Institution of Gas Engineers & Managers

This article describes hydrogen production via water splitting because of high green energy demand globally. The amounts of hydrogen produced with zirconium in thermal processes at 473 K and radiation-thermal processes at 473 K and 773K were 1.55 x 1018 2.2 x 1018 and 4.1 x 1018 molecules/g. These amounts on aluminum and stainless steel were 1.05 x 1018 1.95 x 1018 and 3.0 x 1018 molecules/g; and 0.30 x 1018 1.27 x 1018 and 2.6 x 1018 molecules/g. A comparison was carried out and the order of hydrogen production was zirconium > aluminum > stainless steel. The activation energy in radiation-thermal and thermal processes were 14.2 and 65.0 kJ/mol (Zr) 12.05 and 63.1 kJ/mol (Al) and 11.16 and 61.52 kJ/mol (SS). The mechanisms of water splitting were developed and described for future use. The described methods are scalable and can be transferred to a pilot scale.

High-temperature (HT) proton exchange membrane (PEM) fuel cells (FC) offer key advantages for sustainable transportation especially in heavy-duty applications due to their improved thermal efficiency and water management. This study introduces an inverse design framework to develop flow field plates integrated with a gas diffusion layer (GDL) enabling scalable electrochemical performance from the unit cell to the plate level. A reduced-order homogenization-based multiphysics model is developed to evaluate designs with approximately 1000× faster computation. Flow channel orientation is optimized using a tensor field method and dehomogenized into manufacturable geometries. Optimized designs validated through high-fidelity 3D simulations show up to 12% higher average current density and 88% lower pressure drop compared to conventional parallel and mesh configurations. To address fabrication challenges solid-to-porous metal additive manufacturing is employed producing monolithic structures that integrate flow channels with a porous metal GDL. Both numerical and physical tests confirm high permeability and improved power output compared to carbon-based GDLs. These findings highlight the effectiveness of combining advanced computational modeling with metal 3D printing to enhance the performance and manufacturability of high-temperature PEMFC supporting their broader adoption in sustainable energy applications.

The transition to carbon-neutral energy has renewed interest in hydrogen as a gas turbine fuel in the form of fuel blends with hydrocarbons. However the distinct fluid properties and chemical kinetics of hydrogen and hydrocarbon blends necessitate redeveloped combustor designs. While conventional combustor design and emissions estimation through computational fluid dynamics (CFD) is preferred it is computationally intensive and impractical for system-level simulations. To alleviate this a thermofluid network model was developed to predict the performance of a MGT combustor operating on pure and fuel blends of propane and hydrogen. It incorporates sub-component pressure losses and heat transfer and presents the first implementation of well-stirred and plug-flow reactors into Flownex SE. A 3-D CFD study of the combustor revealed that hydrogen addition improved combustion efficiency and reduced wall temperatures. However although it produces less CO2 it leads to 70 % more CO and 80 % more NO than for propane-only operation. Validated against the 3-D CFD data the network model predicted the combustor outlet total temperature and pressure within 0.55 % and 0.26 % respectively. The change in total pressure across subcomponents (<6 %) and the mass flow distribution showed similarly strong agreement. Major species mass fractions CO₂ and H₂O were predicted accurately. However by assuming that the temperature and composition are uniform within combustion zones zone and wall temperatures and pollutant predictions deviated considerably. NO was overpredicted by a factor of 8.2–10.7 and CO was overpredicted for propane-only but underpredicted for blended cases. The network model achieved this performance 420 times faster than CFD making it suitable for rapid design exploration.

Ammonia is a cornerstone of modern agriculture supplying the nitrogen essential for crops that nourish nearly half the global population. Yet its production is responsible for ~2 % of global greenhouse gas emissions. To meet climate and food security goals sustainable low-carbon and resilient ammonia production systems are needed. Here we develop a spatially explicit techno-economic model to compare centralized and decentralized ammonia production pathways across the U.S. a major global ammonia producer and consumer spanning the full supply chain from hydrogen production to fertilizer delivery. We integrate high-resolution supply and demand data and apply linear optimization to estimate delivered ammonia costs accounting for geographic mismatches and transportation. Our results show that decentralized ammonia production whether powered by grid electricity or solar energy is substantially more expensive than centralized production from natural gas or coal. Centralized natural gas-based ammonia has a median production cost of 326 USD/tonne NH3 compared to 499 USD/tonne for coal. Decentralized grid-powered systems range from 659 to 1634 USD/tonne and solar-powered systems from 1077 to 2266 USD/tonne. Transportation costs for centralized production range from 7 to 85 USD/tonne with a median of 40 USD/tonne resulting in a delivered cost of 343 USD/tonne. Median delivered costs for decentralized grid- and solar-powered systems are 1069 and 1494 USD/tonne respectively. Decentralized systems require electricity prices below 19 USD/MWh (grid) and 17 USD/MWh (solar) to achieve cost parity well below 2024 U S. averages of 117 USD/MWh. These results highlight the economic challenges facing decentralized ammonia production and the importance of electricity cost reductions tax credits carbon pricing or further technological breakthroughs for broader viability.

Solid oxide fuel cell (SOFC) systems offer high-efficiency conversion of the chemical energy of fuel gases into electrical energy. To meet market and policy targets such systems must be able of operating on an industrial scale and be compatible with environmentally friendly fuels. This study models the scale-up of a 750 W naturalgas-fueled SOFC to a 240 kW system with various gas-path configurations evaluating the impact of blending up to 30 vol% of hydrogen (H2) into the methane feed. Aspen Plus simulations coupled with pressure-loss and carbon-deposition models were used to optimize recirculation ratio and reactant utilization for maximum efficiency. The parallel configuration achieved the highest electrical efficiency of 64.0 % while series-connected and intermediate systems suffered from increased pressure losses. H2 admixture simulations confirm that operation is feasible without loss of efficiency in the small- and large-scale systems due to reduced carbondeposition potential. A techno-economic analysis indicates a 91.7 % cost reduction through scale-up and a 1.6 % cost increase for adjusting the system to H2 admixtures. The economic viability of the large-scale system was evaluated for all tested fuel compositions (0.201–0.204 €/kWh) with payback times under 20 years at market-relevant electricity prices. These results demonstrate the technical and economic feasibility of large-scale H2-adapted SOFC systems for industrial decarbonization.

In this work a plasma fluidized bed reactor has been studied as an electrified methane decomposition reactor for sustainable hydrogen production. A combined 3D rotating gliding arc/fluidized bed reactor assembly demonstrates a stable operation with a CH4/Ar mixture containing up to 8 vol% of CH4. The reactor provides a 97.2 % H2 selectivity at a methane conversion of 16.6 % and energy costs of 10.6 kJ L− 1 . This performance provides a new benchmark for electrified H2 production with a potential to utilise renewable electricity. In addition carbon materials are produced. The characterizations show difference in the morphology of the materials collected in different reactor zones.

Hydrogen’s increasing potential as an alternative fuel for heavy-duty transport has led to the conversion of conventional diesel compression-ignition engines to spark-ignition hydrogen operation. Hydrogen’s broad flammability range enables leaner operation achieving both higher engine efficiency and near-zero emissions. In particular direct injection hydrogen combustion improves volumetric efficiency and reduces problems including pre-ignition and knock related to hydrogen port-fuel injection. In the present work we performed an optical investigation of direct injection (DI) hydrogen combustion under leaner mixture conditions. The study was conducted using a heavy-duty optical diesel engine modified for spark-ignition operation. Bottom-view natural flame luminosity and OH-PLIF imaging were conducted along with in-cylinder pressure measurements. Experiments were conducted at three air-excess ratios (3 3.4 and 3.8) with spark timings (ST) varied from − 15 ◦CA aTDC to − 30 ◦CA aTDC. Hydrogen injection ended at − 30 ◦CA aTDC with the start of injection adjusted accordingly to achieve the desired lambda conditions. The maximum IMEPg corresponded to the lowest COV of the IMEPg indicating optimal spark timing for lean DI hydrogen combustion. The optimized spark timing for λ = 3 λ = 3.4 and λ = 3.8 were occurred at − 25 ◦CA aTDC − 25 ◦CA aTDC and − 30 ◦CA aTDC respectively. The corresponding COV of IMEPg values were below 5 % indicating stable combustion. The flame kernel first initiates at the spark plug and then propagates toward the piston’s outer boundary however the flame propagation does not remain as a continuous front unlike port-fuel injected hydrogen combustion. The effect of fuel stratification is evident in combustion luminosity and OH-PLIF images showing pockets of varying intensity within the combustion chamber. Natural flame luminosity images reveal incomplete flame coverage and asymmetric combustion emphasizing the need for metal engine experiments to further quantify the unburned hydrogen and associated combustion losses.

This review explores the evolving role of hydrogen in global decarbonization analysing national hydrogen strategies value chain developments and future market potential. Through a comprehensive review of policy frameworks market trends and technology pathways the paper evaluates hydrogen’s role in decarbonising sectors such as steel ammonia methanol refining transport and power generation. The study highlights the expected growth in global hydrogen demand projected cost reductions and advancements in production technologies including electrolysis and carbon capture-integrated hydrogen production. While green hydrogen offers a sustainable pathway challenges remain in infrastructure development energy efficiency and the integration of hydrogen into existing energy networks. The paper considers the economic and technological factors affecting international hydrogen trade. Despite more than 30 national hydrogen strategies being in place significant challenges remain particularly in scaling renewable electricity and infrastructure to meet growing hydrogen demand projected to reach up to 600 Mt by 2050. Key players such as Australia Norway and the Middle East are positioning themselves as major hydrogen exporters by leveraging their abundant natural resources and strategic infrastructure. On the demand side countries like Japan South Korea Germany and the Netherlands are emerging as leading importers investing heavily in hydrogen hubs and import terminals to secure future energy supplies. The expansion of hydrogen storage and transportation alongside investments in large-scale hydrogen hubs will be critical for market growth. Additionally the study emphasize the need for policy alignment strategic investments and cross-border cooperation to accelerate hydrogen adoption. Hydrogen can become a key element of the global clean energy transition by addressing optimal energy consumption and by leveraging renewable resources.

Fuel cell electric vehicles (FCEVs) are zero-emission but face cost and power density challenges. To mitigate these limitations a novel 3D-ordered nano-structured self-supporting membrane electrode assembly (MEA) has been developed. This paper investigates the optimal component sizing of the battery and fuel cell in FCEVs equipped with 3D-ordered MEAs integrating the energy management. To explore the trade-offs between component cost operational cost and fuel cell degradation the sizing and energy management problem is formulated into a multi-objective optimisation problem. A Pareto frontier (PF) study is conducted using the decomposed multi-objective evolutionary algorithm (MOEA/D) for a more diverse distribution of feasible solutions. The modular design of fuel cells is derived from a scaled and stressed experiment. After executing MOEA/D across the three aggressive driving cycles power source configurations are selected from the corresponding PFs based on objective trade-offs ensuring robustness of the overall system. The optimisation performance of the MOEA/D is compared with that of the multi-objective Particle Swarm Optimisation. In addition the selected powertrain configurations are evaluated and compared through standard and realworld driving cycles in a simulation environment. This paper also performs a sensitivity analysis to reveal the influence of diverse component unit costs and hydrogen price. The results indicate that the mediumsized configuration consisting of a 63.31 kW fuel cell stack and a 52.15 kWh battery pack delivers the best overall performance. It achieves a 26.71% reduction in component cost and up to 12.76% savings in hydrogen consumption across various driving conditions. These findings provide valuable insights into the design and optimisation of fuel cell systems for FCEVs.

Coastal regions in Cameroon including Douala Kribi Campo Dibamba and Limbe faced persistent electricity challenges driven by grid instability growing demand and dependence on fossil fuels. Solar resource availability was high but intermittent whereas tidal energy was predictable and energy-dense yet underused. This pilot delivers the first Cameroonian assessment of an off-grid tidal/PV/electrolyzer/hydrogen-storage/fuel-cell architecture explicitly co-optimizing electricity service and green hydrogen production and evaluating performance with a tri-metric economic lens (net present cost levelized cost of electricity and the levelized cost of hydrogen). The system was optimized to minimize net present cost (NPC) levelized cost of electricity (LCOE) levelized cost of hydrogen (LCOH) and three tidal-flow scenarios were analyzed to represent hydrokinetic variability. The design served households small businesses fishing activities schools and health facilities with a baseline demand of 389.50 kWh/day; surplus renewable power drove the electrolyzer to produce hydrogen for later reconversion in the fuel cell. Under the first scenario (1.25 m/s average speed) the optimal mix comprised 137 PV modules (600 W each) a 100 kW fuel cell six 40 kW tidal turbines six 10 kW electrolyzers a 19.5 kW converter and 41 hydrogen tanks (40 L each) yielding an NPC of US$ 2.16 million an LCOE of US$ 0.782/kWh and a LCOH of US$ 19.2/kg of hydrogen. The second scenario (1.47 m/s) required only 12 PV modules one electrolyzer and an 11.3 kW converter lowering costs to an NPC of US$ 1.52 million an LCOE of US$ 0.553/ kWh and a LCOH of US$ 15.4/kg of hydrogen. In the third scenario (1.61 m/s) the configuration shifted to 298 PV modules three tidal turbines eight electrolyzers and a 39.6 kW converter resulting in the highest NPC (US$ 2.47 million) and LCOE (US$ 0.901/kWh) with a LCOH of US$ 18.8/kg of hydrogen. The study also contributes a transparent component-wise employment indicator linking installed capacities/energies to jobs; deployment is expected to create about seven local jobs during installation and early operation tidal turbines (3) solar panels (1) electrolyzers (1) hydrogen tanks (1) and fuel cell (1) with additional minor operation and maintenance positions thereafter. Social analysis indicated improved energy access support for local livelihoods and job creation; environmental results confirmed clean operation with limited marine disturbance. A sensitivity study varying capital and replacement-cost multipliers showed robust performance across economic conditions. Taken together these contributions provide a decision-ready blueprint for coastal communities: a first-of-its-kind Cameroonian hybrid that quantifies both electricity and hydrogen costs (including feasible LCOH) and demonstrates socio-economic co-benefits offering a cost-effective pathway to strengthen energy security foster local development and reduce environmental impact.

The adoption of clean hydrogen is expected to transform the global energy landscape reducing greenhouse gas emissions bridging gaps in renewable energy integration and driving innovation across multiple sectors. In the medical and pharmaceutical industries hydrogen offers unique opportunities for transformative progress. This review critically examines recent advances in three domains: hydrogen fuel cells as reliable scalable and sustainable energy solutions for hospitals; molecular hydrogen as a therapeutic and preventive medical gas particularly for brain disorders; and hydrogenation technologies for the efficient and sustainable pharmaceutical production. Despite encouraging advancements widespread adoption remains limited by economic constraints regulatory gaps and limited clinical evidence. Addressing these barriers through technological innovation largescale studies and life-cycle sustainability assessments is essential to translate hydrogen’s full potential into clinical and industrial practice. Responsible adoption of green hydrogen is poised to reshape the clinical approach to global health and enhance the quality of life for people worldwide.

This study presents an experimental investigation of a direct injection ammonia-fuelled engine using hydrogen pre-chamber jet ignition. All tests have been conducted in an optically accessible combustion chamber that is installed in the head of a single-cylinder engine. The effect of ammonia injection timing on ignition and combustion characteristics was investigated with the timing varied from 165 CAD BTDC to 40 CAD BTDC. The experiments were conducted with a fixed spark timing of 14 CAD BTDC while ammonia injection duration was adjusted to maintain a main chamber global equivalence ratio of 0.6. Two pre-chamber nozzle configurations a single-hole and a multi-hole were tested. The results show that the later NH3 injection timing (40 CAD BTDC) significantly improved combustion with a peak in-cylinder pressure of 80 bar measured compared to a peak in-cylinder pressure of 50 bar with earlier injection (165 CAD BTDC). This study indicates the importance of optimising ammonia injection timing in order to enhance combustion stability and efficiency. The hydrogen pre-chamber jet ignition combined with a late ammonia injection is a promising approach for addressing the combustion challenges of ammonia as a zero-carbon fuel for maritime applications.

Underground hydrogen storage (UHS) is a relatively new technology that demonstrates notable potential for the efficient storage of large quantities of green hydrogen. Its large-scale implementation requires a comprehensive understanding of numerous factors including safe and effective storage methods as well as overcoming various thresholds and challenges. This article presents strategies for accelerating the implementation of this technology identifying the thresholds and challenges affecting the development and future scale-up of UHS. It characterises challenges and constraints related to geology (including the type and geological characterisation of structures hydrogen storage capacity and hydrogen interactions with underground environments) the technological aspects of hydrogen storage (such as infrastructure management and monitoring) and economic and legal considerations. The need for the rapid implementation of demonstration projects has been emphasised. The identified thresholds and challenges along with the resulting recommendations are crucial for paving the way for the large-scale implementation of UHS. Addressing these issues will significantly influence the implementation of this technology post-2030.

H2 is increasingly recognized as a cornerstone of global decarbonization strategies including in hard-toabate sectors such as aviation. Its large-scale applicability remains limited owing to the limited diversity and maturity of low-carbon production pathways. Approximately 96% of global H2 production originates from non-renewable sources primarily through steam methane reforming (SMR) which remains the most commercially established route. Another critical barrier to the substitution of conventional aviation fuels lies in hydrogen storage as the current volumetric energy density and cryogenic storage requirements render onboard integration impractical for most aircraft configurations. To address these challenges this study developed a techno-economic and environmental benchmarking framework that compares conventional thermal reforming technologies (SMR autothermal and POX) with emerging electrochemical routes (water electrolysis and alcohol electro-oxidation) highlighting their potential roles in the transition toward sustainable aviation fuels (SAF). By normalizing efficiency energy intensity CO2 emissions and cost (USD kg 1 H2 and USD GJ 1 ) this study quantifies the trade-offs that define current and emerging pathways. SMR remains the industrial baseline (70%–85% thermal efficiency 1–2 USD kg−1 H2 9–12 kg CO2 kg−1 H2) whereas ethanol-based electrochemical reforming operates 0.3–0.9 V below conventional electrolysis achieving up to 40% lower electrical energy demand (∼2.4 kW h Nm−3 H2 with near-zero direct emissions. A sensitivity analysis demonstrates that a 60% reduction in catalyst cost or electricity prices below 0.03 USD (kW h)−1 could make electrochemical reforming cost-competitive with SMR. This study consolidates fragmented knowledge into a comprehensive roadmap that links catalyst performance and technology readiness for aviation decarbonization by integrating engineering metrics with policy and infrastructure perspectives to identify realistic transition pathways toward sustainable hydrogen and hybrid aviation fuels.

Hydrogen handling equipment suffers from interaction with their operating environment which degrades the mechanical properties and compromises component integrity. Hydrogen-assisted cracking is responsible for several industrial failures with potentially severe consequences. A thorough failure analysis can determine the failure mechanism locate its origin and identify possible root causes to avoid similar events in the future. Postmortem fractographic analysis can classify the fracture mode and determine whether the hydrogen-metal interaction contributed to the component’s breakdown. Experts in fracture classification identify characteristic marks and textural features by visual inspection to determine the failure mechanism. Although widely adopted this process is time-consuming and influenced by subjective judgment and individual expertise. This study aims to automate fractographic analysis through advanced computer vision techniques. Different materials were tested in hydrogen atmospheres and inert environments and their fracture surfaces were analyzed by scanning electron microscopy to create an extensive image dataset. A pre-trained Convolutional Neural Network was finetuned to accurately classify brittle and ductile fractures. In addition Grad-CAM interpretability method was adopted to identify the image regions most influential in the model’s prediction and compare the saliency maps with expert annotations. This approach offered a reliable data-driven alternative to conventional fractographic analysis.

The recent updates to the Single Day-Ahead Coupling (SDAC) framework in the European energy market along with new rules for providing manual frequency restoration reserve (mFRR) products in the Nordic Energy Activation Market (EAM) have introduced a finer Market Time Unit (MTU) resolution. These developments underscore the growing importance of flexible assets such as power-to-hydrogen (PtH) facilities in delivering system flexibility. However to successfully participate in such markets well-designed and accurate bidding strategies are essential. To fulfill this aim this paper proposes a Mixed Integer Linear Programming (MILP) model to determine the optimal bidding strategies for a typical PtH facility accounting for both the technical characteristics of the involved technologies and the specific participation requirements of the mFRR EAM. The study also explores the economic viability of sourcing electricity from nearby wind turbines (WTs) under a Power Purchase Agreement (PPA). The simulation is conducted using a case study of a planned PtH facility at the Port of Hirtshals Denmark. Results demonstrate that participation in the mFRR EAM particularly through the provision of downward regulation can yield significant economic benefits. Moreover involvement in the mFRR market reduces power intake from the nearby WTs as capacity must be reserved for downward services. Finally the findings highlight the necessity of clearly defined business models for such facilities considering both technical and economic aspects.

For five decades photocatalysis has promised clean hydrogen from solar energy yet a persistent “efficiency ceiling” linked to fundamental challenges including the trade-off between light absorption and redox potential in single-component materials has hindered its practical application. This review illuminates three key paradigm shifts overcoming this challenge. First we examine Z-scheme and S-scheme heterojunctions which resolve the bandgap dilemma by spatially separating redox sites to achieve both broad light absorption and strong redox power. Second we discuss replacing the sluggish oxygen evolution reaction (OER) with value-added organic oxidations. This strategy bypasses kinetic bottlenecks and improves economic viability by co-producing valuable chemicals from feedstocks like biomass and plastic waste. Third we explore manipulating the reaction environment where synergistic photothermal effects and concentrated sunlight can dramatically enhance kinetics and unlock markedly enhanced solar-to-hydrogen (STH) efficiencies. Collectively these strategies chart a clear course to overcome historical limitations and realize photocatalysis as an impactful technology for a sustainable energy future.

China is developing renewable energy bases (REBs) in the desert and Gobi regions. However the intermittency of renewable energy and the temporal mismatch between peak renewable generation and peak load demand severely disrupt the power supply reliability of these REBs. Hydrogen storage technology characterized by high energy density and long-term storage capability is an effective method for enhancing the power supply reliability. Therefore this paper proposes a REB planning model in the desert and Gobi regions considering seasonal hydrogen storage introduction as well as electricity-carbon-hydrogen markets trading. Furthermore a combination scenario generation method considering extreme scenario optimization is proposed. Among which the extreme scenarios selected through an iterative selection method based on maximizing scenario divergence contain more incremental information providing data support for the proposed model. Finally the simulation was conducted in the desert and Gobi regions of Yinchuan Ningxia Province China primarily verifying that (1) the REB incorporating hydrogen storage can fully leverage hydrogen storage to achieve seasonal and long-term electricity transfer and utilization. The project has a payback period of 10 years with an internal rate of return of 13.30% and a return on investment of 16.34% thus showing significant development potential. (2) Compared to the typical battery-involved REB the hydrogen-involved energy storage facility achieved a 59.39% annual profit a 10.98% internal rate of return a 14.93% return on investment and a 1.51% improvement in power supply reliability by sacrificing a 52.49% increase in construction cost. (3) Compared to REB planning based only on typical scenarios the power supply reliability of REBs based on the proposed combination scenario generation method improved by 8.58%.

Hydrogen-rich gas (HRG) injection is a promising low-carbon solution for blast furnace ironmaking. This study conducted numerical simulations in the lower part of a blast furnace to analyze the combustion behavior of coinjected coke oven gas (COG) and pulverized coal (PC) within the raceway and the associated thermal load on the tuyere. A three-dimensional computational fluid dynamics model incorporating fluid–thermal–solid coupling and the GRI-Mech 3.0 chemical kinetic mechanism (validated for 300–2500 K) was established to simulate the lance–blowpipe–tuyere–raceway region. The simulation results revealed that moderate COG injection accelerated volatile release from PC and enlarged the high-temperature zone (>2000 K). However excessive COG injection intensified oxygen competition and shortened the residence time of PC ultimately decreasing the burnout rate. Notably although COG has high reactivity its injection did not cause an increase in tuyere temperature. By contrast the presence of an unburned gas layer near the upper wall of the tuyere and the existence of a strong convective cooling effect contributed to a reduction in tuyere temperature. An optimized cooling water channel was designed to enhance flow distribution and effectively suppress localized overheating. The findings of this study offer valuable technical insights for ensuring safe COG injection and advancing low-carbon steelmaking practices.

In northern China the long winter heating period is accompanied by severe wind curtailment. To address this issue a joint optimization scheduling strategy of electric vehicles (EVs) and electro–olefin–hydrogen electromagnetic energy supply device (EHED) is proposed to promote deep wind–solar integration. Firstly the feasibility analysis of EVs participating in scheduling is conducted and the operation models of dispatchable EVs and thermal energy storage EHEDs within the scheduling period are established. Secondly a control strategy for the joint optimization scheduling of wind–solar farms EVs EHEDs and power grid is constructed. Then an economic dispatch model for joint optimization of EVs and EHEDs is established to minimize the system operation cost within the scheduling period and the deep wind–solar integration of the joint optimization model is studied by considering EVs under different demand responses. Finally the proposed model is solved by CPLEX solver. The simulation results show that the established joint optimization economic dispatch model of EV-EHEDs can improve the enthusiasm of dispatchable EVs to participate in deep wind–solar integration reduce wind curtailment power and decrease the overall system operation cost.

Hydrogen leakage is a critical safety concern for high-pressure storage systems where orifice geometry significantly influences dispersion and risk. Previous studies on leakage and diffusion have mostly focused on closed or semi-closed environments while thorough exploration has been conducted on open and unshielded environments. This work compares three typical orifice types—circular slit and Y-type—through controlled experiments. Results show that circular orifices generate directional jets with steep gradients but relatively low concentrations with a 1 mm case reaching only 0.725% at the jet core. Slit orifices exhibit more uniform diffusion; at 1 mm concentrations ranged from 2.125% to 2.625%. Y-type orifices presented the highest hazard with 0.5 mm leaks producing 2.9% and 1 mm cases approaching the 4% lower flammability limit within 375 s. Equilibrium times increased with orifice size from 400–800 s for circular and slit leaks to up to 900 s for Y-type leaks some of which failed to stabilize. Response behavior also varied: Y-type leaks achieved rapid multi-point responses (as short as 10 s) while circular and slit leaks responded more slowly away from the jet core. Overall risk ranking was circular < slit < Y-type underscoring the urgent need for geometry-specific monitoring strategies sensor layouts and emergency thresholds to ensure safe hydrogen storage.

This paper proposes a hybrid-mode operation strategy for an offshore hydrogen-producing wind turbine (OHP-WT) capable of grid-following (GFL) and grid-forming (GFM) operation under both normal and low-voltage ride-through (LVRT) conditions. Unlike conventional centralized wind-to-hydrogen (W2H) schemes the proposed turbine-level architecture integrates W2H converters directly into the DC link of a three-level neutral-point-clamped converter. A supervisory power-sharing and mode-switch layer is developed above established GFL and GFM controls to coordinate active and reactive power regulation DC-link balancing and hydrogen-load management according to grid conditions. The proposed strategy is validated through detailed PLECS simulations and real-time hardware-in-the-loop experiments using identical parameters. Results show that the GFL mode achieves accurate power dispatch and shallow-fault LVRT compliance while the GFM mode maintains voltage and frequency stability under weak grid and severe-fault conditions. In all cases maximum-power-point tracking (MPPT) is preserved and hydrogen production continuously absorbs surplus power to stabilize the DC link. The findings demonstrate that the hybrid-mode OHP-WT enables transition between grid support and hydrogen production effectively reducing wind-power curtailment and enhancing offshore grid resilience.

Green hydrogen is essential for advancing the energy transition as it is regarded as a CO2-neutral flexible and storable energy carrier. Particularly in steel production which is known for its high energy intensity hydrogen has great potential to replace conventional energy sources. In a game-theoretic bi-level optimization model involving a power plant operator and a steel company we investigate in which situations the production and use of green hydrogen is advantageous from an economic and ecological point of view. Through an extensive case study based on a realworld scenario we can observe that hydrogen production can serve as a profitable and flexible secondary income opportunity for the power plant operator and help avoid curtailment and spot market losses. On the other hand the steel manufacturer can reduce CO2 emissions and associated costs while also meeting the growing customer demand for low-carbon products. However our findings also highlight important trade-offs and uncertainties. While lower electricity generation costs or improved electrolyzer efficiency enhance hydrogen’s competitiveness increases in coal and CO2 emission prices do not always result in greater hydrogen adoption. This is due to the persistent reliance on a non-replaceable share of coal in steel production which raises the overall cost of both low-carbon and carbon-intensive steel. The model further shows that consumer demand elasticity plays a critical role in determining hydrogen uptake. These insights underscore the importance of not only reducing hydrogen costs but also designing supportive policies that address market acceptance and the full cost structure of green industrial products.

A comprehensive understanding of consumer preferences and demand factors is essential for successfully implementing demand-side strategies for alternative energy solutions such as hydrogen. This study aims to identify the key determinants influencing the adoption propensity for Hydrogen fuel cell vehicles (HFCVs) in the Kingdom of Saudi Arabia (KSA). Developing a conceptual framework to organise the key factors influencing consumers’ decisions to adopt or reject this technology. Using data from an online survey of 384 prospective customers we employed structural equation modelling (SEM) via Smart-PLS 4.1 to analyze consumer intent. The findings reveal that perceived benefits barriers opinions and governmental initiatives have a significant impact on the likelihood of HFCV adoption. The study emphasises the significance of collaborative efforts among key stakeholders including manufacturers hydrogen producers research institutions and financial entities in addressing challenges and advancing the development of the hydrogen transportation ecosystem in KSA. Financial incentives and subsidies such as purchasing subsidies awareness and reduced registration costs for HFCVs may be instituted.

With the growing significance of hydrogen in the global energy transition research on its pricing mechanisms has become increasingly crucial. Focusing on hydrogen markets predominantly supplied by electrolytic production this study proposes a nodal marginal hydrogen price decomposition algorithm that explicitly incorporates the time-delay dynamics inherent in hydrogen transmission. A four-dimensional price formation framework is established comprising the energy component network loss component congestion component and time-delay component. To address the nonconvex optimization challenges arising in the market-clearing model an improved second-order cone programming method is introduced. This method effectively reduces computational complexity through the reconstruction of time-coupled constraints and reformulation of the Weymouth equation. On this basis the analytical expression of the nodal marginal hydrogen price is rigorously derived elucidating how transmission dynamics influence each price component. Empirical studies using a modified Belgian 20-node system demonstrate that the proposed pricing mechanism dynamically adapts to load variations with hydrogen prices exhibiting a strong correlation with electricity cost fluctuations. The results validate the efficacy and superiority of the proposed approach in hydrogen energy market applications. This study provides a theoretical foundation for designing efficient and transparent pricing mechanisms in emerging hydrogen markets.

The operational optimization of industrial boilers utilizing hydrogen-enriched natural gas is constrained by two critical gaps: insufficient understanding of the coupled effects of hydrogen blending ratio equivalence ratio and boiler load on combustion performance— compounded by unresolved challenges of combustion instability flashback and elevated NOx emissions—and a lack of systematic investigations combining these parameters in industrial-scale systems (prior studies often focus on single variables like hydrogen fraction). To address this a comprehensive computational fluid dynamics (CFD) analysis was conducted on a 2.1 MW industrial boiler employing the Steady Laminar Flamelet Model (SLFM) with a modified k-ε turbulence model and the GRI-Mech 3.0 mechanism. Simulations covered hydrogen fractions (f(H2) = 0–25%) equivalence ratios (Φ = 0.8–1.2) and load conditions (15–100%). All NOx emissions reported herein are normalized to 3.5% O2 (mg/Nm3 ) for regulatory comparison. Results show that increasing the hydrogen content raises the flame temperature and NOx emissions while reducing CO and unburned hydrocarbons; a higher equivalence ratio elevates temperature and NOx with Φ = 0.8 balancing efficiency and emission control; and reducing load significantly lowers furnace temperature and NO emissions. Notably the boiler’s unique staged-combustion configuration (81% fuel supply to the central rich-combustion nozzle 19% to the concentric lean-combustion nozzle) was found to mitigate NOx formation by 15–20% compared to single-inlet burner designs and its integrated cyclone blades (generating maximum swirling velocity of 14.2 m/s at full load) enhanced fuel–air mixing which became particularly critical for maintaining combustion stability at low loads (≤20%) and high hydrogen blending ratios (≥20%). This study provides quantitative trade-off insights between combustion efficiency and pollutant formation offering actionable guidance for the safe efficient operation of hydrogen-enriched natural gas in industrial boilers.

This study investigates the combustion process in a marine spark-ignition engine fueled with an ammonia–hydrogen blend (15% hydrogen by volume) using a passive pre-chamber. A 3D-CFD model supported by a 1D engine model was employed to analyze equivalence ratios between 0.7 and 0.9 and pre-chamber nozzle diameters from 7 to 3 mm. Results indicate that combustion is consistently initiated by turbulent jets but at an equivalence ratio of 0.7 the charge combustion is incomplete. For lean mixtures reducing nozzle size improves flame propagation although not sufficiently to ensure stable operation. At an equivalence ratio of 0.8 reducing the nozzle diameter from 7 to 5 mm advances CA50 by about 6 CAD while further reduction causes minor variations. At richer conditions nozzle diameter plays a negligible role. Optimal performance was achieved with a 7 mm nozzle at equivalence ratio 0.8 delivering about 43% efficiency and 1.17 MW per cylinder.

The hydrogen energy industry is rapidly developing positioning hydrogen refueling stations (HRSs) as critical infrastructure for hydrogen fuel cell vehicles. Within these stations hydrogen compressors serve as the core equipment whose performance and reliability directly determine the overall system’s economy and safety. This article systematically reviews the working principles structural features and application status of mechanical hydrogen compressors with a focus on three prominent types based on reciprocating motion principles: the diaphragm compressor the hydraulically driven piston compressor and the ionic liquid compressor. The study provides a detailed analysis of performance bottlenecks material challenges thermal management issues and volumetric efficiency loss mechanisms for each compressor type. Furthermore it summarizes recent technical optimizations and innovations. Finally the paper identifies current research gaps particularly in reliability hydrogen embrittlement and intelligent control under high-temperature and high-pressure conditions. It also proposes future technology development pathways and standardization recommendations aiming to serve as a reference for further R&D and the industrialization of hydrogen compression technology.

The gradual exhaustion of fossil fuel reserves along with the adverse effects of their consumption on global climate drives the need for research into alternative energy sources that can meet the growing demand in a sustainable and eco-friendly way. Among these hydrogen stands out as one of the most promising options for the automotive sector being the cleanest available fuel and capable of being produced from renewable resources. This paper reviews the existing literature on compression ignition engines operating in a dualfuel configuration where diesel serves as the ignition source and hydrogen is used to enhance the combustion process. The reviewed studies focus on engine systems with hydrogen injection into the intake manifold. The investigations analyzed the influence of hydrogen energy fraction on combustion characteristics engine performance combustion stability and exhaust emissions in diesel/hydrogen dual-fuel engines operating under full or near-full-load conditions. The paper identifies the main challenges hindering the widespread and commercial application of hydrogen in diesel/hydrogen dual-fuel engines and discusses potential methods to overcome the existing barriers in this area.

Fuel cells are highly efficient electrochemical devices that convert the chemical energy of fuel directly into electrical energy while generating minimal pollutant emissions. In recent decades they have established themselves as a key technology for sustainable energy supply in the transport sector stationary systems and portable applications. In order to assess their real contribution to environmental protection and energy efficiency a comprehensive analysis of their life cycle Life Cycle Assessment (LCA) is necessary covering all stages from the extraction of raw materials and the production of components through operation and maintenance to decommissioning and recycling. Particular attention is paid to the environmental challenges associated with the extraction of platinum catalysts the production of membranes and waste management. Economic aspects such as capital costs the price of hydrogen and maintenance costs also have a significant impact on their widespread implementation. This manuscript presents detailed mathematical models that describe the electrochemical characteristics energy and mass balances degradation dynamics and cost structures over the life cycle of fuel cells. The models focus on proton exchange membrane fuel cells (PEMFCs) with possible extensions to other types. LCA is applied to quantify environmental impacts such as global warming potential (GWP) while the levelized cost of electricity (LCOE) is used to assess economic viability. Particular attention is paid to the sustainability challenges of platinum catalyst extraction membrane production and end-of-life material recovery. By integrating technical environmental and economic modeling the paper provides a systematic perspective for optimizing fuel cell deployment within a circular economy.

Integrated Energy Systems (IESs) which leverage the synergistic coordination of electricity heat and gas networks serve as crucial enablers for a low-carbon transition. Current research predominantly treats energy storage as a subordinate resource in dispatch schemes failing to simultaneously optimise IES economic efficiency and storage operators’ profit maximisation thereby overlooking their potential value as independent market entities. To address these limitations this study establishes an operator-autonomous management framework incorporating electrical thermal and hydrogen storage in IESs. We propose a joint optimal dispatch model for hybrid energy storage systems in low-carbon IES operation. The upper-level model minimises total system operation costs for IES operators while the lower-level model maximises net profits for independent storage operators managing various storage assets. These two levels are interconnected through power price and carbon signals. The effectiveness of the proposed model is verified by setting up multiple scenarios for example analysis.

The effect of tempering temperature and tempering time on the density of hydrogen traps hydrogen diffusivity and microhardness in a vanadium-modified AISI 4140 martensitic steel was determined. Tempering parameters were selected to activate the second third and fourth tempering stages. These conditions were intended to promote specific microstructural transformations. Permeability tests were performed using the electrochemical method developed by Devanathan and Stachurski and microhardness was measured before and after these tests. It was observed that hydrogen diffusivity is inversely proportional to microhardness while the density of hydrogen traps is directly proportional to microhardness. The lowest hydrogen diffusivity the highest trap density and the highest microhardness were obtained in the as-quenched condition and the tempering at 286 ◦C for 0.25 h. In contrast tempering at a temperature corresponding to the fourth tempering stage increases hydrogen diffusivity and decreases the density of hydrogen traps and microhardness. However as the tempering time or temperature increases the opposite occurs which is attributed to the formation of alloy carbides. Finally hydrogen has a softening effect for tempering temperatures corresponding to the fourth tempering stage tempering times of 0.25 h and in the as-quenched condition. However with increasing tempering time hydrogen has a hardening effect.

The growing demand for green hydrogen is driving the expansion of water electrolysis. The resulting oxygen byproduct offers potential added value when used in sectors with high oxygen demand such as wastewater treatment. This study investigates the techno-economic viability of using electrolysis oxygen to supplement conventional air blowers in the aeration process of municipal wastewater treatment plants (WWTPs) to reduce aeration costs and thereby improve the overall economics of hydrogen production. A comprehensive system model is developed incorporating renewable electricity supply water electrolysis hydrogen compression storage and transport as well as WWTP aeration via conventional air blowers and electrolysis oxygen. Results show that electrolysis oxygen can reduce WWTP aeration costs by up to 68%. If these cost reductions are attributed as a benefit to the hydrogen system they correspond to hydrogen supply cost savings of up to 0.39 EUR/kgH2. However the analysis indicates that economic viability is substantially influenced by factors such as the distance of hydrogen transport from the WWTP to the European Hydrogen Backbone feed-in point which should not exceed 25 km and the alignment between the scale of hydrogen production and the size of the WWTP with cost-effective integration being particularly feasible for larger WWTPs (≥500000 PE).

Hybrid renewable energy systems (HRESs) are an effective tool for addressing the challenges of rural electrification in sub-Saharan Africa (SSA). However their viability is limited by the lifespan environmental impacts high costs and inefficiency of conventional energy storage technologies (battery and pumped-hydro). This study examines a hydrogen-based energy storage system combined with photovoltaic (PV) and wind energy for the electrification of Dargalla a village in northern Cameroon. The goal is to meet community and agricultural electricity needs while optimizing the system. The analysis utilized HOMER software to simulate model and optimize the system. The optimal architecture consisted of a 50-kW photovoltaic (PV) array a 10-kW wind turbine a 10-kW fuel cell a 30-kW electrolyser a 25-kg hydrogen tank and a 10-kW converter. The optimised system’s net present cost and cost of energy were assessed at USD 138202 and USD 0.443/kWh respectively. Sensitivity analysis results showed that areas with high wind speeds would be mainly suitable for the proposed system. Moreover with the upcoming decrease in the costs of fuel cells and PV components such systems are expected to become more economically viable in the future leading to the conclusion that integration of hydrogen-based energy storage technology in HRESs in SSA can effectively address the United Nations Sustainable Development Goals (UNSDG) and the historic Paris Climate Agreement (HCA).

In order to assess the decarbonization potential and overall environmental benefits of new reduction pathways in the ironmaking industry using hydrogen to produce Direct Reduced Iron (DRI) a coupled approach combining process simulation for rigorous technical and energy evaluation of iron ore conversion and Life Cycle Assessment (LCA) for environmental assessment was developed and extended to two alternative renewable heating strategies: (i) electric gas heating and (ii) solar reactor heating. The entire hydrogen-based ironmaking process including conversion in a shaft reactor gas and solid heating gas recycling and electrolysis was therefore simulated. The hydrogen-based reduction of iron ores in the shaft reactor was modeled using a rigorous reactor model describing the reduction of multi-layer iron ore pellets in countercurrent gas–solid moving beds with the particularity of representing the dual influence of particle size and temperature on conversion. The remainder of the process including gas recycling and hydrogen production was simulated using ProSim software. The hydrogen-based green ironmaking scenarios were then compared to MIDREX NG a leading natural gas-based reduction technology. Hydrogen-based scenarios powered by the French electricity mix reduce carbon footprints by 53 % for electric gas heating and 57 % for solar reactor heating potentially reaching 82 % (− 0.79 kgCO2-eq/kgDRI) with low-carbon electricity (hydro nuclear). Compared to MIDREX NG the energy requirements of both hydrogen-based scenarios are primarily determined by the use of electricity for hydrogen production illustrating the importance of hydrogen production for the assessment of future hydrogen-based green ironmaking.

Developing green hydrogen energy can alleviate the problem of CO2 emissions caused by excessive use of fossil fuels. In-situ capture of CO2 for enhanced H2 production in zero-carbon energy biomass-H2O gasification can achieve the dual effects of green H2 production and negative carbon. The study used red mud (RM) to modify CaO and prepare dual-functional materials (DFMs). And the in-situ CO2 capture enhanced H2 production and regeneration cycle performance of DFMs in biomass-H2O gasification were studied and the influence of biomass ash on the H2 production and low-temperature (650 ◦C) regeneration performance of DFMs in the cycle was analyzed. The results are as follows: In DFMs catalyzed biomass-H2O gasification due to the continuous deposition of alkali and alkaline earth metals (AAEMs) in biomass ash with increasing cycle times its catalytic effect increased H2 production by 27 % after twenty cycles and the pore structure degradation and cycle stability of DFMs decreased by 44.71 %. DFMs have demonstrated excellent catalytic performance and cycling stability in the catalytic removal of ash from biomass. After twenty cycles the production of H2 only decreased by 20.59 % and the performance of CaO decreased by 26.67 % demonstrating the enormous potential of DFMs for in-situ CO2 capture and enhanced H2 production.

Climate-change mitigation in North America demands rapid deep cuts in carbon-dioxide emissions from hard-toabate industrial power-generation and transport sectors. Carbon capture and storage (CCS) is one of the few technological routes that can decouple continued use of fossil-derived energy and materials from their climate externalities. Yet deployment across the US and Canada still trails the scale implied by regional net-zero pledges. This review addresses that gap by synthesizing technical economic policy and social dimensions of CCS and complements global syntheses with a granular assessment of North America’s unique emission profile infrastructure advantages and regulatory frameworks. Methodologically the review disaggregates the CCS chain into six pillars: (i) current emission baselines; (ii) capture systems icluding post- pre- and oxy-combustion chemical-looping combustion (CLC) and direct air capture (DAC); (iii) capture technologies (e.g. absorption adsorption membrane cryogenic and hybrid processes); (iv) storage pathways (geological oceanic and emerging biological or mineral options); (v) cross-cutting economic policy and social factors; and (vi) deployment status plus future outlook. Post-combustion capture remains the most retrofit-ready option for the region’s ageing coal and gas fleet yet solvent regeneration still imposes energy penalties of 8–10 percentagepoints. Pre-combustion and oxy-fuel routes offer thermodynamic advantages for new-build plants but require high-capex gasifiers or cryogenic air separation units slowing adoption. Emerging CLC and DAC concepts could unlock low-carbon fuels and negative emissions respectively but remain costly and pre-commercial. No single technology meets all performance criteria making hybrid configurations—such as membrane–cryogenic or membrane–amine schemes—particularly promising. North America’s subsurface offers multi-teratonne theoretical storage capacity in saline formations depleted hydrocarbon reservoirs and CO2-EOR sites suggesting physical room is not the bottleneck. Instead economics dominate: levelized capture costs today range from around $15/tCO2 in natural-gas processing to over $120/t in power and cement and long-distance pipeline networks are sparse outside existing enhanced oil recovery (EOR) corridors. Recent federal incentives can shift project economics decisively yet policy volatility and permitting hurdles still threaten investment certainty. Societal acceptance emerges as another critical lever. Surveys reveal generally favorable attitudes toward CCS in principle but heightened opposition to local storage projects. Transparent monitoring–verification frameworks benefit-sharing mechanisms and durable bipartisan policies are therefore essential to secure a “social licence” for large-scale CO2 injection. This review concludes that widescale CCS in North America is technically feasible and increasingly cost-competitive when paired with robust incentives abundant storage capacity and existing pipeline know-how. Realizing its full mitigation potential will hinge on coordinated build-out of transport networks harmonized federal–provincial regulations continued R&D into low-energy capture materials and integrated assessments that weigh CCS alongside renewables efficiency and negative-emission strategies. The roadmap presented herein provides stakeholders with actionable insights to accelerate that transition positioning North America as both a proving ground and a global exemplar for scalable responsibly governed CCS.

The management of sewage sludge presents a pressing environmental and economic challenge due to its increasing global production and complex hazardous composition. Gasification offers a viable method for converting this waste into valuable energy resources. This study investigates whether integrating experimental and computational techniques can enhance the understanding and optimization of sludge gasification. Two types of sewage sludge SSG from Rethymno and SSD from Dubai were evaluated using an entrained flow gasifier under controlled thermal and flow conditions. The methodology combines equilibrium modeling computational fluid dynamics (CFD) drop tube reactor (DTR) experiments and artificial neural network (ANN) modeling. The ANN was combined with Kissinger analysis to obtain kinetics from the ANN outputs and derive thermodynamic parameters used to enhance CFD fidelity. Gas composition analysis and scanning electron microscopy (SEM) revealed that SSD decomposes more easily with a lower activation energy (42.29–138.31 kJ/mol) and a lower Gibbs free energy. In contrast SSG demonstrated greater thermal stability and reactivity. SSG achieved consistently higher cold gas efficiency (CGE) reaching 53.66 % in equilibrium modeling 45.50 % in CFD and 38.90 % in experiments compared to SSD’s 48.86 % 37.81 % and 31.19 % respectively. SEM imaging confirmed an increase in porosity and surface area for SSG after gasification. These results indicate that the type of sludge has a significant impact on energy recovery and that ANN-calibrated thermokinetics and CFD enhance process predictability. This integrated method scales hydrogen generation and promotes sustainable waste-toenergy technology.

Underground hydrogen storage (UHS) represents a large-scale energy storage system aiming to ensure a consistent supply by storing hydrogen generated from surplus energy. In the practice of UHS cushion gas is typically injected into the formation to maintain reservoir pressure for efficient hydrogen withdrawal. This paper reviews the impact of cushion gas on the performance of UHS from both experimental and numerical simulation perspectives. The thermophysical (e.g. density viscosity compressibility and solubility) and petrophysical (interfacial tension wettability and relative permeability) properties as well as the mixing and diffusion behavior of different cushion gases were compared. The corresponding impact of different cushion gases on plume migration and trapping potential is then discussed. Furthermore this review critically analyzes and explains the impact of various factors on the performance of UHS including the type of cushion gas the composition of cushion gas mixtures the volume of injected cushion gas and the effects of bio-methanation processes. The corresponding analysis specifically focuses on key performance indicators including H2 recovery factor formation pressure brine production and H2 outflow purity. Thus this review provides a comprehensive analysis of the role of cushion gas in UHS offering insight into the effective management and optimization of cushion gas injection in field-scale UHS operations.

This study investigates the potential of green hydrogen production from small and large-scale photovoltaic water electrolysis systems under tropical climate conditions with particular emphasis on the Levelized Cost of Hydrogen (LCOH) in Santo Domingo Dominican Republic. The hydrogen production system was developed using MATLAB/SIMULINK R2023b. The system simulation incorporates a commercial proton exchange membrane (PEM) electrolyzer driven by a DC/DC converter is also evaluated under varying environmental scenarios based on real meteorological data for temperature and solar irradiance. Dynamic simulations were performed to analyze the relationship between solar resource availability and hydrogen production. Results indicate that at small-scale 3.68 kWp PV + 0.017 kW PEM LCOH is 104.52 USD/kg for PV-only compared to 17.09 USD/kg for a grid sourced electricity case. At large-scale 100 MWp PV + 60 MWe PEM LCOH falls to 7.05 USD/kg under PVonly operation Utilization factor Uf = 0.31 and 3.61 USD/kg with grid supplied backup Uf = 0.85 illustrating the massive cost reduction achievable through economies of scale. Model validation showed a high degree of accuracy with an average percentage error of 1.41 % when comparing simulated and manufacturer provided parameters curves. A comparative carbon footprint analysis demonstrated the environmental advantages of PV driven hydrogen production over conventional fossil fuels methods. These findings are especially relevant for such climates and support the advancement of Sustainable Development Goals 7 and 13 positioning green hydrogen as a key vector for the clean energy transition.

The accelerating global demand for hydrogen is pushing for renewable and waste derived hydrogen production processes where date palm waste (DPW) has been identified as an available and unexploited agricultural residue that has the potential to be a sustainable source of hydrogen. The current work focuses on developing and evaluating four different process configurations in terms of energy environment and economics for producing hydrogen from DPW using Aspen Plus® simulation tool. Case 1 represents the standalone DPW gasification with CO₂ capture via methanol absorption Case 2 represents the DPW gasification with CaO-based chemical looping for CO₂ capture Case 3 represents the DPW gasification integrated with steam methane reforming (SMR) and methanol-based CO₂ capture and Case 4 represents the DPW gasification integrated with SMR and CaO-based CO₂ capture. Each case was evaluated in terms of syngas composition hydrogen production lower heating value CO₂ captured utility demand process efficiency and H2 production cost. Hydrogen production ranged from 974.55 t/year (Case 1) and 988.83 t/year (Case 2) to 2032.32 t/year (Case 3) and 2048.61 t/year (Case 4). CO₂ capture was also more effective in Case 4 (16929.49 t/year) compared to Case 1 (7676.30 t/year). Process efficiency improved from 33 % in Case 1 to 47 % in Case 2 and from 32 % in Case 3 to further to 55 % in Case 4. Economically Case 1 offered the highest hydrogen production cost ($5.03/kg) followed by Case 2 ($4.77/kg) while Case 3 and Case 4 achieved significantly lower production costs of $2.89/kg and $2.69/kg respectively.

The application of OH* chemiluminescence diagnostics is becoming increasingly prevalent in the combustion characterization of hydrogen. As the current literature is lacking a systematic study of OH* chemiluminescence in non-premixed turbulent natural gas (NG) and hydrogen (H2 ) flames the present work was designed to address this research gap. Therefore extensive experiments were performed on a semi-industrial burner operating at 50–100 kW in NG/H2–Air/O2 combustion modes which were complemented by comprehensive numerical simulations including 1D laminar counterflow diffusion flamelet calculations and full 3D CFD simulations of the semi-industrial furnace setup. In this way an OH* chemistry model is presented that accurately predicts the global reaction zone characteristics and their difference between CH4 and H2 in air-fired and oxygen-fired flames. The comprehensive numerical approach in conjunction with the subsequent study of different operating conditions yielded novel insights into both combustion modeling and the underlying thermochemical phenomena providing an essential contribution to the transition of the thermal energy sector towards hydrogen as an alternative carbon-free fuel.

This study presents a comparative life cycle and economic assessment of using clean hydrogen as a sustainable alternative to natural gas and propane for corn grain drying. The study compares the environmental performance limited to GWP100 and cost-effectiveness of hydrogen from various renewable sources (hydro wind solar) and plasma pyrolysis of natural gas against conventional fossil fuels under two delivery scenarios: pipeline and trucking. A life cycle assessment is conducted using Open LCA to quantify the carbon intensity of each fuel from cradle to combustion at multiple energy requirements based on four burner efficiencies across each scenario. In parallel economic analysis is conducted by calculating the fuel cost required per ton of dried corn grains at each efficiency across both scenarios. The results indicate that green hydrogen consistently outperforms current fuels in terms of emissions but it is generally more expensive at lower burner efficiencies and in trucking scenarios. However the cost competitiveness of green hydrogen improves significantly at higher efficiency and with pipeline infrastructure development it can become more economical when compared to propane. Hydrogen produced via plasma pyrolysis offers high environmental and economic costs due to its electricity and natural gas requirements. Sensitivity analysis further explores the impact of a 50% reduction in hydrogen production and transportation costs revealing that hydrogen could become a viable option for grain drying in both pipeline and trucking scenarios. This study highlights the long-term potential of hydrogen in reducing carbon emissions and offers insights into the economic feasibility of hydrogen adoption in agricultural drying processes. The findings suggest that strategic investments in hydrogen infrastructure could significantly enhance the sustainability of agricultural practices paving the way for a greener future in food production.

Separation of H2 from CO2 is crucial in industry since they are the products of water gas shift reaction. In addition the demand for pure H2 as well as the potential reuse of CO2 as reactant are increasing as a consequence of the transition from fossil fuels to decarbonization processes. In this scenario this work aims to propose a possible solution to get simultaneously pure H2 and CO2 meeting the world’s requirements in terms of reduction of CO2 emissions and transition to cleaner energy. A simulated plant combining Pd-based and SAPO-34 membrane modules is able to provide pure H2 with a final recovery higher than 97%. In addition the entire CO2 fed to SAPO-34 unit is recovered in the permeate stream with a concentration of 97.7%. A cost analysis shows that feed gas gives a higher contribution than compression heat exchange and membranes (e.g. 70 20 3 and 7% respectively). Net profit and net present value are positive within a specific feed gas price range (e.g. net profit up to 0.10 and 0.155 $/Nm3 depending on the labour cost set) showing that the process can be cost-effective and profitable. H2 purification cost ranges between 2.6 and 7.8 $/kg.

This article discusses the potential of using the double-Wiebe function to model combustion in a compression-ignition engine fueled by diesel fuel or its substitutes such as hydrotreated vegetable oil (HVO) and rapeseed methyl ester (RME) and hydrogen injected into the engine intake manifold. The hydrogen amount ranged from 0 to 35% of the total energy content of the fuels burned. It was found that co-combustion of liquid fuel with hydrogen is characterized by two distinct combustion phases: premixed and diffusion combustion. The premixed phase occurring just after ignition is characterized by a rapid combustion rate which increases with an increase in hydrogen injected. The novelty in this work is the modified formula for a double-Wiebe function and the proposed parameters of this function depending on the amount of hydrogen added for co-combustion with liquid fuel. To model this combustion process the modified double-Wiebe function was proposed which can model two phases with different combustion rates. For this purpose a normalized HRR was calculated and based on this curve coefficients for the double-Wiebe function were proposed. Satisfactory consistency with the experiment was achieved at a level determined by the coefficient of determination (R-squared) of above 0.98. It was concluded that the presented double-Wiebe function can be used to model combustion in 0-D and 1-D models for fuels: RME and HVO with hydrogen addition.

Contemporary research into decarbonized fuels such as H2/NH3 has highlighted complex challenges with applied combustion with marked changes in thermochemical properties leading to significant issues such as limited operational range flashback and instability particularly when attempts are made to optimize emissions production in conventional lean-premixed systems. Non-premixed configurations may address some of these issues but often lead to elevated NOx production particularly when ammonia is retained in the fuel mixture. Optimized fuel injection and blending strategies are essential to mitigate these challenges. This study investigates the application of a 75 %/25 %mol H2/NH3 blend in a swirl-stabilized combustor operated at elevated conditions of inlet temperature (500 K) and ambient pressure (0.11–0.6 MPa). A complex nonmonotonic relationship between swirl number and increasing ambient combustor pressure is demonstrated highlighting the intricate interplay between swirling flow structures and reaction kinetics which remains poorly understood. At medium swirl (SN = 0.8) an increase in pressure initially reduces NO emissions diminishing past ~0.3 MPa with an opposing trend evident for high swirl (SN = 2.0) as NO emissions fall rapidly when combustor pressure approaches 0.6 MPa. High-fidelity numerical modeling is presented to elucidate these interactions in detail. Numerical data generated using Detached Eddy Simulations (DES) were validated against experimental results to demonstrate a change in flame anchoring on the axial shear layer and marked change in recirculated flow structure successfully capturing the features of higher swirl number flows. Favorable comparisons are made with optical data and a reduction in NO emissions with increasing pressure is demonstrated to replicate changes to the swirling flame chemical kinetics. Findings provide valuable insights into the combustion behavior of hydrogen-rich ammonia flames contributing to the development of cleaner combustion technologies.

Energy transition is crucial for climate change mitigation and Sustainable Development Goals (SDGs) and has been a key government focus in Colombia since 2022 which must carefully consider its energy roadmap. This study evaluates three potential scenarios for achieving nearly 100% renewable energy by 2035: replacing fossil fuels with biofuels using hydrogen for transport and industrial heat and relying entirely on renewable electricity. This paper discusses these scenarios’ technical economic and social challenges including the need for substantial investments in renewable energy technologies and energy storage systems to replace fossil fuels. The discussion highlights the importance of balancing energy security environmental concerns and economic growth while addressing social priorities such as poverty eradication and access to healthcare and education. The results show that while the Colombian government’s energy transition goals are commendable a rapid energy transition requires 4 to 8 times the government’s projected 34 billion USD investment making it economically unfeasible. Notably focusing on wind photovoltaic and green hydrogen systems which need storage is too costly. Furthermore replacing fossil fuels in transport is impractical though increasing biofuel production could partially substitute fossil fuels. Less energy-intensive alternatives like trains and waterway transport should be considered to reduce energy demand and carbon footprint.

While renewable energy deployment has accelerated in recent years fossil fuels continue to play a dominant role in electricity generation worldwide. This necessitates the development of transitional strategies to mitigate greenhouse gas emissions from this sector while gradually reducing reliance on fossil fuels. This study investigates the potential of blending green hydrogen with natural gas as a transitional solution to decarbonize Jordan’s electricity sector. The research presents a comprehensive techno-economic and environmental assessment evaluating the compatibility of the Arab Gas Pipeline and major power plants with hydrogen–natural gas mixtures considering blending limits energy needs environmental impacts and economic feasibility under Jordan’s 2030 energy scenario. The findings reveal that hydrogen blending between 5 and 20 percent can be technically achieved without major infrastructure modifications. The total hydrogen demand is estimated at 24.75 million kilograms per year with a reduction of 152.7 thousand tons of carbon dioxide per annum. This requires 296980 cubic meters of water per year equivalent to only 0.1 percent of the National Water Carrier’s capacity indicating a negligible impact on national water resources. Although technically and environmentally feasible the project remains economically constrained requiring a carbon price of $1835.8 per ton of carbon dioxide for economic neutrality.

The urgent need to mitigate climate change has elevated green hydrogen as a sustainable alternative to fossil fuels while green cryptocurrencies have emerged to address the environmental concerns of traditional cryptocurrency mining. This study investigates the dynamic correlation between the green hydrogen market and selected green cryptocurrencies (Cardano Stellar Hedera Algorand and Chia) from July 2021 to April 2024 utilizing the Dynamic Conditional Correlation GARCH (DCC-GARCH) model with robustness checks using EGARCH and GJR-GARCH specifications. Our findings reveal significant correlations with peaks reaching up to 50% in 2022 a period likely influenced by the Russia-Ukraine conflict. Subsequently a decline in these correlations was observed in 2023. These results underscore the interconnectedness of sustainability-driven markets suggesting potential contagion effects during periods of global instability. The high persistence of correlation shocks (α + β values approaching unity) indicates that correlation regimes tend to be long- lasting with important implications for portfolio diversification and risk management strategies. Robustness checks using EGARCH and GJR-GARCH specifications confirmed qualitatively similar patterns reinforcing the validity of our findings into the evolving landscape of green finance and energy

The transport of natural gas blended with hydrogen is a key strategy for the low-carbon energy transition. However the influence mechanism of its thermo-physical property variations on centrifugal compressor performance remains insufficiently understood. This study systematically investigates the effects of the hydrogen blending ratio (HBR 0–30%) inlet temperature and rotational speed on key compressor parameters (pressure ratio polytropic efficiency and outlet temperature) through numerical simulations. In order to evaluate the influence of hydrogen blending on the performance and stability of centrifugal compressors a three-dimensional model of the compressor was established and the simulation conducted was verified with the experimental data. Results indicate that under constant inlet conditions both the pressure ratio and outlet temperature decrease with increasing HBR while polytropic efficiency remains relatively stable. Hydrogen blending significantly expands the surge margin shifting both surge and choke lines downward and consequently reducing the stable operating range by 27.11% when hydrogen content increases from 0% to 30%. This research provides theoretical foundations and practical guidance for optimizing hydrogen-blended natural gas centrifugal compressor design and operational control.