Shipping is responsible for roughly 3 percent of all carbon dioxide emissions around the globe. The International Maritime Organization or IMO therefore set itself the goal of at least halving this figure by the year 2050, relative to a 2008 baseline. Due to the high power requirements and the large distances traveled by ships, fully electric solutions are only possible in isolated cases. Hydrogen and its derivatives are therefore attracting increasing interest from the maritime industry because of their potential to greatly reduce ship emissions. The challenge in this sector is, firstly, how to store the hydrogen on board safely in a minimal amount of space and, secondly, how to engineer the overall energy system to meet various requirements while optimizing its control.
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The Hitzler Werft shipyard in Lauenburg, Germany, is currently building the Coriolis research vessel for the Helmholtz-Zentrum Hereon research center in Geesthacht. The ship will be fitted with a diesel electric power system in addition to batteries and a hydrogen system. The latter was designed by Hereon together with the DLR Institute of Maritime Energy Systems and the engineering consultancy Technolog in Hamburg.
Hydrogen system lab on board
The hydrogen system lab – H2SL – is designed to be a hydrogen system that is spread across the vessel. The main components are a metal hydride tank, which was developed by Hereon, and a low-temperature proton exchange membrane (PEM) fuel cell. Accompanying these are various pieces of peripheral equipment, such as a bunker station for hydrogen, a tank connection space at the metal hydride tank and two vent masts.
For a comparably small vessel such as the Coriolis, whose length is just under 30 meters (100 feet), extremely careful consideration is needed when arranging the components. One of the reasons for this is because there are no binding regulations yet that govern the use of hydrogen on board.
The definition of hazardous zones and the distances that need to be maintained between ventilation facilities come from the IGF Code, which regulates the handling of low-flashpoint fuels in shipping and has been primarily used for liquefied natural gas up until now. The code does not yet take into account the special properties of hydrogen, for instance its much higher volatility compared with LNG. Among other things, this evident in the size and shape of the hazardous zones (see the spherical hazardous zones around the vents and air inlets). Work on the IGF Code is currently ongoing to extend its scope to include the use of hydrogen.
The tank system, consisting of an actual metal hydride tank and the mandatory inertable tank connection space, will be built on a 5-foot container base plate and have around half the height. In addition to the weight of the metal hydride itself, the overall weight is made up of the steel tank shells, pipework and, in particular, the pressure vessel of the tank connection space. The overall system volume of around 4 cubic meters (140 cubic feet) and an overall system weight of 5 metric tons mean that the tank system stores approximately 30 kilograms of hydrogen.
This allows the fuel cell to supply the ship with roughly 500 kilowatt-hours of green energy. That said, this can only happen if the bunkering of green hydrogen is actually possible and permitted – a challenge in itself, as initial exploratory talks with port authorities and hydrogen producers have shown.
Prior to the shipyard tender, the energy requirement for craft propulsion was ascertained at SVA Potsdam using a model test and subsequently scaled up. The shape of the Coriolis is optimized for operation at low speed as this matches the primary operating profile of inshore journeys (see fig. 3).
Due to the low power requirement for creep speed, the fuel cell, which will have a rated electrical power of around 100 kilowatts, can be used in combination with the battery for numerous monitoring activities and in the other operating states of the Coriolis e.g., during layovers, without having to switch on a diesel engine. As well as the propulsion system, the electrical consumers on board also need to be supplied, although these only require a fraction of the power needed for propulsion.
Metal hydride tanks
From Hereon’s perspective, the following properties make metal hydride or MH tanks attractive for a range of maritime applications:
Moderate loading pressures of well under 100 bar at operating temperatures below 100 °C
Cold start of a MH tank possible in principle even at temperatures below 0 °C (Hereon EP 3 843 190)
By the very nature of MH tanks, the hydrogen is chemically bound meaning the tanks cannot suddenly release large quantities of hydrogen, which is a significant on-board safety advantage.
The low loading pressures allow a flexible structural form which makes it easy to adapt to the shape of the ship à saves space. Today’s pressurized hydrogen tanks take up a lot of room, especially on small vessels, which reduces valuable cargo space.
The high weight can even be advantageous in certain applications, e.g., for sailing ships where it can be used instead of the obligatory “deadweight” ballast for stability.
Research in the H2SL
Hereon and DLR are working together to investigate which types of ship are best suited to the combination of a low-temperature fuel cell and a metal hydride tank for the propulsion system. The goal of the two research institutes is to create a guiding principle that enables the Coriolis energy system concept to be adapted and integrated easily into other ships and types of craft.
The H2SL offers many more opportunities to pursue innovative research approaches in addition to facilitating zero-emission operation. Hereon and DLR are planning an intensive program of research using the power system and are expecting to gain valuable knowledge and real-time data on relevant research issues. This will be made possible by running the H2SL in a real maritime environment with the option to access operating data remotely online and immediately adjust the control parameters. The effects of these changes will then be the subject of further study.
DLR will develop a digital twin of the hydrogen energy system based on the operating data in order to produce a continuous record of the system status, optimize the system control and derive feedback for the operation.
What’s more, the information should allow operational strategies to be developed for the Coriolis’ hybrid energy system. The variation in energy sources, i.e., battery, fuel cell and combustion engine, creates a high degree of flexibility with regard to operation in a wide range of energy consumption scenarios. The goal is to achieve an optimal balance in relation to fuel consumption and operating costs through intelligent load sharing for a wide variety of traveling and loading states.
A benefit of carrying out this kind of investigative work on a research vessel is that strategies developed from theoretical principles can be transferred directly to the energy management system, allowing them to be swiftly validated during operation.
Hybrid energy systems are being built into ships with increasing frequency. The knowledge gained from sailing the Coriolis will supply valuable information in future that can also be transferred to other types of craft and thus contribute toward reducing emissions in the maritime sector.
Hydrogen is the most abundant element in the universe and is a renewable energy source, so it’s no surprise that people are interested in feasible ways to produce more. A particular area of focus involves creating hydrogen from seawater. Here’s a closer look at recent progress in that area.
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Many researchers quickly realize they’re more likely to make meaningful gains by working with other experts with the same focus. That’s the primary concept of a project involving multiple institutions. The goal is to create a prototype that makes hydrogen from low-grade liquids, including seawater and wastewater.
Participants will work toward that goal by relying on experts with knowledge of electrolyzers and membranes. Over the project’s four-year span, researchers hope to find membranes using abundantly available metals like nickel and iron. They also want to find alternatives to options that cause pollution or have persistent adverse effects, making the associated electrolyzers easier to recycle.
Researchers hope to accelerate their prototype-creation process after identifying future options. Ireland’s University of Galway will be the project’s lead institution. However, participating organizations from Israel, Spain and Germany will also be involved.
This project is part of larger European Commission endeavors to find feasible routes toward the increased production of green hydrogen. For example, the recently announced European Hydrogen Bank’s goal is to domestically produce 10 million metric tons of renewable hydrogen by 2030. That amount would be on top of 10 million metric tons sourced from imports.
People could replace hydrogen with fossil fuels if these collective efforts succeed, resulting in cleaner, more environmentally friendly transportation options. Additionally, facilitating hydrogen production could provide the chemical industry with a more sustainable raw material for producing fertilizers, steel and more.
A newly developed electrocatalyst
Many companies are working on achieving net-zero status. However, there’s no single way to do that. One option is to pursue new technologies to reduce greenhouse gas emissions. Researchers also investigate or create pioneering technologies in their quests to get hydrogen from seawater. Electrolysis involves splitting water into hydrogen and oxygen, and improving that process could make hydrogen from seawater more accessible.
Consider how a team from the Texas Center for Superconductivity at the University of Houston (UH) in the United States made a nickel- and iron-based electrocatalyst that interacts with copper cobalt during seawater electrolysis. That achievement could overcome previously identified challenges associated with obtaining hydrogen from seawater. For example, current electrocatalysts used to achieve oxygen evolution reaction (OER) are prohibitively costly.
The researchers determined that the OER electrocatalysts they made were among the best performers of all multimetal candidates. Another exciting revelation is that the associated technology and process could make hydrogen production extremely affordable.
As lead researcher Zhifeng Ren explained, 1 kilogram of hydrogen currently requires about 50 kilowatt-hours of electricity to make. If the rate for grid-sourced power is USD 0.10 per kilowatt-hour, it costs USD 5 per kilogram of hydrogen for the power alone. That’s far too expensive to make the possibility attractive.
However, a feasible workaround identified during this study is to use surplus power produced by wind turbines or solar panels. That approach would make the power cost less than USD 0.01 per kilowatt-hour. Ren clarified that this option only becomes viable if people continue pursuing hydrogen creation methods that rely on green energy. Researchers can apply the things learned now to future developments in this area.
Researchers make improvements
Hydrogen research is moving forward in ways that go beyond seawater. For example, Italy has Europe’s first hydrogen-powered residential building, which doubles as a living lab. A hydrogen fuel cell powered by solar and geothermal sources provides all the facility’s heat and electricity.
However, one of the most appealing things about making hydrogen from seawater is that the liquid is plentiful and easily available. Getting clean power from the liquid becomes a more realistic prospect when scientists develop better ways to split the hydrogen and oxygen in seawater.
A team from Pennsylvania State University in the US built a proof-of-concept seawater electrolyzer that uses an electric current to accomplish the splitting mechanism. It relies on a thin and semipermeable membrane originally utilized to purify water through reverse osmosis.
The researchers experimented with two commercially available reverse-osmosis membranes and discovered one performed well while the other proved unsuccessful. They clarified more work is necessary to pinpoint the difference in results. However, since they measured the amount of energy needed for reactions, the membrane’s deterioration rate and how well it resisted ion movement, the team already had lots of useful data.
In another case, a group at the University of Central Florida, also in the US, made a thin film with nanostructures on its surface. The nanostructures featured nickel selenide with added phosphor and iron. Previous efforts had limited efficacy due to competing reactions.
The researchers confirmed the new method overcame that problem and is a reliable, cost-effective solution. Experiments revealed the innovation remained highly efficient and stable for more than 200 hours. Future work will focus on making the newly developed materials more electrically efficient and searching for new options to commercialize and fund these efforts.
There’s still a long way to go before getting hydrogen from seawater becomes a widespread and often-utilized option. However, the efforts highlighted here and elsewhere show that people worldwide are eager to reach that goal.
Zero-emission power system for a river and coastal vessel
Shipping is responsible for roughly 3 percent of all carbon dioxide emissions around the globe. The International Maritime Organization or IMO therefore set itself the goal of at least halving this figure by the year 2050, relative to a 2008 baseline. Due to the high power requirements and the large distances traveled by ships, fully electric solutions are only possible in isolated cases. Hydrogen and its derivatives are therefore attracting increasing interest from the maritime industry because of their potential to greatly reduce ship emissions. The challenge in this sector is, firstly, how to store the hydrogen on board safely in a minimal amount of space and, secondly, how to engineer the overall energy system to meet various requirements while optimizing its control.
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The Hitzler Werft shipyard in Lauenburg, Germany, is currently building the Coriolis research vessel for the Helmholtz-Zentrum Hereon research center in Geesthacht. The ship will be fitted with a diesel electric power system in addition to batteries and a hydrogen system. The latter was designed by Hereon together with the DLR Institute of Maritime Energy Systems and the engineering consultancy Technolog in Hamburg.
Hydrogen system lab on board
The hydrogen system lab – H2SL – is designed to be a hydrogen system that is spread across the vessel. The main components are a metal hydride tank, which was developed by Hereon, and a low-temperature proton exchange membrane (PEM) fuel cell. Accompanying these are various pieces of peripheral equipment, such as a bunker station for hydrogen, a tank connection space at the metal hydride tank and two vent masts.
For a comparably small vessel such as the Coriolis, whose length is just under 30 meters (100 feet), extremely careful consideration is needed when arranging the components. One of the reasons for this is because there are no binding regulations yet that govern the use of hydrogen on board.
The definition of hazardous zones and the distances that need to be maintained between ventilation facilities come from the IGF Code, which regulates the handling of low-flashpoint fuels in shipping and has been primarily used for liquefied natural gas up until now. The code does not yet take into account the special properties of hydrogen, for instance its much higher volatility compared with LNG. Among other things, this evident in the size and shape of the hazardous zones (see the spherical hazardous zones around the vents and air inlets). Work on the IGF Code is currently ongoing to extend its scope to include the use of hydrogen.
The tank system, consisting of an actual metal hydride tank and the mandatory inertable tank connection space, will be built on a 5-foot container base plate and have around half the height. In addition to the weight of the metal hydride itself, the overall weight is made up of the steel tank shells, pipework and, in particular, the pressure vessel of the tank connection space. The overall system volume of around 4 cubic meters (140 cubic feet) and an overall system weight of 5 metric tons mean that the tank system stores approximately 30 kilograms of hydrogen.
This allows the fuel cell to supply the ship with roughly 500 kilowatt-hours of green energy. That said, this can only happen if the bunkering of green hydrogen is actually possible and permitted – a challenge in itself, as initial exploratory talks with port authorities and hydrogen producers have shown.
Prior to the shipyard tender, the energy requirement for craft propulsion was ascertained at SVA Potsdam using a model test and subsequently scaled up. The shape of the Coriolis is optimized for operation at low speed as this matches the primary operating profile of inshore journeys (see fig. 3).
Due to the low power requirement for creep speed, the fuel cell, which will have a rated electrical power of around 100 kilowatts, can be used in combination with the battery for numerous monitoring activities and in the other operating states of the Coriolis e.g., during layovers, without having to switch on a diesel engine. As well as the propulsion system, the electrical consumers on board also need to be supplied, although these only require a fraction of the power needed for propulsion.
Metal hydride tanks
From Hereon’s perspective, the following properties make metal hydride or MH tanks attractive for a range of maritime applications:
Moderate loading pressures of well under 100 bar at operating temperatures below 100 °C
Cold start of a MH tank possible in principle even at temperatures below 0 °C (Hereon EP 3 843 190)
By the very nature of MH tanks, the hydrogen is chemically bound meaning the tanks cannot suddenly release large quantities of hydrogen, which is a significant on-board safety advantage.
The low loading pressures allow a flexible structural form which makes it easy to adapt to the shape of the ship à saves space. Today’s pressurized hydrogen tanks take up a lot of room, especially on small vessels, which reduces valuable cargo space.
The high weight can even be advantageous in certain applications, e.g., for sailing ships where it can be used instead of the obligatory “deadweight” ballast for stability.
Research in the H2SL
Hereon and DLR are working together to investigate which types of ship are best suited to the combination of a low-temperature fuel cell and a metal hydride tank for the propulsion system. The goal of the two research institutes is to create a guiding principle that enables the Coriolis energy system concept to be adapted and integrated easily into other ships and types of craft.
The H2SL offers many more opportunities to pursue innovative research approaches in addition to facilitating zero-emission operation. Hereon and DLR are planning an intensive program of research using the power system and are expecting to gain valuable knowledge and real-time data on relevant research issues. This will be made possible by running the H2SL in a real maritime environment with the option to access operating data remotely online and immediately adjust the control parameters. The effects of these changes will then be the subject of further study.
DLR will develop a digital twin of the hydrogen energy system based on the operating data in order to produce a continuous record of the system status, optimize the system control and derive feedback for the operation.
What’s more, the information should allow operational strategies to be developed for the Coriolis’ hybrid energy system. The variation in energy sources, i.e., battery, fuel cell and combustion engine, creates a high degree of flexibility with regard to operation in a wide range of energy consumption scenarios. The goal is to achieve an optimal balance in relation to fuel consumption and operating costs through intelligent load sharing for a wide variety of traveling and loading states.
A benefit of carrying out this kind of investigative work on a research vessel is that strategies developed from theoretical principles can be transferred directly to the energy management system, allowing them to be swiftly validated during operation.
Hybrid energy systems are being built into ships with increasing frequency. The knowledge gained from sailing the Coriolis will supply valuable information in future that can also be transferred to other types of craft and thus contribute toward reducing emissions in the maritime sector.
Authors: Klaus Taube, Hereon, Geesthacht, Volker Dzaak, Markus Mühmer
The energy transition in Europe can only succeed if CO2-intensive sectors are rapidly decarbonized as well. In this, green hydrogen will very likely play a central role. Because in many energy-intensive applications, there is no other CO2-neutral alternative. The quantities of hydrogen required to achieve climate neutrality are very high for Europe, however. For decarbonization of today’s H2 production in Europe, about 250 TWh of H2 would be needed. In its hydrogen strategy, the EU assumes an availability of 2,250 TWh by 2050.
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As the energy crisis in the previous year showed, dependence on imported energy sources is strategically risky. In this respect, larger quantities of hydrogen should be produced in Europe in order to avoid falling into comparable dependencies to that today with fossil energy sources.
In this context, as an independent technological consulting firm in Germany, DNV has investigated for gas grid operators Gascade and Fluxys the extent to which offshore hydrogen production is economically and strategically sensible and how a large-scale integration of offshore electrolysis into a European grid could make a significant contribution to the supply security of Europe.
Offshore wind energy is most economical
The starting point for the investigations is a comparison of five H2 value chains examined with regard to their H2 generation costs. This assumes production in Central Europe with respect to the wind and solar profiles. Compared are the production chains: onshore wind, onshore PV, offshore wind with onshore electrolysis and HVAC (high-voltage alternating current) or HVDC transmission, and offshore wind with offshore electrolysis and pipeline transmission.
The results of the modeling show that the production of hydrogen by offshore wind energy is in principal the most economical. This is particularly due to the high full load hours – about 5,000 – of the electrolyzer that offshore wind can achieve and through which the capital costs in relation to production become most advantageous.
With the use of offshore wind energy, there is still the question of whether electrolysis should rather take place onshore or offshore. This aspect as well is examined in detail in the study. A comparison of the importance of energy transmission costs on total LCOH (levelized cost of hydrogen) between the three options
1) wired HVAC connection with electrolysis onshore and
2) wired HVDC connection with electrolysis onshore versus
3) pipeline-based hydrogen transmission with electrolysis offshore
shows that up to a distance of about 125 km (78 mi) off the coast, HVAC transmission is more cost-effective compared to HVDC transmission. At distances beyond this, however, pipeline connection is more cost-effective, based on total LCOH. Electrolysis for more distant offshore areas should consequently be carried out offshore. For the study, this limit is drawn at 100 km, as a single pipeline can also integrate several offshore wind farms (see yellow-hatched area in Fig. 2).
If land use, as onshore electrolysis takes up significant area, is considered as a further factor, offshore electrolysis has yet another advantage: The already very intensive land use onshore will not be further intensified. The compact design that is possible offshore is significantly more advantageous.
89 gigawatts in the North Sea in planning
In a next step, the study investigates the offshore wind generation potential for areas in the North Sea and Baltic Sea with a distance to shore of more than 100 km (62 mi). Only those areas are taken into account that have so far been designated for wind projects by the respective countries. The corresponding evaluations show that within the 100 km criterion, 89 GWel of offshore wind energy projects in the North Sea are currently for the most part in the early planning phase. There is still far more potential in the surfaces of the North Sea; however, they are not currently designated for use for wind energy.
If the identified wind potential in the North Sea of 89 GW were to be used exclusively for the generation of hydrogen, then this would correspond to an H2 production volume of around 350 TWh per year, or 9 Mio. tonnes annually. Such a quantity would cover 15 to 20 percent of Europe’s hydrogen demand in 2050, depending on the forecast study used as a basis.
In the Baltic Sea, the potential is significantly lower, at least if the 100 km criterion is stringently applied, because of the shorter distances of the stations from the coast. A deep look at the production potential in the Baltic Sea region was not conducted in the study. However, a corresponding offshore wind backbone in the Baltic Sea could also efficiently drive an onshore H2 production in Sweden and Finland with transmission to Central Europe and additionally be combined with a production at sea.
Differences between natural gas and H2 pipelines
Basing upon the results of the economic viability and the possible potentials from the areas, the study next details the possible technical implementation. Here, it is less about the offshore electrolysis itself, but specifically about options to connect offshore hydrogen production to an onshore grid via an offshore pipeline network. For this, numerous issues need to be addressed, in order to create a hydrogen backbone that can be operated safely.
When comparing for example the transport of natural gas, which is common in offshore environments, with the transport of hydrogen, which has not yet been carried out in offshore environments, several aspects must be taken into account. First, natural gas and hydrogen have different energy contents when they are transported through a pipeline. Natural gas consists mainly of methane (CH4) and normally has an energy content – upper calorific value – between 34 and 43 MJ/m³.
Hydrogen, on the other hand, has a much lower volumetric energy content than natural gas of about 12.7 MJ/m³. This means that when hydrogen is transported through a pipeline, a much larger volume of gas is required to transport the same amount of energy in natural gas. Hydrogen, however, is also a much lighter gas than natural gas.
At normal temperature and pressure, for example, a cubic meter of hydrogen has about one-ninth the mass of a cubic meter of natural gas, which results in a much higher flow rate at the same pressure differences. The combination of these two aspects – low calorific value and light weight – has an equalizing effect, so the energy transmission of hydrogen and that of natural gas are nevertheless similar.
Furthermore, hydrogen has a much higher diffusivity in steel than natural gas and therefore promotes the embrittlement of pipelines following cyclic loadings. This effect can be controlled by an avoidance of cyclic loading, using lower quality steels, – which are softer and therefore less susceptible to cracking – and using a thicker pipeline wall. This also generally limits, however, the ability to reuse existing natural gas pipelines for hydrogen transport.
Taking all this into consideration, the study therefore comes to the conclusion that due to its different volumetric, gravimetric and molecular properties, the transport of hydrogen differs greatly from that of natural gas in offshore pipelines. Offshore hydrogen pipelines should therefore fulfill specific design criteria in order to ensure adequate transport capacity and to be able to operate safely and enduringly. On the basis of the analyses carried out, whose key points alone are treated in this article, the authors conclude that a repurposing of existing offshore pipelines is in most cases uneconomical, especially if the pipeline is to be part of an integrated system and connect several wind farms.
High pressure level possible
As a final step, the study details the technical implementation of a hydrogen backbone in the North Sea. Discussed are, among other things, questions regarding pipeline routing and pressure regimes as well as pipeline costs and required storage capacity as a result of fluctuating H2 production. The transport network sketched in the study connects wind farms in the North Sea with onshoring points in six countries bordering the Sea. For the connection, terminal points on the planned onshore backbones in the countries were selected. The network thus formed has a total length of 4,500 km (2,800 mi) and generally has a north-to-south flow direction.
In the study, a complete hydraulic analysis is not performed, but rather a few approximate calculations. In order to, for example, determine the required feed-in pressure for the transport of hydrogen from Norway to Germany, corresponding calculations were carried out for the necessary pipeline sections (see Fig. 3).
The assumed pipe diameter is 48 inches (1,200 mm). With these parameters, the required feed-in pressure was calculated for different capacities of the pipeline. For an H2 capacity of 25 GW connected to this pipeline section, for example, an inlet pressure of 192 bar is calculated. This is a very high pressure level for offshore H2 pipelines.
The DNV joint industry project (JIP) H2Pipe at this time is investigating the design, construction and operation of offshore H2 pipelines with a pressure of up to 250 bar. Although these pipelines are not commercially available yet, DNV and the JIP partner companies see no major technical constraints to the realization of such pipelines. The economic feasibility in terms of material selection for the pipelines and ancillary equipment, however, will have to be demonstrated in the coming years.
In addition to the pipeline system, the storage demand is also analyzed in the study. Connection to sufficient storage capacity is necessary for near-continuous supply over time. On this, the study shows that about 30 percent of the annual production must be stored, as a prerequisite for this H2 supply based on fluctuating renewable energies. The study accordingly assumes a connection to salt cavern storage facilities in northern Germany and the Netherlands.
Cost calculation
The costs for the outlined network were subsequently estimated. For the North Sea, the total length of the planned backbone is 4,200 km (2,600 mi). Assuming a pipe diameter of 36 to 48 inches (910 to 1,200 mm), the price thus lies between 3,000 and 4,500 euros per meter of pipeline.
According to the assumptions made, the additional LCOH for the pipeline system is between 0.13 and 0.20 EUR per kg hydrogen, i.e. 4.0 to 6.6 EUR per MWh. Since the levelized total cost of offshore hydrogen is 3 to 5 EUR per kg, this means an addition of only 2.6 to 6.7 percent, based on direct production costs.
In addition to pipelines, an appropriate compression regime must be considered. The cost of a compressor varies considerably with the size. The maximum capacity of today’s compressors is about 16 MWel (input capacity). Under the assumption of central compressors for a wind farm; an output pressure of the electrolyzers of 30 bar; an input capacity of the hydrogen backbone of 200 bar, and an arrangement of four compressors, each with 50 percent of the total capacity required and 200 percent of the installation costs; the investment amounts to 46 million EUR for a 1‑GWel wind farm and 66 million EUR for a 2‑GWel wind farm. Thus, the additional LCOH is between 0.06 and 0.08 EUR per kg hydrogen, which corresponds in value to 2.0 to 2.7 EUR per MWh. Since the levelized total cost of offshore hydrogen is 3 to 5 EUR per kg, this means an addition of 1.2 to 2.7 percent.
Overall, the cost for the pipeline and compression is around ten percent of the total specific cost of hydrogen. In addition to pipeline and compression costs, the storage must also be considered as a third component to be added to the LCOH. The result is an additional 0.22 to 0.35 EUR per kg H2 for this.
With the determined system components, the investment costs were estimated in the study as 35 to 52 billion euros to build the outlined North Sea hydrogen backbone. In conjunction with the results of the LCOH analysis, hydrogen from North Sea offshore wind farms can be supplied to Central Europe with it at specific costs of about 4.69 to 4.97 EUR per kg in year 2030. From the point of view of the authors, these costs are competitive with the cost for imports.
In order to implement the outlined system, a coordinated and swift action by the coastal nations involved is imperative. Only so can the necessary network and scaling effects be realized, and an offshore backbone contribute to hydrogen supply to Europe by 2050.
Authors: Claas Hülsen, Ton van Wingerden, Daan Geerdink
Behind us lies an extraordinary period with a plurality of crises: pandemic, war, climate catastrophe, energy scarcity, inflation, etc. Even if the acute phase of the pandemic is over, other crises are still ongoing and will presumably remain with us for some time to come.
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Nevertheless, in the meantime, some things have settled into place. Inflation is not rising further at least, and the natural gas situation has been mastered, for the time being. Even the blackout predicted by some after the shutdown of the last three remaining nuclear power plants in Germany did not materialize. Instead, there is more renewable energy in this country than ever before – particularly in the electricity sector.
A good opportunity to take a breath and take stock of the situation: Where do we stand today? How is the energy transition progressing? What has been achieved so far in H2 and FC technology?
I have been engaged in hydrogen and fuel cells since 1997. At that time, this topic was a teeny-tiny niche. Fuel cells seemed interesting because they emit only hot air – only steam –and no harmful carbon compounds at all. There was hardly any literature on them; only a few research activities and demonstration projects. Federal support programs for them were nil.
A few car manufacturers were “already” experimenting with metal hydride storage for FC cars in the 1990s, and others with hydrogen. At the turn of the millennium, the first H2 and FC trade fairs and congresses emerged, but a portion of these disappeared again shortly after.
Optimistic developers joyfully announced back then that hydrogen-powered vehicles would be on the roads in 2004, and fuel cell-powered heaters in basements. Instead of series production, however, what followed were promises that it would finally happen in 2007, 2010, 2014 and 2017. H2 hype followed H2 hype, but of a market, there was no sign.
At times, the fuel cell had already been laid to rest – at least in the media. Several areas of application that were considered at the time lost interest. For example, the fuel cell-powered movie camera or the FC cargo bike.
New momentum first came into play in the 2010s, when hydrogen was being contemplated as a storage medium for renewable energies. Until then, it had always been said: Energy storage isn’t something we need. It was only when the idea of sector coupling emerged that it gradually became apparent that hydrogen could be a suitable medium for this purpose.
During this time, buzzwords such as power-to-gas, decarbonization and electrification emerged. The fuel cell fell little by little out of focus; however, increasingly more sights were set on hydrogen.
Nevertheless, several years passed in which the much-invoked Energiewende (energy turnaround) did not really gain ground. It took events like Fukushima, Dieselgate, debates on the health-related limits of emissions, and the founding of Fridays for Future until it became clear to political decision-makers as well that we can’t get by without hydrogen.
What then followed was the European Green Deal and numerous national hydrogen strategies in many countries around the world. The first large commercial and industrial businesses began to change their strategy and – at least partially – turned away from fossil energy structures.
It became increasingly clear that solar and wind power, – contrary to the many prior negative prognostications – together with suitable energy storage, have the potential to defossilize not only the power sector but also other energy sectors.
Most recently since the Russian war of aggression on Ukraine, it has become obvious that the times of cheap fossil energies are over, once and for all – which is positive in multiple respects. Because high prices for natural gas, oil and coal, which are likely to keep rising due to the growing cost of CO2 certificates, not only reduce energy consumption, they demand a change to more decentralization as well as more independence.
But where do we stand now?
Today, we have available to us almost too many H2 trade fairs and congresses – worldwide. We have investment commitments in the billions from major corporations. We have political strategies for establishing a Europe-wide H2 backbone in order to distribute renewable energies in the form of H2 gas across the continent.
We also have, however, millions of citizens who are very unsure and fearful of the future. Many cannot afford either heat pumps or electric cars. So their complaints are loud but, at the same time, understandable. That is why it is all the more important today to explain the energy transition, as well as H2 and FC technology, in a way that makes sense.
We are at the beginning of a gigantic transformation process that demands a lot from us all. At the same time, this process holds immense potential for development and redevelopment. That’s why it’s crucial to talk more about opportunities and less about problems.
I am absolutely certain that this process of change is possible without substantial loss of prosperity. We can show how new jobs can be created, how sustainable environmental standards can be set, how resources can be conserved, and at the same time how the standard of living can at least be maintained, if not improved– worldwide even.
A prerequisite for this, though, is that we do not leave everything up to the free market, but rather create suitable framework conditions that offer sufficient freedom to act but also planning security and, above all, are generation-fair.
At this year’s H2POLAND exhibition in the Polish city of Poznań, representatives of the “three seas states” took part in a signing ceremony to formally launch a joint hydrogen project. The countries involved in the initiative are all European Union members located between the Baltic, Adriatic and Black seas, namely the Baltic states, Poland, Ukraine, Hungary, Czech Republic and Slovakia.
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Tomoho Umeda, founder of Polish companies Hynfra and Hynfra Energy Storage, led the discussions between the country representatives on the joint enterprise. The Polish businessman, who has Japanese roots, expressed regret that Central and Eastern Europe, or CEE for short, is rarely involved in the rapid development of the hydrogen industry in the European Union: “There’s a lot of nodding but when it comes down to business, CEE tends to be sidelined in key developments.” The three seas hydrogen project intends to change precisely that.
Shared connections
Poland is at the heart of current growth in the Eastern European hydrogen sector. That’s not just because Poland, with its population of almost 40 million people, is by far the biggest economy in Eastern Europe, but due to the large number of underground salt caverns that make it an ideal location for storing hydrogen. A fact that Umeda emphasized several times in his speech.
The countries that want to push forward the development of hydrogen industries in this region have more in common than being overlooked members of the EU. What unites them most is that they are all countries of the former Eastern bloc. This common past means they share certain similarities, as particularly evidenced by their infrastructure and the special regulation of the energy sector.
Umeda highlighted the pipeline infrastructure and heat supply in Central and Eastern Europe. Aside from a dense district heating network, common elements across these countries also include long-distance interregional connections which stem from Soviet times. New networks are also being added, such as the Lithuania-Poland and Poland-Slovakia gas connections which only became operational a few years ago.
Czech representative Vaclav Bystriansky made it clear in his address that these transmission lines as well as zero-emission energy generation have a vital role to play in the development of the hydrogen sector. In his opinion, the old model of east-west transmission is outdated and should be relinquished. He is convinced that there will be more north-south connections in future.
For his country this means working much more closely with its northern neighbors. “Poland has the storage capacity and Czech Republic has the nuclear power plants,” said Bystriansky, summarizing the direction of future cooperation.
Slovakia echoed Bystriansky’s remarks, but adding that the nations of Central and Eastern Europe have a lot they could learn from each other. This was said to include, above all else, learning from the mistakes of others. An essential point that was also stressed by other officials is the potential use of waste incineration for the production of hydrogen. Incineration is currently a weighty issue in Eastern Europe. The view from the Slovakian side: “You shouldn’t just get fixated on renewables alone but instead use what makes sense and satisfies the conditions.”
Estonian delegate Sven Parkel responded that countries in Central and Eastern Europe could only earn a better position in EU committees by joining forces. He said they must represent their interests in Brussels collectively, otherwise they would not be heard by dominant EU countries such as Germany and France. What’s more, Parkel suggested that they should put on a united front when addressing the regulatory elements of the region’s hydrogen industry at an administrative and public authority level.
Ukraine boasts greatest hydrogen potential
István Lepsényi from the Hungarian Hydrogen Technology Association, who took his place right next to the Ukrainian delegate Oleksandr Riepkin, astonished the gathering in Poznań with his particularly political statement. In contrast to the pro-Russian position of Hungarian Prime Minister Viktor Orbán, Lepsényi expressed his personal feelings in relation to Ukraine’s struggle against its Russian aggressor. He hopes Ukraine will soon win and an end will be brought to a horrendous war which the Russians have waged against Ukraine.
Ukraine and its hydrogen potential was one of the thematic high points of the panel discussion which preceded the signing of the joint hydrogen project. Oleksandr Riepkin started by thanking first of all Poland for preventing the certain death of millions of people from Ukraine by opening its hearts and homes and offering all it has to the Ukrainians fleeing the rape and murder of the Russians. The audience responded with almost unceasing applause and cries of solidarity. He also announced that his country would be entering a hydrogen partnership with Poland, saying: “As sisters and brothers, Poland and Ukraine can achieve anything and be a match for anyone.”
After Riepkin had detailed Ukraine’s options for zero-emission electricity generation, he turned his attention to the existing collaboration with Poland on energy issues. The power connection between the countries has now been reestablished and in future could be extended and utilized for hydrogen production. The Ukrainian suggested that CEE nations should specialize in individual areas, thus sharing the load which would be important for competitiveness in the hydrogen industry.
“Central and Eastern Europe should also step out from under the shadow of Western Europe and itself manufacture the electrolyzer plants that enable hydrogen production. A domination of Western European technology is to be avoided,” the audience in Poznań was told. “Our technology is just as good as German technology – only more affordable,” added Czech delegate Bystriansky.
Riepkin then took a look at the problems that could ensue from hydrogen production in the CEE region. For instance, there are now drought-prone areas where conflicts could arise with agriculture in relation to water supply and land for renewable energy. Producing hydrogen using nuclear power could be an alternative, as expressed by the Czech and Slovakian representatives.
The three seas hydrogen project appeared ready to expand toward Scandinavia, with Estonia and Finland being obvious candidates. Both countries have connected up their gas pipelines in a move that creates promising opportunities for hydrogen grids. There was likewise optimism that the two remaining three seas states – Romania and Bulgaria – will join the hydrogen initiative in the foreseeable future.
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