Institution of Gas Engineers & Managers

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.