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.
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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.
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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 Monika Roessiger | Sep 10, 2024 | Development, Europe, hydrogen development, Market, News
H2 generation on floating offshore wind power plants
How to ramp up the production of green hydrogen in just a few years and distribute it quickly across the country independently of the development of the H2 core network explained Jens Cruse, shipbuilding engineer, at the end of January this year before an expert audience in Hamburg.
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Self-sufficient, floating wind power plants, placed in European waters, are to produce the molecule required primarily in industry for defossilization, directly on the platform by electrolysis from desalinated seawater, and to bind it to the LOHC (liquid organic hydrogen carrier – see also p. 23). Shuttle tankers, which have long been common in the oil industry, could then transport the valuable cargo to land or to the nearest port on a monthly basis, for example.
Jens Cruse, who after years of research set up his own company, lists the advantages of direct H2 production on the high seas: “Such a model can save up to 50 percent of investment costs because neither electricity nor gas pipes have to be laid.” The expensive grid connection is also eliminated, which speeds up the entire process because you don’t have to wait for lengthy approval procedures. Operating costs are also reduced if you are not tied to a pipe system. The so-termed offshore H2 generators are intended to be used where there is a lot of wind, almost around the clock.
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“You don’t have to travel to Patagonia, Namibia or Australia,” says the founder and managing director of Cruse Offshore GmbH. “We have this right on our doorstep in Europe, particularly off the coasts of Norway, Ireland and Scotland,” he says. The electrolysis systems that are still relatively expensive today could run the whole year there, with a maximum of free to harvest wind energy.
Definitely more cost-effective
Producing hydrogen at sea by integrating the electrolyzer into the wind power station would cost even less than producing hydrogen in an offshore wind farm that is connected to the water splitting system via a power cable. Another advantage of the integrated solution is that the low-voltage direct current from the wind power station can be used directly by the electrolyzer. This saves on the conversion of electricity and the associated losses. Transporting hydrogen via pipeline is known to be more cost-effective than transmitting the electricity via lines. By connecting the electrolyzer directly to the wind power station, the basic costs are also eliminated that would otherwise have to be taken into account for a platform at sea or a land area for parking the container with the electrolysis plant.
In the model, the floating system withstood the heaviest loads, states Professor Moustafa Abdel-Maksoud, director of the Institute of Fluid Dynamics and Ship Theory at the Technical University of Hamburg (TUHH), who, together with his team, carried out simulations to optimize the system for extreme weather conditions at sea and tests in the TUHH’s wind and wave tunnel. Not even a simulated wave more than 16 meters high impaired the functioning of the system. “The system works perfectly, and it’ll pay off,” says Abdel-Maksoud. “We are technically and scientifically capable of realizing this,” he says. The innovative technology also avoids competition for space with conventional offshore wind farms and is not dependent on surplus electricity for H2 production.
Technically and economically feasible
After years of preparatory work and scientific tests, Cruse with a consortium is now planning to build a 5‑MW plant that combines wind power, seawater desalination, electrolysis and H2 storage in LOHCs. This is being done as part of the three-year research project ProHyGen, which is receiving support from the German economy ministry (BMWK) [1]. This is a joint project with, besides Cruse Offshore GmbH and the TUHH, also the university Friedrich-Alexander-Universität Erlangen-Nürnberg (FAU), the machine and gearbox manufacturer Renk and the company specializing in the processing of crude oil derivatives H&R.
That the production of green hydrogen on floating plants is economically and technically feasible is also demonstrated by another BMWK-funded project, by research institute Fraunhofer ISE [2]. Its concept also envisions the climate-neutral gas being transported by ship, but not bound to LOHCs, instead stored in pressurized tanks in which the hydrogen is compressed to 500 bar.
The 5‑MW prototype from ProHyGen is to be deployed in the German exclusive economic zone (EEZ). The foundation of the planned H2 offshore generator will consist of four “floaters” that are connected under water and filled with ballast water. The material used is the sheet steel in shipbuilding. One of the floaters carries the wind power station; another houses a plant for desalinating seawater as well as an electrolyzer and a component for storing the hydrogen in an LOHC. Below this is a rotating buoy and the anchor cables used to attach the H2 offshore generator to the seabed. Two further floaters consist of double-walled tanks in which the LOHC carrier fluid is stored. These are normal oil tanks. The existing oil infrastructure can also be used in other ways with this process, stresses Cruse, indicating the railways and waterways that already connect industrial ports with industrial sites today. Hamburg, for example, offers the best conditions for this, because heavy metal production companies located in the port are already potential customers for hydrogen. In addition, the tanks with the hydrogen bound to the carrier oil can be distributed deep into the country by train or barge, as is currently still the case with fossil fuels. This long-established transport network extends to neighboring European countries. A functioning infrastructure is also an important criterion for a rapid market ramp-up of the hydrogen economy.
This sketch shows where the necessary systems are located
Investors wanted
“After testing of the prototype, the system will be scaled up to 15 MW and in the course of 2025 produced in series,” explains Jens Cruse, who has registered a patent for the process and is responsible for the industrial utilization of the concept. A further goal of the joint project ProHyGen is the planning of offshore H2 parks in the gigawatt range. If all goes well, installation of the first 3‑GW park producing green hydrogen could begin in the second half of 2027, according to Cruse. “To do this, however, we need financially strong partners who want to support these future-oriented innovations,” he says.
The green hydrogen bound in an LOHC can be transported to land by ship
References:
[1] https://www.tuhh.de/fds/research/current/modular-ship-assist-1
[2] https://www.ise.fraunhofer.de/de/presse-und-medien/presseinformationen/2023/wasserstofferzeugung-auf-dem-meer-fraunhofer-ise-entwickelt-konzept-fuer-wasserstofferzeugung-auf-einer-offshore-plattform.html
by Niels Hendrik Petersen | Jul 15, 2024 | Development, Europe, News
Energy group Axpo and the company Rhiienergie have launched the first H2 production plant for green hydrogen in the canton of Graubünden in eastern Switzerland. The plant, which has a capacity of 2.5 megawatts, will produce up to 350 metric tons of hydrogen a year and is situated directly adjacent to the Reichenau hydropower plant in Domat/Ems. According to Axpo, it is the biggest plant of its kind in Switzerland.
Thanks to the hydrogen produced by the plant, up to 1.5 million liters of diesel will be saved annually. The hydrogen is compressed on site at the plant, meaning that the sustainable gas can be supplied to refueling stations and industrial customers in the future. The H2 production facility is directly connected to the Reichenau hydropower plant in which Axpo holds a majority stake. The connection to a run-of-river power plant makes this a groundbreaking project for Axpo. It is also the first plant in Graubünden canton. Christian Capaul, CEO of Rhiienergie, describes the new production facility as a flagship project.
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by Niels Hendrik Petersen | Jun 13, 2024 | Development, Germany, News, Policy
The European Commission is allocating nearly 720 million euros to seven projects for renewable hydrogen in Europe. Together, the involved stakeholders aim to produce 1.58 million tons of renewable hydrogen over ten years, thereby avoiding more than 10 million tons of CO2 emissions. Of the selected projects, five are located in Spain and Portugal, with two more in Finland and Norway. The condition: they must begin producing renewable hydrogen within a maximum of five years after signing the grant agreement. They will then receive a fixed premium for up to ten years. This subsidy is intended to offset the price difference between their production costs and the market price for hydrogen. In total, there were 132 bids.
No project from Germany was selected. Therefore, the German government is now allocating 350 million euros from national funding in a new auction process for the highest-ranked projects in Germany that did not qualify for EU-level funding but still meet the funding criteria. The auctions are financed by revenues from emissions trading. Wopke Hoekstra, EU Commissioner for Climate Action, sees this as a crucial step towards the production of renewable hydrogen in Europe. “I encourage other member states to follow Germany’s lead to promote the production of renewable hydrogen at the national level through our European auction platform,” said Hoekstra.
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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.
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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.
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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
by Benjamin Böckler | Jun 11, 2024 | Development, Energy storage, Europe, Germany, hydrogen development, News
Flow measurement of high-pressure gas and liquid hydrogen
In the field of flow measurement, the use of hydrogen, especially regeneratively produced hydrogen, as a process gas and energy carrier has become a focal point in many applications. Due to the need to use storage capacity efficiently, hydrogen must be stored under high pressure or in liquid state. Metrologically verified quantity measurement is needed for the low to high pressure range of gaseous and liquefied hydrogen applications. In addition, appropriate traceability chains to the SI system need to be established for the wide range of operating conditions in order to make valid statements about the measurement accuracy and stability of the flow meters used. The EMPIR project 20IND11 MetHyInfra addresses these challenges by providing reliable data, metrological infrastructure, validated procedures and normative support.
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Critical Flow Venturi Nozzles (CFVN) are widely used today and represent a standardised and accepted method of flow measurement. The main details of the shape and theoretical model are defined in the ISO 9300 standard. CFVNs are used in legal metrology and are recognised as a reliable standard with high long-term stability. The low cost and low maintenance CFVNs provide stable, reproducible measurements with a well-defined geometry and are only dependent on the gases used. The ISO 9300 standard describes two nozzle shapes, cylindrical and toroidal. In reality, however, the nozzle contours manufactured to this standard deviate from these ideal shapes. In most cases, the actual shape is between the two ideal shapes.
The achievable measurement uncertainty is also limited by the quality of the models of the thermophysical properties of the gases to be measured. The current reference Equation of State (EoS) for normal hydrogen (n-H2) was developed by Leachman et al [1]. Due to the limited thermodynamic measurement data available for n-H2 with comparatively high measurement uncertainties, the uncertainties for the various properties are generally an order of magnitude higher than for other gases.
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Therefore, in this project, new Speed of Sound (SoS) measurements were performed at temperatures from 273 to 323 K and pressures up to 100 MPa. The data obtained were used to develop a new EoS for n-H2 optimised for gas-phase calculations [2]. The measurements made it possible to significantly reduce the uncertainties of the SoS calculated from the EoS in the investigated temperature and pressure range.
Extensive Computational Fluid Dynamics (CFD) simulations were carried out in the project to gain further insight into the flow physics in the nozzle. For this purpose, a numerical model for high-pressure hydrogen flows in the CFVN was developed in OpenFOAM, taking into account various relevant gas effects such as compressibility effects, boundary layer effects and transition effects. The results obtained are in much better agreement with the experimental data than previously available implementations.
In order to be able to evaluate and compare the flow behaviour of non-ideal nozzle contours, CFD simulations were also carried out for the ideal nozzles investigated experimentally in this project, as well as for parameterised nozzles. The flow coefficient of these non-ideal nozzles can be predicted very well using the proposed nozzle shape characterisation. The implementations developed in the project are freely available [3].
Figure 2: Mobile HRS flow standard
As there is currently no test facility with traceable standards available, that can be used to calibrate CFVNs directly with high pressure hydrogen, an alternative method had to be developed. The chosen approach is to calibrate a Coriolis flow meter (CFM) under high pressure conditions (range 10 MPa to 90 MPa) with a traceable gravimetric primary standard, so that it can later be used as a reference for the nozzle calibration.
The H2 test filling station (Hydrogen Refuelling Station, HRS) at the Centre for Fuel Cell Technology (ZBT) in Duisburg was selected for the calibration of the reference meter. For the measurements, a Rheonik RHM04 CFM was installed as a reference flow meter in the “warm zone” of the HRS, i.e. upstream of the heat exchanger and the pressure control valve. In this area, the temperature is always close to the ambient temperature and the pressure is constantly high, typically around 90 MPa. A mobile HRS primary flow standard was used for the calibration, which was connected directly to the HRS and thus took the role of a vehicle.
In the final step, the results of the CFVN measurement campaign will be compared with those of the CFD simulations. The newly developed EoS will be used in both the measurement campaign and the CFD simulations in order to compare both results in the best possible way.
Measurement method for liquid hydrogen
In addition to gaseous hydrogen, the project focuses on liquefied hydrogen (LH2). There are currently no primary or transfer standards for the measurement of LH2. The uncertainty associated with using a flow meter to measure the quantity of LH2 is unknown and unquantified as there is no direct traceability to calibrations using LH2 as the calibration liquid. The lack of calibration facilities means that meters used with LH2 must be calibrated with alternative liquids such as water, liquid nitrogen (LN2) or liquefied natural gas (LNG).
The project has therefore developed three approaches based on completely independent traceability chains for LH2 flow measurement. The first two approaches are applicable to flow rates during loading and unloading of LH2 tankers (flow rates up to 3,000 kg/h for a DN25 cross-section at pressures up to about 1 MPa), the third for smaller flow rates (4 kg/h for a DN3 cross-section at pressures up to about 0.2 MPa).
The first approach is based on the evaluation of the transferability of water and LNG calibrations to LH2 conditions. The study will identify and analyse potential uncertainty contributions for cryogenic CFMs. The experimental and theoretical analysis will serve as a basis for guidelines for the design and selection of CFMs suitable for SI traceable LH2 flow measurements. CFMs are a well-accepted technology for direct measurement of mass flow and density of liquids and are typically used in cryogenic custody transfer for transport fuel applications.
The literature review identified several temperature correction models applicable to LH2 flow measurement, i.e. how the LH2 flow measurement should be corrected due to temperature effects affecting the CFM measurement. Numerical finite element methods (FEM) for U-shaped, arc-shaped and straight pipe designs have been used to predict the temperature sensitivity of CFMs for LH2 flow measurement [4]. Finally, FEM can also be used to estimate the achievable measurement uncertainty using the current state of the art for LH2 flow measurement.
The second approach is based on cryogenic Laser Doppler Velocimetry (LDV) and is referred to as “Référence en Débitmétrie Cryogénique Laser” (RDCL). Traceability is ensured by velocity measurements and it can be used either as a primary standard or as a secondary standard for flow measurements of LH2. Its in-situ calibration uncertainty in cryogenic flows (i.e. LN2, LNG) has been estimated to be 0.6% (k = 2) [5]. Since the RDCL can be installed in any LNG plant, it has the advantage that a representative calibration can be performed directly in the plant under process conditions.
Figure 3: LDV standard for traceable cryogenic flow measurement
The third approach is known as the vaporisation method. Traceability to SI units is ensured in the gas phase by calibrated Laminar Flow Elements (LFE) after the liquefied gas has been evaporated. The LFEs are traceable to the Physikalisch-Technische Bundesanstalt (PTB). As with the first approach, the transferability of alternative liquid calibrations using water, LN2 and liquefied helium (LHe) must be evaluated, as the calibration rig is not suitable for direct use of LH2 for safety reasons. The lower flow range and the fact that non-explosive gases are used are operational advantages of the evaporation method. Another benefit is the use of LHe (boiling point about 4 K) so that the uncertainty of the alternative liquid calibration is based on interpolation rather than extrapolation.
An important aspect to consider in the vaporisation method is the conversion of para hydrogen (para-H2) to normal hydrogen (n-H2), which has been studied in detail by Günz [6]. At low temperatures, para-H2 is present almost exclusively; at room temperature, the ratio changes to 25% para-H2 and 75% ortho-hydrogen (n-H2). Para-H2 and ortho-hydrogen differ significantly in certain physical properties such as thermal conductivity, heat capacity or SoS. These can strongly influence the gas flow measurement, depending on the measuring principle of the flow meter. LFEs used to measure gas flow at ambient conditions are not affected by this as density and viscosity show negligible differences, particularly in the temperature range of interest here.
In summary, the results of the project will increase the confidence of end users and consumers. The methods presented will ensure reliable measurement data, which is important for increasing the share of hydrogen in total energy consumption.
This project (20IND11 MetHyInfra) has received funding from the EMPIR programme co-financed by the Participating States and from the European Union’s Horizon 2020 research and innovation programme.
Literatur
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Authors: Oliver Büker, RISE Research Institutes of Sweden, Borås, Sweden, Benjamin Böckler, PTB Physikalisch-Technische Bundesanstalt, Braunschweig, Germany
