Decarbonisation Technology - August 2023 Issue

For users who can accept a vapour phase product at these system pressures, minimal additional infrastructure is required. However, due to the variability of renewable power available for generating green hydrogen vs the ratable consumption, some storage systems will be required. The common storage options are compressed gas tanks, salt caverns, and even liquid hydrogen vessels. Each of these options requires additional capital expenditure and operating expenses. Salt caverns are an excellent option for storage but are only available in select areas. Therefore, most entities will need to use compressed gas storage or liquid hydrogen storage. For storage tanks, five different tank types are available (I, II, III, IV, and V). The most common tank type is I, a metallic vessel that can store gases up to 14,500 psi. Types III, IV, and V are able to store up to above these levels, with Type IV usually used for fuel cell hydrogen storage. Liquid hydrogen storage can be an attractive option, but the key trade-offs are energy input requirements and boil-off. In order to liquefy hydrogen, the temperature must be reduced to -253°C (-423°F). This requires the use of a system like the pre-cooled Claude system, which utilises liquid nitrogen as a cooling source, and an ortho/para catalytic conversion step to get the hydrogen atom rotations in the same para form to avoid excess boil-off. The energy to liquefy hydrogen is around 35-45% of the energy content of the hydrogen itself, which reduces the overall cycle efficiency of hydrogen via liquefication. Typical boil-off rates range from 6-15% per day, which requires re-liquefication or use of the boil-off material for energy generation, albeit with a reduction in available volume. Therefore, the application of liquid hydrogen storage must be evaluated closely to maximise the energy delivery to the final user. For smaller scale distribution systems, tanker trucks are typically applied. These trucks can transport hydrogen in either liquid or gaseous form, depending on the needs of the end consumer. Standard tank sizes are ~350 kg for Type III tanks and ~1,000 kg for Type IV tanks. To put this into perspective, the typical fuel cell vehicle will hold 5 kg and assume that the

typical refuelling station services 150 vehicles per day. Therefore, one to three trucks would need to go between the central storage facility and distribution sites. Assuming a typical gasoline tanker truck capacity of 3,000 gallons, a typical fill-up of 15 gallons per vehicle, and the same 150 vehicles per day, a single gasoline tanker could service a refuelling station per day. Though not different conceptually from distribution systems for liquid fuel sources like gasoline and diesel, the infrastructure and transportation requirements for liquid fuels vs hydrogen sources will need to evolve. A novel option that is receiving attention is the use of LOHC. The leading pathway for LOHC is the use of toluene/cyclohexane (or isomer variants), methanol, or ammonia as a liquid. As a demonstration of this scheme, the produced hydrogen is ‘attached’ to the carrier by conversion of toluene to cyclohexane (or saturated states of isomer variants) via the hydrogenation reaction and then transported via more conventional liquid transportation methods. Hydrogen is then released by converting the saturated molecule back to toluene via dehydrogenation. The carrier has similar properties to conventional gasoline or diesel, opening the opportunity to leverage existing liquid hydrocarbon logistics assets. Though additional processing steps are required, and extra energy is consumed in these processing steps, using LOHCs could be an effective option to address the transport challenges of pure hydrogen. An example of this approach is occurring between Australia and Japan, as trial runs have been completed and contracts been awarded to create a hydrogen supply chain between the two nations, leveraging coal gasification and carbon capture to produce decarbonised hydrogen and a LOHC to transport the hydrogen. Each of these elements is driving a diversification of energy production from large centralised facilities to smaller scaled and co-located hydrogen hubs. A hydrogen hub is defined as a centrally co-located network of hydrogen producers, consumers, and local logistics to create tight integration of large