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The power-to-methane technology is promising for long-term, high-capacity energy storage. Currently, there are two different industrial-scale methanation methods: the chemical one (based on the Sabatier reaction) and the biological one (using microorganisms for the conversion). The second method can be used not only to methanize the mixture of pure hydrogen and carbon dioxide but also to methanize the hydrogen and carbon dioxide content of low-quality gases, such as biogas or deponia gas, enriching them to natural gas quality; therefore, the applicability of biomethanation is very wide. In this paper, we present an overview of the existing and planned industrial-scale biomethanation facilities in Europe, as well as review the facilities closed in recent years after successful operation in the light of the scientific and socioeconomic context. To outline key directions for further developments, this paper interconnects biomethanation projects with the competitiveness of the energy sector in Europe for the first time in the literature. The results show that future projects should have an integrative view of electrolysis and biomethanation, as well as hydrogen storage and utilization with carbon capture and utilization (HSU&CCU) to increase sectoral competitiveness by enhanced decarbonization. [ABSTRACT FROM AUTHOR]

Blending green hydrogen within the gas infrastructure is seen as the first move towards Europe's climate neutrality by 2050. Especially, Europe and North African have privileged role in energy cooperation sharing a woven and complex set of natural resources, knowledge, infrastructure, clear goals towards sustainable development. Developing common projects about hydrogen can mutually help both Europe and North Africa to achieve more sustainable, reliable and modern energy systems. This paper simulates the Greenstream gas corridor (connecting Libya to Italy) under increasing hydrogen blending scenarios using a transient and multi-component fluid-dynamic model of the gas transmission system. The additional compression energy required and the compressors' operating hours are evaluated under the hypothesis that the energy content of the transported gas is maintained. The hydrogen profiles needed to generate the blends are obtained and used to optimally size a photovoltaic-powered electrolysis system, minimizing the compressed hydrogen storage. The results indicate that the additional energy costs of transporting hydrogen blends are up to 32.5% higher than natural gas transport, while negligibly impacting the overall efficiency of energy transport. The mismatch between solar hydrogen production and pipeline receiving potential highlights a challenge to be tackled to boost intersectoral integration. • Increasing European and North Africa cooperation with green hydrogen shared projects. • Multi-component transient fluid-dynamic gas network model applied to Greenstream. • Assessment of hydrogen blending scenarios on transmission energy costs. • Sizing of green hydrogen production electrolysis plant. • Hydrogen buffer storage design to control gas quality. [ABSTRACT FROM AUTHOR]

[Display omitted] • Market relevance of aboveground hydrogen storage is investigated. • Aboveground storage will likely play a much smaller role than underground storage. • Storage costs are the most decisive factor for market relevance. • Efficiency and systemic suitability can improve aboveground storage competitiveness. • Based on current projections, aboveground storage will only gain small market shares. Hydrogen storage is expected to play a crucial role in the comprehensive defossilization of energy systems. In this context, the focus is typically on underground hydrogen storage (e.g., in salt caverns). However, aboveground storage, which is independent of geological conditions and might offer other technical advantages, could provide systemic benefits and, thereby, gain shares in the hydrogen storage market. Against this background, this paper examines the market relevance of aboveground compared to underground hydrogen storage. Using the open-source energy system model and optimization framework of Europe, PyPSA-Eur, the influence of geological independence, storage cost relations, and technical storage characteristics (i.e., efficiencies) on mentioned market relevance of aboveground hydrogen storage are investigated. Further, the expectable market relevance based on current cost projections for the future is assessed. The studies show that in terms of hydrogen capacities, aboveground hydrogen storage plays a considerably smaller role compared to underground hydrogen storage. Even when assuming comparatively low aboveground storage cost, it will not exceed 1.7% (1.9 TWh H2,LHV) of total hydrogen storage capacities in a cost-optimal European energy system. Regarding the amounts of annually stored hydrogen, aboveground storage could play a larger role, reaching a maximum share of 32.5% (168 TWh H2,LHV a-1) of total stored hydrogen throughout Europe. However, these shares are only achievable for low cost storage in particularly suited energy system supply configurations. For higher aboveground storage costs or lower efficiencies, shares drop below 10% sharply. The analysis identifies some especially influential factors for achieving higher market relevance. Besides storage costs, the demand-orientation of a particular aboveground storage system (e.g., hydrogen storage at demand pressure levels) plays an essential role in market relevance. Further, overall efficiency can be a beneficial factor. Still, current projections of future techno-economic characteristics show that aboveground hydrogen storage is too expensive or too inefficient compared to underground storage. Therefore, to achieve notable market relevance, rather drastic cost reductions beyond current expectations would be needed for all assessed aboveground hydrogen storage technologies. [ABSTRACT FROM AUTHOR]

The role of hydrogen in a future energy system with a high share of variable renewable energy sources (VRES) is regarded as crucial in order to balance fluctuations in electricity generation. These fluctuations can be compensated for by flexibility measures such as the expansion of transmission, flexible generation, larger back-up capacity and storage. Salt cavern storage is the most promising technology due to its large storage capacity, followed by pumped hydro storage. For the underground storage of chemical energy carriers such as hydrogen, salt caverns offer the most promising option owing to their low investment cost, high sealing potential and low cushion gas requirement. This paper provides a suitability assessment of European subsurface salt structures in terms of size, land eligibility and storage capacity. Two distinct cavern volumes of 500,000 m3 and 750,000 m3 are considered, with preference being given for salt caverns over bedded salt deposits and salt domes. The storage capacities of individual caverns are estimated on the basis of thermodynamic considerations based on site-specific data. The results are analyzed using three different scenarios: onshore and offshore salt caverns, only onshore salt caverns and only onshore caverns within 50 km of the shore. The overall technical storage potential across Europe is estimated at 84.8 PWh H2 , 27% of which constitutes only onshore locations. Furthermore, this capacity decreases to 7.3 PWh H2 with a limitation of 50 km distance from shore. In all cases, Germany has the highest technical storage potential, with a value of 9.4 PWh H2, located onshore only in salt domes in the north of the country. Moreover, Norway has 7.5 PWh H2 of storage potential for offshore caverns, which are all located in the subsurface of the North Sea Basin. • Technical H 2 storage in bedded salt deposits and salt domes across Europe. • Potential is thermodynamically derived, and respects geospatial exclusions. • Total on- and offshore European hydrogen storage potential estimated at 84.8 PWh H2. • Onshore salt caverns within 50 km of the coast constitute 7.3 PWh H2 (~30%). • Highest national storage potential is observed in Germany with 9.4 PWh H2. [ABSTRACT FROM AUTHOR]

This paper describes the setting up and first call results of the Fuel Cells and Hydrogen Joint Undertaking (FCH JU) established by the European Union (Council regulation No 521/2008 of 30 May 2008 setting up the Fuel Cells and Hydrogen Joint Undertaking, Official Journal of the European Union, 2008;L153:1–20). Funding for low carbon energy research on hydrogen and fuel cells in Europe has been gradually increasing since 1990 but has gained significant visibility with the establishment of the Joint Undertaking which is an innovative industry-led scheme, covering the full innovation cycle, from research to market entry. Significant projects led by industry are now running and hydrogen energy has great practical potential in five application areas; transport and refuelling infrastructure; hydrogen production and storage; stationary power production and combined heat and power; early markets; and cross-cutting areas such as codes and standards, regulation, life-cycle assessment, training. [ABSTRACT FROM AUTHOR]

In Europe, electrification is considered a key option to obtain a cleaner production of steel at the same time as the electricity system production portfolio is expected to consist of an increasing share of varying renewable electricity (VRE) generation, mainly in the form of solar PV and wind power. We investigate cost-efficient designs of hydrogen-based steelmaking in electricity systems dominated by VRE. We develop and apply a linear cost-minimization model with an hourly time resolution, which determines cost-optimal operation and sizing of the units in hydrogen-based steelmaking including an electrolyser, direct reduction shaft, electric arc furnace, as well as storage for hydrogen and hot-briquetted iron pellets. We show that the electricity price following steelmaking leads to savings in running costs but to increased capital cost due to investments in the overcapacity of steel production units and storage units for hydrogen and hot-briquetted iron pellets. For two VRE-dominated regions, we show that the electricity price following steel production reduces the total steel production cost by 23% and 17%, respectively, as compared to continuous steel production at a constant level. We also show that the cost-optimal design of the steelmaking process is dependent upon the electricity system mix. [ABSTRACT FROM AUTHOR]