Italy

HyCARE project supported by the Clean Hydrogen Partnership of the European Union deals with a prototype of hydrogen storage tank using a solid-state hydrogen carrier. Up to 40 kilograms of hydrogen are stored in twelve tanks at less than 50 barg and less than 100 °C. The innovative design is based on a standard twenty-foot container including twelve TiFe-based metal hydride (MH) hydrogen storage tanks coupled with a thermal energy storage in phase change materials (PCM). This article aims at showing the main risks related to hydrogen storage in a MH system and the safety barriers considered based on HyCARE’s specific risk analysis.<br/>Regarding the TiFe MH material used to store hydrogen experimental tests showed that the exposure of the MH to air or water did not cause spontaneous ignition. Furthermore an explosion within the solid MH cannot propagate due to internal pore size. Additionally in case of leakage the speed of hydrogen desorption from the MH is self-limited which is an important safety characteristic since it reduces the potential consequences from the hydrogen release scenario.<br/>Regarding the integrated system the critical scenarios identified during the risk analysis were: explosion due to release of hydrogen inside or outside the container internal explosion inside MH tanks due to accidental mix of hydrogen and air and asphyxiation due to inert gas accumulation in the container. This identification phase of the risk analysis allowed to pinpoint the most relevant safety barriers already in place and recommend additional ones if needed to further reduce the risk that were later implemented.<br/>The main safety barriers identified were: material and component selection (including the MH selected) safety interlocks safety valves ventilation gas detection and safety distances.<br/>The risk management process based on risk identification and assessment contributed to coherently integrate inherently safe design features and safety barriers.

Among the different hydrogen premixed combustion concepts direct injection (DI) is one of the most promising for internal combustion engine (ICE) applications. However to fully exploit the benefits of this solution the optimization of the mixture preparation process is a crucial factor. In the present work a study of the hydrogenair mixture formation process in a DI H2-ICE for off-road applications was performed through 3D-CFD simulations. First a sensitivity analysis on the injection timing was carried out to select the optimal injection operating window capable of maximizing mixture homogeneity without a significant volumetric efficiency reduction. Then different spray injector guiding caps were tested to assess their effect on in-cylinder dynamics and mixture characteristics consequently. Finally the impact of swirl intensity on hydrogen distribution has been assessed. The optimization of the combustion chamber geometry has allowed the achievement of significant improvements in terms of mixture homogeneity.

Green hydrogen (H2 ) a promising clean energy source garnering increasing attention worldwide can be derived through various pathways resulting in differing levels of greenhouse gas emissions. Notably Green H2 production can utilize different methods such as integrating standard photovoltaic panels thermal photovoltaic or concentrated photovoltaic thermal collectors with electrolyzers. Furthermore it can be conditioned to different states or carriers including liquefied H2 compressed H2 ammonia and methanol and stored and transported using various methods. This paper employs the Life Cycle Assessment methodology to compare 18 different green hydrogen pathways and provide recommendations for greening the hydrogen supply chain. The findings indicate that the production pathway utilizing concentrated photovoltaic thermal panels for electricity generation and hydrogen compression in the conditioning and transportation stages exhibits the lowest environmental impact emitting only 2.67 kg of CO2 per kg of H2 .

Hydrogen is a promising solution for the decarbonisation of several hard-to-abate end uses which are mainly in the industrial and transport sectors. The development of an extensive hydrogen delivery infrastructure is essential to effectively activate and deploy a hydrogen economy connecting production storage and demand. This work adopts a mixed-integer linear programming model to study the cost-optimal design of a future hydrogen infrastructure in presence of cross-sectoral hydrogen uses taking into account spatial and temporal variations multiple production technologies and optimised multi-mode transport and storage. The model is applied to a case study in the region of Sicily in Italy aiming to assess the infrastructural needs to supply the regional demand from transport and industrial sectors and to transfer hydrogen imported from North Africa towards Europe thus accounting for the region’s role as transit point. The analysis integrates multiple production technologies (electrolysis supplied by wind and solar energy steam reforming with carbon capture) and transport options (compressed hydrogen trucks liquid hydrogen trucks pipelines). Results show that the average cost of hydrogen delivered to demand points decreases from 3.75 €/kgH2 to 3.49 €/kgH2 when shifting from mobilityonly to cross-sectoral end uses indicating that the integrated supply chain exploits more efficiently the infrastructural investments. Although pipeline transport emerges as the dominant modality delivery via compressed hydrogen trucks and liquid hydrogen trucks remains relevant even in scenarios characterised by large hydrogen flows as resulting from cross-sectoral demand demonstrating that the system competitiveness is maximised through multi-mode integration.

The forthcoming implementation of national policies towards hydrogen blending into the natural gas grid will affect the technical and economic parameters that must be taken into account in the design of building heating systems. This study evaluates the implications of using hydrogenenriched natural gas (H2NG) blends in condensing boilers and Gas Adsorption Heat Pumps (GAHPs) in a residential building in Rome Italy. The analysis considers several parameters including nonrenewable primary energy consumption CO2 emissions Levelized Cost of Heat (LCOH) and Carbon Abatement Cost (CAC). The results show that a 30% hydrogen blend achieves a primary energy consumption reduction of 12.05% and 11.19% in boilers and GAHPs respectively. The presence of hydrogen in the mixture exerts a more pronounced influence on the reduction in fossil primary energy and CO2 emissions in condensing boilers as it enhances combustion efficiency. The GAHP system turns out to be more cost-effective due to its higher efficiency. At current hydrogen costs the LCOH of both technologies increases as the volume fraction of hydrogen increases. The forthcoming cost reduction in hydrogen will reduce the LCOH and the decarbonization cost for both technologies. At low hydrogen prices the CAC for boilers is lower than for GAHPs; therefore replacing boilers with other gas technologies rather than electric heat pumps increases the risk of creating stranded assets. In conclusion blending hydrogen into the gas grid can be a useful policy to reduce emissions from the overall natural gas consumption during the process of end-use electrification while stimulating the development of a hydrogen economy.

The transition from fossil fuels to the renewable energies (wind solar) is a key factor to face climate change and build a sustainable reliable and secure energy system. To balance the intermittent energy demand and supply affecting the renewable sources the surplus of electrical energy may be converted in hydrogen and then storage in geological formations. While the risks associated to the natural gas storage in the sub-surface are well known from decades those associated with hydrogen underground storage (UHS) are relatively underexplored. This paper presents an inventory of risks related to large H2-storage in depleted gas and oil fields salt caverns and aquifers. Different issues such as integrity and durability of materials H2 leakages and interaction with the reservoir H2 uncontrolled outflow from the wellhead with potential combustion of air-hydrogen mixture (fire and explosion) soil subsidence and induced seismicity are analyzed.

The growing concern about climate change and the contemporary increase in mobility requirements call for faster cheaper safer and cleaner means of transportation. The retrofitting of fossil-fueled piston engine ultralight aerial vehicles to hydrogen power systems is an option recently proposed in this direction. The goal of this investigation is a comparative analysis of the environmental impact of conventional and hydrogen-based propulsive systems. As a case study a hybrid electric configuration consisting of a fuel cell with a nominal power of about 30 kW a 6 kWh LFP battery and a pressurized hydrogen vessel is proposed to replace a piston prop configuration for an ultralight aerial vehicle. Both power systems are modeled with a backward approach that allows the efficiency of the main components to be evaluated based on the load and altitude at every moment of the flight with a time step of 1 s. A typical 90 min flight mission is considered for the comparative analysis which is performed in terms of direct and indirect emissions of carbon dioxide water and pollutant substances. For the hydrogen-based configuration two possible strategies are adopted for the use of the battery: charge sustaining and charge depleting. Moreover the effect of the altitude on the parasitic power of the fuel cell compressor and consequently on the net efficiency of the fuel cell system is taken into account. The results showed that even if the use of hydrogen confines the direct environmental impact to the emission of water (in a similar quantity to the fossil fuel case) the indirect emissions associated with the production transportation and delivery of hydrogen and electricity compromise the desired achievement of pollutant-free propulsion in terms of equivalent emissions of CO2 and VOCs if hydrogen is obtained from natural gas reforming. However in the case of green hydrogen from electrolysis with wind energy the total (direct and indirect) emissions of CO2 can be reduced up to 1/5 of the fossil fuel case. The proposed configuration has the additional advantage of eliminating the problem of lead which is used as an additive in the AVGAS 100LL.

This article analyzes a power-to-hydrogen system designed to provide high-temperature heat to hard-to-abate industries. We leverage on a geospatial analysis for wind and solar availability and different industrial demand profiles with the aim to identify the ideal sizing of plant components and the resulting Levelized Cost of Hydrogen (LCOH). We assess the carbon intensity of the produced hydrogen especially when grid electricity is utilized. A methodology is developed to size and optimize the PV and wind energy capacity the electrolyzer unit and hybrid storage by combining compressed hydrogen storage with lithium-ion batteries. The hydrogen demand profile is generated synthetically thus allowing different industrial consumption profiles to be investigated. The LCOH in a baseline scenario ranges from 3.5 to 8.9 €/kg with the lowest values in wind-rich climates. Solar PV only plays a role in locations with high PV full-load hours. It was found that optimal hydrogen storage can cover the users’ demand for 2–3 days. Most of the considered scenarios comply with the emission intensity thresholds set by the EU. A sensitivity analysis reveals that a lower variability of the demand profile is associated with cost savings. An ideally constant demand profile results in a cost reduction of approximately 11 %.

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.

The multi-generation systems with simultaneous production of power by renewable energy in addition to polymer electrolyte membrane electrolyzer and fuel cell (PEMFC-PEMEC) energy storage have become more and more popular over the past few years. The fresh water provision for PEMECs in such systems is taken into account as one of the main challenges for them where conventional desalination technologies such as reverse osmosis (RO) and mechanical vapor compression (MVC) impose high electricity consumption and costs. Taking this point into consideration as a novelty solar still (ST) desalination is applied as an alternative to RO and MVC for better techno-economic justifiability. The comparison made for a residential building complex in Hawaii in the US as the case study demonstrated much higher technical and economic benefits when using ST compared with both MVC and RO. The photovoltaic (PV) installed capacity decreased by 11.6 and 7.3 kW compared with MVC and RO while the size of the electrolyzer declined by 9.44 and 6.13% and the hydrogen storage tank became 522.1 and 319.3 m3 smaller respectively. Thanks to the considerable drop in the purchase price of components the payback period (PBP) dropped by 3.109 years compared with MVC and 2.801 years compared with RO which is significant. Moreover the conducted parametric study implied the high technical and economic viability of the system with ST for a wide range of building loads including high values.