United Kingdom

One of the major challenges in harnessing energy from renewable sources like wind and solar is their intermittent nature. Energy production from these sources can vary based on weather conditions and time of day making it essential to store surplus energy for later use when there is a shortfall. Energy storage systems play a crucial role in addressing this intermittency issue and ensuring a stable and reliable energy supply. Green hydrogen sourced from renewables emerges as a promising solution to meet the rising demand for sustainable energy addressing the depletion of fossil fuels and environmental crises. In the present study underground hydrogen storage in various geological formations (aquifers depleted hydrocarbon reservoirs salt caverns) is examined emphasizing the need for a detailed geological analysis and addressing potential hazards. The paper discusses challenges associated with underground hydrogen storage including the requirement for extensive studies to understand hydrogen interactions with microorganisms. It underscores the importance of the issue with a focus on reviewing the the various past and present hydrogen storage projects and sites as well as reviewing the modeling studies in this field. The paper also emphasizes the importance of incorporating hybrid energy systems into hydrogen storage to overcome limitations associated with standalone hydrogen storage systems. It further explores the past and future integrations of underground storage of green hydrogen within this dynamic energy landscape.

Reducing industrial emissions to achieve net-zero targets by the middle of the century will require profound and sustained changes to how energy intensive industries operate. Preliminary activity is now underway with governments of several developed economies starting to implement policy and providing funding to support the deployment of low carbon infrastructure into high emitting industrial clusters. While clusters appear to offer the economies of scale and institutional capacity needed to kick-start the industrial transition to date there has been little systematic assessment of the factors that may influence the success of these initiatives. Drawing from academic and grey literature this paper presents a rapid evidence assessment of the approaches being used to drive the development of low carbon industrial clusters internationally. Many projects are still at the scoping stage but it is apparent that current initiatives focus on the deployment of carbon capture technologies alongside hydrogen as a future secondary revenue stream. This model of decarbonisation funnels investment into large coastal clusters with access to low carbon electricity and tends to obscure questions about the integration of these technologies with other decarbonisation interventions such as material efficiency and electrification. The technology focus also omits the importance that a favourable location and shared history and culture appears to have played in helping progress the most advanced initiatives; factors that cannot be easily replicated elsewhere. If clusters are to kick-start the low-carbon industrial transition then greater attention is needed to the social and political dimensions of this process and to a broader range of decarbonisation interventions and cluster types than represented by current projects.

This study focuses on development of a CFD model able to simulate the experimentally observed critical nozzle diameter for hydrogen non-premixed flames. The critical diameter represents the minimum nozzle size through which a free jet flame will remain stable at all driving pressures. Hydrogen non-premixed flames will not blow-out at diameters equal to or greater than the critical diameter. Accurate simulation of this parameter is important for assessment of thermally activated pressure relief device (TPRD) performance during hydrogen blowdown from a storage tank. At TPRD diameters below the critical value there is potential for a hydrogen jet flame to blow-out as the storage tank vents potentially leading to hydrogen accumulation in an indoor release scenario. Previous experimental studies have indicated that the critical diameter for hydrogen is approximately 1 mm. In this study flame stability is considered across a range of diameters and overpressures from 0.1 mm to 2 mm and from 0.2 MPa to 20 MPa respectively. The impact of turbulent Schmidt number Sct which is the ratio of momentum diffusivity (kinematic viscosity) and mass diffusivity on the hydrogen concentration profile in the region near the nozzle exit and subsequent influence on critical diameter was investigated and discussed. For lower Sct values the enhanced mass mixing resulted in smaller predicted critical diameters. The use of value Sct=0.61 in the model demonstrated the best agreement with experimental values of the critical diameter. The model reproduced the critical diameter of 1 mm and then was applied to predict flame stability for under-expanded hydrogen jets.

National Nuclear Laboratory (NNL) is aiming to demonstrate through a research and development programme that nuclear enabled hydrogen can be used to support future clean energy systems. Demonstrating the safe operation of hydrogen facilities co-generating with a nuclear reactor will be key to enabling the deployment and success of nuclear enabled hydrogen technologies in the future. During the deployment continuity of supply will be paramount and possibly requires inter-seasonal storage. Co-generation is a means of using a source of energy in this case a nuclear reactor to efficiently produce power and thermal energy. Since a great deal of the heat energy is lost to the environment in a power plant making use of wasted energy for other useful output like the production of hydrogen and direct heating would be advantageous to plant economics and energy system flexibility. The civil nuclear industry is regulated around the world. This approach ensures that all the activities related to the production of power from nuclear and the hazards associated with ionising radiation are controlled in a manner which protects workers members of the public property and the environment. Nuclear safety assessments follow a rigorous process and are required as part of the Nuclear Site Licence. A fundamental requirement which is cited in the UK legislation is that the risks associated with all activities at the licensed site be reduced to As Low As Reasonably Practicable (ALARP). The principle places a requirement on duty holders to implement measures to reduce risk where doing so is considered reasonable and proportionate. The inclusion of risks for hazardous materials associated with the hydrogen production facilities need to be considered and this requires harmonisation of two different safety and regulatory governance regimes which have not previously interacted in this way. The safety demonstration for nuclear facilities is provided through the Safety Case.

The adoption of liquid hydrogen (LH2) as an energy carrier presents significant opportunities for distributing large quantities of hydrogen efficiently. However ensuring safety of LH2 transfer operations requires the evo lution of suitable technologies and regulatory framework. This study offers an extensive overview of technical considerations and safety aspects pertaining to liquid hydrogen installations and mobile applications. A signif icant lack of regulations specifically tailored for LH2 transfer operations is highlighted. Additionally experi mental findings and outcomes of the modelling activities carried out in previous research are presented shedding light on the combustion and ignition behaviour of liquid hydrogen during accident scenarios. The identification of research gaps and ongoing research projects underscores the importance of continued investigation and development of this critical area.

The introduction of hydrogen in natural gas pipeline systems introduces integrity challenges due to the nature of interactions between hydrogen and line pipe steel materials. However not every natural gas pipeline is equal in regards to the challenges potentially posed by the repurposing to hydrogen. Existing codes and practices penalise high-grade materials on the basis of a perceived higher susceptibility to hydrogen embrittlement in regards to their increased strength. This philosophy challenges the realisation of a hydrogen economy because it puts at economical and technical risk the conversion of almost half of the natural gas transmission systems in western countries.

The paper addresses the question whether pipe grade is actually a good proxy to strength and predictor to assess the performance of steel line pipes in hydrogen. Drivers that could affect the suitability of pipeline conversion in hydrogen from an integrity management perspective and industry experience of other hydrogen-charging applications are reviewed. In doing so the paper challenges the basis of the assumption that low-grade steels (up to X52 / L360) are automatically safer for hydrogen repurposing while at the other end of the spectrum higher-grade materials (>X52 / L360) are inevitably less suitable for hydrogen service.

Ultimately the paper discusses that materials sampling and testing of representative line pipes populations should be placed at the core of hydrogen repurposing strategies in order to safely address conversion and to maximize the hydrogen chain value. The paper addresses alternatives to make the sampling smart and cost-effective.

Decarbonising the global housing stock is imperative for reaching climate change targets. In the United Kingdom hydrogen is currently being tested as a replacement fuel for natural gas which could be used to supply low-carbon energy to parts of the country. Transitioning the residential sector towards a net-zero future will call for an inclusive understanding of consumer preferences for emerging technologies. In response this paper explores consumer attitudes towards domestic cooking and heating technologies and energy appliances of the future which could include a role for hydrogen hobs and boilers in UK homes. To access qualitative evidence on this topic we conducted ten online focus groups (N = 58) with members of the UK public between February and April 2022. The study finds that existing gas users wish to preserve the best features of gas cooking such as speed responsiveness and controllability but also desire the potential safety and aesthetic benefits of electric systems principally induction hobs. Meanwhile future heating systems should ensure thermal comfort ease of use energy efficiency and smart performance while providing space savings and noise reduction alongside demonstrable green benefits. Mixed-methods multigroup analysis suggests divergence between support levels for hydrogen homes which implies a degree of consumer heterogeneity. Foremost we find that domestic hydrogen acceptance is positively associated with interest and engagement with renewable energy and fuel poverty pressures. We conclude that internalising the perspectives of consumers is critical to enabling constructive socio-technical imaginaries for low-carbon domestic energy futures.

Green energy is at the forefront of current policy research and engineering but some of the potential fuels require either a lot of deeper research or a lot of infrastructure before they can be implemented. In the case of hydrogen both are true. This report aims to analyse the potential of hydrogen as a future fuel source by performing a life-cycle assessment. Through this the well-to-tank phase of fuel production and the usage phase of the system have been analysed. Models have also been created for traditional fuel systems to best compare results. The results show that hydrogen has great potential to convert marine transport to operating off green fuels when powered through low-carbon energy sources which could reduce a huge percentage of the international community’s greenhouse gas emissions. Hydrogen produced through wind powered alkaline electrolysis produced emission data 5.25 g of CO2 equivalent per MJ compared to the 210 g per MJ produced by a medium efficiency diesel equivalent system a result 40 times larger. However with current infrastructure in most countries not utilising a great amount of green energy production the effects of hydrogen usage could be more dangerous than current fuel sources owing to the incredible energy requirements of hydrogen production with even grid (UK) powered electrolysis producing an emission level of 284 g per MJ which is an increase against standard diesel systems. From this the research concludes that without global infrastructure change hydrogen will remain as a potential fuel rather than a common one.

If hydrogen fuel is available to support the transportation sector decarbonization its usage can be placed either directly onboard in a fuel cell vehicle or indirectly off-board by using a fuel cell power station to produce electricity to charge a battery electric vehicle. Therefore in this work the direct and indirect conversion scenarios of hydrogen to vehicle propulsion were investigated regarding energy efficiency. Thus in the first scenario hydrogen is the fuel for the onboard electricity production to propel a fuel cell vehicle while in the second hydrogen is the electricity source to charge the battery electric vehicle. When simulated for a drive cycle results have shown that the scenario with the onboard fuel cell consumed about 20% less hydrogen demonstrating higher energy efficiency in terms of driving range. However energy efficiency depends on the outside temperature when heat loss utilization is considered. For outside temperatures of − 5 ◦C or higher the system composed of the battery electric vehicle fueled with electricity from the off-board fuel cell was shown to be more energyefficient. For lower temperatures the system composed of the onboard fuel cell again presented higher total (heat + electricity) efficiency. Therefore the results provide valuable insights into how hydrogen fuel can be used for vehicle propulsion supporting the hydrogen economy development.

Porous carbons have been extensively investigated for hydrogen storage but to date appear to have an upper limit to their storage capacity. Here in an effort to circumvent this upper limit we explore the potential of oxygen-rich activated carbons. We describe cellulose acetate-derived carbons that combine high surface area (3800 m2 g−1 ) and pore volume (1.8 cm3 g−1 ) that arise almost entirely (>90%) from micropores with an oxygen-rich nature. The carbons exhibit enhanced gravimetric hydrogen uptake (8.1 wt% total and 7.0 wt% excess) at −196 °C and 20 bar rising to a total uptake of 8.9 wt% at 30 bar and exceptional volumetric uptake of 44 g l −1 at 20 bar and 48 g l −1 at 30 bar. At room temperature they store up to 0.8 wt% (excess) and 1.2 wt% (total) hydrogen at only 30 bar and their isosteric heat of hydrogen adsorption is above 10 kJ mol−1 .

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.

Offshore green hydrogen emerges as a guiding light in the global pursuit of environmental sustainability and net-zero objectives. The burgeoning expansion of offshore wind power faces significant challenges in grid integration. This avenue towards generating offshore green hydrogen capitalises on its ecological advantages and substantial energy potential to efficiently channel offshore wind power for onshore energy demands. However a substantial research void exists in efficiently integrating offshore wind electricity and green hydrogen. Innovative designs of offshore hydrogen platforms present a promising solution to bridge the gap between offshore wind and hydrogen integration. Surprisingly there is a lack of commercially established offshore platforms dedicated to the hydrogen industry. However the wealth of knowledge from oil and gas platforms contributes valuable insights to hydrogen platform design. Diverging from the conventional decentralised hydrogen units catering to individual turbines this study firstly introduces a pioneering centralised Offshore Green Hydrogen Platform (OGHP) which seamlessly integrates modular production storage and offloading modulars. The modular design of facilitates scalability as wind capacity increases. Through a detailed case study centred around a 100-Megawatt floating wind farm the design process of offshore green hydrogen modulars and its floating sub-structure is elucidated. Stability analysis and hydrodynamic analysis are performed to ensure the safety of the OGHP under the operation conditions. The case study will enhance our understanding OGHP and its modularised components. The conceptual design of modular OGHP offers an alternative solution to ‘‘Power-to-X’’ for offshore renewable energy sector.

A new model is presented to predict hydrogen-assisted fatigue. The model combines a phase field description of fracture and fatigue stress-assisted hydrogen diffusion and a toughness degradation formulation with cyclic and hydrogen contributions. Hydrogen-assisted fatigue crack growth predictions exhibit an excellent agreement with experiments over all the scenarios considered spanning multiple load ratios H2 pressures and loading frequencies. These are obtained without any calibration with hydrogen-assisted fatigue data taking as input only mechanical and hydrogen transport material properties the material’s fatigue characteristics (from a single test in air) and the sensitivity of fracture toughness to hydrogen content. Furthermore the model is used to determine: (i) what are suitable test loading frequencies to obtain conservative data and (ii) the underestimation made when not pre-charging samples. The model can handle both laboratory specimens and large-scale engineering components enabling the Virtual Testing paradigm in infrastructure exposed to hydrogen environments and cyclic loading.

Industry is the biggest sector of energy consumption and greenhouse gas emissions whose decarbonisation is essential to achieve the Sustainable Development Goals. Carbon capture energy efficiency improvement and hydrogen are among the main strategies for industrial decarbonization. However novel approaches are needed to address the key requirements and differences between sectors to ensure they can work together to well integrate industrial decarbonisation with heat CO2 and hydrogen. The emerging Calcium Looping (CaL) is attracting interest in designing CO2-involved chemical processes for heat capture and storage. The reversibility relatively high-temperature (600 to 900 ◦C) and high energy capacity output as well as carbon capture function make CaL well-fit for CO2 capture and utilisation and waste heat recovery from industrial flue gases. Meanwhile methane dry reforming (MDR) is a promising technology to produce blue hydrogen via the consumption of two major greenhouse gases i.e. CO2 and CH4. It has great potential to combine the two technologies to achieve insitu CO2 utilization with multiple benefits. In this paper progresses on the reaction conditions and performance of CaL for CO2 capture and industrial waste heat recovery as well as MDR were screened. Secondly recent approaches to CaL-MDR synergy have been reviewed to identify the advantages. The major challenges in such a synergistic process include MDR catalyst deactivation CaL sorbents sintering and system integration. Thirdly the paper outlooks future work to explore a rational design of a multi-function system for the proposed synergistic process.

Energy transition is a key driver to combat climate change and achieve zero carbon future. Sustainable and costeffective hydrogen production will provide valuable addition to the renewable energy mix and help minimize greenhouse gas emissions. This study investigates the performance of in-situ hydrogen production (IHP) process using a full-field compositional model as a precursor to experimental validation The reservoir model was simulated as one geological unit with a single point uniform porosity value of 0.13 and a five-point connection type between cell to minimize computational cost. Twenty-one hydrogen forming reactions were modelled based on the reservoir fluid composition selected for this study. The thermodynamic and kinetic parameters for the reactions were obtained from published experiments due to the absence of experimental data specific to the reservoir. A total of fifty-four simulation runs were conducted using CMG STARS software for 5478 days and cumulative hydrogen produced for each run was recorded. Results generated were then used to build a proxy model using Box-Behnken design of experiment method and Support Vector Machine with RBF kernel. To ascertain accuracy of the proxy models analysis of variance (ANOVA) was conducted on the variables. The average absolute percentage error between the proxy model and numerical simulation was calculated to be 10.82%. Optimization of the proxy model was performed using genetic algorithm to maximize cumulative hydrogen produced. Based on this optimized model the influence of porosity permeability well location injection rate and injection pressure were studied. Key results from this study reveals that lower permeability and porosity reservoirs supports more hydrogen yield injection pressure had a negligible effect on hydrogen yield and increase in oxygen injection rate corelated strongly with hydrogen production until a threshold value beyond which hydrogen yield decreased. The framework developed in the study could be used as tool to assess candidate reservoirs for in-situ hydrogen production.

As global economies seek to transition to low-carbon energy systems to achieve net zero targets hydrogen has potential to play a key role to decarbonise sectors that are unsuited to electrification or where long-term energy storage is required. Hydrogen can also assist in enabling decentralized renewable power generation to satisfy higher electricity demand to match the scale-up of electrified technologies. In this context suitable transport storage and distribution networks will be essential to connect hydrogen generation and utilisation sites. This paper presents a techno-economic impact evaluation of international marine hydrogen transportation between Canada and the Netherlands comparing liquid hydrogen ammonia and a dibenzyl toluene liquid organic hydrogen carrier (LOHC) as potential transport vectors. Economic costs energy consumption and losses in each phase of the transportation system were analysed for each vector. Based on the devised scenarios our model suggests levelised costs of hydrogen of 6.35–9.49 $2022/kgH2 and pathway efficiencies of 55.6–71.9%. While liquid hydrogen was identified as the most cost-competitive carrier sensitivity analysis revealed a merit order for system optimisation strategies based upon which LOHC could outperform both liquid hydrogen and ammonia in the future.

Ammonia production currently contributesalmost 11% of global industrial carbon dioxide emissions or1.3% of global emissions. In the context of global emissiontargets and growing demand decarbonization of this processis highly desirable. We present a method to calculate a firstestimate for the optimum size of an ammonia productionplant (at the process level) the required renewable energy(RE) supply and the levelized cost of ammonia (LCOA) forislanded operation with a hydrogen buffer. A model wasdeveloped to quantitatively identify the key variables thatimpact the LCOA (relative to a ±10 GBP/tonne change inLCOA): levelized cost of electricity (±0.89 GBP/MWh) electrolyzer capital expenditure (±65 GBP/kW) minimum Haber−Bosch (HB) load (±12% of rated power) maximum rate of HB load ramping and RE supply mix. Using 2025/2030 estimatesresults in a LCOA of 588 GBP/tonne for Lerwick Scotland. The application of the model will facilitate and improve theproduction of carbon-free ammonia in the future.

Aviation is a major contributor to transportation carbon emissions but aims to reduce its carbon footprint. Sustainable and environmentally friendly green hydrogen fuel is essential for decarbonization of this industry. Using the extremely low temperature of liquid hydrogen in aviation sector unlocks the opportunity for cryoelectric aircraft concept which exploits the advantageous properties of superconductors onboard. A significant barrier for green hydrogen adoption relates to its high cost and the immediate need for large-scale production which Proton Exchange Membrane Water Electrolyzers (PEMWE) can address through optimal dynamic performance high lifetimes good efficiencies and importantly scalability. In PEMWE the cell is a crucial component that facilitates the electrolysis process and consists of a polymer membrane and electrodes. To control the required production rate of hydrogen the output power of cell should be monitored which usually is done by measuring the cell’s potential and current density. In this paper five different machine learning (ML) models based on different algorithms have been developed to predict this parameter. Findings of the work highlight that the model based on Cascade-Forward Neural Network (CFNN) is investigated to accurately predict the cell potential of PEMWE under different anodic material and working conditions with an accuracy of 99.998 % and 0.001884 in terms of R2 and root mean square error respectively. It can predict the cell potential with a relative error of less than 0.65 % and an absolute error of below 0.01 V. The Standard deviation of 0.000061 for 50 iterations of stability analysis indicated that this model has less sensitivity to the random selection of training data. By accurately estimating different cell’s output with one model and considering its ultra-fast response CFNN model has the potential to be used for both monitoring and the designing purposes of green hydrogen production.

Shipping corridors act as the arteries of the global economy. The maritime shipping sector is also a major source of greenhouse gas emissions accounting for 2.9% of the global total. The international nature of the shipping sector combined with issues surrounding the use of battery technology means that these emissions are considered difficult to eliminate. This work explores the transition to renewable fuels by examining the use of electrofuels (in the form of liquid hydrogen methane methanol ammonia and Fischer-Tropsch fuel) to decarbonise large container ships from a technical economic and environmental perspective. For an equivalent range to current fossil fuel vessels the cargo capacity of vessels powered by electrofuels decreases by between 3% and 16% depending on the fuel of choice due to the lower energy density compared with conventional marine fuels. If vessel operators are willing to sacrifice range cargo space can be preserved by downsizing onboard energy storage which necessitates more frequent refuelling. For a realistic green hydrogen cost of €3.5/kg (10.5 €c/kWh) in 2030 the use of electrofuels in the shipping sector results in an increase in the total cost of ownership of between 124% and 731% with liquid hydrogen in an internal combustion engine being the most expensive and methanol in an internal combustion engine resulting in the lowest cost increase. Despite this we find that the increased transportation costs of some consumer goods to be relatively small adding for example less than €3.27 to the cost of a laptop. In general fuels which do not require cryogenic storage and can be used in internal combustion engines result in the lowest cost increases. For policymakers reducing the environmental impact of the shipping sector is a key priority. The use of liquid hydrogen which results in the largest cost increase offers a 70% reduction in GHG emissions for an electricity carbon intensity of 80 gCO2e/ kWh which is the greatest reduction of all fuels assessed in this work. A minimum carbon price of €400/tCO2 is required to allow these fuels to reach parity with conventional shipping operations. To meet European Union emissions reductions targets electricity with an emissions intensity below 40 gCO2e/kWh is required which suggests that for electrofuels to be truly sustainable direct connection with a source of renewable electricity is required.

This paper describes the performance of explosion free in fire self-venting (TPRD-less) composite tanks of Type IV in fires of realistic intensity HRR/A=1 MW/m2 in conditions of first responders’ intervention. This breakthrough safety technology does not require the use of thermally activated pressure relief devices (TPRD). It provides microleaks-no-burst (LNB) performance of high-pressure hydrogen storage tanks in a fire. Two fire intervention strategies are investigated one is the removal of a vehicle with LNB tank from the fire and another is the extinction of the fire. The removal from the fire scenario is investigated for one carbon-carbon and one carbon-basalt double-composite wall tank prototype. The fire extinction scenario is studied for four carbon-basalt prototypes. All six prototypes of 7.5 L volume and nominal working pressure of 70 MPa demonstrated safe release of hydrogen through microchannels of the composite wall after melting a liner. The technology allows fire brigades to apply standard intervention strategies and tactics at the fire scene with hydrogen vehicles if LNB tanks are used in the vehicle.

This study aims to explore the techno-economic potential of harnessing waste heat from a Small Modular Reactor (SMR) to fuel Direct Air Carbon Capture (DACC) and High Temperature Steam Electrolysis (HTSE) technologies. The proposed system’s material flows and energy demands are modelled via the ASPEN Plus v12.1 where results are utilised to provide estimates of the Levelised Cost of DACC (LCOD) and Levelised Cost of Hydrogen (LCOH). The majority of thermal energy and electrical utilities are assumed to be supplied directly by the SMR. A sensitivity analysis is then performed to investigate the effects of core operational parameters of the system. Key results indicate levelised costs of 4.66 $/kgH2 at energy demands of 34.37 kWh/kgH2 and 0.02 kWh/kgH2 thermal for HTSE hydrogen production and 124.15 $/tCO2 at energy demands of 31.67 kWh/tCO2 and 126.33 kWh/tCO2 thermal for carbon capture; parameters with most impact on levelised costs are air intake and steam feed for LCOD and LCOH respectively. Both levelised costs i.e. LCOD and LCOH would decrease with the production scale. The study implies that an integrated system of DACC and HTSE provided the best cost-benefit results however the cost-benefit analysis is heavily subjective to geography politics and grid demand.

The HyDeploy2 project seeks to address a key issue for UK energy customers: how to reduce the carbon they emit in heating their homes. The UK has a world class gas grid delivering heat conveniently and safely to more than 83% of homes. Emissions can be reduced by lowering the carbon content of gas through blending with hydrogen. This delivers carbon savings without customers requiring disruptive and expensive changes in their homes. It also provides the platform for deeper carbon savings by enabling wider adoption of hydrogen across the energy system.

This paper aims to present an overview of the current state of hydrogen storage methods and materials assess the potential benefits and challenges of various storage techniques and outline future research directions towards achieving effective economical safe and scalable storage solutions. Hydrogen is recognized as a clean secure and costeffective green energy carrier with zero emissions at the point of use offering significant contributions to reaching carbon neutrality goals by 2050. Hydrogen as an energy vector bridges the gap between fossil fuels which produce greenhouse gas emissions global climate change and negatively impact health and renewable energy sources which are often intermittent and lack sustainability. However widespread acceptance of hydrogen as a fuel source is hindered by storage challenges. Crucially the development of compact lightweight safe and cost-effective storage solutions is vital for realizing a hydrogen economy. Various storage methods including compressed gas liquefied hydrogen cryocompressed storage underground storage and solid-state storage (material-based) each present unique advantages and challenges. Literature suggests that compressed hydrogen storage holds promise for mobile applications. However further optimization is desired to resolve concerns such as low volumetric density safety worries and cost. Cryo-compressed hydrogen storage also is seen as optimal for storing hydrogen onboard and offers notable benefits for storage due to its combination of benefits from compressed gas and liquefied hydrogen storage by tackling issues related to slow refueling boil-off and high energy consumption. Material-based storage methods offer advantages in terms of energy densities safety and weight reduction but challenges remain in achieving optimal stability and capacities. Both physical and material-based storage approaches are being researched in parallel to meet diverse hydrogen application needs. Currently no single storage method is universally efficient robust and economical for every sector especially for transportation to use hydrogen as a fuel with each method having its own advantages and limitations. Moreover future research should focus on developing novel materials and engineering approaches in order to overcome existing limitations provide higher energy density than compressed hydrogen and cryo-compressed hydrogen storage at 70 MPa enhance costeffectiveness and accelerate the deployment of hydrogen as a clean energy vector.

The global transition towards clean energy sources is becoming essential to reduce reliance on conventional fuels and mitigate carbon emissions. In the future the clean energy storage landscape green hydrogen and green ammonia (powered by renewable energy sources) are emerging as key players. This study explores the prospectives and feasibility of producing and storing offshore green hydrogen and green ammonia. The potential power output of Hornsea one and Hornsea two winds farms in the United Kingdom was calculated using real wind data. The usable electricity from the Hornsea one wind farm was 5.83 TWh/year and from the Hornsea two wind farm it was 6.44 TWh/year harnessed to three different scenarios for the production and storage of green ammonia and green hydrogen. Scenario 1 fulfil the requirement of green hydrogen storage for flexible ammonia production but consumes more energy for green hydrogen compression. Scenario 2 does not offer any hydrogen storage which is not favourable in terms of flexibility and market demand. Scenario 3 offers both a direct routed supply of produced hydrogen for green ammonia synthesis and a storage facility for green hydrogen storage. Detailed mathematical calculations and sensitivity analysis was performed based on the total energy available to find out the energy storage capacity in terms of the mass of green hydrogen and green ammonia produced. Sensitivity analysis in the case of scenario 3 was conducted to determine the optimal percentage of green hydrogen going to the storage facility. Based on the cost evaluation of three different presented scenarios the levelized cost of hydrogen (LCOH) is between USD 5.30 and 5.97/kg and the levelized cost of ammonia (LCOA) is between USD 984.16 and USD 1197.11/tonne. These prices are lower compared to the current UK market. The study finds scenario 3 as the most appropriate way in terms of compression energy savings flexibility for the production and storage capacity that depends upon the supply and demand of these green fuels in the market and a feasible amount of green hydrogen storage.

The decarbonization of the maritime sector represents a priority in the energy policy agendas of the majority of Countries worldwide and the International Maritime Organization (IMO) has recently revised its strategy aiming for an ambitious zero-emissions scenario by 2050. In these regards there is a broad consensus on hydrogen as one of the most promising clean energy vectors for maritime transport and a key towards that goal. However to date an international regulatory framework for the use of hydrogen on-board of ships is absent this posing a severe limitation to the adoption of hydrogen technologies in this sector. To cope with this issue this paper presents a preliminary gap assessment analysis for the International Code of Safety for Ship Using Gases or other Low-flashpoint Fuels (IGF Code) with relation to hydrogen as a fuel. The analysis is structured according to the IGF Code chapters and a bottom-up approach is followed to review the code content and assess its relevance to hydrogen. The risks related to hydrogen are accounted for in assessing the gaps and providing a first level set of recommendations for IGF Code updates. By this means this work settles the basis for further research over the identified gaps towards the identification of a final set of recommendations for the IGF Code update.

: This article investigates how safety culture impacts the safety performance of blue hydrogen projects. Blue hydrogen refers to decarbonized hydrogen produced through natural gas reforming with carbon capture and storage (CCS) technology. It is crucial to decide on a suitable safety policy to avoid potential injuries financial losses and loss of public goodwill. The system dynamics approach is a suitable tool for studying the impact of factors controlling safety culture. This study examines the interactions between influencing factors and implications of various strategies using what-if analyses. The conventional risk and safety assessments fail to consider the interconnectedness between the technical system and its social envelope. After identifying the key factors influencing safety culture a system dynamics model will be developed to evaluate the impact of those factors on the safety performance of the facility. The emphasis on safety culture is directed by the necessity to prevent major disasters that could threaten a company’s survival as well as to prevent minor yet disruptive incidents that may occur during day-to-day operations. Enhanced focus on safety culture is essential for maintaining an organization’s long-term viability. H2-CCS is a complex socio-technical system comprising interconnected subsystems and sub-subsystems. This study focuses on the safety culture sub-subsystem illustrating how human factors within the system contribute to the occurrence of incidents. The findings from this research study can assist in creating effective strategies to improve the sustainability of the operation. By doing so strategies can be formulated that not only enhance the integrity and reliability of an installation as well as its availability within the energy networks but also contribute to earning a good reputation in the community that it serves.

By passing the delegated acts supplementing the revised Renewable Energy Directive the European Commission has recently set a regulatory benchmark for the classifcation of green hydrogen in the European Union. Controversial reactions to the restricted power purchase for electrolyser operation refect the need for more clarity about the efects of the delegated acts on the cost and the renewable characteristics of green hydrogen. To resolve this controversy we compare diferent power purchase scenarios considering major uncertainty factors such as electricity prices and the availability of renewables in various European locations. We show that the permission for unrestricted electricity mix usage does not necessarily lead to an emission intensity increase partially debilitating concerns by the European Commission and could notably decrease green hydrogen production cost. Furthermore our results indicate that the transitional regulations adopted to support a green hydrogen production ramp-up can result in similar cost reductions and ensure high renewable electricity usage.

The turbocharged dual-fuel engine is modeled and connected online to optimiser platform for transient input variation of input parameters decided by designed algorithms. This task is undertaken to enable intelligent control of the propulsion system including the Hydrogen injection instantly to reduce the thermal irreversibility. Therefore two methods of optimisation are applied to data collected from a turbocharged dual fuel operated propulsion system with direct diesel fuel injection and hydrogen port injection. This study investigates the application of multi-objective game theory (MOGT) and non-dominated sorting genetic algorithm II (NSGA-II) for optimising the performance of a diesel-hydrogen dual-fuel engine. The system is designed in 1D framework with input variability of the turbocharger efficiency hydrogen mass injection air compression ratio (Rp) and start of combustion (SoC). The objective is to set maximized the volume work while minimising the entropy generation and NO emission. The first populations in the optimisation procedures are initialised with uniform Latin hypercube and random space filler design of experiment (DoE) for both optimisers. The MOGT can find the best solution faster than NSGA-II with slightly better result. The statistics showed that MOGT generates 12 more unfeasible designs that do not meet the constraint limit on NO emission. The findings indicate that for different optimisation algorithms there are some factors with different effect direction and size on the objectives. Addi tionally it is discovered that although MOGT solution makes higher objective function value the NSGA-II optimal solution leads to better engine efficiency and lower fuel consumption.

The transition to low-carbon energy systems requires efficient hydrogen production methods that minimise CO2 emissions. This study presents a techno-economic assessment of hydrogen production via methane pyrolysis utilising a novel liquid metal bubble column reactor (LMBCR) designed for CO2-free hydrogen and solid carbon outputs. Operating at 20 bar and 1100 ◦C the reactor employs a molten nickel-bismuth alloy as both catalyst and heat transfer medium alongside a sodium bromide layer to enhance carbon purity and facilitate separation. Four operational scenarios were modelled comparing various heating and recycling configurations to optimise hydrogen yield and process economics. Results indicate that the levelised cost of hydrogen (LCOH) is highly sensitive to methane and electricity prices CO2 taxation and the value of carbon by-products. Two reactor configurations demonstrate competitive LCOHs of 1.29 $/kgH2 and 1.53 $/kgH2 highlighting methane pyrolysis as a viable low-carbon alternative to steam methane reforming (SMR) with carbon capture and storage (CCS). This analysis underscores the potential of methane pyrolysis for scalable economically viable hydrogen production under specificmarket conditions.

The integration of wind and solar energy with green hydrogen technologies represents an innovative approach toward achieving sustainable energy solutions. This review examines state-ofthe-art strategies for synthesizing renewable energy sources aimed at improving the efficiency of hydrogen (H2 ) generation storage and utilization. The complementary characteristics of solar and wind energy where solar power typically peaks during daylight hours while wind energy becomes more accessible at night or during overcast conditions facilitate more reliable and stable hydrogen production. Quantitatively hybrid systems can realize a reduction in the levelized cost of hydrogen (LCOH) ranging from EUR 3.5 to EUR 8.9 per kilogram thereby maximizing the use of renewable resources but also minimizing the overall H2 production and infrastructure costs. Furthermore advancements such as enhanced electrolysis technologies with overall efficiencies rising from 6% in 2008 to over 20% in the near future illustrate significant progress in this domain. The review also addresses operational challenges including intermittency and scalability and introduces system topologies that enhance both efficiency and performance. However it is essential to consider these challenges carefully because they can significantly impact the overall effectiveness of hydrogen production systems. By providing a comprehensive assessment of these hybrid systems (which are gaining traction) this study highlights their potential to address the increasing global energy demands. However it also aims to support the transition toward a carbon-neutral future. This potential is significant because it aligns with both environmental goals and energy requirements. Although challenges remain the promise of these systems is evident.

Bioenergy with carbon capture and storage (BECCS) technology is expected to support net-zero targets by supplying low carbon energy while providing carbon dioxide removal (CDR). BECCS is estimated to deliver 20 to 70 MtCO2 annual negative emissions by 2050 in the UK despite there are currently no BECCS operating facility. This research is modelling and demonstrating the flexibility scalability and attainable immediate application of BECCS. The CDR potential for two out of three BECCS pathways considered by the Intergovernmental Panel on Climate Change (IPCC) scenarios were quantified (i) modular-scale CHP process with post-combustion CCS utilising wheat straw and (ii) hydrogen production in a small-scale gasifier with pre-combustion CCS utilising locally sourced waste wood. Process modelling and lifecycle assessment were used including a whole supply chain analysis. The investigated BECCS pathways could annually remove between − 0.8 and − 1.4 tCO2e tbiomass− 1 depending on operational decisions. Using all the available wheat straw and waste wood in the UK a joint CDR capacity for both systems could reach about 23% of the UK’s CDR minimum target set for BECCS. Policy frameworks prioritising carbon efficiencies can shape those operational decisions and strongly impact on the overall energy and CDR performance of a BECCS system but not necessarily maximising the trade-offs between biomass use energy performance and CDR. A combination of different BECCS pathways will be necessary to reach net-zero targets. Decentralised BECCS deployment could support flexible approaches allowing to maximise positive system trade-offs enable regional biomass utilisation and provide local energy supply to remote areas.

The concept of the “hydrogen economy” was first coined by Prof. John Bockris during a talk he gave in 1970 at the General Motors Technical Center. Bockris’s talk introduced the vision of a world economy in which energy was carried in the form of hydrogen resulting in zero emissions at its point of use—be that as a chemical feedstock or as a fuel for industrial or domestic heating for power generation in a gas turbine or in a fuel cell “engine” for transport applications. Despite several waves of significant interest and investment however due to the relative costs and technological immaturity of hydrogen technologies the hydrogen economy was never delivered at scale nor was there sufficient motivation to create the technology needed to overcome these hurdles.<br/>But today as the world seeks to transition to a truly net-zero carbon economy hydrogen has returned to the fore as a key energy carrier—not as a hydrogen economy but as “hydrogen in the economy” synergistically working alongside low- to zero-carbon electricity to decarbonize those parts of the economy that are too expensive or too difficult to be directly decarbonized with electricity. These include:<br/>♦ Transport applications in which large amounts of energy are needed on the vehicle such as planes trains shipping long-distance trucks and heavy-duty vehicles;<br/>♦ Industrial applications such as steelmaking and cement manufacturing;<br/>♦ Long-term energy storage for days to weeks at a time;<br/>♦ The production of green chemicals such as green ammonia and green methanol;<br/>♦ Industrial (and potentially residential) heating.

In the latest OIES podcast from the Hydrogen Programme James Henderson talks to Abdurahman Alsulaiman about his latest paper entitled “Navigating Turbulence: Hydrogen’s Role in the Decarbonisation of the Aviation Sector.” In the podcast we discuss the current balance of fuels in the aviation sector the importance of increasing efficiency of aero-engines and the impact of increasing passenger miles travelled. The podcast then considers different decarbonisation options for the sector focussing on a change of engine technology to allow the use of alternative fuels such as hydrogen or electricity but also looking at the potential for hydrogen to play an important role in the development of Sustainable Aviation Fuels (SAFs) for use with current engine technology. We also look at Low Carbon Aviation Fuels which are essentially existing fuels derived from a significantly decarbonised supply chain and assess whether they have an important role to play as the aviation sector targets a net zero outcome.

The podcast can be found on their website.

As climate change intensifies determining a developing region’s role in achieving net-zero emissions worldwide is crucial. However regional efforts considering historical emissions remain underexplored. Here we assess energy system changes technology adoption and investments needed for developing regions including five major- and minor-emitting nations. Our analysis using an integrated assessment model shows a large gap in regional efforts toward global net-zero emissions stemming from the necessary shift of energy systems to low-carbon resources. The use of new technologies like electric vehicles hydrogen and carbon capture varies by region with the highest adoption required between 2020 and 2030. Financing this shift needs an average gross domestic product (GDP) investment rise of 0.464% in minor-emitting regions and up to 2.1% in major-emitting regions by 2085. Our results could guide policies and support setting quantifiable targets for developing nations. The findings are key to facilitating strategic technology use and finance mobilization to achieve a carbon-neutral future.

This article presents a comprehensive review of the current landscape and prospects of large-scale hydrogen storage technologies with a focus on both onshore and offshore applications and flexibility. Highlighting the evolving technological advancements it explores storage and compression techniques identifying potential research directions and avenues for innovation. Underwater hydrogen storage and hybrid metal hydride com pressed gas tanks have been identified for offshore buffer storage as well as exploration of using metal hydride slurries to transport hydrogen to/from offshore wind farms coupled with low pressure high flexibility elec trolyser banks. Additionally it explores the role of metal hydride hydrogen compressors and the integration of oxyfuel processes to enhance roundtrip efficiency. With insights into cost-effectiveness environmental and technology considerations and geographical factors this review offers insights for policymakers researchers and industry stakeholders aiming to advance the deployment of large-scale hydrogen storage systems in the transition towards sustainable energy.

This study aimed to compare hydrogen ammonia methanol and waste-derived biofuels as shipping fuels using life cycle assessment to establish what potential they have to contribute to the shipping industry’s 100% greenhouse gas emission reduction target. A novel approach was taken where the greenhouse gas emissions associated with one year of global shipping fleet operations was used as a common unit for comparison therefore allowing the potential life cycle greenhouse gas emission reduction from each fuel option to be compared relative to Paris Agreement compliant targets for international shipping. The analysis uses life cycle assessment from resource extraction to use within ships with all GHGs evaluated for a 100-year time horizon (GWP100). Green hydrogen waste-derived biodiesel and bio-methanol are found to have the best decarbonisation po tential with potential emission reductions of 74–81% 87% and 85–94% compared to heavy fuel oil; however some barriers to shipping’s decarbonisation progress are identified. None of the alternative fuels considered are currently produced at a large enough scale to meet shipping’s current energy demand and uptake of alternative fuel vessels is too slow considering the scale of the challenge at hand. The decarbonisation potential from alternative fuels alone is also found to be insufficient as no fuel option can offer the 100% emission reduction required by the sector by 2050. The study also uncovers several sensitives within the life cycles of the fuel options analysed that have received limited attention in previous life cycle investigations into alternative shipping fuels. First the choice of allocation method can potentially double the life cycle greenhouse gas emissions of e-methanol due to the carbon ac counting challenges of using waste carbon dioxide streams during fuel production. This leads to concerns related to the true impact of using carbon dioxide captured from fossil-fuelled processes to produce a combustible product due to the resultant high downstream emissions. Second nitrous oxide emissions from ammonia combustion are found to be highly sensitive due to high greenhouse gas potency potentially offsetting any greenhouse reduction potential compared to heavy fuel oil. Further uncertainties are highlighted due to limited available data on the rate of nitrous oxide production from ammonia engines. The study therefore highlights an urgent need for the shipping sector to consider these factors when investing in new ammonia and methanol engines; failing to do so risks jeopardizing the sector’s progress towards decarbonisation. Finally whilst alternative fuels can offer good decarbonisation potential (particularly waste derived biomethanol and bio-diesel and green hydrogen) this cannot be achieved without accelerated investment in new and retrofit vessels and new fuel supply chains: the research concludes that existing pipeline of vessel orders and fuel production facilities is insufficient. Furthermore there is a need to integrate alternative fuel uptake with other decarbonisation strategies such as slow steaming and wind propulsion.

In recent years the intensification of human activities has led to an increase in waste production and energy demand. The treatment of pollutants contained in wastewater coupled to energy recovery is an attractive solution to simultaneously reduce environmental pollution and provide alternative energy sources. Hydrogen represents a clean energy carrier for the transition to a decarbonized society. Hydrogen can be generated by photosynthetic water splitting where oxygen and hydrogen are produced and the process is driven by the light energy absorbed by the photocatalyst. Alternatively hydrogen may be generated from hydrogenated pollutants in water through photocatalysis and the overall reaction is thermodynamically more favourable than water splitting for hydrogen. This review is focused on recent developments in research surrounding photocatalytic and photoelectrochemical hydrogen production from pollutants that may be found in wastewater. The fundamentals of photocatalysis and photoelectrochemical cells are discussed along with materials and efficiency determination. Then the review focuses on hydrogen production linked to the oxidation of compounds found in wastewater. Some research has investigated hydrogen production from wastewater mixtures such as olive mill wastewater juice production wastewater and waste activated sludge. This is an exciting area for research in photocatalysis and semiconductor photoelectrochemistry with real potential for scale up in niche applications.

Hydrogen is poised to play a pivotal role in achieving net-zero targets and advancing green economies. However a range of complex operational challenges hinders its planning production delivery and adoption. At the same time numerous drivers within the hydrogen value chain present significant opportunities. This paper investigates the intricate relationships between these drivers and barriers associated with hydrogen supply chain (HSC). Utilising expert judgment in combination Grey-DEMATEL technique we propose a framework to assess the interplay of HSC drivers and barriers. Gaining insight into these relationships not only improves access to hydrogen but also foster innovation in its development as a low-carbon resource. The use of prominence scores and net influence rankings for each driver and barrier in the framework provides a comprehensive understanding of their relative significance and impact. Our findings demonstrate that by identifying and accurately mapping these attributes clear cause-and-effect relationships can be established contributing to a more nuanced understanding of the HSC. These insights have broad implications across operational policy scholarly and social domains. For instance this framework can aid stakeholders in recognizing the range of opportunities available by addressing key barriers to hydrogen adoption.

Hydrogen spark-ignition direct-injection engines result in no carbon emissions at use but NOX remains a challenge. This study demonstrates that with lean combustion (ϕ < 0.38) in-cylinder NOX can be reduced to a quarter of the current maritime regulatory limit. An original contribution of this work is the use of speciesresolved emissions formation across multiple engine load conditions. A novel chemically detailed combustion modelling framework was developed in CHEMKIN-Pro incorporating the evolution of the CRECK C1–C3 NOX mechanism for improved high-pressure accuracy. The framework was extensively validated using crank-angleresolved data across 9–18 bar loads. The model accurately reproduced pressure traces heat release angles and NOX. Mechanistic analysis revealed a shift from thermal Zeldovich NOX to intermediate-species (notably N2Odriven) as equivalence ratio and pressure varied. The findings highlighted the use of a high-fidelity chemical kinetic modelling framework not only to match experimental results but to gain physically grounded insight into actionable near-zero emission strategies.

The research focuses on enhancing hydrogen production using a blend of municipal solid waste (MSW) with Biomass and mixed plastic waste (MPW) under the Bioenergy with Carbon Capture Utilisation and Storage (BECCUS) concept. The key challenges include optimising the feedstock blends and gasification process parameters to maximise hydrogen yield and carbon dioxide capture. This study introduces a novel approach that employs sorption-enhanced gasification and a high-temperature regenerator reactor. Using this method syngas streams with high hydrogen contents of up to 93 mol% and 66 mol% were produced respectively. Thermodynamic simulations with Aspen Plus® validated the integrated system for achieving high-purity hydrogen (99.99 mol%) and effective carbon dioxide isolation. The system produced 70.33 molH2 /kgfeed when using steam as a gasifying agent while 37.95 molH2 /kgfeed was produced under air gasification conditions. Case I employed a mixture of MSW and wood residue at a ratio of 1:1.25 with steam and calcium oxide added at 2:1 and 0.92:1 respectively resulting in 68.80 molH2 /kgfeed and a CO2 capture efficiency of 92 %. Case II utilised MSW and MPW at a 1:1 ratio with steam and calcium oxide at 2:1 and 0.4:1 respectively producing 100.17 molH2 /kgfeed and achieving a 90.09 % CO2 capture efficiency. The optimised parameters significantly improve hydrogen yield and carbon capture offering valuable insights for BECCUS applications.

Green hydrogen is likely to play a major role in decarbonising the aviation industry. It is crucial to understand the effects of microstructure on hydrogen redistribution which may be implicated in the embrittlement of candidate fuel system metals. We have developed a multiscale finite element modelling framework that integrates micromechanical and hydrogen transport models such that the dominant microstructural effects can be efficiently accounted for at millimetre length scales. Our results show that microstructure has a significant effect on hydrogen localisation in elastically anisotropic materials which exhibit an interesting interplay between microstructure and millimetre-scale hydrogen redistribution at various loading rates. Considering 316L stainless steel and nickel a direct comparison of model predictions against experimental hydrogen embrittlement data reveals that the reported sensitivity to loading rate may be strongly linked with rate-dependent grain scale diffusion. These findings highlight the need to incorporate microstructural characteristics in hydrogen embrittlement models.