Publications

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.

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.