability. SOEC, as noted, is not yet practical offshore due to the difficulty of managing high-temperature equipment on unmanned platforms, unless future concepts integrate SOECs onshore or on larger platforms where waste heat is available and space is ample. SOEC remains the lowest-ranked for near-term offshore use in any scenario; its fragile ceramics and heat requirements keep its TRL low and unsuitable for unmanned platforms, and require significant breakthroughs to be viable offshore. Figure 6 provides a qualitative, literature-based comparison of electrolyzer technologies relevant to OW2H systems.

Table 5. Suitability of electrolyzer technologies for offshore wind-to-hydrogen systems under different deployment scenarios.

Criterion	AEL	PEM	AEM	SOEC
TRL	9 (commercial) [11]	9 (commercial) [11]	6 (pilot scale) [65]	7–8 (demonstration) [65]
Footprint and mass	Large liquid electrolyte; heavy; better suited for onshore or fixed offshore platforms [62].	Compact, modular stacks; high power density; favorable for floating and deep-sea platforms [58,66]	Similar to PEM but smaller scale; currently limited to experimental and pilot-scale systems [67]	High-temperature ceramic stacks with insulation and heat exchangers; heavy and complex; limiting suitability for offshore deployment [44]
Dynamic response/minimum load	Limited load-following capability; minimum load 20–30%; slow ramping compared to PEM, making frequent cycling less suitable [62]	Excellent dynamic response with fast ramping and start/stop capability; low minimum load (5–10%), well-suited for variable renewable operation [60]	Good dynamic response; limited long-term operational data due to early technology maturity [68]	Designed for steady-state operation; limited tolerance to rapid load changes due to thermal inertia and degradation risks [69]
Marine adaptability	Liquid electrolyte risk of leakage; corrosion issues; sensitivity to platform motion and inclination, making offshore deployment more challenging [62]	Solid polymer membrane; robust to tilt/vibration; requires high-purity water; good marine adaptability [70]	Solid membrane; no liquid electrolyte; potential cost advantage, but durability and long-term stability remain uncertain under marine conditions [5].	High-temperature operation is difficult offshore; requires continuous heat supply [5]
CAPEX (USD per kW)	Low stack CAPEX (300–500 USD/kW) due to mature manufacturing, non-precious catalysts, and simple materials [71].	Moderate stack CAPEX (400–900 USD/kW) driven by noble-metal catalysts and membrane costs, but benefiting from scale-up and learning effects [65]	Early stage stack CAPEX estimates (500–700 USD/kW); potential for cost reduction due to non-precious catalysts, but limited commercial data [72]	High stack CAPEX (>1000 USD/kW) owing to ceramic materials, high-temperature components, and complex balance-of-plant requirements [71]
Suitability for fixed-bottom platform	Well-suited for large fixed offshore platforms where space and mass constraints are less critical; low cost [67]	Due to strong dynamic response, compact and modular design; well-suited for fixed offshore platforms; if cost acceptable [71]	Limited current suitability; early-stage technology with uncertain long-term reliability and lack of offshore demonstration [73]	Not yet viable for offshore deployment due to high-temperature operation, system complexity, and durability concerns [66]
Suitability for floating platform	Limited suitability due to mass and liquid electrolyte limit applicability; sloshing risk [67]	Excellent suitability owing to compactness and low inertia makes PEM ideal for floating and deep-sea projects [71]	Promising but not yet demonstrated offshore [73]	Currently unsuitable for floating platforms due to temperature management challenges [66]

compares different electrolyzer technologies and their suitability for offshore deployment.

5. Offshore Electrolyzer Deployment Challenges

Producing green hydrogen offshore introduces significant design and maintenance challenges compared to onshore electrolysis. Harsh marine conditions mean that electrolyzers and associated equipment must be engineered for durability and reliability far beyond typical onshore requirements [73,74]. Experience from offshore wind shows that operations and maintenance (O&M) can account for a large share of lifecycle costs (often 15–30%) [75], and maintaining hydrogen systems at sea is expected to be even more demanding. Simulation studies indicate that adding offshore hydrogen production can substantially reduce overall system availability [75,76]. This underscores that keeping electrolyzers running in marine environments will be complex and costly.

5.1. Corrosion and Material Degradation

Marine environments are notorious for saltwater corrosion and humidity, which can deteriorate metals, electrical contacts, and coatings on offshore equipment. Salt spray and chloride ions accelerate corrosion of electrolyzer components, piping, and balance-of-plant systems. All structural materials and enclosures must therefore be marine-grade and corrosion-resistant. Special coatings, cathodic protection (sacrificial anodes), and the use of stainless steel or corrosion-proof alloys are required to protect against seawater damage [76,77]. These protective measures add cost and complexity but are essential as corrosion issues are known to significantly drive up O&M costs in offshore energy projects [78]. Offshore electrolyzers will similarly require frequent inspections and preventative maintenance to manage corrosion and fouling (e.g., salt or marine growth on water intake systems) [79].

Another concern is hydrogen embrittlement and material compatibility. Hydrogen can permeate and weaken certain metals, so any offshore pipeline or storage vessel for hydrogen must be designed with appropriate materials and coatings [76,80]. Ensuring long-term material integrity in the face of both saltwater and hydrogen exposure is an active area of research and adds to maintenance requirements (for instance, more regular checks for cracks or leaks). Some analyses predict that electrolyzer stacks at sea might have reduced service life compared to onshore, due to less controlled operating conditions and impurities (even with desalination) in the water supply [81]. These factors translate to increased OPEX (operational expenditure) over project life.

5.2. Wind, Waves, and Structural Loads

Offshore electrolyzer installations withstand extreme weather and ocean conditions. Platforms and equipment are exposed to high winds, powerful waves, and even storms or hurricanes, depending on the region, imposing strict structural design requirements. High winds generate large lateral forces on platforms and can stress equipment housings; thus, housings need to be robust and sealed against water ingress (designs similar to offshore oil and gas enclosures) [82].

Wave loads are a major consideration, especially for floating systems. A floating wind–hydrogen platform will experience constant motion (heave, pitch, roll) due to waves. These motions can impact electrolyzer performance and reliability. Dynamic loading and vibration could potentially shorten equipment life or cause more frequent faults if not mitigated [40]. Design adaptations such as shock-absorbing mounts, gimbaled platforms, or motion-damping systems are required to protect sensitive components. In the case study of the ERM Dolphyn project [80,83] for a floating wind–hydrogen platform, only minor modifications were needed for a standard PEM electrolyzer to operate on a semisubmersible, chiefly adding protection against environmental exposure and tweaking ancillary equipment like fluid level gauges. This is a promising sign, suggesting that with proper design, electrolyzers can be prepared for offshore use. Nonetheless, any offshore hydrogen structure (whether a fixed platform or floating) must be designed for structural integrity under worst-case wind and wave conditions, which raises capital cost. Equipment should be mounted above the splash zone on platforms to avoid direct wave impacts, and if floating, the platform must be moored and sized to minimize excessive motion [84]. All of these engineering choices (larger platforms, heavier-duty structures) again increase costs and complexity compared to an onshore installation.

Even with robust design, maintenance at sea is far more challenging than on land. Offshore sites are remote, often tens of kilometers from shore, and accessible only by specialized vessels or helicopters. This means any inspection or repair requires careful planning around weather windows and often expensive marine operations. Crew transfer is generally unsafe if waves exceed 1.5 m in height [85]. As a result, offshore wind farms typically have at most 120–150 suitable days per year for maintenance access in regions like the North Sea. Hydrogen platforms would face the same limitation, causing longer downtime if an electrolyzer or compressor needs unplanned repair during bad weather. This constraint forces operators to adopt preventative maintenance and robust remote monitoring. Any maintenance activity at sea also carries higher safety risks as it involves rough seas, strong winds, and the challenge of working on tall structures or confined platform spaces. These factors often necessitate halting work until conditions improve, further adding to downtime. All of this contributes to a higher cost of hydrogen produced offshore [86]. One approach to lower O&M cost is to design unmanned or minimally attended platforms where the electrolyzer system would operate remotely with automation, and only infrequent visits are made for major maintenance [87]. Conversely, if a platform is manned (with a regular crew on board), it must be larger and meet offshore accommodation standards, which significantly increases cost and complexity.

Early pilot projects, like Lhyfe’s Sealhyfe, have shown valuable insights: over 14 months of offshore operation, it achieved around 70% uptime with fewer than ten maintenance visits, demonstrating that with careful planning and remote monitoring, marine electrolyzers can be maintained with limited intervention [86,88]. As projects scale up to tens or hundreds of megawatts, maintaining many electrolyzer units at sea will require streamlined O&M strategies. Clustering maintenance tasks during favorable weather, using autonomous inspection drones/ROVs for routine checks, and employing service operation vessels (SOVs) with motion-compensated gangways to increase the safe access days are all being considered to mitigate maintenance challenges.

6. System Integration Configurations

A primary decision in system integration is whether to send the wind power to shore via cables, onshore electrolysis, and produce hydrogen on land, or to produce hydrogen directly offshore at the wind farm, known as offshore electrolysis. In some cases, a hybrid approach is employed in which a wind farm could both send power to the grid and produce hydrogen (either offshore or onshore), depending on conditions. Hybrids offer operational flexibility (e.g., maximize electricity sales when prices are high, produce hydrogen when they are low), at the expense of a higher CAPEX for dual infrastructure. To systematically compare integration choices, five representative OW2H system configurations have been defined in the literature [85,86,87,88,89,90]. These configurations vary by electrolyzer placement (onshore vs. offshore), hydrogen production distribution (centralized vs. decentralized), and grid connection presence, and collectively encompass the main configurations under consideration.

6.1. Centralized Onshore Electrolysis

Wind turbines send electricity to shore via an undersea cable (HVAC or HVDC, depending on distance). On land, the power is fed to a single large electrolyzer plant at the grid connection point, where hydrogen is produced [73]. All turbines effectively act as a conventional wind farm feeding the grid, with the electricity then used for H₂ production onshore. The benefit of the onshore electrolysis configuration, Figure 7, is that it leverages easier access for maintenance, existing industrial infrastructure, and avoids many technical challenges of the marine environment [89]. However, it requires high-capacity submarine power cables and onshore facilities, and may face grid bottlenecks if trying to land huge volumes of intermittent power [66,90]. Also, it necessitates robust and efficient subsea cables, which can be costly and subject to transmission losses [91]. Essentially, onshore production shifts the problem to transmitting electricity to shore, which is feasible but can become a limiting factor for far-offshore sites or very large projects.

6.2. Centralized Offshore Electrolysis

Offshore electrolysis, by contrast, generates hydrogen on a platform within the wind farm, exporting energy via hydrogen pipelines or ship transport [92]. This can be advantageous for very distant or very large wind farms: hydrogen pipelines can often carry more energy over long distances [66,93]. Also, eliminating the need for long subsea transmission cables to bring electricity onshore can significantly reduce capital expenditure (CAPEX) and operational expenditure (OPEX) associated with electricity transmission [94]. Offshore production also allows the wind farm to operate independently of the onshore grid (avoiding curtailment when the grid is saturated). However, maintaining electrolyzers and equipment at sea is more complex and costly, as discussed above. Also, offshore systems currently lack the economies of scale and operational experience of onshore plants. The optimal strategy depends on project scale, distance to shore, and infrastructure costs. For near-shore moderate projects, onshore electrolysis might be simpler, whereas for far-offshore GW-scale projects, offshore H₂ production could reduce the number of export cables and bypass onshore grid limitations (especially if hydrogen has a ready market). Figure 8 depicts a simplified centralized offshore hydrogen production system configuration.

6.3. Decentralized Offshore Electrolysis

In the decentralized approach, each (or a group of a few) wind turbine has its own electrolyzer unit, typically installed on the turbine platform or an attached auxiliary structure [43,89]. Hydrogen is generated at or near each turbine and then collected via a network of small-diameter inter-array pipelines that connect the turbines. These H₂ gathering lines feed into a common line (manifold) that transports the combined hydrogen flow to shore via a main pipeline, Figure 9.

The decentralized scheme eliminates the need for a massive centralized H₂ platform, which can be an advantage in deep waters (avoiding one very large floating structure). Instead, each turbine’s foundation or floater is adapted to support the added electrolyzer and equipment. The electrolyzer units at individual turbines are smaller (dividing total capacity by N turbines), which could lead to some economy-of-scale loss [54,95]; however, modular electrolyzers may scale fairly linearly, and the parallel operation provides redundancy (one unit offline only knocks out one turbine’s H₂ output). Losses in this scenario include minimal electrical transmission loss (only short cable runs, if any, from the turbine generator to its electrolyzer) and some manifold piping losses, but those are small due to stepwise collection.

6.4. Hybrid Offshore (Centralized)

In this configuration, a wind farm has both an offshore H₂ electrolyzer platform and a grid export cable [53,85]; Figure 10. The key is that the electrolyzer is powered exclusively by the wind farm (no import of grid power for H₂), but not all wind power must go to hydrogen; any excess beyond the electrolyzer’s capacity is sent to the onshore grid. In practice, the wind farm’s AC inter-array network feeds a central offshore H₂ platform; simultaneously, the farm is connected via HVDC/HVAC export to shore. The electrolyzer might be sized to consume, say, 80–90% of the farm’s peak output, so during high winds any surplus goes via cable to the grid (preventing the need to oversize the electrolyzer for rare peaks), and during low winds the electrolyzer may run below capacity while some power still flows to the grid.

This configuration provides two revenue streams (hydrogen and electricity) and operational flexibility; the operator can curtail hydrogen production to sell power when electricity prices are high, and vice versa. This improves asset utilization and revenue; can enhance grid support (electrolyzer can ramp down to free up power for the grid when needed). This layout essentially combines the complexities of configuration 2 (offshore H₂ platform) with those of a traditional wind farm grid connection. Higher CAPEX is needed because both pipeline and cables are needed. And requires sophisticated energy management to decide in real time how to split power between H₂ and electricity export.

6.5. Onshore Hybrid (Grid and Hydrogen)

This scenario is similar to configuration 1 (onshore electrolysis) but with the change that not all power has to go to hydrogen, the wind farm can also feed the grid directly. Practically, this means the wind farm is grid-connected via HVDC/HVAC and delivers power to an onshore substation; at that point, some of the power is routed to an onshore electrolyzer (central plant), and the rest can be sold as electricity, Figure 11.

Onshore Hybrid avoids offshore H₂ equipment entirely as the electrolyzer is on land, but like configuration 4, it involves dual use of the energy [53,85]. One could also convert the hydrogen to ammonia onshore if targeting export markets; indeed, configuration 5 could be coupled with an onshore ammonia plant at the landing point, allowing the hybrid project to export ammonia via port when international demand justifies it (though ammonia conversion adds costs, it might piggyback on existing port facilities). For the core analysis, configuration 5 is treated as having the same physical components as configuration 1 plus the option to sell power. Losses include cable transmission loss and any converter loss, as well as electrolyzer efficiency loss for the portion used for H₂. Because the electrolyzer is onshore, no dedicated offshore platform is needed, and maintenance is easier; this tends to reduce the OPEX compared to offshore electrolysis.

7. Hydrogen Storage and Transport

The intermittency of wind power necessitates energy storage solutions to ensure a stable hydrogen production rate to maximize system utilization. In OW2H systems, storage can take the form of hydrogen storage or electrical storage (batteries), or a combination. Storing hydrogen produced from offshore wind can buffer short-term fluctuations in power supply and allow continuous delivery to end-users or conversion processes. Options include pressurized gaseous storage, subsea storage, salt caverns, or conversion to stable carriers like ammonia or liquid organic hydrogen carriers (LOHCs) that can be stored in tanks [96,97]. Battery storage can be combined with hydrogen production to create a hybrid energy storage system, using batteries for fast response and hydrogen for bulk energy storage, which can greatly enhance the overall reliability and efficiency of an OW2H system [98]. The integration of energy storage systems is crucial for enhancing the viability and efficiency of offshore wind-to-hydrogen production. By converting renewable energy into green hydrogen, it enables long-duration storage and reduces dependence on fossil fuels [42]. This supports decarbonization across sectors like transport and industry while improving energy security.

Different storage methods vary widely in energy density, conversion efficiency, weight/volume requirements, safety, and maturity, especially when deployed on offshore platforms.

Table 6. Comparison of Hydrogen Storage and Transport options for Offshore Wind-to-Hydrogen Systems (including key parameters and suitability considerations).

Storage Method	Volumetric Density (kg H2/m3)	Energy Conversion Losses (% Energy Penalty)	Offshore Suitability and TRL
Compressed H2 (Gas)	20–40 kg/m3 (at 200–700 bar) [99]	Compression requires 5–15% of energy content for high pressure; no phase change.	Mature (TRL9): Widely used onshore (cylinders, pipelines). For offshore: Limited buffer storage due to space/weight.
Liquefied H2 (LH2)	70 kg/m3 (at 1 atm, 20 K) [100]	Liquefaction consumes 30–40% of H2 energy. Boil-off 0.1–0.3% per day (must be managed/utilized).	Tech proven onshore (TRL8): used in industrial gas and rocket fuel sectors. Offshore: no in situ LH2 production yet; would require heavy cryo equipment and reliable cooling at sea. Enables ship transport of H2 in liquefied form.
Metal Hydrides (Solid Storage)	50–150 kg/m3 (in solid matrix, alloy-dependent) [99]	Minimal compression energy needed (operate 1–30 bar). overall round-trip efficiency 90%	Emerging (TRL4–5): high volumetric capacity proven in labs and small demos. Not yet scaled commercially for energy storage. Offshore potential: could serve as compact buffer storage on platforms or subsea.
LOHC (Liquid Organic Carrier)	50–60 kg/m3 (hydrogenated liquid) [101]	Hydrogenation/dehydrogenation: 30–40% energy loss total. 11 kWh/kg_H2 needed as heat to release H2 (if waste heat not reused).	Demonstration stage (TRL6–7): small plants and one-off international shipments completed. Offshore use: conceptually attractive (utilizes conventional tankers and storage).
Ammonia (NH3)	120 kg/m3 (liquid NH3 at 8 bar)	Conversion: 15% energy penalty to synthesize NH3 (Haber-Bosch). Cracking NH3 back to H2 costs 25–30% (if required). If used directly, only one conversion loss.	Commercial tech (TRL9): ammonia production and shipping are well-established globally. Offshore integration: First pilot in 2025 (China) proved viability. Suitable for large-scale hydrogen export; can be sent via chemical tankers or pipelines. Offers flexibility of direct use in engines, turbines, or fertilizer production, reducing need for reconversion.

compares these options in terms of technology readiness, energy efficiency penalties, suitability for offshore use, relative costs, and safety/environmental factors.

The choice of hydrogen storage form offshore directly influences how the energy is moved to end-use. Compressed hydrogen gas is typically best for shorter distances, as it can be fed into subsea pipelines for direct transport to shore. However, pipelines become less economical over very long distances (e.g., >300–500 km or for international export) [93]. In those cases, chemical carriers shine. Converting hydrogen to ammonia enables the use of existing ammonia shipping infrastructures as ammonia tankers can carry the fuel to global markets, and at the destination, the ammonia can either be used directly (e.g., co-fired in power plants or as fertilizer feedstock) or cracked back into H₂. The high density of ammonia means fewer shipments (and thus lower transport cost per energy unit) compared to liquid hydrogen. In addition, hydrogen-enriched liquids can be pumped to a tanker and transported under ambient conditions without specialized cryogenic or pressurized vessels. Liquefied hydrogen could be used for shipping as well. Specialized LH₂ vessels are being developed, but the technology is still emerging, and boil-off loss and insulation requirements make long voyages challenging. Each storage method also links with downstream distribution modes onshore. For example, if hydrogen is landed via pipeline as compressed gas, it might be injected into local pipeline networks or stored in salt caverns onshore. If landed as ammonia, it might go directly to industrial users (e.g., fertilizer plants, ships equipped to burn ammonia) or to hubs where it is converted back to H₂ for distribution via truck or pipeline. In practice, hybrid strategies may be employed: for instance, an offshore wind complex could use compressed H₂ pipeline transport for regional distribution, while also converting a portion to ammonia for export markets.

The optimal hydrogen storage or carrier for an offshore project depends on key project parameters: the scale of H₂ production, the distance to shore (or to end-user), and the intended end-use of the hydrogen.

Table 7. Simplified decision matrix for hydrogen storage and carrier selection in offshore wind-to-hydrogen (OW2H) project scenarios.

Project Scenario	Distance to Shore	Hydrogen Scale	End-Use/Destination	Recommended H2 Storage/Carrier	Key Rationale
Near-shore OW2H supplying local industry (e.g., refinery, steel, gas grid)	Short (≤50 km)	Small–Medium (<50–200 MW)	Direct onshore H2 use	Compressed gas pipeline (optionally pressurized offshore)	Lowest cost and losses; avoids conversion; pipeline CAPEX manageable at short distances
OW2H feeding regional H2 network or industrial cluster	Moderate (50–200 km)	Medium–Large (100–500+ MW)	Gas grid blending or clustered demand	Dedicated H2 pipeline (with compression as needed)	Pipelines remain cost-effective up to a few hundred km if demand is continuous
Remote offshore/islanded project targeting export	Long (>200–300 km)	Very large (GW-scale)	International export	Ammonia or liquid H2 shipping	Long pipelines uneconomic; chemical carriers suit long distances and global trade
Floating OW2H pilot or demonstration, no pipeline access	Any (off-grid)	Small (1–10 MW)	Periodic delivery to shore	On-site storage + ship transport (compressed H2 or ammonia)	Pipelines unjustified at pilot scale; modular storage enables proof-of-concept
Hybrid offshore project (electricity + hydrogen, flexible operation)	Short–Moderate	Medium	Domestic power and/or H2	Grid cable + H2 pipeline + short-term on-site storage	Enables switching between power and H2; small storage buffers operational variability
Large OW2H serving chemical production (fertilizer, fuels)	Moderate–Long	Large (>500 MW)	Chemical synthesis	Direct offshore ammonia or LOHC production	Avoids reconversion; aligns carrier with end-use; reduces logistics complexity
Bulk supply to near-shore industrial hubs with storage needs	Short (≤50 km)	Very large (>500 MW)	Industrial clusters	Large-diameter pipeline + underground storage	Strong economies of scale; potential reuse of gas infrastructure

provides a simplified decision matrix. Generally, for short distances and moderate scales, compressed gaseous transport via pipeline is preferred, whereas long distances or need for export may favor chemical carriers like ammonia. End-use is crucial: if the hydrogen will be used directly (e.g., in a local industrial cluster or injected into a pipeline network), delivering it as hydrogen (gas or liquid) makes sense; but if it is destined for overseas export or use as fertilizer feedstock, converting to ammonia might be more practical.

8. Results and Discussion

The reviewed studies collectively assess feasibility, cost drivers, scalability, and deployment pathways across different offshore configurations.

Table 8. Key Studies on Offshore Green Hydrogen Production (2015–2025).

Study	Scope	CAPEX	LCOH (USD/kg)	Geographic Location	Type of Study	Results
Loisel et al. (2015) [102]	Economic evaluation of hybrid offshore wind systems including hydrogen	CAPEX includes offshore wind + electrolyzer + infrastructure	USD 4.3 USD14/kg) from study scenarios	Offshore wind contexts (general)	Techno-economic evaluation	LCOH around EUR 4–13/kg in 2030; cost is highly sensitive to CAPEX and design choices
Morgan et al. (2017) [103]	offshore wind electrolysis to H2/ammonia	Modeled offshore wind + electrolyzer + storage CAPEX (detailed breakdown,	Offshore wind H2: EUR 8.68/kg (USD 9–10/kg) (AEL) and EUR 10.49/kg (USD 12/kg)	Gulf of Maine, USA (generic)	Techno-economic modeling and case analysis	Offshore hydrogen/ammonia is economically sensitive; AEL produced lower LCOH; costs reduce under favorable assumptions
Babarit et al. (2018) [104]	Mobile offshore wind fleets producing hydrogen at sea	Not explicitly reported; vessel, electrolyzer, storage dominate	Short-term: 7.7–10.2 Long-term: 3.8–6.2	Far offshore (global oceans)	Techno-economic modeling	Offshore mobile H2 production potentially competitive long-term; near-term needs policy support
D’Amore-Domenech and Leo (2019) [105]	Review of seawater electrolysis tech for offshore H2	Not provided	Not provided	Global marine/offshore context	Technology review	Identifies seawater electrolyzer options, durability issues with saline environments; highlights low-temperature electrolysis as most promising for offshore use
Dinh et al. (2021) [106]	Dedicated offshore wind farms producing hydrogen	Not explicitly reported; Offshore wind, electrolyzer, storage	5.4 (based on EUR 5/kg viability threshold)	Irish Sea	Techno-economic viability modeling	Offshore wind-to-H2 viable by 2030 at EUR 5/kg; storage duration strongly affects profitability
Song et al. (2021) [107]	Offshore wind to onshore H2	Offshore wind, electrolyzer, storage, and transport (not reported as a single CAPEX figure)	USD 1.8–USD 2.0/kg for MCH transport (baseline; meets Japan targets)	Offshore wind areas of China and Japan	Techno-economic modeling and supply chain analysis	China’s offshore wind meets Japan’s 2030/2050 cost targets
Rogeau et al. (2023) [92]	Offshore wind-to-hydrogen cost and resource assessment	Detailed cost modeling.	EUR 4.5–7.5/kg (2020) EUR 1.5–3.0/kg (2050)	European seas	Techno-economic + geospatial	Large EU offshore hydrogen potential; costs fall sharply by 2050; >1000 TWh ≤ EUR 3/kg.
Cheng and Hughes (2023) [108]	Offshore wind’s role in renewable hydrogen production	AUD2336/kW; solar PV AUD824/kW; electrolyzer AUD923/kW	USD 3.2– USD 4.0 USD/kg) in 2030 unconstrained; (USD 1.5 USD/kg) under aggressive cost reductions	Australia	Techno-economic modeling	LCOH USD 1.5 USD/kg) requires AUD43/MWh wind and cost reductions and low electrolyzer costs
Albalawi et al. (2025) [109]	Offshore wind-powered electrolysis vs. onshore hydrogen	Offshore wind and floating foundations drive high CAPEX	Offshore: USD 6.47–USD 8.01/kg; With cost reductions: USD 4.57–USD 6.07/kg	Red Sea, Saudi Arabia	Techno-economic modeling	Onshore remains cheaper; offshore H2 cost is currently high but could fall with tech cost declines
Almeida et al. (2024) [1]	Offshore wind to H2. compares offshore vs. onshore production	Not explicitly given; driven by offshore wind turbines and electrolyzers	Min: USD 4.76/kg (Northeast Brazil, offshore)	Brazil	Techno-economic modeling	Offshore wind H2 can be cost-competitive; best case 4.76 USD/kg
Balaji and You (2024) [110]	Offshore wind-to-green H2. direct H2 delivery (pipelines vs. LH2 shipping)	Offshore wind + electrolysis + transport dominate	Delivered cost: USD 2.50–USD 7.00/kg	Coastal USA	Techno-economic + optimization + LCA	75% of US coastal H2 demand from 0.96 TW offshore wind; delivered cost USD 2.50–USD 7.00/kg; pipeline transport cheaper; hubs reduce cost
Lanni et al. (2025) [111]	Offshore wind-to-hydrogen	Offshore wind + electrolyzer costs considered	USD 5.4–USD 6.5/kg)	Sicily and Adriatic Sea, Italy	Techno-economic assessment	Offshore dedicated H2 production yields LCOH in line with sector norms; 70–80 EUR/MWh wind cost and 5–6 EUR/kg H2. Offshore hydrogen viable with future cost declines.
Jiang et al. (2025) [93]	offshore wind-to-hydrogen routes (distributed, centralized, onshore)	Offshore wind + cables + desalination + electrolyzers considered;	USD 7/kg (2025) declining toward < USD 1/kg by 2050 projected	General offshore wind contexts (model-based)	Techno-economic modeling	Onshore hydrogen from offshore wind generally more economical; higher capacity factors and scale reduce cost; distance and desalination drive costs
Travaglini et al. (2025) [72]	Compare onshore vs. offshore wind-to-H2 configurations	Cost drivers include electrolyzers, cables, turbines, infrastructure	USD 3.2–USD 11.2/kg) post-2030 depending on configuration	Dutch North Sea	Techno-economic modeling	Centralized offshore electrolysis (C-OFF with PEM) yields lowest costs; decentralized offshore (D-OFF) and onshore variants span wide range due to infrastructure and electrolyzer type differences
Travaglini et al. (2024) [78]	Floating offshore wind (FOWT) + green hydrogen during curtailments	(Focus on FOWT and hydrogen system costs)	USD 4.1–USD 5.9/kg) range depending on method	Mediterranean Sea (near Sardinian coast)	Techno-economic analysis	LCOH from floating offshore wind range USD 4.1–USD 5.9/kg; model considers curtailment-driven production optimization
Ligęza et al. (2023) [86]	Centralized offshore wind-to-hydrogen production case study	Offshore wind + PEM electrolysis system cost drivers	Not directly reported; profitability suggested with design	Baltic Sea (Poland)	Techno-economic modeling	600 MW offshore platform yields up to 3508.85 t H2/month; offshore wind–hydrogen likely profitable under Polish wind conditions and high-capacity factors ( 45–50%)
Lei et al. (2024) [112]	Offshore wind to H2 supply chains	Individual costs modeled	Min: USD 3.6/kg (pipeline to port)	(not tied to one region; modeling focus)	Techno-economic modeling	Cheapest pipeline delivery; LCOH sensitive to distance and electricity price
Liu et al. (2025) [94]	integrated offshore wind → seawater electrolysis → salt cavern hydrogen storage system	Costs discussed conceptually (system components)	Not reported	Coastal China (Jiangsu focus case discussion)	System review and feasibility	Coupling offshore wind, seawater electrolysis, and salt cavern storage offers a pathway to decouple grid constraints and improve wind utilization
Armijo and Philibert (2020) [113]	flexible H2 and NH3 production from variable wind and solar	Wind, PV, electrolyzer, storage costs modeled	5.3–5.97/kg	Chile and Argentina	Techno-economic modeling	Hybrid wind + solar configuration yields LCOH in the mid-single digits; flexibility and storage impact costs
Niblett et al. (2024) [5]	Review of OW2H production systems	Cost drivers reviewed (wind and electrolyzer costs, infrastructure)	4–6 USD /kg (typical green hydrogen cost cited)	Global	Review	identifies typical current LCOH 4–6 USD /kg and discusses tech challenges and opportunities
Ramakrishnan et al. (2024) [42]	Critical review of OW2H production systems	Discusses cost drivers (wind turbines, electrolyzers, seawater treatment)	4–10/kg (different scenarios)	Global	Review and perspective	Reviews technical and economic aspects; highlights high-capacity factors (60–70%) offshore and the potential for cost-competitive hydrogen

presents a structured synthesis of peer-reviewed studies from 2015 to 2025, focusing exclusively on offshore green hydrogen production. The selected studies encompass diverse geographical regions, technological approaches, and methodological frameworks. Key contributions include techno-economic assessments, system design proposals, environmental evaluations, and policy analyses related to the integration of offshore renewable energy (primarily wind) with water electrolysis. Each study is summarized by its specific contributions, methodology, technology type, scale of analysis, and regional focus. Together, these entries reflect the current state of knowledge and highlight critical research trends, innovations, and challenges in scaling offshore hydrogen systems.

The reported LCOH values (ranging from USD 1.5/kg up to >USD 10/kg in different scenarios) vary widely primarily because of differing assumptions in each study. For instance, DeSantis et al. 2021 [114] note that pipeline transport distance and electricity price strongly affect delivered hydrogen cost. Studies assuming very low renewable electricity prices (e.g., USD 30–USD 40/MWh in optimistic future cases) [115] naturally project much lower LCOH than those assuming current prices, i.e., USD 70–USD 80/MWh. Similarly, capacity factor differences (e.g., 50% vs. 30%) can swing LCOH by nearly a factor of two, since higher utilization spreads capital costs over more hydrogen output. Indeed, multiple analyses confirm that LCOH is highly sensitive to electricity price and utilization rate, as well as electrolyzer CAPEX. For instance, Morgan et al. (2017) [103] found a EUR 4–13/kg range depending on design/capex assumptions, highlighting CAPEX sensitivity.

It is also noted that the results of sensitivity analyses in the literature, for example, Albalawi et al. (2025) [109] show that reaching USD 1.5/kg H₂ requires extremely low wind electricity cost (AUD 43/MWh) and aggressive electrolyzer cost reductions. Babarit et al. (2018) [104] found that alkaline electrolyzers yielded slightly lower LCOH than PEM in their scenario, underlining how technology choice and efficiency play a role when other assumptions are fixed. Overall, it can be synthesized that electricity price, capacity factor, and capital cost are the three “factors” that most strongly govern LCOH. To improve interpretability, a harmonized comparison

Table 9. Comparison of reported levelized cost of hydrogen (LCOH) ranges across offshore wind-to-hydrogen studies and their convergence under harmonized assumptions.

Study (Year)	Original LCOH Range (USD/kg)	Key Original Assumptions Driving Spread	Harmonized LCOH Under Common Inputs (USD/kg)
Loisel et al. (2015) [102]	4–14	Wide CAPEX scenarios; early offshore concepts; high uncertainty	6–8
Morgan et al. (2017) [103]	9–12	Higher electricity price; detailed offshore infrastructure	6–8
Babarit et al. (2018) [104]	3.8–10.2	Mobile fleets; long-term optimistic vs. short-term pessimistic	6–7
Dinh et al. (2021) [106]	5.4	EUR 5/kg viability threshold; storage-sensitive	5–6
Song et al. (2021) [107]	1.8–2.0	Very low electricity cost; optimized export chain	5–6
Rogeau et al. (2023) [92]	4.5–7.5 (2020); 1.5–3 (2050)	Geospatial optimization; future wind cost decline	6–7 (2020 basis)
Cheng and Hughes (2023) [108]	1.5–4.0	Extremely low wind LCOE (AUD 43/MWh)	5–6
Albalawi et al. (2025) [109]	6.5–8.0	Floating foundations; high near-term CAPEX	6–7
Almeida et al. (2024) [1]	4.8	Favorable Brazilian offshore wind	5–6
Travaglini et al. (2025) [72]	3.2–11.2	Configuration-dependent (C-OFF, D-OFF, onshore)	5–8
Lanni et al. (2025) [111]	5.4–6.5	Mediterranean wind costs; realistic CAPEX	5–6
Niblett et al. (2024) (review) [5]	4–6	Synthesis of recent studies	5–6
Ramakrishnan et al. (2024) (review) [42]	4–10	Broad scenario coverage	5–7

is provided to show how differing studies converge (LCOH 5–8 /kg) when aligned to common inputs: commercial AEL/PEM, mid-range electricity cost (USD 60/MWh), 50% capacity factor, and discount rate of 6–8%. Policymakers and developers should interpret raw LCOH values with these assumptions in mind, e.g., a project at USD 5/kg might simply be benefiting from a lower assumed power price, rather than fundamental design superiority. By normalizing these factors, the credibility of cross-study comparisons improves, giving confidence that offshore wind-to-hydrogen can reach USD 2–USD 4/kg in the long term if both power costs and electrolyzer costs decline as projected.

As projects demonstrate basic feasibility, the integration of offshore wind and hydrogen faces several significant challenges that must be overcome for large-scale commercialization. These challenges span technical, economic, environmental, and infrastructural domains:

8.1. Technical Challenges (System Reliability and Marine Harshness)

Offshore OW2H systems must operate in a harsh marine environment. Constant salt spray, high humidity, and strong waves/winds accelerate corrosion and equipment degradation [97]. This affects all components, including wind turbines, electrolyzers, pipelines, and electrical systems, necessitating “marine-grade” engineering (special coatings, cathodic protection, durable materials) to prevent frequent failures. In addition, Electrolyzers on floating or fixed platforms must withstand motion, vibrations, and the harsh marine environment [40]. These stresses can accelerate wear of electrolyzer stacks and balance-of-plant components. Unlike a steady onshore power supply, offshore electrolyzers must handle highly variable power input as wind fluctuates. Also, converting offshore wind-to-hydrogen involves multiple energy conversion steps where inefficiencies compound. Wind turbines generate electricity, which must be transmitted (with some losses) and converted to DC for electrolysis. Electrolyzers typically operate at 60–70% efficiency (meaning 30–40% of energy is lost as heat) [79]. If wind power is intermittent, electrolyzers may often run at partial load or be idled, which lowers overall utilization efficiency. Running electrolyzers off their optimal steady-state point further increases the energy per kg H₂ produced. Additional losses occur if hydrogen is then compressed, transported, or converted to other carriers (ammonia, etc.). Zhao et al. [116] notes that the end-to-end efficiency (wind to hydrogen energy) can be below 30% once all losses are included. While some losses are unavoidable, improving overall efficiency is a challenge as it requires minimizing conversion steps (e.g., using direct coupling of turbines to electrolyzers at appropriate voltages), capturing waste heat (from electrolyzers) if possible, and using high-efficiency components.

Furthermore, due to wind’s variability, hydrogen production from wind power is intermittent, which challenges users who need a steady supply. Without mitigation, either costly hydrogen storage or flexible demand is required. Solutions include on-site storage, oversizing systems, or hybrid energy setups. Offshore storage options like seabed caverns are still experimental and expensive. Therefore, managing production fluctuations through buffering, demand management, or grid support is essential for viable wind-to-hydrogen systems. For example, Li et al. (2025) [117] demonstrate that coupling a Weather Research and Forecasting (WRF) numerical simulation with a deep learning correction model can significantly improve short-term wind power forecasting accuracy. Accurate wind prediction is crucial for OW2H systems, as it allows proactive adjustment of electrolyzer operation to buffer the inherent wind power fluctuations. By using such hybrid simulation and AI approaches, operators can better anticipate and mitigate the effects of wind intermittency, reducing forced electrolyzer downtime and optimizing hydrogen production scheduling. Likewise, machine learning can be applied for predictive maintenance; models trained on equipment performance data can predict component degradation or failures before they happen, enabling timely maintenance in the challenging offshore environment.

8.2. Economic and Financial Challenges

All reviews agree that offshore green hydrogen is currently expensive. OW2H projects require very high upfront capital expenditures. They combine the costs of offshore wind farms (already capital-intensive) with those of electrolyzer systems and hydrogen infrastructure (compression, pipelines, or ships, storage). Building an offshore electrolyzer platform adds significant expense—a bespoke platform, possibly floating, with equipment that must be marinized and possibly explosion-proof, etc. Currently, the Levelized Cost of Hydrogen (LCOH) from offshore wind is estimated to be substantially higher than hydrogen from fossil fuels or even from onshore renewables, primarily due to these capital costs and the nascent state of the technology. Without subsidies or carbon pricing, most projects are not financially viable yet. At present, LCOH estimates often range from USD 5 to USD 10/kg for early projects, which is a multiple of current fossil-derived hydrogen costs. This cost gap means that robust financial support (grants, tax credits, contracts-for-difference) is often required to make the first projects viable. Also, accurately evaluating the cost–benefit of offshore wind-to-hydrogen (OW2H) systems is difficult due to uncertain future variables such as electrolyzer costs, offshore wind prices, and carbon markets. Techno-economic models rely on assumptions that vary widely, e.g., if electrolyzer costs fall significantly by 2030, OW2H becomes more viable; if not, it may remain uneconomical. Furthermore, like many renewables, OW2H is expected to benefit from economies of scale and learning-by-doing. However, reaching those scale benefits requires initial investments in manufacturing and supply chains that are not yet in place. There is thus a near-term challenge of high specific costs until a critical mass is reached. This is where government can play a role in helping jump-start scale via coordinated projects or “hubs.” Additional uncertainties include the future price of green hydrogen and potential revenues from byproducts or grid services. Investors also perceive risk in unproven offshore H₂ technology, which raises the cost of capital. Thus, costs will drop with large-scale deployment and learning, but large deployment will not happen until costs drop or someone underwrites the initial losses. Overcoming the financing challenge will likely require a combination of government incentives, public–private partnerships, and risk-sharing mechanisms to fund early projects.

Also, the reported TRLs carry direct implications for project bankability, financing conditions, and deployment timelines. In general, technologies at TRL 8–9, meaning they are proven in an operational environment, are considered bankable by commercial financiers because they offer a documented performance history and predictable risk profile. Conventional monopile or jacket foundations (TRL 9) and PEM electrolyzers with decades of onshore deployment (TRL 8–9) exemplify such maturity, enabling projects to access project finance at a lower weighted average cost of capital. In contrast, components at TRL ≤6–7, corresponding to prototype or demonstration stages, are met with investor caution. Floating offshore wind-to-hydrogen projects illustrate this challenge: floating wind platforms (e.g., semi-submersibles at TRL 7) and especially novel electrolyzer concepts such as direct seawater AEM electrolysis (TRL 5) carry elevated technical and operational uncertainty. This increased risk translates into higher financing costs, partial risk exclusion by lenders, or the need for government guarantees and public funding. Consequently, early OW2H projects often depend on public support to bridge the transition from TRL 6 to TRL 8, as banks and insurers typically require successful demonstrations before assuming full exposure.

In practical terms, lower TRL levels introduce cost and schedule contingencies that further constrain investment. Developers must account for potential redesigns, performance shortfalls, or delays, which can deter private capital. A technology at TRL 5 today is also unlikely to be deployed at scale within the next five years without intermediate pilot projects. For example, solid oxide electrolyzers, currently around TRL 5 for offshore applications, are not expected to contribute to 2030 deployment targets; instead, PEM electrolyzers (TRL 8–9) will dominate initial commercial projects. Similarly, floating hydrogen platforms are unlikely to be fully bankable until pilot plants advance them from TRL 7 to TRL 8, potentially between 2025 and 2027. Lenders commonly require formal technology qualification or certification (e.g., DNV-type processes), effectively demanding TRL 8 before approving project finance. As a result, technologies at TRL 8–9 in the mid-2020s, such as fixed offshore wind and PEM electrolysis, are expected to dominate near-term deployments, while advanced concepts like AEM electrolyzers or subsea hydrogen storage (TRL 4–5) will remain in the demonstration phase until after 2030. This does not diminish their long-term importance; rather, it highlights that achieving short-term deployment targets requires deploying mature technologies now while systematically de-risking emerging ones. Ultimately, TRL functions as a proxy for investment risk, and the bankability gap between TRL 9 and TRL 6 technologies is a key determinant of OW2H rollout. Recognizing this linkage in roadmaps is essential, as realizing large-scale offshore hydrogen by 2035–2040 will depend on today’s early-stage concepts advancing to full maturity within the coming decade.

8.3. Life-Cycle Environmental Footprint

Beyond operational emissions (which are essentially zero for green hydrogen production, it is critical to consider the embodied (life-cycle) emissions of offshore wind-to-hydrogen systems. Manufacturing and installing offshore wind turbines, platforms, electrolyzers, desalination units, and pipelines entails significant energy and material use, which translates into upfront CO₂ emissions. For example, fabrication of large steel components (monopiles, jackets, pipeline segments) and concrete gravity bases has a considerable carbon footprint. One life-cycle assessment (LCA) study of a 77 MW offshore wind farm with on-site hydrogen found that the green hydrogen’s life-cycle GHG emissions can be below 1 kg CO₂ per kg H₂ [118]. This is dramatically lower than conventional “grey” hydrogen from fossil fuels, with typical life-cycle emissions of approximately 9–12 kg CO₂e per kg H₂ for natural-gas-based SMR, and 18–30 kg CO₂e per kg H₂ for coal gasification hydrogen [119]. Balaji and You (2024) [110] similarly project life-cycle emissions under 4 kg CO₂e/kg H₂ delivered at shore for U.S. offshore projects, well below typical thresholds for low-carbon hydrogen. However, these benefits only materialize after an initial carbon payback period; the CO₂ emitted to build the turbines, platforms, and electrolyzers must be offset by the clean hydrogen produced. For offshore wind farms, this carbon payback is on the order of months to a few years of operation, and adding hydrogen production extends it slightly (due to added equipment), but still within a few years.

From a life-cycle perspective, the dominant environmental advantage of OW2H is the avoidance of operational emissions, but ensuring truly minimal total GHG impact requires attention to the upstream factors. Thus, employing LCA in project planning along with design for recyclability and end-of-life management of components is required. For instance, turbine blades and electrolyzer stacks should have recycling pathways to prevent waste and recover materials. Overall, taking a holistic LCA approach aligns with the decarbonization goals by confirming that offshore wind-to-hydrogen systems deliver a net positive climate benefit. Continuous improvement in materials and manufacturing (and using renewable energy in those processes) will drive this down further, ensuring that offshore hydrogen truly supports deep decarbonization.

8.4. Regulatory and Permitting Hurdles

While many countries now have ambitious OW2H targets (as summarized above), translating these into projects faces non-trivial regulatory hurdles. A critical barrier is offshore permitting. Most jurisdictions have established processes for permitting offshore wind farms, but adding hydrogen production (electrolyzers, pipelines, etc.) introduces new complexity. Developers often must navigate multiple permitting frameworks, one for the wind farm and separate ones for an industrial chemical plant or gas infrastructure, because an integrated OW2H project does not fit neatly into existing categories. This fragmented permitting can significantly delay projects. For instance, an offshore wind farm might get its consent in a considerable amount of time, but obtaining approval for an electrolyzer platform and hydrogen pipeline could add years of additional regulatory review, pushing timelines out further than a wind-only project. Streamlined, unified permitting for OW2H is not yet common, though some countries are moving in that direction (e.g., Germany’s draft regulations now explicitly include offshore hydrogen facilities) [120]. Until such frameworks are in place, OW2H developers face uncertainty and extended lead times, impacting investment decisions.

Another emerging issue is hydrogen certification and grid codes. Guarantee-of-origin schemes for hydrogen (to certify it as “green”) are being developed in the EU and elsewhere, but questions remain on how to certify hydrogen produced offshore: how to verify the renewable input and track it, especially if the system is hybrid-fed by grid power at times. Clarity in certification is needed so that offshore H₂ can count toward national green hydrogen targets and earn premium pricing.

Cross-border infrastructure is another frontier: Europe’s vision of transnational hydrogen pipelines in the North Sea, for example, raises questions of jurisdiction and regulatory alignment. Maritime law (UNCLOS) and bilateral agreements will govern any international offshore hydrogen pipelines. Today, no dedicated offshore H₂ pipeline exists; the first movers must navigate untested legal waters, which could delay projects that plan to send hydrogen to a different country. Regulatory uncertainty around who authorizes and oversees an offshore H₂ pipeline (and how safety is regulated across EEZ boundaries) may extend project development times until treaties or EU directives clarify this. Similarly, standards for hydrogen pipelines (materials, allowable blends) are still being finalized; without them, investors perceive higher risk in building long pipelines for hydrogen.

Deployment timelines will thus depend not just on technology readiness but heavily on regulatory agility. An OW2H project might be technically feasible by, say, 2028, but if permitting and codes are unresolved, it could slip to 2030+ before operation. As a result, some national strategies (like in the UK and Netherlands) are now explicitly addressing these barriers, e.g., creating one-stop permitting processes for offshore energy hubs, clarifying that offshore hydrogen production is an allowable use of offshore leases, and funding studies on hydrogen pipeline regulation. Reducing regulatory uncertainty (through clear rules and streamlined processes) could accelerate deployment by a few years, which is crucial for meeting 2030 targets. Conversely, if these barriers remain, even well-funded projects may face protracted timelines. In summary, offshore permitting, hydrogen certification, grid integration rules, and cross-border regulations are key non-technical factors that will directly affect how quickly OW2H moves from pilots to large-scale reality. Policy-makers need to harmonize and update these frameworks in parallel with technology development.

8.5. Energy Management and Control Strategies

Efficient operation of an OW2H system requires advanced energy management to handle the variability of wind and optimize hydrogen production. One key challenge is to smooth power fluctuations to avoid frequent electrolyzer shutdown or load cycling, which can reduce efficiency and stack life. Research demonstrates that by using a supercapacitor to absorb short-term wind gusts and an adaptive control scheme for the electrolyzers, the switching (on/off) frequency of electrolyzer units can be reduced by over 90%, while hydrogen output increases by 44% compared to naive control [121].

Control architectures range from simple feedback loops to complex model-predictive control. For instance, Monroy-Morales et al. (2024) [122] evaluate different control structures for combined offshore electricity and H₂ production, showing that proper coordination between grid export and hydrogen maximizes overall value. In practical terms, an offshore wind farm with hydrogen could be operated in two modes: if power output exceeds grid demand or is during low price periods, more power is diverted to electrolyzers; during high price periods or grid needs, hydrogen production is throttled down. Implementing this requires real-time optimization. Forecasting integration is critical: AI-driven algorithms can forecast near-term wind output and electricity prices and pre-emptively adjust electrolyzer loads. By forecasting wind ramps, the system can, for example, preemptively lower electrolyzer consumption ahead of a predicted lull (preventing an abrupt shutdown), or conversely ramp up hydrogen production when a surplus is expected. This kind of predictive control smooths operations and can align hydrogen output with periods of low grid value, improving economics.

Overall, integrating robust control architectures is crucial for OW2H viability. Without smart energy management, an offshore hydrogen system might experience inefficient operation (e.g., electrolyzers idling during wind dips or wearing out due to constant on-off). With advanced control, as studies show, the system can maintain high utilization and even provide grid support. This review emphasizes that future research and pilot projects should devote attention to control strategies on par with hardware innovations. Developing standard control algorithms for hybrid wind–hydrogen plants and demonstrating them (perhaps as part of national hydrogen hub programs) will pave the way for optimized, digitalized OW2H farms. In the next section (Section 9), we noted how AI and big data are poised to enhance operations. Indeed, the convergence of digital optimization with offshore hardware is a key enabler for scaling up OW2H.

8.6. Infrastructure and Supply Chain Constraints

Developing OW2H at scale requires building substantial new infrastructure to handle hydrogen. If hydrogen is produced offshore, subsea pipelines might be needed to transport it to shore. Laying new hydrogen pipelines or repurposing natural gas pipelines raises technical issues: hydrogen can embrittle steel over time, so materials and operating conditions must be carefully chosen; compressors and valves need to be hydrogen-compatible. Long undersea pipeline projects also face high capital costs and maintenance challenges (similar to gas pipelines, but with fewer existing examples for hydrogen, so with higher risks). Alternatively, shipping hydrogen by ship (either as liquid H₂ or converted to ammonia or methanol) requires infrastructure like floating or fixed ammonia storage, specialized tanker ships, and port facilities for loading/unloading. These do not exist yet at scale and would need parallel development. On the storage side, buffering production could involve pressurized storage tanks on platforms or at onshore terminals, or potentially underground salt caverns if geology permits; the latter has been proposed (e.g., storing H₂ in seabed salt caverns near wind farm sites), but there is no real-world demonstration yet. Each infrastructure element (platforms, pipelines, storage, and ships) entails huge investment and coordination. Many coastal regions currently lack any hydrogen pipeline network, so OW2H projects must start from scratch. If, instead, electricity is brought to shore and hydrogen is produced on land, then the existing grid must be upgraded to handle large power inflows, or new HVDC export links must be built, which is another form of infrastructure challenge. In short, the entire supply chain from production to end-use needs development. The timing mismatch is tricky as it is not useful to produce massive hydrogen offshore if pipelines or markets are not ready to take it, and conversely, nobody will build pipelines if there is no hydrogen supply yet. Overcoming this requires integrated planning (e.g., governments planning “hydrogen valleys” where production, transport, and use are developed in concert). It also requires standardizing hydrogen infrastructure (valves, compressors, purity standards) to ensure interoperability.

In sum, while offshore wind-to-hydrogen systems are technically feasible and hold immense promise, a range of formidable challenges must be addressed. The next section will interpret these findings in the broader context of energy transition goals, analyze how the identified challenges can be mitigated, and highlight the compelling opportunities that drive the continued interest in OW2H despite the hurdles.

9. Opportunities and Future Perspectives

Despite the challenges detailed above, offshore wind-to-hydrogen integration offers powerful opportunities that make it a potentially transformative element of the future energy landscape. This review identified multiple areas where OW2H can provide significant benefits and open new pathways:

9.1. Market and Economic Opportunities

Offshore wind represents an immense, untapped renewable resource in many regions. By harnessing this vast resource for hydrogen production, countries can generate large quantities of green hydrogen, far beyond what limited onshore renewables could supply. Many industrialized regions with high energy demand (e.g., Northern Europe, East Asia, U.S. coasts) also have excellent offshore wind potential nearby, offering the chance to produce clean hydrogen locally at scale for use in steel mills, chemical plants, refineries, and transport hubs that are often located in coastal areas. Unlike onshore renewables, offshore wind farms can be sited far from population centers, minimizing land-use conflicts and easing public acceptance for deploying very large capacities. This abundant resource opportunity means OW2H could become a cornerstone for meeting national and regional hydrogen demands in a sustainable way.

OW2H systems not only produce renewable energy but also enhance grid stability by converting surplus wind power into hydrogen. This allows excess energy to be stored instead of curtailed, and used later during low wind or high demand periods, improving wind utilization and mitigating intermittency. Electrolyzers can also act as flexible grid assets, quickly adjusting power intake to support frequency and voltage regulation. This integration boosts energy system resilience and enables greater renewable penetration.

At the same time, OW2H opens access to large and growing markets for green hydrogen in industries like ammonia production, refining, steelmaking, and heavy transport. These sectors consume vast amounts of hydrogen, and replacing fossil-based sources with green hydrogen offers significant decarbonization potential. OW2H also provides flexibility, allowing producers to target the most profitable markets, including global exports through hydrogen derivatives like ammonia or methanol. Even electrolysis byproducts, like oxygen, can add value. Together, these revenue streams support economic growth, job creation, and a transition for offshore oil and gas workers into clean energy sectors.

Producing hydrogen from domestic offshore wind enhances energy security by reducing dependence on imported fossil fuels. Countries with strong offshore wind resources can create a stable, local supply of clean fuel for key sectors, shielding themselves from volatile global energy markets. For example, the UK or Germany could use North Sea wind to produce hydrogen and reduce natural gas imports for industry. Some countries, like Australia, see green hydrogen as a future export product, aiming to supply markets such as the EU, which plans to import up to 10 million tons of renewable hydrogen by 2030.

9.2. Technological and Innovation Opportunities

The technical challenges facing OW2H also highlight clear opportunities for innovation that can enhance its viability. Electrolyzer technologies are rapidly improving, with ongoing research focused on cheaper catalysts, higher current densities, and longer lifespans, developments that could significantly reduce hydrogen costs. Offshore-specific electrolyzer designs, such as compact, modular systems resistant to motion and salinity, are a promising area for R&D. Advances in materials, including anti-corrosion coatings, durable alloys, and membranes that tolerate impure water, could improve long-term performance in harsh marine environments.

Wind technology is also evolving, with next-generation turbines (15–20 MW+) and mass-producible floating foundations expected to cut offshore wind costs, thereby lowering the cost of hydrogen production. Innovative system designs are emerging as well, for example, integrating electrolyzers within turbine bases to minimize cable losses, or creating multi-functional “energy islands” that combine wind, solar, storage, and electrolysis infrastructure. These integrated approaches could streamline operations and improve efficiency, offering promising pathways to scale OW2H more affordably and reliably.

OW2H opens the door to innovative system designs that enhance performance and efficiency. Hybrid offshore setups combining wind, solar, and wave energy can deliver a more stable power supply to electrolyzers, as shown in pilot projects. Thermal integration, such as using waste heat from compressors or fuel cells to warm solid oxide electrolyzers, can further boost efficiency. Adding onboard energy storage like batteries or ultracapacitors helps smooth short-term power fluctuations and optimize electrolyzer use. Another promising area is direct seawater electrolysis, which eliminates the need for desalination by using special catalysts to handle seawater impurities, potentially simplifying and reducing the cost of offshore hydrogen production.

Digital technologies offer powerful tools to enhance OW2H efficiency and reduce costs. AI, big data, and automation can optimize operations without major capital investment. For instance, digital twins can model OW2H systems in real time, helping to maximize hydrogen output and extend equipment life. AI can forecast wind patterns and adjust electrolyzer loads to stabilize production or align with low electricity prices. Autonomous systems for turbine inspection and underwater cable checks can lower offshore maintenance costs and improve safety. These smart solutions unlock greater value from existing infrastructure and streamline operations across the OW2H value chain.

In summary, the technological trajectory for OW2H is very encouraging. Innovations in renewables, electrolysis, digital control, and system integration are continuously emerging, many of which directly tackle the current barriers. The confluence of these advancements provides a strong basis to believe that today’s challenges can be progressively mitigated. In the next section, it is discussed how these opportunities, combined with supportive policy and collaborative strategies, can be leveraged to drive offshore wind-to-hydrogen forward, and what implications this has for stakeholders.

9.3. Policy and Regulatory Landscape

The policy and regulatory environment for OW2H is rapidly evolving as governments and international organizations recognize its importance for climate goals. At the global level, bodies like IRENA and IEA highlight green hydrogen’s role, while frameworks such as the Paris Agreement and forums like IPHE encourage knowledge sharing and funding for clean hydrogen initiatives, though without binding rules.

Regionally, the EU leads with clear targets and funding, linking offshore wind with hydrogen in its hydrogen strategy and national programs. Countries like Germany, the Netherlands, and the UK are actively supporting OW2H through roadmaps, funding schemes, and emerging support models like Contracts for Difference. Outside Europe, nations such as Australia, Japan, and South Korea are beginning to align offshore wind policies with hydrogen ambitions, with Australia permitting its first offshore wind zones and Japan funding offshore hydrogen pilots.

Permitting remains a bottleneck, as many countries lack streamlined processes for OW2H, forcing developers to navigate fragmented systems. Some nations, like Germany and the UK, are now adapting laws and regulations to cover offshore hydrogen infrastructure. Standards and certification for offshore hydrogen are also progressing, with bodies like DNV and ISO developing guidelines and certification schemes expanding to cover electrolytic hydrogen, supporting market growth and traceability.

Financial incentives and funding programs, such as the EU Innovation Fund, Germany’s H₂Global, and the US Hydrogen Shot, are de-risking OW2H investment and accelerating pilot projects. Additionally, maritime law, especially UNCLOS, governs offshore activities and will influence future international hydrogen pipelines and cross-border projects.

In summary, policy support for OW2H is strengthening, with growing targets, funding, and regulatory clarity, but continued work is needed to fully harmonize and enable large-scale, integrated offshore wind-to-hydrogen projects.

9.4. Strategic Implications for Stakeholders

Technological advances are promising, but achieving commercial scale will depend on supportive and sustained policy frameworks. Policymakers play a pivotal role by setting clear long-term targets, providing financial incentives, and streamlining permitting processes, ideally through coordinated, single-agency approvals. It is vital to maintain consistent policy signals and avoid frequent reversals or limited-duration pilots, as the industry needs confidence that support for OW2H will last over decades. Harmonizing standards and certification at both national and international levels will also help reduce risk and enable market growth.

For the industry, cross-sector partnerships are essential. Wind developers, electrolyzer manufacturers, and offshore engineering firms should work together from the outset, leveraging each other’s strengths to develop robust, bankable projects. Anticipating future demand by scaling up manufacturing and supply chains ahead of time will enable faster cost reductions and wider market adoption. Standardizing designs and components across projects can also reduce costs and accelerate deployment. A phased project approach, starting with pilots, then moving to demonstration and commercial scale, helps manage technical and financial risk, allowing stakeholders to build expertise and supply chain relationships for long-term success.

Ultimately, OW2H should not be viewed in isolation but as an integral part of the broader energy transition, linking offshore renewables, hydrogen infrastructure, and industrial decarbonization strategies. National energy planners, industry, and end-users must coordinate to align wind farm locations, hydrogen production, and demand centers, preventing mismatches and optimizing value. The shift toward this kind of integrated, systems-based planning is already visible in leading countries and should become standard practice.

10. Conclusions

Offshore wind-to-hydrogen (OW2H) systems embody a promising intersection of renewable energy generation and clean fuel production. This review highlighted that offshore wind offers clear advantages for green hydrogen, thanks to its high-capacity factors and vast resource potential, enabling more consistent and large-scale power supply to electrolyzers compared to many land-based sources. Recent advances in turbine technology, particularly the emergence of larger, more cost-efficient, and floating turbines, along with technical progress in alkaline and PEM electrolyzers, have moved the field forward. Pilot projects in Europe and Asia have shown that the key components of OW2HS, from powering electrolyzers with offshore wind to handling hydrogen production offshore, are technically feasible. The rapid increase in global interest, supported by government strategies and corporate investment, further indicates strong momentum toward scaling up OW2H.

However, realizing the full potential of OW2H still depends on addressing several notable challenges. The marine environment introduces engineering demands such as corrosion resistance, reliable desalination, and integration of variable wind with electrolyzer operation. Economically, offshore hydrogen is still costly compared to fossil-based alternatives, and the supporting infrastructure, such as pipelines, storage, and conversion facilities, is only beginning to develop. The lack of commercial-scale projects means there is limited real-world data on performance and cost at scale, and while policy and regulatory frameworks, though improving, are often not yet fully adapted for offshore hydrogen, which causes uncertainties around permitting, standards, and market access. Environmental and social impacts, such as effects on marine ecosystems and coexistence with other ocean uses, must also be managed. Nonetheless, these barriers are countered by strong innovation, potential economies of scale, targeted policy support, and growing collaboration across sectors, all of which can significantly reduce or overcome these hurdles.

The opportunities offered by OW2H are substantial. Successfully integrating offshore wind and hydrogen could be transformative for global decarbonization, enabling emission reductions in hard-to-electrify sectors like steelmaking and shipping, while boosting energy security and grid flexibility by turning surplus wind into storable, versatile fuel. For wind-rich regions, OW2H could also open lucrative export markets for green hydrogen and ammonia, and as the sector expands, it will drive job creation and new industrial activity across manufacturing, engineering, and operations. Importantly, OW2H also presents an elegant solution to renewable intermittency by allowing wind farms to maximize output through hydrogen production.

In summary, OW2H is technically feasible and offers significant environmental, economic, and energy system benefits. Achieving its large-scale deployment will require continued innovation, infrastructure buildout, and supportive policy frameworks, but the trajectory marked by rapid technological progress, increasing demonstration projects, and strengthening policy backing suggests that these challenges are surmountable. Offshore wind-powered hydrogen is emerging as a vital, achievable pillar of a low-carbon energy system, capable of bridging the gap between abundant renewables and sectors that are otherwise difficult to decarbonize.

Limitations and Future Recommendations

Despite the comprehensive scope of this review, several limitations must be acknowledged. First, most analyzed studies are simulation-based or small-scale pilots, which introduces uncertainty; real commercial-scale performance may differ. Second, the data synthesis relies on published information that may not capture confidential or proprietary technology developments; thus, some parameter ranges could evolve rapidly. Third, the review focuses on broad system configurations and does not perform original techno-economic optimization; detailed modeling is needed to quantify costs and performance under specific site conditions. Finally, emerging technologies (e.g., direct seawater electrolysis, AEM, and proton-conducting SOECs) are still at low TRL and may change the landscape as they mature.

Several priority research directions emerge that will be critical for enabling the large-scale deployment of offshore wind-to-hydrogen (OW2H) systems over the next decade.

• Offshore-Optimized Electrolyzer Technologies

Future research should focus on improving the long-term durability of electrolyzers under offshore conditions, including corrosion, humidity, motion, and highly dynamic power input. While PEM electrolyzers are currently the most suitable option, advances in AEM and seawater electrolysis could significantly reduce costs if stability and lifetime issues are resolved through offshore pilot demonstrations.

2.

Materials and Corrosion Resistance

The development of corrosion-resistant materials, coatings, and hydrogen-compatible alloys is essential to reduce maintenance needs and extend component lifetimes for offshore platforms, pipelines, and storage systems. Progress in this area will directly improve reliability and economic viability.

3.

Energy Management and Digital Control

Advanced control strategies integrating wind forecasting, hydrogen demand, and electricity market signals should be further developed and validated. Digital twins, AI-based forecasting, and power-smoothing approaches can improve electrolyzer utilization, reduce degradation, and enhance overall system efficiency.

4.

Cost Reduction, Standardization, and Bankability

Achieving competitive hydrogen costs will require component standardization, modular offshore designs, and large-scale demonstrations. Linking technology readiness levels to financing, insurance, and risk allocation frameworks is critical to accelerate the transition from pilot projects to commercial deployment.

Addressing these priorities through coordinated research, demonstration, and policy support will be essential for transforming offshore wind-powered hydrogen into a mature and competitive pillar of the global decarbonized energy system.