Applications & Pathways

This paper presents a novel energy management strategy (EMS) to control a wind-hydrogen microgrid which includes a wind turbine paired with a hydrogen-based energy storage system (HESS) i.e. hydrogen production storage and re-electrification facilities and a local load. This complies with the mini-grid use case as per the IEA-HIA Task 24 Final Report where three different use cases and configurations of wind farms paired with HESS are proposed in order to promote the integration of wind energy into the grid. Hydrogen production surpluses by wind generation are stored and used to provide a demand-side management solution for energy supply to the local and contractual loads both in the grid-islanded and connected modes with corresponding different control objectives. The EMS is based on a hierarchical model predictive control (MPC) in which long-term and short-term operations are addressed. The long-term operations are managed by a high-level MPC in which power production by wind generation and load demand forecasts are considered in combination with day-ahead market participation. Accordingly the hydrogen production and re-electrification are scheduled so as to jointly track the load demand maximize the revenue through electricity market participation and minimize the HESS operating costs. Instead the management of the short-term operations is entrusted to a low-level MPC which compensates for any deviations of the actual conditions from the forecasts and refines the power production so as to address the real-time market participation and the short time-scale equipment dynamics and constraints. Both levels also take into account operation requirements and devices’ operating ranges through appropriate constraints. The mathematical modeling relies on the mixed-logic dynamic (MLD) framework so that the various logic states and corresponding continuous dynamics of the HESS are considered. This results in a mixed-integer linear program which is solved numerically. The effectiveness of the controller is analyzed by simulations which are carried out using wind forecasts and spot prices of a wind farm in center-south of Italy.

Green hydrogen production is expected to play a major role in the context of the shift towards sustainable energy stipulated in the Fit for 55 package. Green hydrogen and its derivatives have the capacity to act as effective energy storage vectors while fuel cell-powered vehicles will foster net-zero emission mobility. This study evaluates the potential of green hydrogen production in Power-to-Gas (P2G) systems operated in former mining sites where sand and gravel aggregate has been extracted from lakes and rivers under wet conditions (below the water table). The potential of hydrogen production was assessed for the selected administrative unit in Poland the West Pomerania province. Attention is given to the legal and organisational aspects of operating mining companies to identify the sites suitable for the installation of floating photovoltaic facilities by 2050. The method relies on the use of GIS tools which utilise geospatial data to identify potential sites for investments. Basing on the geospatial model and considering technical and organisational constraints the schedule was developed showing the potential availability of the site over time. Knowing the surface area of the water reservoir the installed power of the floating photovoltaic plant and the production capacity of the power generation facility and electrolysers the capacity of hydrogen production in the P2G system can be evaluated. It appears that by 2050 it should be feasible to produce green fuel in the P2G system to support a fleet of city buses for two of the largest urban agglomerations in the West Pomerania province. Simulations revealed that with a water coverage ratio increase and the planned growth of green hydrogen generation it should be feasible to produce fuel for net-zero emission urban mobility systems to power 200 buses by 2030 550 buses by 2040 and 900 buses by 2050 (for the bus models Maxi (40 seats) and Mega (60 seats)). The results of the research can significantly contribute to the development of projects focused on the production of green hydrogen in a decentralised system. The disclosure of potential and available locations over time can be compared with competitive solutions in terms of spatial planning environmental and societal impact and the economics of the undertaking.

Given China’s ambition to realize carbon peak by 2030 and carbon neutralization by 2060 hydrogen is gradually becoming the pivotal energy source for the needs of energy structure optimization and energy system transformation. Thus hydrogen combined with renewable energy has received more and more attention. Nowadays power-to-hydrogen power-to-methanol and power-to-ammonia are regarded as the most promising three hydrogen-driven power-to-X technologies due to the many commercial or demonstration projects in China. In this paper these three hydrogen-driven power-to-X technologies and their application status in China are introduced and discussed. First a general introduction of hydrogen energy policies in China is summarized and then the basic principles technical characteristics trends and challenges of the three hydrogen-driven power-to-X technologies are reviewed. Finally several typical commercial or demonstration projects are selected and discussed in detail to illustrate the development of the power-to-X technologies in China.

Clean hydrogen is a key pillar for the net zero economy which can be deployed by consistent utilization on heavy-duty transport. This study investigates a distributed green hydrogen infrastructure (DHI) for heavy-duty transportation consisting of on-site hydrogen production storage compression and refueling systems in Italy. Two options for energy supply are analyzed: grid connection using green energy via Power Purchasing Agreements (PPAs) and direct connection to the photovoltaic field respectively. Radiation data are representative of the three main Italian areas namely South (Catania) Center (Roma) and North (Milano). The sensitivity analysis varies the PPA value between 50 V/MWh and 200 V/MWh and the water electrolysis capacity factor between 20% and 100%. The study finds that the LCOH ranges from 7.4 V/kgH2 to 67.8 V/kgH2 for the first option and 5.5 V/kgH2 to 27.5 V/kgH2 for the second option with Southern Italy having the lowest LCOH due to higher solar irradiation. The research shows that a DHI can offer economic and technical benefits for heavy-duty mobility. However the performance is highly influenced by external conditions such as hydrogen demand and electricity prices. This study provides valuable insights into designing and operating a DHI for heavy-duty mobility promoting a carbon-free society.

This study introduced the methodology for integrating ethylene glycol/water mixture (GW) systems which supply heat energy to the liquid hydrogen (LH2 ) fuel gas supply system (FGSS) and manage the temperature conditions of the battery system. All systems were designed and simulated based on the power demand of a 2 MW class platform supply vessel assumed as the target ship. The LH2 FGSS model is based on Aspen HYSYS V14 and the cell model that makes up the battery system is implemented based on a Thevenin model with four parameters. Through three different simulation cases the integrated GW system significantly reduced electric power consumption for the GW heater during ship operations achieving reductions of 1.38% (Case 1) 16.29% (Case 2) and 27.52% (Case 3). The energy-saving ratio showed decreases of 1.86% (Case 1) 21.01% (Case 2) and 33.80% (Case 3) in overall energy usage within the GW system. Furthermore an examination of the battery system’s thermal management in the integrated GW system demonstrated stable cell temperature control within ±3 K of the target temperature making this integration a viable solution for maintaining normal operating temperatures despite relatively higher fluctuations compared to an independent GW system.

This research conducted a probabilistic life-cycle assessment (pLCA) into the greenhouse gas (GHG) emissions performance of nine combinations of truck size and powertrain technology for a recent past and a future (largely decarbonised) situation in Australia. This study finds that the relative and absolute life-cycle GHG emissions performance strongly depends on the vehicle class powertrain and year of assessment. Life-cycle emission factor distributions vary substantially in their magnitude range and shape. Diesel trucks had lower life-cycle GHG emissions in 2019 than electric trucks (battery hydrogen fuel cell) mainly due to the high carbon-emission intensity of the Australian electricity grid (mainly coal) and hydrogen production (mainly through steam–methane reforming). The picture is however very different for a more decarbonised situation where battery electric trucks in particular provide deep reductions (about 75–85%) in life-cycle GHG emissions. Fuel-cell electric (hydrogen) trucks also provide substantial reductions (about 50–70%) but not as deep as those for battery electric trucks. Moreover hydrogen trucks exhibit the largest uncertainty in emissions performance which reflects the uncertainty and general lack of information for this technology. They therefore carry an elevated risk of not achieving the expected emission reductions. Battery electric trucks show the smallest (absolute) uncertainty which suggests that these trucks are expected to deliver the deepest and most robust emission reductions. Operational emissions (on-road driving and vehicle maintenance combined) dominate life-cycle emissions for all vehicle classes. Vehicle manufacturing and upstream emissions make a relatively small contribution to life-cycle emissions from diesel trucks (

Grids require electricity storage. Two emerging storage technologies are battery storage (BS) and green hydrogen storage (GHS) (hydrogen produced and compressed with clean-renewable electricity stored then returned to electricity with a fuel cell). An important question is whether GHS alone decreases system cost versus BS alone or BS+GHS. Here energy costs are modeled in 145 countries grouped into 24 regions. Existing conventional hydropower (CH) storage is used along with new BS and/or GHS. A method is developed to treat CH for both baseload and peaking power. In four regions only CH is needed. In five CH+BS is lowest cost. Otherwise CH+BS+GHS is lowest cost. CH+GHS is never lowest cost. A metric helps estimate whether combining GHS with BS reduces cost. In most regions merging (versus separating) grid and non-grid hydrogen infrastructure reduces cost. In sum worldwide grid stability may be possible with CH+BS or CH+BS+GHS. Results are subject to uncertainties.

Decarbonizing road transportation is vital for addressing climate change given that the sector currently contributes to 16% of global GHG emissions. This paper presents a comparative analysis of electric and hydrogen mobility infrastructures in a remote context i.e. an off-grid island. The assessment includes resource assessment and sizing of renewable energy power plants to facilitate on-site self-production. We introduce a comprehensive methodology for sizing the overall infrastructure and carry out a set of techno-economic simulations to optimize both energy performance and cost-effectiveness. The levelized cost of driving at the hydrogen refueling station is 0.40 e/km i.e. 20% lower than the electric charging station. However when considering the total annualized cost the battery-electric scenario (110 ke/year) is more favorable compared to the hydrogen scenario (170 ke/year). To facilitate informed decision-making we employ a multi-criteria decision-making analysis to navigate through the techno-economic findings. When considering a combination of economic and environmental criteria the hydrogen mobility infrastructure emerges as the preferred solution. However when energy efficiency is taken into account electric mobility proves to be more advantageous.

This paper investigated the opportunities and challenges of integrating ports into hydrogen (H2 ) supply chains in the context of Australia and Japan because they are leading countries in the field and are potential leaders in the upcoming large-scale H2 trade. Qualitative interviews were conducted in the two countries to identify opportunities for H2 ports necessary infrastructure and facilities key factors for operations and challenges associated with the ports’ development followed by an online survey investigating the readiness levels of H2 export and import ports. The findings reveal that there are significant opportunities for both countries’ H2 ports and their respective regions which encompass business transition processes and decarbonisation. However the ports face challenges in areas including infrastructure training standards and social licence and the sufficiency and readiness levels of port infrastructure and other critical factors are low. Recommendations were proposed to address the challenges and barriers encountered by H2 ports. To optimise logistics operations within H2 ports and facilitate effective integration of H2 applications this paper developed a user-oriented working process framework to provide guidance to ports seeking to engage in the H2 economy. Its findings and recommendations contribute to filling the existing knowledge gap pertaining to H2 ports.

Ever more stringent emission regulations for vehicles encourage increasing numbers of battery electric vehicles on the roads. A drawback of storing electric energy in a battery is the comparable low energy density low driving range and the higher propensity to deplete the energy storage before reaching the destination especially at low ambient temperatures. When the battery is depleted stranded vehicles can either be towed or recharged with a mobile recharging station. Several technologies of mobile recharging stations already exist however most of them use fossil fuels to recharge battery electric vehicles. The proposed novel zero emission solution for mobile charging is a combined high voltage battery and hydrogen fuel cell charging station. Due to the thermal characteristics of the fuel cell and high voltage battery (which allow only comparable low coolant temperatures) the thermal design for this specific application (available heat exchanger area zero vehicle speed air flow direction) becomes challenging and is addressed in this work. Experimental methods were used to obtain reliable thermal and electric power measurement data of a 30 kW fuel cell system which is used in the Mobile Hydrogen Powersupply. Subsequently simulation methods were applied for the thermal design and optimisation of the coolant circuits and heat exchangers. It is shown that an battery electric vehicle charging power of 22 kW requires a heat exchanger area of 1 m2 of which 60 % is used by the fuel cell heat exchanger and the remainder by the battery heat exchanger to achieve steady state operation at the highest possible ambient temperature of 436 °C. Furthermore the simulation showed that when the charging power of 22 kW is solely provided by the high voltage battery the highest possible ambient temperature is 42 °C. When the charging power is decreased operation up to the maximum ambient temperatures of 45 °C can be achieved. The results of maximum charging power and limiting ambient temperature give insights for further system improvements which are: sizing of fuel cell or battery trailer design and heat exchanger area operation strategy of the system (power split between high voltage battery and fuel cell) as well as possible dynamic operation scenarios.