Australia

Reversible solid oxide cells (rSOC) enable the efficient cyclic conversion between electrical and chemical energy in the form of fuels and chemicals thereby providing a pathway for longterm and high-capacity energy storage. Amongst the different fuels under investigation hydrogen methane and ammonia have gained immense attention as carbon-neutral energy vectors. Here we have compared the energy efficiency and the energy demand of rSOC based on these three fuels. In the fuel cell mode of operation (energy generation) two different routes have been considered for both methane and ammonia; Routes 1 and 2 involve internal reforming (in the case of methane) or cracking (in the case of ammonia) and external reforming or cracking respectively. The use of hydrogen as fuel provides the highest round-trip efficiency (62.1%) followed by methane by Route 1 (43.4%) ammonia by Route 2 (41.1%) methane by Route 2 (40.4%) and ammonia by Route 1 (39.2%). The lower efficiency of internal ammonia cracking as opposed to its external counterpart can be attributed to the insufficient catalytic activity and stability of the state-of-the-art fuel electrode materials which is a major hindrance to the scale-up of this technology. A preliminary cost estimate showed that the price of hydrogen methane and ammonia produced in SOEC mode would be ~1.91 3.63 and 0.48 $/kg respectively. In SOFC mode the cost of electricity generation using hydrogen internally reformed methane and internally cracked ammonia would be ~52.34 46.30 and 47.11 $/MWh respectively.

Direct seawater electrolysis (DSE) has emerged as a compelling route to sustainable hydrogen production leveraging the vast global reserves of seawater. However the inherently complex composition of seawater—laden with halide ions multivalent cations (Mg2+ Ca2+) and organic/biological impurities—presents formidable challenges in maintaining both selectivity and durability. Chief among these obstacles is mitigating chloride corrosion and suppressing chlorine evolution reaction (ClER) at the anode while also preventing the precipitation of magnesium and calcium hydroxides at the cathode. This review consolidates recent advances in material engineering and cell design strategies aimed at controlling undesired side reactions enhancing electrode stability and maximizing energy efficiency in DSE. We first outline the fundamental thermodynamic and kinetic hurdles introduced by Cl⁻ and other impurities. This discussion highlights how these factors accelerate catalyst degradation and drive suboptimal reaction pathways. We then delve into innovative approaches to improve selectivity and durability of DSE—such as engineering protective barrier layers tuning electrolyte interfaces developing corrosion-resistant materials and techniques to minimize Mg/Ca-related precipitations. Finally we explore emerging reactor configurations including asymmetric and membrane-free electrolyzers which address some barriers for DSE commercialization. Collectively these insights provide a framework for designing next-generation DSE systems which can achieve large-scale cost-effective and environmentally benign hydrogen production.

Against the dual backdrop of intensifying carbon emission constraints and the large-scale integration of renewable energy integrated electricity–hydrogen energy systems (EH-ESs) have emerged as a crucial technological pathway for decarbonising energy systems owing to their multi-energy complementarity and cross-scale regulation capabilities. This paper proposes an operational optimisation and carbon reduction capability assessment framework for EH-ESs focusing on revealing their operational response mechanisms and emission reduction potential under multi-disturbance conditions. A comprehensive model encompassing an electrolyser (EL) a fuel cell (FC) hydrogen storage tanks and battery energy storage was constructed. Three optimisation objectives—cost minimisation carbon emission minimisation and energy loss minimisation—were introduced to systematically characterise the trade-offs between economic viability environmental performance and energy efficiency. Case study validation demonstrates the proposed model’s strong adaptability and robustness across varying output and load conditions. EL and FC efficiencies and costs emerge as critical bottlenecks influencing system carbon emissions and overall expenditure. Further analysis reveals that direct hydrogen utilisation outperforms the ‘electricity–hydrogen–electricity’ cycle in carbon reduction providing data support and methodological foundations for low-carbon optimisation and widespread adoption of electricity–hydrogen systems.

Hydrogen shaft injection into blast furnaces (BFs) has a large potential to eliminate carbon dioxide emissions yet the temporal evolution of thermal and chemical states following shaft-injected hydrogen utilisation has not been reported in the open literature. In this research a recently developed transient-state multifluid BF model is applied to elucidate the temporal evolution of in-furnace phenomena. Besides a domain-average method is adopted to analyse the extensive simulation data to determine the time required to attain the next steady-like state. The results show that the evolution of thermal and chemical conditions varies across different regions with distinct characteristics near the furnace wall. The shifts in iron oxide reduction behaviour are completed within 10 to 20 h after the new operation and the transition time points to the next steady-like states of thermal and chemical conditions are different. As the hydrogen flow rate increases the average transition time decreases. However 2 to 4 days are required for the studied BF to reach a new steady-like state in the considered scenarios. The model offers a cost-effective approach to investigating the transient smelting characteristics of an ironmaking BF with hydrogen injection.

This study explores the design and feasibility of a novel fuel cell-powered wind farm for residential electricity hydrogen/oxygen production and cooling/heating via a compression chiller. Wind turbine energy powers Proton Exchange Membrane (PEM) electrolyzers and a compression chiller unit. The proposed system was modeled using EES thermodynamic software and its economic viability was assessed. A case study across seven Italian regions with varying wind potentials evaluated the system’s feasibility in diverse weather conditions. Multi-objective optimization using Response Surface Methodology (RSM) determined the number of wind turbines as optimum number of electrolyzers & fuel cell units. Optimization results indicated that 37 wind turbines 1 fuel cell unit and 2 electrolyzer units yielded an exergy efficiency of 27.98 % and a cost rate of 619.9 $/h. TOPSIS analysis suggested 32 wind turbines 2 electrolyzers and 2 reverse osmosis units as an alternative configuration. Further twelve different scenarios were examined to enhance the distribution of wind farmgenerated electricity among the grid electrolyzers and reverse osmosis systems. revealing that directing 25 % to reverse osmosis 20 % to electrolyzers and 55 % to grid sales was optimal. Performance analysis across seven Italian cities (Turin Bologna Florence Palermo Genoa Milan and Rome) identified Genoa Palermo and Bologna as the most suitable locations due to favorable wind conditions. Implementing the system in Genoa the optimal site could produce 28435 MWh of electricity annually prevent 5801 tons of CO2 emissions (equivalent to 139218 $). Moreover selling this clean electricity to the grid could meet the annual clean electricity needs of approximately 5770 people in Italy

Hydrogen is increasingly recognized as a key energy vector for achieving deep decarbonization across urban and industrial sectors. Supporting global efforts to reduce greenhouse gas (GHG) emissions and achieve the Sustainable Development Goals (SDGs) it is essential to understand the multi-sectoral role of the hydrogen value chain spanning production storage and end-use applications with particular emphasis on smart city systems and industrial processes. Green hydrogen production technologies including alkaline water electrolysis (AWE) proton exchange membrane (PEM) electrolysis anion exchange membrane (AEM) electrolysis and solid oxide electrolysis cells (SOECs) are evaluated in terms of efficiency scalability and integration potential. Storage pathways are examined across physical storage (compressed gas cryo-compressed and liquid hydrogen) material-based storage (solid-state absorption in metal hydrides and chemical carriers such as LOHCs and ammonia) and geological storage (salt caverns depleted gas reservoirs and deep saline aquifers) highlighting their suitability for urban and industrial contexts. In the smart city domain hydrogen is analyzed as an enabler of zero-emission transportation low-carbon residential and commercial heating and renewable-integrated smart grids with long-duration storage capabilities. System-level studies demonstrate that coordinated integration of these applications can deliver higher overall energy efficiency deeper reductions in life-cycle GHG emissions and improved resilience of urban energy systems compared with sector-specific approaches. Policy frameworks safety standards and digitalization strategies are reviewed to illustrate how hydrogen infrastructure can be embedded into interconnected urban energy systems. Furthermore industrial applications focus on hydrogen’s potential to decarbonize energy-intensive processes and enable sector coupling between electricity heat and manufacturing. The environmental implications of hydrogen deployment are also considered including resource efficiency life-cycle emissions and ecosystem impacts. In contrast to reviews addressing isolated aspects of hydrogen technologies this study synthesizes technological infrastructural and policy dimensions integrating insights from over 400 studies to highlight the multifaceted role of hydrogen in sustainable urban development and industrial decarbonization and the added benefits achievable through coordinated cross-sector deployment strategies.

Hydrogen is increasingly recognised as a potential critical energy carrier in decarbonising global energy systems. Australia is positioning itself as a potential leader in offshore renewable hydrogen production by leveraging existing liquified natural gas export infrastructure activating its abundant renewable energy resources and harnessing its extensive offshore marine acreage. Despite this there is limited research on the techno-economic and regulatory pathways for offshore hydrogen development in Australia as an enabler of its net zero manufacturing and export ambitions. This study offers a multidisciplinary assessment and review of Australia’s offshore renewable hydrogen potential. It aims to examine the technical legal and economic challenges and opportunities to enable and adapt the existing Australian offshore electricity regulatory regime and enable policy to facilitate future renewable offshore hydrogen licensing and production. Overall the findings provide practical insights for advancing Australia’s offshore hydrogen transition including technical innovations needed to scale offshore wind development. The study demonstrates how a specific offshore hydrogen licensing framework could reduce legal uncertainties to create economies of scale and reduce hydrogen investment risk to unlock the full potential of developing offshore renewable hydrogen projects.

Australia’s path to net-zero emissions by 2050 depends heavily on the development and commercialisation of hydrogen as a substitute for hydrocarbons across transport power generation and industrial heat sectors. With hydrocarbons currently supplying over 90% of national energy needs hydrogen must scale rapidly to fill the gap. Existing low-carbon hydrogen production methods blue hydrogen via steam methane reforming and green hydrogen via electrolysis are constrained by high water requirements posing a challenge in water-scarce regions targeted for hydrogen development. This paper investigates dry reforming of methane (DRM) as a water-independent alternative using CO₂ as a reactant. DRM offers dual benefits: reduced reliance on freshwater resources and the utilisation of CO₂ supporting broader emissions reduction goals. Recent improvements in nickel-copper catalyst performance enhance the viability of DRM for industrial-scale hydrogen production. The Middle Arm Precinct in the Northern Territory is highlighted as an ideal site for implementation given its access to offshore gas fields containing both methane and CO₂ presenting a unique opportunity for resource-integrated low-emission hydrogen production.

The aviation industry is responsible for approximately 2–3% of worldwide CO2 emissions and is increasingly subjected to demands for the attainment of net-zero emissions targets by the year 2050. Traditional fossil jet fuels which exhibit lifecycle emissions of approximately 89 kg CO2-eq/GJ play a substantial role in exacerbating climate change contributing to local air pollution and fostering energy insecurity. In contrast Sustainable Aviation Fuels (SAFs) derived from renewable feedstocks including biomass municipal solid waste algae or through CO2- and H2-based power-to-liquid (PtL) represent a pivotal solution for the immediate future. SAFs generally accomplish lifecycle greenhouse gas (GHG) reductions of 50–80% (≈20–30 kg CO2-eq/GJ) possess reduced sulfur and aromatic content and markedly diminish particulate emissions thus alleviating both climatic and health-related repercussions. In addition to their environmental advantages SAFs promote energy diversification lessen reliance on unstable fossil fuel markets and invigorate regional economies with projections indicating the creation of up to one million green jobs by 2030. This comprehensive review synthesizes current knowledge on SAF sustainability advantages compared to conventional aviation fuels identifying critical barriers to large-scale deployment and proposing integrated solutions that combine technological innovation supportive policy frameworks and international collaboration to accelerate the aviation industry’s sustainable transformation.

Australia has set a new climate target of reducing emissions by 62–70% below 2005 levels by 2035 with sustainable aviation fuel (SAF) central to achieving this goal. This review critically examines techno-economic analysis (TEA) and life cycle assessment (LCA) of Powerto-Liquid (PtL) electrofuels (e-fuels) which synthesize atmospheric CO2 and renewable hydrogen (H2) via Fischer-Tropsch (FT) synthesis. Present PtL pathways require ~0.8 kg of H2 and 3.1 kg of CO2 per kg SAF with ~75% kerosene yield. While third-generation feedstocks could cut greenhouse gas emissions by up to 93% (as low as 8 gCO2e/MJ) real world reductions have been limited (~1.5%) due to variability in technology rollout and feedstock variability. Integrated TEA–LCA studies demonstrate up to 20% energy efficiency improvements and 40% cost reductions but economic viability demands costs below $3/kg. In Australia abundant solar resources vast transport networks and supportive policy frameworks present both opportunities and challenges. This review provides the first comprehensive assessment of PtL-FT SAF for Australian conditions highlighting that large-scale development will require technological advancement feedstock development infrastructure investment and coordinated policy support.