Publications

The transport sector heavily relies on the use of fossil fuels which are causing major environmental concerns. Solutions relying on the direct or indirect use of electricity through efuel production are emerging to power the transport sector. To ensure environmental benefits are achieved over this transition an accurate estimation of the impact of the use of electricity is needed. This requires a high temporal resolution to capture the high variability of electricity. This paper presents a previously unseen temporal analysis of the carbon intensity of e-fuels using grid electricity in countries that are members of the European Network of Transmission System Operators (ENTSO-E). It also provides an estimation of the potential load factor for producing low-carbon e-fuels according to the European Union legislative framework. This was achieved by building on top of the existing EcoDynElec tool to develop EcoDynElec_xr a python tool enabling—with an hourly time resolution—the calculation visualisation and analysis of the historical time-series of electricity mixing from the ENTSO-E. The results highlight that in 2023 very few European countries were reaching low carbon intensity for electricity that enables the use of grid electricity for the production of green electrolytic hydrogen. The methodological assumptions consider the consumption of the electricity mix instead of the production mix and the considered time step is of paramount importance and drastically impacts the potential load factor of green hydrogen production. The developed tools are released under an open-source license to ensure transparency result reproducibility and reuse regarding newer data for other territories or for other purposes.

Photovoltaic (PV) and wind energy generation result in low greenhouse gas footprints and can supply electricity to the grid or generate hydrogen for various applications including seasonal energy storage. Designing integrated wind–PV–electrolyzer underground hydrogen storage (UHS) projects is complex due to the interactions between components. Additionally the capacities of PV and wind relative to the electrolyzer capacity and fluctuating electricity prices must be considered in the project design. To address these challenges process modelling was applied using cost components and parameters from a project in Austria. The hydrogen storage part was derived from an Austrian hydrocarbon gas field considered for UHS. The results highlight the impact of the renewable energy source (RES) sizing relative to the electrolyzer capacity the influence of different wind-to-PV ratios and the benefits of selling electricity and hydrogen. For the case study the levelized cost of hydrogen (LCOH) is EUR 6.26/kg for a RES-to-electrolyzer capacity ratio of 0.88. Oversizing reduces the LCOH to 2.61 €/kg when including electricity sales revenues or EUR 4.40/kg when excluding them. Introducing annually fluctuating electricity prices linked to RES generation results in an optimal RES-to-electrolyzer capacity ratio. The RES-to-electrolyzer capacity can be dynamically adjusted in response to market developments. UHS provides seasonal energy storage in areas with mismatches between RES production and consumption. The main cost components are compression gas conditioning wells and cushion gas. For the Austrian project the levelized cost of underground hydrogen storage (LCHS) is 0.80 €/kg with facilities contributing EUR 0.33/kg wells EUR 0.09/kg cushion gas EUR 0.23/kg and OPEX EUR 0.16/kg. Overall the analysis demonstrates the feasibility of integrated RES–hydrogen generation-seasonal energy storage projects in regions like Austria with systems that can be dynamically adjusted to market conditions.

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 aviation industry is facing challenges related to its environmental impact and thus the pressing need to develop aircraft technologies aligned with the society climate goals. Hydrogen is emerging as a potential clean fuel for aviation as it offers several advantages in terms of supply potential and weight specific energy. One of the key factors enabling the use of H2 in aviation is the development of reliable and safe storage technologies to be integrated into aircraft design. This work provides an overview of the technologies currently being investigated or developed for the storage of hydrogen within the aircraft which would enable the use of hydrogen as a sustainable fuel for aviation with emphasis on tanks material and structural aspects. The requirements dictated by the need of integrating the fuel system within existing or ex-novo aircraft architectures are discussed. Both the storage of gaseous and liquid hydrogen are considered and the main challenges related to the presence of either high internal pressures or cryogenic conditions are explored in the background of recent literature. The materials employed for the manufacturing of hydrogen tanks are overviewed. The need to improve the storage tanks efficiency is emphasized and issues such as thermal insulation and hydrogen embrittlement are covered as well as the reference to the main structural health monitoring strategies. Recent projects dealing with the development of onboard tanks for aviation are eventually listed and briefly reviewed. Finally considerations on the tank layout deemed more realistic and achievable in the near future are discussed.

The use of hydrogen-blended natural gas presents an efficacious pathway toward the rapid large-scale implementation of hydrogen energy with pipeline transportation being the principal method of conveyance. However pipeline materials are susceptible to hydrogen embrittlement in high-pressure hydrogen environments. Natural gas contains various impurity gases that can either exacerbate or mitigate sensitivity to hydrogen embrittlement. In this study we analyzed the mechanisms through which multiple impurity gases could affect the hydrogen embrittlement behavior of pipeline steel. We examined the effects of O2 and CO2 on the hydrogen embrittlement behavior of L360 pipeline steel through a series of fatigue crack growth tests conducted in various environments. We analyzed the fracture surfaces and assessed the fracture mechanisms involved. We discovered that CO2 promoted the hydrogen embrittlement of the material whereas O2 inhibited it. O2 mitigated the enhancing effect of CO2 when both gases were mixed with hydrogen. As the fatigue crack growth rate increased the influence of impurity gases on the hydrogen embrittlement of the material diminished.

The strategic importance of hydrogen has gained significant recognition as nations across the world have committed to achieving net zero. Here in the UK there’s a widespread consensus that hydrogen is critical to achieving our net zero target. This commitment culminated in the launch of the UK’s first Hydrogen Strategy and has been reaffirmed by Chris Skidmore’s Independent Review of Net Zero. Both these documents highlight hydrogen’s importance not only to net zero but growing the UK industrial base1 . Analysis by Hydrogen UK estimates up to 20000 jobs could be created by 2030 contributing £26bn in cumulative GVA2. These economic benefits flow from all areas of the value chain ranging from production storage network development and off-taker markets. However with large scale projects still to take final investment decisions current volumes of low-carbon hydrogen produced and consumed fall well below the government’s 2030 ambitions. Encouragingly the UK has a positive track record of deploying low carbon technologies. The combination of the UK’s world leading policies and incentive schemes alongside our vibrant RD&I and engineering environment has enabled rapid deployment of technologies like offshore wind and electric vehicles. Yet despite being world leaders in deployment early opportunities for regional supply chain growth and job creation were not fully realised and taken advantage of from inception. The hydrogen sector is therefore at a tipping point. To capitalise on the economic opportunity hydrogen offers the UK must learn from prior technology deployments and build a strong domestic hydrogen supply chain in parallel to championing deployment. This report delivers on a recommendation from the Hydrogen Champion Report which encouraged industry to create an industry led supply chain strategy3 . With Hydrogen UK steering the work on behalf of the UK hydrogen industry this study focusses on identifying the actions needed to mature a local supply chain that can support the initial deployment of hydrogen technologies across the value chain. The report is segmented into two sections. The first section outlines a voluntary ambition for local content from industry alongside the potential intervention mechanisms needed to achieve the ambition. The second section exploresthe challenges companies across the hydrogen value chain face in maximising UK supply chain opportunities.

This report can be found on Hydrogen UK's website.

Hydrogen is one of the most popular alternatives for energy storage. Because of its low volumetric energy density hydrogen should be compressed for practical storage and transportation purposes. Recently electrochemical hydrogen compressors (EHCs) have been developed that are capable of compressing hydrogen up to P = 1000 bar and have the potential of reducing compression costs to 3 kWh/kg. As EHC compressed hydrogen is saturated with water the maximum water content in gaseous hydrogen should meet the fuel requirements issued by the International Organization for Standardization (ISO) when refuelling fuel cell electric vehicles. The ISO 14687−2:2012 standard has limited the water concentration in hydrogen gas to 5 μmol water per mol hydrogen fuel mixture. Knowledge on the vapor liquid equilibrium of H2O−H2 mixtures is crucial for designing a method to remove H2O from compressed H2. To the best of our knowledge the only experimental high pressure data (P > 300 bar) for the H2O−H2 phase coexistence is from 1927 [J. Am. Chem. Soc. 1927 49 65−78]. In this paper we have used molecular simulation and thermodynamic modeling to study the phase coexistence of the H2O−H2 system for temperatures between T = 283 K and T = 423 K and pressures between P = 10 bar and P = 1000 bar. It is shown that the Peng-Robinson equation of state and the Soave Redlich-Kwong equation of state with van der Waals mixing rules fail to accurately predict the equilibrium coexistence compositions of the liquid and gas phase with or without fitted binary interaction parameters. We have shown that the solubility of water in compressed hydrogen is adequately predicted using force-field-based molecular simulations. The modeling of phase coexistence of H2O−H2 mixtures will be improved by using polarizable models for water. In the Supporting Information we present a detailed overview of available experimental vapor−liquid equilibrium and solubility data for the H2O−H2 system at high pressures.

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.

Japan has formulated a net-zero emissions target by 2050. Existing scenarios consistent with this target generally depend on carbon dioxide removal (CDR). In addition to domestic mitigation actions the import of low-carbon energy carriers such as hydrogen and synfuels and negative emissions credits are alternative options for achieving net-zero emissions in Japan. Although the potential and costs of these actions depend on global energy system transition characteristics which can potentially be informed by the global integrated assessment models they are not considered in current national scenario assessments. This study explores diverse options for achieving Japan's net-zero emissions target by 2050 using a national energy system model informed by international energy trade and emission credits costs estimated with a global energy system model. We found that demand-side electrification and approximately 100 Mt-CO2 per year of CDR implementation equivalent to approximately 10% of the current national CO2 emissions are essential across all net-zero emissions scenarios. Upscaling of domestically generated hydrogen-based alternative fuels and energy demand reduction can avoid further reliance on CDR. While imports of hydrogen-based energy carriers and emission credits are effective options annual import costs exceed the current cost of fossil fuel imports. In addition import dependency reaches approximately 50% in the scenario relying on hydrogen imports. This study highlights the importance of considering global trade when developing national net-zero emissions scenarios and describes potential new roles for global models.

Hydrogen has emerged as a critical energy carrier for achieving global decarbonization and supporting a sustainable energy future. This review explores key advancements in hydrogen production technologies including electrolysis biomass gasification and thermochemical processes alongside innovations in storage methods like metal hydrides and liquid organic hydrogen carriers (LOHCs). Despite its promise challenges such as high production costs scalability issues and safety concerns persist. Biomass gasification stands out for its dual benefits of waste management and carbon neutrality yet hurdles like feedstock variability and energy efficiency need further attention. This review also identifies opportunities for improvement such as developing cost-effective catalysts and hybrid storage systems while emphasizing future research on improving storage efficiency and tackling production bottlenecks. By addressing these challenges hydrogen can play a central role in the global transition to cleaner energy systems.

This paper examines the crucial elements of pipeline-based hydrogen transportation highlighting the particular difficulties and technical developments required to guarantee the sustainable effective and safe supply of hydrogen. This study lists the essential phases of hydrogen pipeline management from design to repair as the relevance of hydrogen infrastructure in the worldwide energy transition continues to rise. It discusses the upkeep monitoring operation and rehabilitation procedures for aged pipelines with an emphasis on the cutting-edge techniques and technology used to mitigate the dangers related to hydrogen’s unique features such as leakage and embrittlement. Together with highlighting the legislative and regulatory frameworks that enable the infrastructure this paper also discusses the material economic and environmental difficulties related to hydrogen pipelines. Lastly it emphasizes how crucial it is to fund research create cutting-edge materials and implement sophisticated monitoring systems to guarantee the long-term dependability and safety of hydrogen pipelines. These initiatives will be crucial in allowing hydrogen’s contribution to the future of renewable energy together with international collaboration on regulatory standards.

The work carried out in this paper focused on “Machine learning models for the prediction of turbulent combustion speed for hydrogen-natural gas spark ignition engines”. The aim of this work is to develop and verify the ability of machine learning models to solve the problem of estimating the turbulent flame speed for a spark-ignition internal combustion engine operating with a hydrogen-natural gas mixture then evaluate the relevance of these models in relation to the usual approaches. The novelty of this work is the possibility of a direct calculation of turbulent combustion speed with a good precision using only machine learning model. The obtained models are also compared to each other by considering in turn as a comparison criterion: the precision of the result calculation time and the ability to assimilate original data (which has not undergone preprocessing). An important particularity of this work is that the input variables of the machine learning models were chosen among the variables directly measurable experimentally based on the opinion of experts in combustion in internal combustion engines and not on the usual approaches to dimensionality reduction on a dataset. The data used for this work was taken from a MINSEL 380 a 380-cc single-cylinder engine. The results show that all the machine learning models obtained are significantly faster than the usual approach and Random Forest (R2: R-squared = 0.9939 and RMSE: Root Mean Square Error = 0.4274) gives the best results. With a forecasting accuracy of over 90 % both approaches can make reasonable predictions for most industrial applications such as designing engine monitoring and control systems firefighting systems simulation and prototyping tools.

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

Steam methane reforming (SMR) is a leading technology for hydrogen production. However this technology is still carbon-intensive since in current SMR units the PSA tail gas containing H2 CO and CH4 is burned at the reformer with air and exits the stack at a CO2 purity of less than 5% which is not feasible to capture. In this paper we aim to either harness the energy content of this gas to generate power in a solid oxide fuel cell (SOFC) or burn it via chemical looping combustion (CLC) or oxy-combustion process to produce off-gas with high CO2 purity ready to storage. Therefore an industrial-scale PSA with 72000 Nm3/h feed capacity was modelled to obtain the tail gas flow rate and composition. Then CLC SOFC and oxy-combustion were modelled to use tail gas. Finally a techno-economic analysis was conducted to calculate each technology's levelised cost of hydrogen (LCOH). It was observed that CO2 purity for CLC meets the criteria for storage (>95%) without further purification. On the other hand from the economic point of view all three technologies show a promising performance with an LCOH of 1.9 €/kg.

The goal of achieving a zero-emission energy system by 2050 requires accurate energy planning to minimise the overall cost of the energy transition. Long-term energy models based on cost-optimal solutions are extremely dependent on the cost forecasts of different technologies. However such forecasts are inherently uncertain. The aim of the present work is to identify a cost-optimal pathway for the Italian energy system decarbonisation and assess how renewable cost scenarios can affect the optimal solution. The analysis has been carried out with the H2RES model a single-objective optimisation algorithm based on Linear Programming. Different cost scenarios for photovoltaics on-shore and off-shore wind power and lithium-ion batteries are simulated. Results indicate that a 100% renewable energy system in Italy is technically feasible. Power-to-X technologies are crucial for balancing purposes enabling a share of non-dispatchable generation higher than 90%. Renewable cost scenarios affect the energy mix however both on-shore and off-shore wind saturate the maximum capacity potential in almost all scenarios. Cost forecasts for lithium-ion batteries have a significant impact on their optimal capacity and the role of hydrogen. Indeed as battery costs rise fuel cells emerge as the main solution for balancing services. This study emphasises the importance of conducting cost sensitivity analyses in long-term energy planning. Such analyses can help to determine how changes in cost forecasts may affect the optimal strategies for decarbonising national energy systems.

Hydrogen has become a key enabler for decarbonization as countries pledge to reach net zero carbon emissions by 2050. With hydrogen infrastructure expanding rapidly beyond its established applications there is a requirement for robust safety practices solutions and regulations. Since the 1980s considerable efforts have been undertaken by the nuclear community to address hydrogen safety issues because in severe accidents of water-cooled nuclear reactors a large amount of hydrogen can be produced from the oxidation of metallic components with steam. As evidenced in the Fukushima accident hydrogen combustion can cause severe damage to reactor building structures promoting the release of radioactive fission products to the environment. A great number of large-scale experiments have been conducted in the framework of national and international projects to understand the hydrogen dispersion and combustion behavior under postulated accidental conditions. Empirical engineering models and computer codes have been developed and validated for safety analysis. Hydrogen recombiners known as Passive Autocatalytic Recombiners (PARs) were developed and have been widely installed in nuclear containments to mitigate hydrogen risk. Complementary actions and strategies were established as part of severe accident management guidelines to prevent or limit the consequences of hydrogen explosions. In addition hydrogen monitoring systems were developed and have been implemented in nuclear power plants. The experience and knowledge gained from the nuclear community on hydrogen safety is valuable and applicable for other industries involving hydrogen production transport storage and use.

Nowadays several technologies based on powertrain electrification and the exploitation of hydrogen represent valuable options for decarbonizing the on-road public transport sector. The considered alternatives should exhibit an effective benchmark between CO2 reduction potential and production/operational costs. Conducting a comprehensive Total Cost of Ownership (TCO) analysis coupled with a thorough Life Cycle Assessment (LCA) is therefore crucial in shaping the future for cleaner urban mobility. From this perspective this study compares different powertrain configurations for a 12 m urban bus: a conventional diesel Internal Combustion Engine Vehicle (ICEV) a series hybrid diesel two hydrogen-based series hybrid vehicles: a Hydrogen Hybrid Electric Vehicle featuring an H2-ICE (H2-HEV) or a Fuel Cell Electric Vehicle (FCEV) and a Battery Electric Vehicle (BEV). Moreover a sensitivity analysis has been conducted on the carbon footprint for power generation considering also the marginal electricity mix. In addition prospective LCA and TCO elements are introduced by addressing future technological projections for the 2030 horizon. The research reveals that as of today the BEV and hydrogen-fueled vehicles have comparable environmental impacts when the marginal electricity mix is considered. The techno-economic analysis indicates that under current conditions FCEVs and H2-HEVs are not cost-effective for CO₂ reduction unless powered by renewable energy sources. However considering future technological advancements and market evolution FCEVs offer the most promising balance between economic and environmental benefits particularly if hydrogen prices reach €4 per kilogram. If hydrogen-powered vehicles remain a niche market BEVs will be the most viable option for decarbonizing the transport sector in most European countries.

The refining industry is shifting from decarbonization to hydrogenation for processing heavy fractions to reduce pollution and improve efficiency. However the carbon footprint of hydrogen production presents significant environmental challenges. This study couples refinery linear programming models with life cycle assessment to evaluate from a long-term perspective the role of low-carbon hydrogen in promoting sustainable and profitable hydrogenation refining practices. Eight hydrogen-production pathways were examined including those based on fossil fuels and renewable energy providing hydrogen for three representative refineries adopting hydrogenation decarbonization and co-processing routes. Learning curves were used to predict future hydrogen cost trends. Currently hydrogenation refineries using fossil fuels benefit from significant cost advantages in hydrogen production demonstrating optimal economic performance. However in the long term with increasing carbon taxes hydrogenation routes will be affected by the high carbon emissions associated with fossil-based hydrogen losing economic advantages compared to decarbonization pathways. With increasing installed capacity and technological advancements low-carbon hydrogen is anticipated to reach cost parity with fossil-based hydrogen before 2060. Coupling renewable hydrogen is expected to yield the most significant economic advantages for hydrogenation refineries in the long term. Renewable hydrogen drives the transition of refining processing routes from a decarbonization-oriented approach to a hydrogenation-oriented paradigm resulting in cleaner refining processes and enhanced competitiveness under emission-reduction pressures.

Green hydrogen production and storage are vital in mitigating carbon emissions and sustainable transition. However the high investment cost and management requirements are the bottleneck of utilizing hybrid hydrogen-based systems in microgrids. Given the necessity of cost-effective and optimal design of these systems the present study examines techno-economic feasibility of integrating hybrid hydrogen-based systems into an outdoor test facility. With this perspective several solar-driven hybrid scenarios are introduced at two energy storage levels namely the battery and hydrogen energy storage systems including the high-pressure gaseous hydrogen and metal hydride storage tanks. Dynamic simulations are carried out to address subtle interactions in components of the hybrid system by establishing a TRNSYS model coupled to a Fortran code simulating the metal hydride storage system. The OpenStudio-EnergyPlus plugin is used to simulate the building load validate against experimental data according to the measured data and monitored operating conditions. Aimed at enabling efficient integration of energy storage systems a techno-enviro-economic optimization algorithm is developed to simultaneously minimize the levelized cost of the electricity and maximize the CO2 mitigation in each proposed hybrid scenario. The results indicate that integrating the gaseous hydrogen and metal hydride storages into the photovoltaic-alone scenario enhances 22.6% and 14.4% of the annual renewable factor. Accordingly the inclusion of battery system to these hybrid scenarios gives a 30.4% and 20.3 % boost to the renewable factor value respectively. Although the inclusion of battery energy storage into the hybrid systems increases the renewable factor the results imply that it reduces the hydrogen production rate via electrolysis. The optimized values of the levelized cost of electricity and CO2 emission for different scenarios vary in the range of 0.376–0.789 $/kWh and 6.57–9.75 ton respectively. The multi-criteria optimizations improve the levelized cost of electricity and CO2 emission by up to 46.2% and 11.3% with respect to their preliminary design.

Growing expectations are being placed on green hydrogen-based steel for decarbonising the global steel industry. However the scale of the expected demand is dispersed across numerous case studies resulting in a fragmented picture. This study examines 28 existing scenarios to provide a cohesive view of future global demand. In the short term the demand for green hydrogen-based steel is expected to be limited constituting 2% of current total steel production by 2030. However a transformation phase is expected around 2040 marked by accelerated growth. By 2050 global demand is projected to reach 660 Mt (with an interquartile range of 368–1000 Mt) equivalent to 35% (19%–53%) of current total steel production. To meet such growing demand green hydrogen supply and electrolyser capacity will need to increase to more than 1000 times current levels by 2050. These trends highlight both short-term limitations and long-term potential. Decarbonisation efforts will therefore require immediate emission reductions with already scalable options while simultaneously building the enabling infrastructure for green hydrogen-based steelmaking to ensure long-term impacts.

Global warming’s major cause is the emission of greenhouse-effect gases (GHG) especially carbon dioxide (CO2) whose main source is the combustion of fossil fuels. Fossil fuels serve as the primary energy source in many industries including shipping which is the focus of this study. One of the measures proposed to tackle GHG emissions is the development of green shipping corridors - carbon-free shipping routes that require the transition to alternative fuels which are gaining competitiveness. One of the reasons for that is carbon pricing which taxes CO2 emissions. However the lack of consensus on the most cost-advantageous alternative fuel in the long run results in the delay of the implementation of green shipping corridors. To make it more accessible for stakeholders to conduct an economic analysis of the various options a framework to determine and minimize the costs of transitioning from fossil fuels to any alternative fuel is proposed over the period of one voyage considering the lost opportunity cost the deployment cost of bunkering vessels at the necessary call ports the cost of converting the vessel the car-bon emissions tax cost and the fuel cost. This will allow stakeholders to choose the most economical alternative fuel accelerating the development of green shipping corridor initiatives. To validate the effectiveness of the framework it was applied in a case study involving a shipowner seeking to transition from heavy fuel oil (HFO) to Ammonia Hydrogen Liquefied Natural Gas (LNG) or Methanol. This study faced limitations due to the unknown costs of installing bunkering vessels for Ammonia and Hydrogen. However it evaluates the cost-effectiveness of alternative fuels providing insights into their short-term economic viability. The results showed that Hydrogen is the most costadvantageous fuel until a deployment cost per bunkering vessel of 1990285$ for a sailing speed of 22 knots and 2190171$ for a sailing speed of 18 knots is reached after which LNG becomes the most economical option regardless of variations in the carbon tax. Moreover a sensitivity analysis was conducted to determine the effects of variations in parameters such as carbon tax fuel prices and vessel conversion costs in the total cost of each fuel option. Results highlighted that even though HFO remains the most economical fuel option even when considering a high increase in carbon tax the cost gap between HFO and alternative fuels narrows significantly with the increase in carbon tax. Furthermore the sailing speed impacts the fuels’ competitiveness as the cost difference between HFO and alternative fuels decreases at higher speeds.

Integrated hydrogen energy systems (IHESs) have attracted extensive attention in miti-gating climate problems. As a kind of large-scale hydrogen storage device undergroundhydrogen storage (UHS) can be introduced into IHES to balance the seasonal energy mis-match while bringing challenges to optimal operation of IHES due to the complex geolog-ical structure and uncertain hydrodynamics. To address this problem a deep deterministicpolicy gradient (DDPG)-based optimal scheduling method for underground space basedIHES is proposed. The energy management problem is formulated as a Markov decisionprocess to characterize the interaction between environmental states and policy. Based onDDPG theory the actor-critic structure is applied to approximate deterministic policy andactor-value function. Through policy iteration and actor-critic network training the oper-ation of UHS and other energy conversion devices can be adaptively optimised which isdriven by real-time response data instead of accurate system models. Finally the effective-ness of the proposed optimal scheduling method and the benefits of underground spaceare verified through time-domain simulations.

In the future steel products will be reheated for hot working using hydrogen instead of natural gas. This study investigated the differences in oxide scale formation between natural gas/air and hydrogen/air combustion at constant air-fuel-ratio. Samples of a hypo-eutectoid eutectoid and hyper-eutectoid steel grade (dimensions: 30 x 30 x 50 mm W x H x L) were exposed to the two atmospheres in a semi-industrial scale furnace for 180 min at three sample core temperatures (1100 1200 and 1280 °C). Specific mass gain was calculated and the samples were metallographically examined. Switching the fuel increased scale formation depending on the steel. The exponential correlation between temperature and scale formation is more pronounced for the eutectoid and the hyper-eutectoid steel grade. Metallographic investigations revealed similar scale morphologies in both atmospheres but with significant temperature dependence. The decarburization depth is atmosphere-independent. Thus switching fuel does not negatively impact the properties of the steel substrate; it only increases scale formation during reheating.

As a paradigm of clean energy hydrogen is gradually attracting global attention. However its unique characteristics of leakage and autoignition pose significant challenges to the development of high-pressure hydrogen storage technologies. In recent years numerous scholars have made significant progress in the field of high-pressure hydrogen leakage autoignition. This paper based on diffusion ignition theory thoroughly explores the mechanism of high-pressure hydrogen leakage autoignition. It reviews the effects of various factors such as gas properties burst disc rupture conditions tube geometric structure obstacles etc. on shock wave growth patterns and autoignition characteristics. Additionally the development of internal flames and propagation characteristics of external flames after ignition kernels generation are summarized. Finally to promote future development in the field of high-pressure hydrogen energy storage and transportation this paper identifies deficiencies in the current research and proposes key directions for future research.

An analysis of the turbulent premixed combustion speed in an internal combustion engine using natural gas hydrogen and intermediate mixtures as fuels is carried out with different air-fuel ratios and engine speeds. The combustion speed has been calculated by means of a two-zone diagnosis thermodynamic model combined with a geometric model using a spherical flame front hypothesis. 48 operating conditions have been analyzed. At each test point the pressure record of 200 cycles has been processed to calculate the cycle averaged turbulent combustion speed for each flame front radius. An expression of turbulent combustion speed has been established as a function of two parameters: the ratio between turbulence intensity and laminar combustion speed and the second parameter the ratio between the integral spatial scale and the thickness of the laminar flame front increased by instabilities. The conclusion of this initial study is that the position of the flame front has a great influence on the expression to calculate the combustion speed. A unified correlation for all positions of the flame front has been obtained by adding one correction term based on the expansion speed as a turbulence source. This unified correlation is thus valid for all experimental conditions of fuel types air–fuel ratios engine speeds and flame front positions. The correlation can be used in quasi-dimensional predictive models to determine the heat released in an ICE.