• Gautier Houriez

Windrogen: North Sea opportunities for green hydrogen production


The demand for hydrogen as a new energy carrier is on the rise. However, today, most of its production remains closely linked to polluting sources of energy. In parallel, in the North Sea, offshore wind capacity has boomed during the last decade. In the same area, many aged oil and gas rigs are reaching the end of their lifespan, triggering decommissioning and renovation issues.


With the combination of these three factors, several opportunities for green hydrogen production in the North Sea exist, as demonstrated by recent studies and projects in Europe. As an important pillar of the energy transition in Europe, Greenfish looks further into this potential. What are the challenges faced by the industry to produce this so-called “green hydrogen?” Is it a long-term scalable solution to a carbon-neutral world? Is it economically viable? Join us for a quick overview of this booming sector.





Back to Basics: Offshore generated power


During the last ten years, offshore wind power generation has experienced a real expansion in Europe. The cumulative installed capacity in Europe went from around 0,5 GW in 2009 to more than 22 GW in 2019 [1]. This major growth is mainly happening in the North Sea as the projects are propelled by four countries: The United Kingdom (UK), Germany (DE), Denmark (DK), and Belgium (BE).



IEA, IRENA


The main improvement to be made in the sector is to streamline production to make turbines more powerful and easier to install. The average installed turbine capacity has more than doubled, going from around 3 MW to just under 8 MW, and the average wind farm capacity has followed this trend, reaching an average 600 MW in 2019, while it was only 200 MW in 2009.


However, due to the reduction of suitable spots, wind farms are now being installed further away from the coast and in deeper water, therefore increasing the costs and difficulties of installation and land connection. The water depth for new projects has reached an average of 33m in 2019, with one project reaching 220 m depth. At the same time, the distance between new wind farms and shores has increased from around 15 km to around 60 km [1].


Back to Basics: Hydrogen uses and generation


Today, hydrogen is mainly used in industry for oil refining, chemical production (mainly ammonia, 27%, and methanol, 11%), iron and steel production, and high-temperature heat (other usages than chemical, iron and steel production) as displayed on Figure 1.


By 2030, each of these fields is expected to grow respectively by 7%, 31%, 100%, and 9% according to the IEA [2], complemented by a rise in the use of hydrogen in other areas such as transport, buildings, and power. As a result, the hydrogen market is expected to grow exponentially.



Depending on the energy used for its production, hydrogen takes on different virtual “colours”. “Green” hydrogen is most often obtained by water electrolysis using renewable electricity. The “blue” one is generated from natural gas and involves CO2 capture (Carbon Capture Utilization and Storage, CCUS). Gas-generated hydrogen without CO2 capture is coloured grey. Finally, hydrogen produced from coal is coloured black [3]. These colours are linked to the amount of CO2 emitted by the production process (only the CO2 emitted during the process is recorded in Figure 2).


CO2 emissions of H2 production depending on the energy used during its production


Today, 76% of hydrogen is producedfrom natural gas and 23% from coal (representing 6% of global natural gas consumption and 2% of global coal consumption). Only 2% is currently produced by electrolysis[2]. Despite the high carbon emissions of grey, black and even blue hydrogen, these technologies remain dominant due to their attractive prices (below 2.5 US$/kgH2 produced [2]).

Water electrolysis - a process intensive in electricity

Electrolysis splits water atoms into H2 and O2 thanks to electricity. The chemical reaction involved is simple: 2 H2O = 2H2 + O2 ; and releases twice the amount of hydrogen as oxygen.


Its use today is mainly associated with the need for extremely pure hydrogen. The overall efficiency of this process is set between 60% and 81%, which is quite low. To give an idea of the magnitude, if the entire hydrogen demand were to be supplied by electrolysis, this would require 3600 TWh/year. This is the annual electricity production of the European Union; a tremendous amount of energy.

Using hydrogen: Electrical connection issues of intermittent energy production sources


Hydrogen production by electrolysis could provide additional flexibility to a constrained power system. For example, by reducing curtailment[1] in grids with a high share of variable renewable electricity. However, it is probably not possible to produce significant amounts of hydrogen using exclusively cheap or free (“otherwise curtailed”) electricity. In this case, electrolysers would only operate about 10% of the time or even less. Given this utilisation rate, the hydrogen produced might not be competitive despite zero-cost electricity, unless the cost of the electrolyser drops significantly.


To reduce the cost of hydrogen production, electrolysers should have a higher utilisation rate, which is not compatible with the occasional availability of curtailed electricity. A balance needs to be struck between purchasing electricity at times when prices are low and increasing the utilisation of electrolysers [2]. Regarding the improvement of the flexibility of the system, other options exist and should be more profitable.


Modern electrolysers can ramp their production up and down on a time scale of minutes or even seconds, and further improvements are expected in the future. From a technological point of view, PEM (Polymer Electrolyte Membrane) electrolysers are able to respond faster than conventional alkaline electrolysers, which partly explains why they are prominently featured in future studies despite their emerging status.


Electrolysers can be strategically placed to ease power grid congestion and to transport hydrogen instead of electricity, thus helping to avoid curtailment from variable renewable energy production. Such a strategy could be considered, for example, in the development of offshore wind power in the North Sea region. Countries have the possibility to transport renewable power either via copper wire or embedded in hydrogen.


In the next section, we will look at several hydrogen projects being developed.

Projects in progress: Gigastack


Gigastack is an award-winning project supported by the UK through the Department for Business, Energy and Industrial Strategy (BEIS) [6,7]. Four industrial entities are involved: ITM Power, Orsted, Phillips 66 and Element Energy.


The goal of the project is to prove that a large-scale green hydrogen production unit using offshore wind turbines and electrolysers can lower production costs. This is part of the UK’s target of zero net greenhouse gas emissions by 2050.


The first phase of the project ended in 2019. It sized 5 MW electrolyser stacks (ITM Power) and evaluated the possible synergies with offshore windfarms (Orsted). It then led to a 100 MW electrolyser market-analysis (Element Energy).


The next step is to carry out a front-end engineering design study and to build a 100 MW electrolyser system [6]. The business plan for a large-scale electrolyser will also be refined, hoping for appropriate regulatory mechanisms. Here are the different scenarios that have been studied:


Scenarios explored in the Gigastack project and associated production costs


Although the scenario 4 is something new and innovative, Gigastack is not the only project studying this opportunity. Tractebel, for instance, is also exploring this option.


Projects in progress: Tractebel (Engie)


Tractebel is working on a new platform designed to contain all the components needed to produce hydrogen, such as electrolysis units to transform the electricity supplied by offshore wind turbines and seawater desalination modules to supply the water needed for electrolysis. A concept of a 400-MW wind-to-hydrogen platform has been designed [7].

As described above, using electricity from offshore wind to produce hydrogen would also help to alleviate congestion in the electricity grid. At the same time, the hydrogen produced could be used to store energy and compensate for seasonal fluctuations in the production from conventional renewables (e.g., solar, wind). Regarding transport issues, hydrogen can be transferred using existing infrastructure such as gas pipelines and storage facilities, or even be stored on ships and transported around the world. In Germany, the federal government is preparing a call for tenders for power-to-gas trials in the North Sea and the Baltic Sea [8].


Projects in progress: Renovation of an old oil and gas platform


In this context of energy transition, the North Sea represents an interesting challenge with more than 600 oil platforms that are beginning to be decommissioned. This can be seen as an opportunity: using these platforms to create energy hubs. Some studies have indeed investigated the possibility of renovating these platforms into power-to-gas hubs, creating synergies by using the existing structure for the conversion and transport of hydrogen. In 2017, a very detailed technical and economic analysis has been published [10], looking at different scenarios for these synergies. It investigated the possibilities for wind farms to produce either gas and electricity or gas only, which differs in the required network infrastructure. The study also looked at whether the platform is still in operation for oil and gas production or not, taking into account the market price of hydrogen. All results are based on data from two platforms, G17 and D18, operated by ENGIE in the North Sea.


This analysis raises several concerns about the technical aspects of these synergies. First, regarding the calculation of the size of the electrolyser, given that the wind is an unsteady source of power and that an electrolyser has a high CAPEX. Sizing comes down to a compromise between the use of maximum power from the wind and the high investment cost. Another challenge is the gas connection. Hydrogen and methane have large differences in their physical properties, requiring the use of different pipes. However, to a certain extent, they can be combined and thus lower the cost if the infrastructure already exists. Finally, the cost of decommissioning an oil and gas platform is not that high, which means that reusing old platforms may be more restricting than cost-saving.


The economic results of these projects (see Figure 5) emphasize a well-known truth about the competitiveness of green hydrogen compared to grey hydrogen. There is no economically viable scenario if the hydrogen is sold at the price of grey hydrogen. Furthermore, the scenario in which the platform is producing both electricity and hydrogen is only viable if it is still in operation, and the production of hydrogen is quite low. Otherwise, the price of the grid connection is too high. Whereas in the case where only hydrogen is produced, the project seems to be feasible as long as there is a market for green hydrogen.


Projects in progress: North Sea wind power hub


As the renovation of oil and gas rig seems to be a tough task, other ambitious projects are considering starting from scratch. This is the case of the North Sea Wind Power Hub, a project that may sound very futuristic. It aims to integrate all the North Sea wind via “energy highways”, as offshore capacity is expected to reach 70 to 150 GW in the area by 2040, and possibly 450 GW by 2050 [9].


This is a Europe-wide project. Countries and energy production units would then be linked by electrical and/or hydrogen connections. The coalition leading this tremendous project is composed of the Port of Rotterdam, Energinet, Gasunie, and Tennet.


Many configurations have been studied, ranging from fully electrical connections to fully hydrogen connections, with two to five countries involved. The location and design of the hubs have also been discussed, but not yet concretised. The North Sea Wind Power Hub claims that the first hub could be operational in the 2030s and is necessary to meet the Paris Agreement on climate change.


This project involves multiple challenges. On the one hand, up to five countries will have to cooperate, which is noteasy. They will have to deal with non-existent legislation, as it is something that has not yet been done. On the other hand, the technological and economic issues related to this project remain the same: developing competitive, carbon-free, and long-term access to electricity and/or hydrogen. Both the long-distance interconnections and the localisation of energy consumption along the coasts are challenging.


Conclusion


At first sight, this paper pointed out that the old oil and gas platforms in the North Sea, coupled with the growing capacity of offshore wind power and the demand for hydrogen, seems to be a great opportunity. Considering the scale of the energy transition challenge, it is fortunate that many coalitions are working on the subject, exploring the feasibility to deliver the cheapest and greenest hydrogen to the coasts.


However, the projects studied in the paper remind that the current costs for hydrogen production from off-shore wind remain extremely high compared to “conventional” - but polluting - hydrogen generation processes. This is happening in an encouraging context where offshore wind farms benefit from an improving economical maturity, which tends to reduce the amount of electrical feed-in tariffs provided by the different governments [11].


Given those two observations, an open question remains debatable for the future of hydrogen in the North Sea:

· Will electricity production from wind sources in the North Sea ever be at a sufficiently low cost to make these ambitious, smart and technologically attractive projects viable?

One thing is certain, it will keep on being an expensive journey. Therefore, to avoid misspending large sums of capital (as these projects require), the consumption of hydrogen (and therefore the planning of its production) should only be limited to cases where it replaces non-electrifiable fossil fuel usages.



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