by Claas Hülsen | Dec 10, 2024 | Energy storage, Europe, Germany, hydrogen development, News
New DNV study analyzes production and export
A new study by the consulting firm DNV investigates the H2 export potential from Sweden, Finland and the Baltic states as well as alternative transport routes to Germany and Central Europe. The study shows whether there is sufficient potential for the production of hydrogen for export in the Baltic Sea region, how economically this hydrogen can be produced and how the countries in the region can benefit from the development of an H2 network and the corresponding trade in hydrogen. For the large-scale export of hydrogen, pan-European pipeline systems can play a decisive role, which is why the study also contains a comparative analysis of possible pipeline routes.
For the decarbonization of central industrial sectors in Central Europe and especially in Germany, the procurement of cheap green hydrogen will be an important challenge in the coming years. Especially the steel industry and basic chemicals will be dependent on the availability of cheap hydrogen. The domestic production of hydrogen in this quickly reaches its limits. It is competing with the decarbonization of electricity generation through renewable energies while at the same time increasing electricity demand through the electrification of key economic sectors – for example in transportation – on the other hand, the domestic production costs for hydrogen in Germany are in some cases significantly higher than in other regions of the world.
In view of this, significant quantities of hydrogen will have to be imported. While sea transport is sometimes the only option for long distances, pipeline-based transport is a cost-efficient option for medium distances. Transport via pipelines has the particular advantage that the hydrogen produced is available in pure form and no transformation losses occur, as is the case with tanker transport in the form of ammonia, for example. Strategically, it is also important for the development of H2 import chains for Europe and Germany to establish stable partnerships that are also resilient in times of crisis, in order to avoid situations similar to the interruption of gas supplies from Russia in the course of the war in Ukraine.
With that, it is in the interests of all parties involved to look around for possible nearby sources of supply within Europe as well. Various pipeline corridors are currently being discussed in this context and are also being funded by the EU as “Projects of Common Interest” (PCI).
In this regard, DNV on behalf of Gascade has investigated the potential of hydrogen sourcing from Sweden, Finland and the Baltic states in recent months. Based on the existing energy policy objectives of the countries mentioned, an estimate was first made of the possible export potential from the Baltic Sea region. Secondly, the costs at which this hydrogen can be provided and which transport routes will be sensible based on the geographical production potential were determined.
The country analyses, which form the basis of the study, present a differentiated picture of the plans of the individual countries in two scenarios. In each of these scenarios, the planned expansion of renewable energies and the domestic demand for electricity and hydrogen are determined. An optimistic scenario for each country assumes an ambitious expansion of renewable energies for most countries using data from the TYNDP 2022 Scenario Report. This expansion will be combined with a correspondingly ambitious expansion of the respective H2 utilization in accordance with the country’s respective H2 strategy. The conservative scenario, in contrast, is less ambitious in all components.
The remaining energy volumes in the respective scenario (after deducting domestic demand from electricity production) are earmarked for the export of hydrogen. It should be noted that this energy could also be earmarked for export as electricity via newly built interconnectors. However, this alternative is not considered further in this study. This results in the following overview of the existing export potential in the two scenarios:
The conservative scenario used in the study shows that Finland in particular can achieve a considerable electricity surplus in 2050, which could be used to produce green hydrogen for export. The Swedish electricity surplus, on the other hand, will decrease continuously over the selected period and the country will no longer have a surplus in 2050. This is due to the moderate expansion targets in Sweden and the simultaneous advance of domestic electrification.
Overall, the conservative scenario results in a potential of about 70 TWhel in 2050 that can be sourced from the region, with Finland being the main source of the surplus. This reported surplus based on the lower ambitions is quite small, mainly because Sweden, due to its own electrification of industry and domestic hydrogen consumption, shows no surplus in 2050. Nevertheless, wind energy makes a significant contribution in the countries: It can be assumed that onshore wind power will be the main source of surplus electricity in the period from 2030 to 2050, accounting for around 40 to 50% (SE) and 70 to 80% (FI) of electricity generation from renewable energy (RE) sources. This is followed by offshore wind power with a share of renewable electricity generation that will increase to 10 to 20% by 2050 (SE) or about 5% in 2030 and 11% in 2050 (FI).
In the optimistic scenario, on the other hand, development in both countries is more balanced. In this scenario, Sweden shows the highest surplus potential in year 2030, which then halves by 2040 due to electrification, but remains stable thereafter. For Finland, an even greater increase is forecast than in the conservative scenario. Over time, the following total potential for surplus electricity for the production of green hydrogen from the region could therefore be achieved: 2030: 16 TWhel, 2040: 90 TWhel, 2050: 119 TWhel.
Also in this scenario, Finland remains the largest surplus electricity producer and would produce around 30 TWhel more than in the conservative scenario. In addition to this is a small potential from the Baltic countries and Poland.
For the following analysis of the pipeline routes, this analysis was not only carried out at country level for each scenario, but also differentiated at the regional level – the basis for this forms the existing and planned distribution of REs in the individual country regions.
Calculation of the H2 production costs
The analysis of production costs is important, as the export of hydrogen as a business is then only sensible if the costs are also competitive in comparison to other possible source regions. In this respect, the levelized cost of hydrogen (LCOH) is the commonly used performance indicator. In a second step, the production costs for green hydrogen are therefore calculated for each region. Compared per region are the LCOH for various production technologies for which the respective regional capacity factors are taken as a basis.
For the calculation of the hydrogen production costs (LCOH), two possible concepts are also examined in the study. First, option 1 assumes that the electrolyzer is operated directly coupled with renewable resources to produce green hydrogen. Alternatively, a different approach is analyzed for the region in which the electricity is drawn from the power grid – which from a regulatory point of view, under certain circumstances specified in the EU Delegated Acts, also make the production of green hydrogen possible. In this case, we check whether the feed-in from renewable energies in the areas examined lies above 90%, as required for an exemption from the RED III criteria with regard to points such as PPAs for renewable energies, additionality and temporal correlation, and then evaluate the hydrogen accordingly on the basis of the electricity costs from the grid.
In summary, the results show that the generation costs of the directly coupled concept appear high. They lie, depending on the region, between 6.15 EUR/kg and 18.75 EUR/kg (see Fig. 2). This seems high compared to the generation costs in southern Europe for directly coupled plants, so at these production costs it is questionable whether exports can be established economically.
Fig. 2: Electricity production costs of hydrogen for direct-coupled onshore wind electrolysis in 2030 for all analyzed NUTS2 regions
Due to the very high share of RE in the Scandinavian regions, however, and the equally low specific CO2 share per kWh (due to the combination of hydropower, nuclear energy and RE), it can be assumed that for the relevant bidding zones in Finland and Sweden the exemptions of the RED III Delegated Act apply, so the electrolyzers can draw energy from the grid. This significantly changes the picture with regard to the LCOH – especially as the electrolyzers can now achieve a much higher number of full load hours and thus reduce the capital costs in relation to the amount of hydrogen generated. In this way, LCOHs between 2.5 EUR/kg and 4.5 EUR/kg are achieved.
As these in turn depend on the electricity costs in the respective country over the time axis, these electricity prices were taken from the DNV electricity price forecast for Finland and Sweden. Due to the increasing electrification in both countries, the demand for electricity will increase between 2030 and 2050 – which will initially lead to rising electricity prices and thus also rising LCOHs. In the long term, however, DNV expects the electricity price to develop moderately, so the LCOH for 2050 is estimated at around 2.5 EUR/kg (see Fig. 3).
Fig. 3: LCOH Sweden and Finland with grid withdrawal 2030 to 2050
As a result of the cost analyses, it was found that, because of the specific system situation, very attractive production costs for hydrogen can be achieved in Scandinavia. This was already evident this year at the pilot auctions of the European Hydrogen Bank.
Export corridors to Central Europe
In the last part of the analysis, on the basis of the regionalized export potential identified, possible export corridors to Central Europe were evaluated. We have based our analysis on the corridors currently described in the network development plans (European Hydrogen Backbone) and compared them with regard to the regionalized export potential from the first part of the study in terms of their costs and capacities as well as their strategic routing. The following figure shows the five variants examined, for each of which an identical starting point in Finland near the city of Turku was chosen for comparison purposes and the determined regionalized export potential is taken as a basis.
Fig. 4: Five analyzed cases for the (simultaneous) use of onshore and offshore pipeline routes
Both routes connect to the planned Finnish onshore hydrogen transport network that will come from the north of Finland.
Onshore route
The onshore route begins with a connection from Turku to Helsinki, where the Gulf of Finland is crossed by an offshore pipeline segment connecting Helsinki with Tallinn. From there, the hydrogen will be transported through Estonia and Latvia via a newly built pipeline until it reaches a 100-kilometer section of a reused natural gas pipeline in Latvia. The total length of the onshore route is around 2,000 km (1,242 mi). For the calculation of the hydrogen transport capacity, the European Hydrogen Backbone Reports make the following assumptions for the various pipeline segments:
- New construction of 36-inch pipelines (50 bar), nominal capacity of 4.7 GWH2, capacity factor 100%
- Reused 36-inch pipelines (50 bar), nominal capacity of 4.7 GWH2, capacity factor of 75%
- New construction of 48-inch pipelines (80 bar), nominal capacity of 16.9 GWH2, capacity factor 75%
Compared to the other pipeline sections, the rededicated sections have a lower operating pressure and therefore a lower transport capacity. These segments therefore represent a bottleneck for transport capacity. Unless booster compressors are used to temporarily increase the flow rate where possible, this restriction determines the transport capacity of the entire route.
This results in a transport capacity of 30.9 TWhH2/year, based on full utilization within the limits of the capacity factors specified above and the parts of the network with the lowest capacity (75% × 4.7 GWH2 = 3.6 GWH2). If the entire route can be expanded to a transport capacity of 4.7 GWH2 , a total of 41.2 TWhH2/year can be transported. At the expected capacity factor for Finnish onshore wind energy of 40%, the transport capacity of a 4.7 GWH2 connection is 16.5 TWhH2/year.
A comparison with the expected order of magnitude of the surplus from Finland shows that the onshore route can only cover the expected hydrogen transport capacity from the surplus from Finland in the optimistic scenario (8.6 TWhH2/year) for 2030. After this time, the onshore route alone will no longer be sufficient to provide adequate transport capacities.
After publication of the DNV study, the consortium Nordic-Baltic Hydrogen Corridor announced that it would abandon its original plans to use pipeline sections consisting of reused natural gas pipelines and – for reasons of transport capacity – would try to provide 48-inch new pipelines over the entire land route. This means that the land route will actually have a greater transport capacity than forecast in this study, if the new 48-inch pipelines can be realized.
Offshore route
The offshore route alternatively starts with a connection from Turku to the island Åland. From there, one or more pipelines with a length of around 760 kilometers run through the Baltic Sea to the Danish island Bornholm. From there, one or more pipelines lead to the German mainland. The total length of an individual pipeline route is around 1,000 km (621 mi). The total length, including a double pipeline route, is about 1,900 km. In this regard, the study analyzed the costs for both a single and a double route.
At a maximum operating pressure of 80 bar, due to the pressure losses induced in the pipeline, a hydrogen recompression is required along the 760‑km route from Åland to Bornholm. In this case, the offshore route must connect to the Swedish island Gotland, to carry out recompression there and/or establish a connection to local supply and demand centers.
For calculation of the hydrogen transport capacity, the European Hydrogen Backbone Reports make the following assumptions:
- New construction of 48-inch pipelines (80 bar)
- Nominal capacity of 16.9 GWH2
- A capacity factor of 75%, which corresponds to an actual capacity of 111.0 TWhH2/year.
- Assuming a capacity factor of 40% (Finnish onshore wind energy), this corresponds to an actual capacity of 59.2 TWhH2/year.
Alternatively, the possibility of a single optimized offshore pipeline sized to be able to transport the expected surplus for all scenarios and years examined was investigated. This pipeline also provided for a connection between the island of Bornholm and the Polish coast in the area Niechorze-Pogorzelica, in order to create a connection with the land-based hydrogen network. The optimization correspondingly provides a dimensioning of a single, about 780‑km pipeline such that it can transport 65 TWhH2/year at a capacity factor of 40% plus X. The aim of the optimization is to ensure that a single pipeline is sufficient to transport the excess hydrogen from Finland in all analyzed scenarios.
Results of the optimization
The calculation was based on the norm ASME B31.12, Option A. This resulted in an operating pressure of 170 bar and a resulting wall thickness of 60.13 mm. This is outside the standardized range of pipeline wall thicknesses available on the market, but is not unprecedented in the industry. For example, the Langeled pipeline, which runs between the UK and Norway, has similar design specifications. The table below summarizes the required specifications.
Tab. 1: Specifications of the 780 km long pipeline from the Åland Islands to Bornholm
Source: DNV
In summary, the offshore route can meet the expected hydrogen transport needs from the surplus from Finland in the following scenarios:
- Single (unoptimized) pipeline (59.2 TWhH2/year): All scenarios are met except the optimistic scenario 2050 (62.4 TWhH2/year).
- Dual (unoptimized) pipelines (118.4 TWhH2/year): All scenarios are fulfilled.
- Single (optimized) pipeline (65.0 TWhH2/year): All scenarios are fulfilled.
Techno-economic analysis
The results of the various pipeline route options are summarized below:
Tab. 2: Levelized costs of hydrogen transport for the analyzed pipeline routes
- Case 1: Only onshore route: The total investment costs are around 5.8 billion euros, but at 1.37 euros/kg H2 based on the levelized cost of hydrogen transport, it is the most expensive option.
- Case 2: Only offshore route – single pipeline: The total investment costs are similar to case 1, but the levelized costs of hydrogen transport are much cheaper at 0.40 euros/kg H2.
- Case 2 (Opt): Only offshore route – single pipeline (optimized): The total investment costs are similar to case 2, but the levelized costs of hydrogen transport are slightly lower at €0.39/kg.
- Case 3: Only offshore route – double pipeline: Levelized cost of €0.40/kg. However, the total investment costs are around €11.8 billion – twice as much as in Case 2.
- Case 4: Onshore route and offshore route – single pipeline: The total investment cost is similar to Case 3, but the weighted average levelized cost is higher at €0.61/kg.
Although offshore pipelines are about 1.5 times more expensive than onshore pipelines of the same diameter, they are, due to the different total transport distance between the onshore and offshore routes (1,000 km or 2,000 km) in combination with the larger overall diameter and pressure (and therefore transport capacity) of the offshore routes, a more cost-effective option for transporting excess hydrogen from Finland to Central Europe. However, from the perspective of diversification and the development of hydrogen production in the Baltic states, an additional onshore route offers greater security of supply.
Conclusions
The option of obtaining hydrogen from the Baltic Sea region is economically and strategically interesting for Central Europe. Low production costs combined with intra-European production can promote the competitiveness of European industry and would make Europe less dependent on imports. For many end applications, the possibility of obtaining pure hydrogen (and not derivatives such as ammonia) is attractive, as it is more efficient and avoids the costs for conversion processes.
A combination of offshore and onshore pipelines can diversify supply, as there is sufficient hydrogen production potential if the potential for excess electricity from renewable energies is used. An optimized offshore pipeline, however, would be the most cost-effective means of transport to Central Europe.
As a result, it can be stated that a strategic dialogue should be initiated between the states bordering the Baltic Sea and the EU countries dependent on hydrogen imports (especially Germany and Poland). The aim should be to develop a common strategy and vision for a hydrogen network in the Baltic Sea region that further develops the previous considerations in the discussion about a European hydrogen backbone and concretizes plans for RE expansion, pipeline planning and industrial utilization. Due to the many aspects that need to be taken into account, a multinational agreement for such hydrogen production and network expansion would be worthwhile.
Authors: Claas Hülsen, Daan Geerdink, Daniel Anton, DNV Energy Systems Germany GmbH, Hamburg
by eaugsten | Nov 18, 2024 | Energy storage, Europe, Germany, Market, News
Metal hydride storage as a complete system
GKN Hydrogen has developed a complete containerized storage system which allows hydrogen to be stored in discs of metal hydride powder. The solution employs solid-state technology to store hydrogen safely for long periods. The pioneering company based in Pfalzen, northern Italy, became part of the British engineering corporation Langley in August 2024.
Admittedly, the many practical benefits of using metal hydrides for hydrogen storage are in no way a new revelation. Metal hydrides are compact and require neither high pressures nor low temperatures. Even in the event of a fire they are relatively safe since most of the hydrogen is firmly bonded in the metal. It’s why developers attempted to use them in hydrogen cars in the 1970s. And yet this technology is still not found in any automobile. One of the reasons for this, as tests showed, is the immense metal weight that had to be carried in relation to the amount of hydrogen stored. Not only that, the issue of on-board heat management proved tricky to handle.
On the other hand, what is relatively new is the use of metal hydride storage systems in stationary applications. Storage solutions for microgrids, neighborhood schemes and industrial units usually stay put. Such systems can also be used for hydrogen mobility, albeit essentially to store hydrogen at the refueling station.
If needs must, the hydrogen can also be moved around in shipping containers. These are best transported by boat or train, though road trains are also possible across the vast expanses of the prairies. “In the USA we are currently developing a mobile refueler. This will enable hydrogen to be transported to remote areas, thereby providing a truck-based refueling option in these locations,” says Dirk Bolz, head of marketing at GKN Hydrogen.
Dirk Bolz, head of marketing at GKN Hydrogen
In these applications, there will be little concern about using titanium-iron alloy as the material and the combined weight of the storage container for 250 kilograms of hydrogen and the associated equipment adding up to over 30 metric tons. It thus allows GKN Hydrogen to sidestep a key problem with this technology.
The company has also found solutions for other challenges: “Our specialist knowledge and intellectual property lie principally in two areas. One of those is production processes – in other words how you press a bonded material from metal powder,” says Bolz. In the early days the powder was formed into small pellets; today they are more like round, flat discs. “The other area is the charging and discharging of the storage system – in other words the thermal cycling of the storage system.”
The actual storage unit is designed as a pipe-in-pipe system (see fig. 1). In the inner pipe, the hydrogen flows around the discs made from compressed metal powder. A heat transfer medium flows through the outer pipe carrying away the heat which arises when hydrogen bonds to the metal. Adding heat reverses the process and the storage system is discharged.
Ten years of hydrogen storage research
GKN’s history can be traced back to the dawn of industrialization. The company started when an ironworks was founded in Dowlais, South Wales, in the 18th century. Since then, it has been involved in a wide range of industrial technologies, including the manufacture of steel, screws and drive shafts for cars. GKN Powder Metallurgy, headquartered in the German city of Bonn, is the specialist in powder metals within the international corporation. Its developers have been working on the application of metal hydrides for hydrogen storage for a good decade. The metal powder is made in the company’s factories spread across the world.
Up until 2023, the production of complete containerized systems was based at the GKN Sinter Metals factory in Bruneck in South Tyrol, Italy. This is where the first pilot applications originated. “Initially it was an off-grid solution for a vacation home and demonstrators at our sites. They were quickly followed by the first fully integrated power-to-power systems that incorporated everything from the electrolyzer and storage system down to the fuel cell,” explains Bolz. A year ago, GKN Hydrogen moved to Pfalzen, a 3,000-strong community located on the outskirts of Bruneck, where the systems are now produced and refined.
Levelized cost of storage rules
As an industrial enterprise, GKN knows full well that price is a key deciding factor for customers. According to Bolz, the current volume of production means the capital costs for a metal hydride storage system, depending on use, are around one and a half times that of a comparable pressurized tank. “Yet, depending on the application, the TCO – total cost of ownership – of our storage systems is on a par with or even below pressurized tanks. That’s due to the much lower maintenance costs.” He therefore recommends paying attention to the levelized cost of storage or LCOS for a specific project.
As the main components of the storage system are unmoving, the cost of maintenance is lower in comparison with high-pressure systems with a compressor unit and the storage system has a longer life expectancy. The efficiency is also greater. This is because once the hydrogen is bound in the metal, it stays there – in contrast with gas or even liquid storage tanks in which some of the molecules are discharged over time. Furthermore, the metal hydride storage system operates at low pressure, which can save considerably on energy costs, depending on the pressure level for production and application.
Batteries compared and contrasted
In addition to straight hydrogen storage systems, GKN Hydrogen also offers turnkey power-to-power solutions which come with the electrolyzer and fuel cell already installed. These are similar to commercial battery systems in terms of size and energy density. The HY2MEDI storage system includes a fuel cell and electrolyzer which are prefitted in a 20-foot (6-m) container. It holds 120 kg of hydrogen. This can then supply around 2 megawatt-hours of electricity using the in-built fuel cell. By comparison, the battery storage system of a well-known manufacturer in the same format has a capacity of 1.9 MWh.
However, metal hydrides and batteries each have their strengths in very different areas of application. Where a high number of short storage cycles are the order of the day, a battery solution comes out clearly on top. The battery manufacturer puts cycle efficiency at “up to 98 percent.” Looking purely at electrical efficiency, metal hydride systems are only 32 percent efficient. If a customer also requires heating, a significant proportion of losses can be used for heating purposes, which brings the overall efficiency to 70 percent. “Our systems are used in buildings or backup solutions for critical infrastructure for longer storage periods, from around two days to several weeks or months.”
GKN Hydrogen’s complete storage system is available as a containerized solution
“In industry, storage volumes and cycling dynamics tend to be the crucial factors,” stresses Bolz. If energy is not released for a long time, a battery’s losses will increase – but not in the case of metal hydride. The metal hydride storage system can also excel when it comes to cycle stability. According to GKN, after 3,500 cycles, the capacity remains at 99 percent of the starting value. Even beyond that, the storage systems have so far proved stable. “To date, we have put our storage solutions through about 6,000 cycles and we haven’t observed any mechanical wear or chemical degradation,” says Bolz.
Advantages for safety
The use of both hydrogen and batteries requires special safety precautions, particularly in relation to explosion and fire prevention. A great deal of experience has been acquired with regard to batteries which reduces anxiety about their use, including applications in residential properties. New battery materials will also greatly increase fire safety in the near future.
Hydrogen in pressurized tanks is, on the other hand, relatively new outside industrial uses. There is little experience of its application in homes or residential areas, in particular, and skepticism abounds. This is where metal hydride storage systems could come in.
“Only around 4 percent of the hydrogen stored in our system is present as gas. The rest is chemically bonded, in other words fixed,” explains Bolz. This minimizes the fire load and risk of explosion. What has been absent so far, compared with batteries, are well-honed practices within public authority approvals procedures. Authorities currently ask for the same evidence as required for high-pressure tanks, says Bolz. But he assumes this will soon change. “At the moment we are working to prove that our storage systems are the safest on the market by carrying out simulations and test installations.”
In fact it is the safety aspect which has recently opened the door to the Japanese market for GKN. In Japan, high-pressure tanks of 10 bar or higher are subject to strict safety regulations. That’s why Mitsubishi Corporation Technos, a Japanese trading company specializing in industrial machines, signed a memorandum of understanding with GKN Hydrogen just a few months ago.
Takeover by Langley Holdings
At the beginning of August, GKN Hydrogen had some big news: The company had joined British group Langley Holdings. This latest move followed several previous shifts at GKN. In 2018, the aerospace and holding company Melrose Industries bought GKN Group. At that time, GKN Hydrogen was still a business unit, becoming a stand-alone company within the group in 2021. In 2023, Melrose separated off several GKN companies into the Dowlais Group, among them GKN Hydrogen.
The new owner Langley is a family-run British corporation which started out in the 1970s as a supplier to the coal industry and has since grown into one of the UK’s biggest private companies. With 90 subsidiaries and a workforce of 5,000 staff, Langley estimates its turnover in 2024 will be about USD 1.5 billion. Around half of these earnings are expected to come from the Power Solutions Division, which will henceforth include GKN Hydrogen. Other companies in this division are Bergen Engines, a Norwegian manufacturer of medium-speed engines, the Italian Marelli Motori, which makes electric motors and generators, and the German Piller Group, which provides uninterruptible power supply systems.
Guido Degen, CEO of GKN Hydrogen, describes the takeover as an opportunity for the company to accelerate development. They are said to be excited about “potential synergies” with other companies in the division. Even before the takeover, GKN Hydrogen saw itself as ready to fly. “To date, we have built and installed 27 systems globally,” said Bolz in early summer. This equates to a storage capacity of 60 MWh around the world. “This is no longer lab status, it’s technology readiness level 9. The manufacturing processes are standardized. Scaled-up series production and the subsequent cost benefits are possible any time – we are, in a sense, prepared for the growth that has been forecast for the sector.”
Eva Augsten
by Monika Roessiger | Nov 11, 2024 | Energy storage
Salt domes as H2 storage sites
A successful ramp-up of the hydrogen market would be impossible without a means of hydrogen storage, and salt caverns are ideally suited to the task. These artificial cavities, more than 1,000 meters (3,200 feet) deep in salt rock, can be primarily found in northwestern Germany. While previously they have contained fossil fuels such as crude oil and natural gas, in the future they are set to hold hydrogen.
Visitors to Harsefeld, a small community near Stade in Niedersachsen, will find themselves surrounded by fields and meadows lined with hedge banks known as “Knicks.” This is the scenery surrounding Storengy Deutschland’s natural gas storage facility which has been in operation since 1992. It is here that the subsidiary of French network operator Engie intends to create one of the first hydrogen storage reservoirs in Germany.
Underground salt caverns have long proved themselves safe places to store large quantities of gas, explains Gunnar Assmann, project manager for hydrogen storage at Storengy. “Storage caverns are cavities engineered in salt rock, which forms a tight, natural barrier.” Consequently, the company plans to create two salt caverns as part of its SaltHy project. The caverns would store hydrogen that can be produced regionally using green electricity generated by onshore or offshore wind turbines, thus emitting zero greenhouse gas emissions.
Northern Germany lends itself to the creation of hydrogen storage infrastructure for several reasons: Firstly, due to the proximity of onshore and offshore wind farms as well as future centers of industrial hydrogen use. In addition, the region holds 80 percent of Europe’s salt cavern storage capacity. And there are already a large number of long-distance gas pipelines that can be repurposed to convey hydrogen. This also explains why the installation of the European Hydrogen Backbone, the EU’s planned long-distance hydrogen pipeline, will kick off in northwestern Germany. The first cavern in SaltHy, which stands for Storage Alignment with Load and Transport of Hydrogen, is due to be linked to this network by a connecting pipeline.
Hydrogen for the steel and chemicals industries
In Harsefeld, the first cavern is expected to be up and running between 2030 and 2032. The decision about the construction of the second cavern will be taken by the company in 2028 and will depend on how the H2 market has developed by that point. The second facility could then become operational in 2034. Each cavern is designed to contain up to 7,500 metric tons of hydrogen. “That would, for example, cover the needs of a regional steel plant that requires 140 metric tons of hydrogen a day for approximately two months,” explains Assmann.
The H2 gas will be treated at the Harsefeld site in an overground facility before being stored below the surface. The storage pressure will be over 200 bar, depending on the quantity. The pressure in the transportation pipeline will, nevertheless, be lower at a maximum of just over 80 bar. The gas will therefore be compressed and cooled in the compressor station prior to storage. When required, the hydrogen can be removed, processed and fed into the grid for onward supply.
A feasibility study carried out by Storengy Deutschland in 2022 came to a positive conclusion, as did a market survey of companies in March this year. “Many of the announced H2 projects for which a connection to a hydrogen storage facility will be relevant are at an advanced stage and are situated in northern Germany,” says the company, which is reassured of the need for new subterranean hydrogen reservoirs in Germany.
Mapping work and preparations for the approvals process are currently underway in Harsefeld. Underground storage facilities are subject to mining law and must be signed off by the relevant regional authorities. The planning, approval, construction and operation of such facilities are a complex matter, explains Assmann, a process engineer who has worked in the energy sector for over 30 years. The cost and effort involved should therefore not be underestimated. Storengy hopes to submit initial documents before the end of this year.
The investment decision on the underground part of the reservoir is expected at the beginning of next year. In view of the long time line for the project, investment will be phased over several stages in order to reduce the risk. If the company goes ahead, it will be spending upfront so it can cover the demand for hydrogen storage that emerged from the market survey.
H2 reservoirs relieve power grid
Construction work could begin in 2026 with the drilling of the first boreholes, says Assmann. The process of debrining a salt cavern, i.e., flushing out the salt with water, takes three to five years depending on its size. Similar to the method used to build natural gas storage reservoirs, here, the intention is to create a roughly cylindrical void that is around 200 meters (650 feet) in height and approximately 60 to 70 meters (195 to 230 feet) in diameter. Thanks to high injection and withdrawal rates, the caverns would also help relieve the strain on the power grid.
Located in the area around Harsefeld and in the Hamburg metropolitan region are large industrial companies that will need considerable amounts of hydrogen in future to defossilize their production processes. This will be the case for both the metalworking industry and the chemicals sector. The Dow factory situated around 20 kilometers (12 miles) from Stade is a case in point. As a cooperation partner, the global corporation, which operates one of the biggest production facilities for chlorine chemicals in Europe on the lower reaches of the river Elbe, will process the salt resulting from debrining the cavern.
The port of Stade together with the planned ammonia terminal will make the town a hub for trade, logistics and industrial development and allow hydrogen to be imported in the form of ammonia, for example. This is why the region is being developed as a focal point for green H2.
Politicians should devise demand schedule
Storengy Deutschland, which boasts a market share of 8 percent in Germany thanks to its six natural gas storage sites, is planning more hydrogen storage facilities besides those in Harsefeld. From a geological standpoint, the sites in Lesum and Peckensen in northern Germany would be suitable, according to Assmann. What is still lacking on the political side, in his opinion, is a schedule for at least the next 10 years which sets out the yearly requirement for converting storage reservoirs to hydrogen and the construction of new hydrogen storage facilities. Details of how much H2 storage capacity should be available – and by when – are yet to be determined, he says. Similarly, questions remain about how the storage facilities will be funded and how access to them will be regulated.
In France, where the parent company has also been managing natural gas storage reservoirs for decades, Storengy is developing a large-scale demonstrator for green hydrogen alongside industrial partners. According to company information, a salt cavern in Étrez in the Auvergne-Rhône-Alpes region with a storage capacity of 44 metric tons of hydrogen is being set up in conjunction with an electrolyzer and applications in the chemicals industry and heavy-duty mobility in order to support the development of the area’s Zero Emission Valley.
Since it isn’t possible to relinquish use of fossil-based forms of energy entirely in the short term, it will not be possible to repurpose the necessary storage reservoirs immediately. “We will have to continue to safeguard supply with natural gas via existing storage facilities,” says Assmann, explaining that this is why it’s necessary to build new storage reservoirs for the emerging hydrogen market. Only when natural gas storage facilities are no longer needed can these be converted for the storage of green gases where required.
by Niels Hendrik Petersen | Sep 12, 2024 | Development, Energy storage, News
Liquid bearer of hope
Many of the technologies for H2 transport are not yet fully developed. Researchers and industry are working to develop safe H2 distribution over long distances, also because Germany will be dependent on H2 imports on a large scale. In addition to ammonia, liquid organic hydrogen carriers (LOHC) have a good chance of being employed in projects and industry. Because they could use the conventional infrastructure of oil tanks and tankers.
The abbreviation LOHC stands for liquid organic hydrogen carriers. In this, hydrogen is chemically and reversibly bound to a liquid organic carrier substance. That can be toluene, benzyltoluene or dibenzyltoluene, for example. LOHCs describe organic compounds that can absorb and release hydrogen and can therefore be used as storage media for hydrogen. All compounds used are liquid under normal conditions and have similar properties to crude oil and its derivatives. The advantage: LOHCs can be used in liquid form in the existing infrastructure.
Normally, hydrogen is produced in gaseous form at a high pressure of 700 bar or in liquid form and stored and transported at extreme temperatures of minus 253 °C in special containers. Both methods, however, are technically complex and expensive. LOHCs offer an attractive alternative here. One advantage: The direct use of an LOHC, for example in fuel cells to generate electricity, makes the handling of hydrogen as a gas unnecessary. “The technology therefore enables a particularly inexpensive and reliable supply to mobile and stationary energy consumers,” states Daniel Teichmann, CEO and founder of Hydrogenious.
LOHCs could simplify H2 transport over long distances, Source: Projektträger Jülich
Reuse of carrier medium
This technology uses little or no fossil fuels. They can be used again and again as in a closed circuit. The process works in two phases: During hydrogenation, the hydrogen is bound to liquid organic hydrogen carriers in the presence of a catalyst, and during H2 release, so dehydrogenation, the gas is released again using heat and a catalyst. The loaded carrier liquid can be stored at ambient pressure and uncooled. For the transport, conventional oil tanks and tankers can therefore be used. When the hydrogen is released, however, the discharged carrier liquid must be returned to the place where it was loaded with hydrogen. Specifically, this means: The ship or tanker would drive in circles fully loaded.
LOHCs are therefore a great hope for H2 transport over long distances. The project TransHyDE on Helgoland is researching, for example, the entire transport chain from the binding of hydrogen to an LOHC through to separation. Currently, the projects are only being implemented on an experimental or small-scale basis.
What is certain, however, is that any form of storage and transport of hydrogen, ammonia, LOHC and other hydrogen-based energy carriers also requires suitable framework conditions. TransHyDE is therefore analyzing the systemic framework and identifying design requirements. The results will then lead to recommendations for action. These include the need to adapt standards, norms and certification options for hydrogen storage and transport technologies.
LOHC technology is also part of the German government’s new hydrogen acceleration law: Because national hydrogen production takes place both through systems for the electrolytic production of hydrogen and through the splitting and dehydrogenation of ammonia and hydrogenated liquid organic hydrogen carriers. The coalition agreement and the update of the national hydrogen strategy provide for the doubling of the national expansion target for electrolysis capacity from 5 to at least 10 GW by 2030.
But that won’t be nearly enough. Germany will need H2 imports. LOHCs could play an important role in this. The new national ports strategy (Nationale Hafenstrategie, NHS) was developed in close conjunction with the implementation of the national hydrogen strategy. In the NHS, the German government assumes that up to 70 percent of hydrogen demand will be covered by imports by 2030, which will mainly occur by ship.
Carrier material benzyltoluene
The LOHC technology from Hydrogenious could be particularly interesting for the maritime transport of hydrogen: Because it uses the existing infrastructure for liquid fuels in the ports and can be transported by tankers or barges. This is entirely in line with the national ports strategy, which aims to create sustainable concepts for the reuse of conventional infrastructure.
Hydrogenious employs the flame-resistant thermal oil benzyltoluene as a carrier medium. According to the company, this enables efficient storage, especially in densely populated port areas (e.g. Rotterdam, see p. 17). Hydrogen stored in an LOHC can be handled at ambient temperature and pressure and has a hazard potential comparable to diesel, describes Andreas Lehmann, Chief Strategy Officer at Hydrogenious LOHC.
The company believes that LOHCs eliminate the shortcomings of existing methods. These are less flammable and cheaper to transport than liquid hydrogen, which is highly explosive, highly vaporizing and requires expensive containers and a new, special infrastructure. The recovered hydrogen also has a high purity, unlike after the reconversion of methanol.
Patrick Schühle works on LOHCs at Universität Erlangen-Nürnberg, Source: FAU
The company Hydrogenious from Erlangen, Germany also participates in various research projects: In the project LOReley, experts from industry and research want to optimize the process of H2 release, so the dehydration. “To release the hydrogen requires reaction accelerators, so catalysts, and temperatures of up to 330 degrees Celsius,” states researcher Dr. Patrick Schühle from the Friedrich-Alexander-Universität Erlangen-Nürnberg (FAU, see Fig. 3). Heat must be supplied to the process all the time. “The less heat you have to provide for the process, the more efficient the entire LOHC technology becomes, because you save energy,” he states.
LOReley developing a plate reactor
Until now, for dehydration, a reactor with tubes into which pellets measuring just a few millimeters were poured was used. The pellets consist of porous aluminum oxide in which the actual active metal platinum is deposited. When the hydrogen-loaded LOHC comes into contact with the pellets, the H2 is released. The researchers of project LOReley have now chosen a new approach and are relying on a plate reactor based on heat exchangers that are otherwise familiar from heating systems, refrigerators or industrial plants.
Another advantage over the previous procedure, the scientists believe, is that the catalyst is firmly attached to the plate. “In the bulk reactor, the pellets can rub against each other and the catalyst may be rubbed off as a powder. In Project LOReley, we have now developed a catalytic layer that is highly resistant to mechanical abrasion and vibrations,” states chemical engineer Schühle.
In this plate dehydration unit, hydrogen was released, Source: Hydrogenious LOHC
In the project, the experts tested the new catalyst reactor concept in the laboratory and on the premises of the participating company Hydrogenious LOHC Technologies, an FAU spin-off. The new plate reactor ran stably for around 1,000 hours. It was also shown that the hydrogen release rate within 15 minutes was able to be doubled. “The heat is not brought comparatively slowly over the entire volume of the reactor, but rather specifically and directly to the catalyst layer,” says Schühle. This flexibility in dynamic operation is certainly relevant in gas power plants or in ship transport.
Schühle and colleagues were able to test their approach on a comparatively small scale. The reactor consisted of ten plates. In the next step, the demonstrator must grow so that it can be used in real operation at a location where the hydrogen is also needed. Only then can they say how good the reactor is in terms of thermal efficiency compared to the standard reactor. LOHCs offer many opportunities. Whether all hopes can be fulfilled the LOReley project, but also the technology as a whole, still needs to be demonstrated.
Transport by ship is 20 percent more expensive
According to an analysis by Aurora Energy Research, transports by ship to Germany are generally at least 20 percent more expensive than pipeline transport: Accordingly, liquefied hydrogen from Spain comes to 4.35 euros and from Morocco to 4.58 euros per kilogram. If transported using liquid organic hydrogen carriers (LOHCs) or ammonia, it would be around 4.57 euros per kilogram from Spain and around 4.70 euros from Morocco, including the costs of converting it back into gaseous hydrogen in Germany. For imports from Australia and Chile, ship transport is generally the only option. They will only reach competitiveness if the hydrogen is transported as ammonia. Then, the costs are 4.84 or 4.86 euros per kg. All of these values are within the range of production costs in Germany. So it would depend on the specific individual case as to which path is competitive. For hydrogen from the United Arab Emirates, the cheapest transport would also be in the form of ammonia; however, at 5.36 euros per kilogram, this would not be competitive in comparison to domestic production.
by Hydrogeit | Jul 22, 2024 | Energy storage, Europe, international, News
Europe’s largest port wants to become sustainable
“How quickly can we implement the energy transition?” This question has been posed for some time by the Port of Rotterdam, the largest European sea freight transshipment point. In the past – and still today – the huge industrial area was shaped by the oil and gas industry. Among other things, four large refineries are located there, which now need to be decarbonized. Boudewijn Siemons, CEO and COO of the Port of Rotterdam Authority, stated, “If it can be done electrically, it should be – with hydrogen otherwise.”
To drive this transformation process forward, together with the gas supplier Gasunie, the port company is initially dedicating itself to infrastructure, because “infrastructure is an enabler,” as Gasunie CEO Willemien Terpstra states. One of the main projects is a new pipeline system – for hydrogen and carbon dioxide. The new construction of the Hydrogen Backbone (H2) as well as the Porthos pipe system (CO2) started in October 2023 with the groundbreaking ceremony by the Dutch king Willem-Alexander.
The port is receiving significant political support. “I see a government that is really working to remove obstacles,” says the port head. This also benefits Germany, where a large proportion of the energy supplied will be forwarded. Accordingly, the Netherlands also sees Germany as the main customer for hydrogen –particularly the state of Nordrhein-Westfalen.
The time of waiting is over, because large coal-fired power plants in the port will be shut down in 2030 (see Fig. 2). However, eliminating CO2 emissions from fossil fuels is only one path to reducing carbon dioxide emissions 55 percent by 2030. In addition to increasing efficiency, negative CO2 emissions will also be necessary, so the carbon dioxide produced must be stored using CCS (carbon capture & storage). “If we want to reduce CO2 emissions, there is no way around CCS,” according to Siemons.
Fig. 2: The coal-fired power plant located behind the substation will be shut down by 2030
The goal is CO2 neutrality by 2050. By then, the approximately 100 million tonnes of crude oil imported annually in Rotterdam are to be replaced by other media. For example, around 15 million tonnes of oil are to be substituted by 20 million tonnes of hydrogen, whereby about 90 percent of the hydrogen required will be imported.
As to the question of how long the planned “temporary use of blue hydrogen” could last, the answer came clear: “Decades.” Blue hydrogen or “low-carbon hydrogen,” as it and other non-green H2 compositions have been called for some time now, are to serve as the initial spark for building an H2 economy. It is already clear today that the associated lock-in effects will be considerable, as the billions invested are to be amortized over at least 15 years.
The capture of CO2 is only part of the task to be accomplished. Extracting small amounts of carbon dioxide from a gas stream is still relatively simple and efficient, but the larger the percentage is to be, the more complex it becomes. The port has initial experience in this area: For example, CO2 is already being captured there and used in greenhouses to improve plant growth. Ulrich Bünger from the energy consulting company LBST is nevertheless skeptical and stated in Rotterdam that CCS is still a long way from being where it is supposed to be. There is “hardly any experience,” according to the energy expert, while the impression is given that the technology is tried and tested.
Infrastructure is key
For the infrastructure and its operators, it doesn’t matter how the hydrogen was produced. Willemien Terpstra, CEO of gas transmission company Gasunie, said on the matter: “We are ready to transport any color.” Accordingly, Gasunie already made the final investment decision for the pipeline construction last year, although only five percent of the capacity has been sold so far, as the appointed CEO since March 2024 has explained. Of course, the government’s strong commitment was decisive here, which is contributing 50 percent of the costs. The aim is to jointly complete the pipe system by 2030, which will then be able to provide 10 GW of power.
Shell refinery in Port of Rotterdam
To H2-international’s inquiry of how the hydrogen would be transported to Rotterdam, CEO Boudewijn Siemons named all the options: ammonia, methanol, LH2 and LOHC – No variant is excluded from the outset. When asked whether the port company could handle large quantities of ammonia safely, Siemons initially hesitated briefly, but then replied confidently, “Yes, I think we can do that. I’m pretty sure of that.” At the same time, however, he conceded that “not every place in the port” is suitable.
As ammonia tanks have been present in the port for a long time, the corresponding expertise already exists. The plan is to triple the storage capacity for ammonia in the next few years compared to 2023. However, such a change in fuels and energy storage media is unlikely to significantly alter the appearance of the world’s eleventh largest port, the operators are certain. Even though the media will be different, many installations will look similar to before. It is already clear today that an infrastructure for LOHC and LH2 is also being developed. Corresponding partnerships with Chiyoda and Hydrogenious already exist.
200‑MW electrolyzer from Shell
The highlight in the harbor, however, is Holland Hydrogen 1 (see Fig. 1), a 200‑MW electrolyzer that is dimensioned in such a way that the green hydrogen produced with the help of wind turbines can then replace the amount of gray hydrogen so far required in the port. The electricity required is sourced from a 759‑MW offshore wind farm (Hollandse Kust Noord) north of Rotterdam, which is directly connected. In order to meet all EU regulations, H2 production (approx. 20,000 tonnes per year) will follow the respective wind supply, even if this means that the electrolyzers cannot run 24/7.
For this project, for which the final investment decision has already been made, Shell received this year’s Green Hydrogen Project Award during the World Hydrogen Summit. The area on which the in total ten 20‑MW electrolyzer modules from Thyssenkrupp Nucera is to be installed is what’s called “proclaimed land” that was wrested from the North Sea. Where the conversion park is being built used to be water. However, it is likely to take until the end of the decade before it goes into operation. In the future, also Holland Hydrogen 2 could follow – a second area with likewise 200 MW. By 2030, this could already be 2 GW.
The H2 pipes (black) and the CO2 pipes (white) are sometimes only 40 cm apart
The corresponding H2 pipeline, which is currently under construction, will then connect the H2 production facility with the various refineries and other customers. Sufficient wind for green hydrogen production is available in Rotterdam. In the port area alone 300 MW of wind power are installed. As this is more electricity than is needed, a large stationary accumulator has already been installed, to be able to temporarily store at least some of this green electricity.
The hydrogen tubes measure 1.2 m (48 inches) in diameter and are pressurized with 30 to 50 bar. The construction of the first 30 kilometers across the port is costing 100 million euros. The entire H2 Backbone network within the Netherlands (1,100 km) is expected to cost 1.5 to 2 billion euros. However, 85 percent of the future H2 pipeline system will consist of repurposed natural gas pipes.
Parallel in construction is the CO2 pipeline Porthos. This pipe system connects numerous locations in the port with the platform off the coast, via which the carbon dioxide is then to be fed into subsea gas fields.
The H2 pipes for the Hydrogen Backbone are ready and are currently being placed underground
Future Land informs about H2 activities
To be able to inform about all these activities, the port has set up “Future Land,” a contact point for tourists, school classes, the press and investors, where they can get answers to their questions about the future of the port. The information center is located right below the world’s largest wind turbine. The Haliade-X 13 is 260 m high (853 ft) and has an output of 14 megawatts. It is designed for offshore wind farms in the North Sea, but has been tested on land since 2021 and can supply six million households with electricity.
In view of the fact that a third of the energy required in Germany comes into the country via Rotterdam, Ursula von der Leyen, President of the European Commission, stated: “If the Port of Rotterdam is doing well, the European economy is doing well.”
Author: Sven Geitmann
by Monika Roessiger | Jun 13, 2024 | Development, Energy storage, Germany, News
Electrolyzers on the test bench
In Hydrogen Lab Bremerhaven, manufacturers and operators of electrolyzers can put their systems to the test. The fluctuating feed-in of wind power is, in contrast to the steady mode of operation, a challenge. How the associated complex processes can be optimized engineers are now testing in real operation.
A gray, windy day in Bremerhaven – a city near the North Sea in Germany. The engineer Kevin Schalk from research institute Fraunhofer IWES showed me the Hydrogen Lab Bremerhaven (HLB) – an extensive open-air test site. It is located next to a blue-painted hangar at the former airport Luneort and contains the most important building blocks for a climate-neutral energy system: a PEM electrolyzer, an alkaline electrolyzer, three compressors, low-pressure and high-pressure storage vessels for hydrogen (up to 40 bar or up to 425 bar), fuel cells and a hydrogen-capable combined heat-and-power plant.
“Our Hydrogen Lab is modular and designed for maximum flexibility,” says Kevin Schalk. All components of the test field are connected to each other by trench routes in which the power and data cables as well as the hydrogen lines run. The pipes for water and wastewater are laid underground. Uniting the installations is the control room, in which all the information comes together and from where the components are monitored and controlled.
Between the plants, there are free spaces where manufacturers or operators can have their own electrolyzers tested. This means that each test specimen can be investigated independently of tests in other parts of the laboratory, states Schalk. If needed, the opposite is also possible: The test specimen can be operated together with other parts of the hydrogen laboratory.
Around the H2 test site, meadows stretch as far as the horizon, dotted with wind turbines. At eight megawatts, the most impressive plant of this kind is located directly next to the open-air laboratory; a gray giant whose rotors turn leisurely in the wind. “When the AD8-180 went into operation in 2016, it was the largest wind turbine in the world” says Kevin Schalk, who is director of Hydrogen Lab Bremerhaven (HLB). The elongated rotor blades indicate that the prototype was actually intended for use at sea. Now, the plant will soon be used to test the production of hydrogen from wind power under real conditions. Up to one tonne of green gas is to be produced there every day.
Direct comparison of different electrolyzers
The team around Kevin Schalk will address the question of how different types of electrolyzers interact with a wind energy plant on a real scale. On the one hand, there is the 1-megawatt PEM electrolyzer that splits distilled water into hydrogen and oxygen. This type of water splitting takes place in an acidic environment, in contrast to alkaline electrolysis in an alkaline milieu. Potassium hydroxide solution (KOH) in a concentration of 20 to 40 percent is used as the electrolyte.
An alkaline electrolyzer (AEL) possesses an anion exchange membrane, thus allowing the OH– ions to pass through. It is cheaper to purchase and distinguishes itself by long-term stability. The most expensive components of an electrolyzer are the stacks as well as the power electronics, so the rectifier and transformer. The question of efficiency, according to Schalk, can hardly be given a blanket answer – at least for complete systems.
If an electrolyzer is operated with fluctuating electricity from renewable energies instead of continuously as in normal operation, this is a challenge for various reasons: A dynamic driving mode puts more strain on the materials, and it can come to a gas contamination in partial load operation, which ultimately leads to shut-down of the system. In the HLB, various operating states are to be compared with each other, so full load or partial load; in addition to the start times from cold or warm standby.
“We can set, for example, the operating mode of an electrolyzer to the seven-day forecast of the wind turbine and then test this operating mode,” explains the engineer. “Together, our electrolyzers can absorb a maximum of 2.3 megawatts. So far, there is generally little data and knowledge about how megawatt electrolyzers behave with fluctuating wind power. The available data are mostly simulations and studies based on measured data in smaller systems and then extrapolated,” he adds.
Unique selling point of the H2 research laboratory
A few hundred meters away from the test laboratory is the Dynamic Nacelle Testing Laboratory (DyNaLab) of Fraunhofer IWES, a large nacelle test stand with a virtual 44‑MVA medium-voltage grid. To this, the Hydrogen Lab is also connected, which allows the electrical integration of the systems into the power grid to be tested. “Dynamic changes in grid frequency or voltage dips can be simulated in this way in order to investigate the effects on an electrolyzer, for example,” says Kevin Schalk. This is a unique selling point and enables researchers to test what will become increasingly important in the future: electrolysis in grid-stabilizing operation. This also includes the two technical options for reconversion to electricity: the hydrogen-capable combined heat-and-power plant and the fuel cell systems.
Fig. 2: Shipping container solution with various hydrogen storage vessels (left) and combined heat-and-power plant
A layman can hardly imagine how difficult it is to set up such a highly complex system in one location. The electrolyzers alone require more than just a water connection from which the water is first sent to a treatment unit so that it is ultra-pure before it can be fed into the electrolyzer stack, explains Kevin Schalk. The hydrogen that is then generated must also be treated and the remaining water removed, which occurs in a drying unit. In addition, the oxygen released during water splitting must be collected and stored safely. Ideally, the oxygen could be used for further applications, for example in an industrial or commercial operation or in a sewage treatment plant.
“And that was just the water; now comes the electricity side,” continues Kevin Schalk. “We have the connection to the public power grid, so we may still have to transform it to achieve the right voltage level. This is followed by the inverter to switch from AC to DC voltage. Then, the current goes into the stacks of the water splitting unit. Whenever the grid “twitches,” so the frequency or voltage changes beyond a certain level, the electrolyzer after it must be able to cope with it. And if the power electronics are not set correctly, the system switches off,” he adds.
In addition, the thermal side of the system must be taken into account. “Initially, the electrolyzer must be heated,” explains Kevin Schalk. “Later, when it is running constantly, it usually needs to be cooled in order to maintain the optimum operating point in each case. This is inevitably accompanied by energy losses,” he adds. That’s it for the PEM electrolyzer. With alkaline electrolysis, the potassium hydroxide solution still has to be removed and recycled.
Getting fit for offshore use
Another key topic for the research lab is taking place as part of the government-supported pioneer project (Wasserstoff-Leitprojekt) H2Mare. Involved is a 100-cubic-meter (3,531-cubic-foot) seawater basin as well as a desalination plant, for which the waste heat from the electrolyzers will be used. This is based on the realization that, in densely populated Germany, larger quantities of green hydrogen are most likely to be produced at sea. Therefore, the electrochemical process for splitting water must be suitable for use on the high seas, because in future electrolyzers will also be connected directly to offshore wind turbines. This in turn requires coupling with a seawater desalination plant, and this combination is energetically favorable because the waste heat from the electrolyzer can be used for the desalination.
Engineer Schalk points out that he and his colleagues adhere to the German or European regulations in all their investigations, such as the EU sustainability certification for compliance with RED II (Renewable Energy Directive). It specifies the conditions under which hydrogen can be certified as “green,” and that is exactly what they want to produce here. “The customers need guaranteed green hydrogen, for example for public transit buses,” he says. An H2 refueling station for commercial vehicles has been built in the bus hub of Bremerhaven. In addition to public transit, there are other potential customers in the region: for example, a shipping company that wants to operate its ship in Cuxhaven with gaseous hydrogen. Or the public mobility company Eisenbahnen und Verkehrsbetriebe Elbe-Weser (EVB) as operator of the hydrogen trains for the regional railroad in Niedersachsen.
Hydrogen Lab Bremerhaven is cooperating with Norddeutsches Reallabor, a large-scale research project funded by the German economy ministry in which several German states are advancing sector coupling based on hydrogen. HLB receives funding totaling around 16 million euros from the European Development Fund as well as the German state of Bremen. In May of this year, the HLB will go from trial to normal operation and will initially produce a good 100 metric tons of hydrogen per year. In the second phase, Kevin Schalk expects over 200 tonnes. “We will be the first large-scale production facility for green H2 in northern Germany,” he says.
Fig. 3: View over the HLB with free working spaces – the control center on the left
