United Kingdom

The safety engineering design of hydrogen systems and infrastructure worker education and training regulatory compliance and engagement with other stakeholders are significant to the viability and public acceptance of hydrogen farms. The only way to ensure these are accomplished is for the field of hydrogen safety engineering (HSE) to grow and mature. HSE is described as the application of engineering and scientific principles to protect the environment property and human life from the harmful effects of hydrogen-related mishaps and accidents. This paper describes a whole hydrogen farm that produces hydrogen from seawater by alkaline and proton exchange membrane electrolysers then details how the hydrogen gas will be used: some will be stored for use in a combined-cycle gas turbine some will be transferred to a liquefaction plant and the rest will be exported. Moreover this paper describes the design framework and overview for ensuring hydrogen safety through these processes (production transport storage and utilisation) which include legal requirements for hydrogen safety safety management systems and equipment for hydrogen safety. Hydrogen farms are large-scale facilities used to create store and distribute hydrogen which is usually produced by electrolysis using renewable energy sources like wind or solar power. Since hydrogen is a vital energy carrier for industries transportation and power generation these farms are crucial in assisting the global shift to clean energy. A versatile fuel with zero emissions at the point of use hydrogen is essential for reaching climate objectives and decarbonising industries that are difficult to electrify. Safety is essential in hydrogen farms because hydrogen is extremely flammable odourless invisible and also has a small molecular size meaning it is prone to leaks which if not handled appropriately might cause fires or explosions. To ensure the safe and dependable functioning of hydrogen production and storage systems stringent safety procedures are required to safeguard employees infrastructure and the surrounding environment from any mishaps.

Green hydrogen is often promoted as a key facilitator for the clean energy transition but its implementation raises concerns around energy justice. This paper examines the socio-political and techno-economic challenges that green hydrogen projects may pose to the three tenets of energy justice: distributive procedural and recognition justice. From a socio-political perspective the risk of neocolonial resource extraction uneven distribution of benefits exclusion of local communities from decision-making and disregard for indigenous rights and cultures threaten all three justice tenets. Techno-economic factors such as water scarcity land disputes and resource-related conflicts in potential production hotspots further jeopardise distributive and recognition justice. The analysis framed by an adapted PEST model reveals that while green hydrogen holds promise for sustainable development its implementation must proactively address these justice challenges. Failure to do so could perpetuate injustices exploitation and marginalisation of vulnerable communities undermining the sustainability goals it aims to achieve. The paper highlights the need for inclusive and equitable approaches that respect local sovereignty integrate diverse stakeholders and ensure fair access and benefit-sharing. Only by centring justice considerations can the transition to green hydrogen catalyse positive social change and realise its full potential as a driver of sustainable energy systems.

Hydrogen (2 ) has a big role to play in energy transition to achieve net-zero carbon emissions by 2050. For 2 to compete with other fuels in the energy market more research is required to mitigate key issues like greenhouse gas (GHG) emissions safety and end-use costs. For these reasons a software-supported technical overview of 2 production storage transportation and utilisation is introduced. Drawbacks and mitigation approaches for 2 technologies were highlighted. The recommended areas include solar thermal or renewable-powered plasma systems for feedstock preheating and oxy-hydrogen combustion to meet operating temperatures and heat duties due to losses; integration of electrolysis of 2 into hydrocarbon reforming methods to replace air separation unit (ASU); use of renewable power sources for electrical units and the introduction of thermoelectric units to maximise the overall efficiency. Furthermore a battolyser system for small-scale energy storage; new synthetic hydrides with lower absorption and desorption energy; controlled parameters and steam addition to the combustor/cylinder and combustors with fitted heat exchangers to reduce emissions and improve the overall efficiency are also required. This work also provided detailed information on any of these systems implementations based on location factors and established a roadmap for 2 production and utilisation. The proposed 2 production technologies are hybrid pyrolysis-electrolysis and integrated AD-MEC and DR systems using renewable bioelectrochemical and low-carbon energy systems. Production and utilisation of synthetic natural gas (NG) using renewablepowered electrolysis of 2 oxy-fuel and direct air capture (DAC) is another proposed 2 energy system for a sustainable 2 economy. By providing these factors and information researchers can work towards pilot development and further efficiency enhancement.

The transition from traditional aviation fuels to low-emission alternatives such as hydrogen is a crucial step towards a sustainable future for aviation. Conventional jet fuels substantially contribute to greenhouse gas emissions and climate change. Hydrogen fuel especially "green" hydrogen offers great potential for achieving full sustainability in aviation. Hybrid/electric/fuel cell technologies may be used for shorter flights while longrange aircraft are more likely to combust hydrogen in gas turbines. Liquid hydrogen is necessary to minimize storage tank weight but the required fuel systems are at a low technology readiness level and differ significantly from Jet A-1 systems in architecture operation and performance. This paper provides an in-depth review covering the development of liquid hydrogen fuel system design concepts for gas turbines since the 1950s compares insights from key projects such as NASA studies and ENABLEH2 alongside an analysis of recent publications and patent applications and identifies the technological advancements required for achieving zeroemission targets through hydrogen-fuelled propulsion.

Hydrogen storage is crucial to developing secure renewable energy systems to meet the European Union’s 2050 carbon neutrality objectives. However a knowledge gap exists concerning the site-specific performance and economic viability of utilizing underground gas storage (UGS) sites for hydrogen storage in Europe. We compile information on European UGS sites to assess potential hydrogen storage capacity and evaluate the associated current and future costs. The total hydrogen storage potential in Europe is 349 TWh of working gas energy (WGE) with site-specific capital costs ranging from $10 million to $1 billion. Porous media and salt caverns boasting a minimum storage capacity of 0.5 TWh WGE exhibit levelized costs of $1.5 and $0.8 per kilogram of hydrogen respectively. It is estimated that future levelized costs associated with hydrogen storage can potentially decrease to as low as $0.4 per kilogram after three experience cycles. Leveraging these techno-economic considerations we identify suitable storage sites.

Blue hydrogen is one of the energy carriers to be adopted by the United Kingdom to reduce emissions to net Zero by 2050 and its use is majorly influenced by policy and technological innovations. With more than 10 blue hydrogen facilities planning productive offtake from 2025 there is an urgent need to confirm the viability of these proposed facilities to aid decarbonisation and the path to conformity to policy regulation. This study discovers that the Acorn blue hydrogen facility can produce blue hydrogen within the low carbon hydrogen standard set by the United Kingdom’s government. In this study a detailed examination of hydrogen production techniques is conducted using lifecycle assessment (LCA) approach aimed to understand the environmental impact of producing 144 tons of hydrogen per day using Acorn hydrogen facility as a case study. This was followed on with sensitive analysis embracing steam and oxygen consumption and methane leakages the ability of the facility meeting the low carbon hydrogen standard economics and the externality-priced production costs that embody the environmental impact. A gate-to-gate LCA shows that the Acorn hydrogen plant must aim at carbon capture rates of >90% to meet the set UK target of 20 gCO2e/MJLHV. The study further identifies from literature that the autothermal reforming (ATR) system with integrated carbon capture and storage (CCS) production technology as the most environmentally sustainable technology at present in comparison to commercially available options studied. This assessment helps to appraise potentially unintended causes and effects of the production of blue hydrogen that should aid future policy guidance and investments.

In the quest for achieving decarbonisation it is essential for different sectors of the economy to collaborate and invest significantly. This study presents an innovative approach that merges technological insights with philosophical considerations at a national scale with the intention of shaping the national policy and practice. The aim of this research is to assist in formulating decarbonisation strategies for intricate economies. Libya a major oil exporter that can diversify its energy revenue sources is used as the case study. However the principles can be applied to develop decarbonisation strategies across the globe. The decarbonisation framework evaluated in this study encompasses wind-based renewable electricity hydrogen and gas turbine combined cycles. A comprehensive set of both official and unofficial national data was assembled integrated and analysed to conduct this study. The developed analytical model considers a variety of factors including consumption in different sectors geographical data weather patterns wind potential and consumption trends amongst others. When gaps and inconsistencies were encountered reasonable assumptions and projections were used to bridge them. This model is seen as a valuable foundation for developing replacement scenarios that can realistically guide production and user engagement towards decarbonisation. The aim of this model is to maintain the advantages of the current energy consumption level assuming a 2% growth rate and to assess changes in energy consumption in a fully green economy. While some level of speculation is present in the results important qualitative and quantitative insights emerge with the key takeaway being the use of hydrogen and the anticipated considerable increase in electricity demand. Two scenarios were evaluated: achieving energy self-sufficiency and replacing current oil exports with hydrogen exports on an energy content basis. This study offers for the first time a quantitative perspective on the wind-based infrastructure needs resulting from the evaluation of the two scenarios. In the first scenario energy requirements were based on replacing fossil fuels with renewable sources. In contrast the second scenario included maintaining energy exports at levels like the past substituting oil with hydrogen. The findings clearly demonstrate that this transition will demand great changes and substantial investments. The primary requirements identified are 20529 or 34199 km2 of land for wind turbine installations (for self-sufficiency and exports) and 44 single-shaft 600 MW combined-cycle hydrogen-fired gas turbines. This foundational analysis represents the commencement of the research investment and political agenda regarding the journey to achieving decarbonisation for a country.

Coastal regions have abundant off-shore wind energy resources and surrounding areas have large-scale liquefied natural gas (LNG) receiving stations. From the engineering perspectives there are limitations in unstable off-shore wind energy and fluctuating LNG loads. This article offers a new energy scheme to combine these 2 energy units which uses surplus wind energy to produce hydrogen and use LNG cold energy to liquefy and store hydrogen. In addition in order to improve the efficiency of utilizing LNG cold energy and reduce electricity consumption for liquid hydrogen (LH2) production at coastal regions this article introduces the liquid air energy storage (LAES) technology as the intermediate stage which can stably store the cold energy from LNG gasification. A new scheme for LNG-LAES-LH2 hybrid LH2 production is built. The case study is based on a real LNG receiving station at Hainan province China and this article presents the design of hydrogen production/liquefaction process and carries out the optimizations at key nodes and proves the feasibility using specific energy consumption and exergy analysis. In a 100 MW system the liquid air storage round-trip efficiency is 71.0% and the specific energy consumption is 0.189 kWh/kg and the liquid hydrogen specific energy consumption is 7.87 kWh/kg and the exergy efficiency is 46.44%. Meanwhile the corresponding techno-economic model is built and for a LNGLAES-LH2 system with LH2 daily production 140.4 tons the shortest dynamic payback period is 9.56 years. Overall this novel hybrid energy scheme can produce green hydrogen using a more efficient and economical method and also can make full use of surplus off-shore wind energy and coastal LNG cold energy.

This study aims to carry out a techno-economic analysis of different hydrogen supply chain designs coupled with the Swedish electricity system to study the inter-dependencies between them. Both the hydrogen supply chain designs and the electricity system were parameterized with data for 2030. The supply chain designs comprehend centralised production decentralised production a combination of both and with/without seasonal variation in hydrogen demand. The supply chain design is modelled to minimize the overall cost while meeting the hydrogen demands. The outputs of the supply chain model include the hydrogen refuelling stations’ locations the electrolyser’s locations and their respective sizes as well as the operational schedule. The electricity system model shows that the average electricity prices in Sweden for zones SE1 SE2 SE3 and SE4 will be 4.28 1.88 8.21 and 8.19 €/MWh respectively. The electricity is mainly generated from wind and hydropower (around 42% each) followed by nuclear (14%) solar (2%) and then bio-energy (0.3%). In addition the hydrogen supply chain design that leads to a lower overall cost is the decentralised design with a cost of 1.48 and 1.68 €/kgH2 in scenarios without and with seasonal variation respectively. The seasonal variation in hydrogen demand increases the cost of hydrogen regardless of the supply chain design.

The use of hydrogen in internal combustion engines is a promising solution for the decarbonisation of the transport sector. The current transition scenario is marked by the unavailability and storage challenges of hydrogen. Dual fuel combustion of hydrogen and gasoline in current spark ignition engines is a feasible solution in the short and medium term as it can improve engine efficiency reduce pollutant emissions and contribute significantly in tank to wheel decarbonisation without major engine modification. However new research is needed to understand how the incorporation of hydrogen affects existing engines to effectively implement gasoline-hydrogen dual fuel option. Understanding the impact of hydrogen on the combustion process (e.g. combustion speed) will guide and optimize the operation of engines under dual fuel combustion conditions. In this work a commercial gasoline direct injection engine has been modified to operate with gasolinehydrogen fuels. The experiments have been carried out at various air–fuel ratios ranging from stoichiometric to lean combustion conditions at constant engine speed and torque. At each one of the 14 experimental points 200-cycle in-cylinder pressure traces were recorded and processed with a quasi-dimensional diagnostic model and a combustion speed analysis was then carried out. It has been understood that hydrogen mainly reduces the duration of the first combustion phase. Hydrogen also enables to increase air excess ratios (lean in fuel combustion) without significantly increasing combustion duration. Furthermore a correlation is proposed to predict combustion speed as a function of the fuel and air mixture properties. This correlation can be incorporated to calculate combustion duration in predictive models of engines operating under different fuel mixtures and different geometries of the combustion chamber with pent-roof cylinder head and flat piston head.