The growing global demand for electrical energy and the necessity for decarbonization highlight the importance of assessing the rational use of renewable resources and energy. Thus, this study examined the energy and exergy performance of two offshore wind energy destinations and conversions in Brazil: (i) storage in chemical bonds of hydrogen and ammonia for export and (ii) direct use of electrical energy in the Brazilian National Interconnected System (SIN). The method was based on an integrated exergy analysis, complemented by indicators such as Energy Return on Energy Investment (EROI), considering the entire production chain: seawater desalination, electrolysis, cryogenic air separation, ammonia synthesis and transport, and the electrical energy pathway through the SIN grid. The results demonstrated that the conversion and transport of ammonia lead to lower efficiencies, greater exergy losses, and lower EROI, whereas the direct use of electrical energy through the integrated system proved to be more efficient, with higher EROI and lower exergy losses. From a public policy perspective, the findings suggest that prioritizing hydrogen and ammonia production for export may result in the externalization of the main exergy and decarbonization benefits associated with their final use. The results therefore highlight the importance of aligning emerging hydrogen strategies with domestic decarbonization priorities, particularly by prioritizing the use of hydrogen and its derivatives in hard-to-abate sectors of the Brazilian economy.
The World Bank’s Lighthouse Strategy identifies Morocco as a first mover exporter of green hydrogen and its derivatives to Europe; however, the engineering feasibility of the associated transport and storage network has not been quantitatively demonstrated. This study addresses that gap through an integrated spatial and multiperiod optimization framework that couples a spatially explicit Mixed Integer Linear Programming (MILP) model with a FlexSim/FloWorks digital twin for discrete event and hydraulic simulation. The MILP simultaneously optimizes electrolysis deployment, hydrogen storage technologies, and multimodal transport across a four node Moroccan export corridor (TanTan, Mohammedia, Jorf Lasfar, and Tanger Med) for the 2030, 2040, and 2050 planning horizons under a net present value objective. The optimal configuration combines a dedicated hydrogen backbone pipeline for the high volume production corridor with shortsea cabotage for the distribution branches, achieving a full chain levelized cost of ammonia (LCOA) of 1176 USD/t, consistent with the World Bank benchmark and reducing costs by 57 USD/t compared with an all cabotage configuration. The optimal network remains robust over a wide range of capital cost and financing assumptions, while the digital twin confirms the hydraulic and operational feasibility of the integrated pipeline–shipping system without critical port congestion. These findings demonstrate that combining optimization with digital twin validation provides a robust engineering basis for planning Morocco’s green hydrogen export infrastructure and supports investment decisions aligned with future CBAM compliant hydrogen and ammonia supply chains.
Green hydrogen production through water electrolysis is a key pathway to the decarbonization of future energy systems. However, part of the electrical input is transformed into waste heat. In this study, alkaline, proton-exchange membrane, anion-exchange membrane, and solid oxide electrolysis systems are compared in terms of operating temperature, heat generation, heat transfer medium, and integration constraints. Reported COP values for commercial high-temperature vapour-compression heat pumps range from 2.4 to 5.8, depending on operating conditions. The heat-pump technologies reviewed include vapour-compression systems with single-stage, multistage, cascade, and transcritical configurations, together with absorption and adsorption systems, with a focus on suitable working fluids and practical limitations. The review distinguishes between direct heat recovery and heat recovery assisted by heat pumps, and it identifies two main areas of application: external supply for district heating, industrial consumers, and energy communities; and internal support for feedwater preheating, water cycle integration, and steam generation. A selection framework is proposed in which source- and sink-temperature compatibility determines thermodynamic feasibility, COP characterizes heat-pump performance, and LCoH supports techno-economic comparison. Direct heat recovery should be preferred when temperatures are compatible, while heat pumps can operate as enabling technologies when temperature upgrading is required and system-level economic and environmental performance remains advantageous.
Liquid-hydrogen fuel-cell propulsion is a promising option for reducing the climate impact of short-range aviation, but its aircraft-level feasibility depends on the concurrent integration of cryogenic storage, megawatt-class propulsion systems, and thermal management. This paper presents an integrated conceptual design and technology-sensitivity assessment of a 101-passenger liquid-hydrogen fuel-cell aircraft, targeting a 1000 nmi design range and a 2040 entry into service, framed within the European Union FAME project. A JPAD-based aircraft sizing framework is coupled with a surrogate model for cryogenic tank sizing to investigate how selected hydrogen-subsystem characteristics propagate, through mission-fuel and tank-sizing convergence loops, to configuration-level performance and compliance with top-level aircraft requirements. The storage-system trade study identifies 2.0 bar as the most favourable sampled tank venting pressure; relative to the other investigated pressure levels, this solution reduces MTOM and design-mission block fuel by up to 8.1% and 9.2%, respectively. The propulsion-architecture study selects a four-engine layout as the best compromise between one-engine-inoperative performance, spanwise structural relief, nacelle drag, and mission fuel consumption, yielding a 2.6–2.7% lower MTOM and a 3.5–3.7% lower design-mission block fuel than the two- and six-engine alternatives. A technology-sensitivity matrix spanning 51–55% fuel-cell efficiency and 60–100% cooling-line speed recovery reveals a non-linear increase in installed power, aircraft mass, and hydrogen consumption as either parameter deteriorates. For the fixed-geometry FAME baseline, the onset of multiple TLAR violations occurs as speed recovery falls through approximately the 70–80% region, depending on fuel-cell efficiency. Within the assumptions of the present model, maintaining fuel-cell efficiency at or above approximately 53% and cooling-line speed recovery above this transition region therefore represents an approximate feasibility condition.
Hydrogen sulfide (H2S), a high-volume by-product of the hydrodesulfurization of fossil fuels, can be valorized by thermolysis to recover both molecular hydrogen and elemental sulfur, rather than being oxidized as in the conventional Claus process. The viability of this route depends on quantitative knowledge of the reaction mechanism and of the energy costs of dissociation, which are difficult to obtain experimentally at the temperatures involved. Here we study H2S thermolysis by reactive molecular dynamics (RMD) with the ReaxFF potential for systems of 1000 H2S molecules at 1 atm, addressing three coupled questions: the simulation parameters required for dilute gases, the energetics of dissociation, and the elementary reaction mechanism. The interaction cutoff radius proved critical: the original 10 Å value, parametrized for condensed systems, misses about 23 eV of attractive non-bonded interaction energy in the gaseous system at 298.15 K (≈0.023 eV per molecule) and fails to capture dissociation at 3000 K within 20 ns, whereas radii of 30–40 Å converge. Using a 40 Å cutoff at 2500, 3000 and 3500 K, atom-resolved species-transition records reveal a free-radical chain mechanism built from the same set of elementary steps at the three temperatures, whose relative contributions shift with temperature: S–H homolysis initiates the chain, hydrogen abstraction (H• + H2S → H2 + HS•) is essentially the exclusive source of H2 (persistent H• + H• recombination contributed only 1, 13 and 17 events, below 0.5% of the abstraction count), and a slow sulfur-condensation stage (S2 → S3 → S4) limits the net conversion, which reached 9.3 ± 0.9%, 26.3 ± 1.4% and 46.7 ± 1.6% within the simulated windows (single-trajectory counting resolution)—kinetically limited values, not equilibrium conversions. The enthalpy of the system rises linearly with the number of H2S molecules consumed (R2 ≥ 0.99), defining energy costs of 2.46 ± 0.04, 3.10 ± 0.08 and 3.95 ± 0.18 eV per molecule that increase with temperature by ≈1.48 eV per 1000 K; at 3500 K the cost lies between the 0 K complete-dissociation limit D0 = 3.90 eV derived from the experimental H–SH bond energy and the Kirchhoff-corrected complete-dissociation enthalpy at that temperature (4.11–4.12 eV), statistically indistinguishable from the latter (a 0.9σ difference). These results provide a thermochemically validated, molecular-level basis for engineering the valorization of residual H2S as a source of green hydrogen.
Underground storage of green hydrogen is a strategic enabler of large-scale renewable deployment, but its feasibility rests on a hard problem: keeping a small, highly mobile molecule confined underground for decades without safety or environmental risk. This critical review examines the containment mechanisms of hydrogen across underground storage types, focusing on geological barriers, well integrity and sealing materials. We evaluate the containment capabilities of salt cavities, deep aquifers and depleted reservoirs, with particular attention to the viscoplastic, self-healing properties of salt that promote confinement, and to the vulnerabilities of well infrastructure and salt–cement interfaces. Emerging alternatives, including lined rock caverns and repurposed abandoned mines, are assessed alongside their distinct operating configurations and use cases. Leakage mechanisms including diffusion, advection, microcracking, cement degradation and hydrogen–material interactions are analysed alongside geomechanical modelling, microbial activity, monitoring strategies, regulatory frameworks, and techno-economic and environmental considerations, including the integration of carbon capture, utilisation and storage (CCUS) with underground hydrogen storage. Well integrity emerges as the dominant risk factor across storage types. The review concludes with design criteria, monitoring priorities and research needs to guide the safe, sustainable deployment of underground hydrogen storage, providing a scientific foundation for future numerical and experimental work on storage tightness.
Liquid hydrogen (LH2) has been regarded as an ideal carrier for large-scale and long-distance hydrogen energy storage and transportation due to its high gravimetric hydrogen storage density, rapid refueling efficiency and favorable safety performance. However, the physical properties of LH2, such as low viscosity and high volatility at the ultra-low temperature of −253 °C, cause complex thermodynamic problems during the refueling process—including drastic phase transitions, concentrated thermal stress, and two-phase flow instability—which act as bottlenecks restricting the large-scale application of LH2. In this paper, research advances achieved domestically and internationally in recent years are reviewed in detail with respect to thermodynamic issues occurring in the ultra-low-temperature LH2 refueling process. Research achievements concerning the thermodynamics of LH2 refueling are classified, summarized and discussed from the perspectives of theoretical thermodynamic analysis, numerical simulation, experimental investigation and refueling process optimization strategies for LH2 refueling. The heat and mass transfer mechanisms involved in LH2 refueling are revealed, the variation in thermodynamic responses during the refueling process is described, the critical factors affecting the thermodynamic behaviors of LH2 refueling are clarified, the industry standards on LH2 refueling are critically assessed, and various refueling process management strategies are discussed. Finally, the future development directions of thermodynamic research on the LH2 refueling process are discussed and prospected on the basis of the development trends and potential prominent challenges faced by LH2 refueling technologies.
The hydrogen economy has emerged as a promising pathway to address climate change and ensure long-term global energy security, with water electrolysis powered by renewable energy as a key enabler of sustainable hydrogen production. Recent advances in various electrolyser technologies have enhanced their suitability for industrial applications, creating new opportunities for deploying green hydrogen. To address the gap in integrated, multi-dimensional assessment tools for groundwater-based hydrogen systems in water-scarce developing countries, this study develops and presents a Structured Assessment Framework for Green Hydrogen Production from Groundwater in South Africa—the first framework to simultaneously integrate hydrogeological sustainability screening, electrolyser technology selection under groundwater quality constraints, disaggregated levelised cost of hydrogen (LCOH) analysis including water treatment costs, comparative life cycle assessment (LCA) of green, blue, and grey hydrogen pathways, and policy and governance alignment within a single operationalised architecture. This included integrating five thematic dimensions: groundwater resource assessment, electrolyser technology integration, economic viability, environmental sustainability, and policy and governance considerations. This systematic review was conducted in accordance with the PRISMA 2020 guidelines, drawing on 130 studies retrieved from Scopus and Web of Science (2015–2025). The analysis examines groundwater quality and suitability, the technical feasibility of electrolyser systems, and the comparative implications of grey, blue, and green hydrogen pathways on cost and environmental performance. The framework also provides strategic guidance for deploying renewable-energy-powered hydrogen systems, emphasising life-cycle impacts, regulatory alignment, and the potential for decentralised hydrogen hubs. Findings highlight the significance of strengths, weaknesses, opportunities, and threats (SWOT) for green hydrogen production using groundwater in South Africa, including export potential and strong linkages to the circular economy. The study offers actionable insights for policymakers, planners, and industry stakeholders seeking to advance a sustainable and economically competitive hydrogen landscape.
Electrified steam methane reforming (eSMR) is emerging as a promising technology for the decarbonization of the chemical industry and low-carbon hydrogen production by coupling renewable electricity with renewable gaseous feedstocks such as biomethane. In this work, structured Ni-based catalysts washcoated on highly thermally conductive SiC open-cell foams (OCFs) were developed and evaluated for biomethane steam-reforming operating conditions. Two catalyst formulations, 30 wt.% Al2O3_30 wt.% CeO2_20 wt.%Ni and SiC_30 wt.% Al2O3_30 wt.%Ce0.25Zr0.75 O2_20 wt.%Ni, were tested in a laboratory-scale indirectly electrically heated reformer. The high thermal conductivity of the SiC-structured support ensured efficient heat transfer throughout the reactor, limiting radial temperature gradients to below 10 °C. Both catalyst formulations exhibited excellent catalytic performance; however, the Ce0.25Zr0.75O2-promoted catalyst achieved the best results, maintaining equilibrium methane conversion at a gas hourly space velocity above 7000 h−1 while reaching a specific electrical energy consumption of 2.06 kWh/Nm3 of produced H2 projected for industrial-scale efficiency. Notably, these performances were obtained with a catalyst loading approximately 20–50% lower than that of conventional commercial alumina pellet catalysts. XRD characterization did not reveal the formation of crystalline graphitic carbon after catalytic operation. Furthermore, the structural evolution of the Ce–Zr–O highlights the active role of the mixed oxide in promoting redox processes and maintaining catalytic activity under reaction conditions. Overall, these results demonstrate that the combination of highly conductive SiC-structured supports and Ce–Zr-promoted Ni catalysts significantly enhances both the thermal and catalytic efficiency of eSMR. The proposed catalyst provides a promising route toward compact, energy-efficient, and decentralized hydrogen production from biomethane, supporting the electrification and decarbonization of future hydrogen generation technologies.
This study presents a mathematical programming approach for the optimal design of a renewable energy system in a grid-connected public building, incorporating green hydrogen production for surplus energy storage. The system includes wind turbines, solar panels, batteries, a hydrogen unit, and a grid connection. Hydrogen can also be sold as vehicle fuel, generating revenue and reducing the environmental impact. Unlike traditional hydrogen smart grid models that rely on continuous capacity variables—which often yield non-commercial fractional unit sizes—our MILP framework strictly enforces discrete equipment capacities matching real-world procurement specifications. The methodology is applied to the Chemical Engineering Department Building at the University of Patras, Greece, with two objectives: minimizing annual cost and minimizing carbon dioxide emissions. While higher grid electricity tariffs increase absolute total energy costs, they significantly enhance the economic competitiveness and payback of local renewable energy and green hydrogen installations, shifting the optimal system configuration toward self-sufficiency and deep decarbonization. Emission minimization achieves substantial reductions with acceptable economic trade-offs, mainly through hydrogen replacing fossil fuels in transport. A GAMS-based model demonstrates that integrating renewables and hydrogen storage can enhance energy security, lower costs, and reduce the environmental impact in public buildings.
Hydrogen blending into natural gas grids can support early renewable hydrogen deployment, but admissible injection depends on local gas flow, blending limits, and upstream hydrogen concentrations. This paper analyses these effects for a regional high-pressure gas-grid section in Styria, Austria, with two hydrogen injection points. A transient gas-network model derives time- and location-dependent injection limits, which are integrated into an electrolyser dispatch optimisation with fixed trailer demand and annual gas-grid injection demand. Three cases are compared: unrestricted injection, a “CH4-based” limit without upstream hydrogen, and an “H2-aware” case representing potential upstream hydrogen injection. For the analysed configuration, blending constraints shift operation away from favourable electricity-price periods, particularly when low prices coincide with reduced gas demand. In the 2025 reference case, the “H2-aware” constraint increases the electricity-cost contribution from 4.22 to 5.45 EUR/kgH2. A robustness analysis using electricity-price series for 2020, 2022, and 2025 shows that the “H2-aware” constraint increases the electricity-cost contribution by 15.8–29.1% relative to unrestricted injection. The results demonstrate that dynamic gas-grid constraints should be considered when assessing blending-based electrolyser projects, while the quantitative findings remain specific to the analysed network and assumptions.
To supply hydrogen to the geographically decoupled demand sites, efficient hydrogen transport is necessary. The existing natural gas pipelines represent a promising transport solution, with the blended hydrogen content expected to steadily increase. An open issue of hydrogen blending is the mixing behavior. Therefore, the effects of different geometric parameters (diameters, angles), operating conditions (velocities, concentrations), and injection layouts (single- and multi-point) on the mixture quality during direct injection of hydrogen into a natural gas pipeline are studied using 3D CFD. The main goal is to find parameters and layouts leading to sufficient mixing quality over a range of operating conditions. The mixing quality is determined based on the coefficient of variation (COV). The results show that the momentum flux ratio is a key parameter governing the mixing behavior. However, a high momentum flux ratio alone does not guarantee sufficient uniformity for all operating conditions. For the investigated range, single-point injection cannot ensure reliable mixing quality, whereas multi-point layouts with higher hydrogen inlet velocities achieve sufficient uniformity.
Hydrogen sampling is an essential part of ensuring reliable and accurate hydrogen fuel quality for expanding heavy-duty vehicle applications. Hydrogen sampling at refuelling stations is highly sensitive to operational conditions, especially temperature, pressure, storage homogeneity, and nozzle-purging procedures. The direct sampling method operates with a hydrogen fuelling station in maintenance mode and requires that parameters be set properly. This study investigated the impact of temperature, pressure, storage bank selection, and venting on hydrogen sample quality. This study shows that hydrogen sampling at refuelling stations is strongly influenced by operational parameters, with temperature and pressure mainly affecting the water content while other contaminants remain largely stable; storage bank composition and insufficient nozzle purging can also significantly bias results through contamination or non-representative sampling. To ensure reliable measurements, this study recommends conducting sampling under representative operational conditions, including matching the delivery temperature and nominal delivery pressure, verifying storage homogeneity, and applying adequate nozzle-purging procedures. However, further validation across different systems is still needed.
Hydrogen has attracted growing interest across the Association of Southeast Asian Nations (ASEAN) region in recent years, driven by net-zero commitments and national decarbonisation strategies. This study explores the evolving role of hydrogen in the ASEAN energy landscape and its potential to support a just and inclusive transition towards sustainable energy systems. Employing an exploratory research approach, this study integrates two complementary transition management frameworks—Multi-Level Perspective (MLP) and Strategic Niche Management (SNM)—to analyse the dynamics of energy transitions across niche, regime, and landscape levels. The integration of these frameworks supports our understanding of how transitions unfold within complex socio-technical systems. The analysis draws on government documents, the academic literature, and the grey literature on evolving hydrogen development projects across ASEAN. The findings indicate that climate commitments and global hydrogen narratives are placing increasing pressure on fossil-fuel-dominated energy regimes across ASEAN. While hydrogen development remains uneven across the region, several countries have made measurable progress through policy development, pilot projects, and international partnerships. This research contributes to the literature by combining MLP and SNM to provide a multi-level understanding of hydrogen transitions in ASEAN and highlights the importance of nurturing niche innovations to enable long-term systemic transformation.
Against the background of the “dual carbon” goals and the integration of a high proportion of renewable energy, hydrogen energy storage, with its advantages of long duration and large scale storage as well as clean energy conversion, has become an important approach to improving the flexibility and security of energy systems. To address the accident risks associated with leakage from high pressure hydrogen storage in stationary hydrogen energy storage facilities, this study takes an integrated hydrogen energy storage station involving hydrogen production, storage, compression, and utilization as the research object. A numerical model for hydrogen leakage and dispersion from high-pressure storage cylinders in an open environment is established to investigate the effects of leakage aperture, natural ventilation, mechanical ventilation, and emergency shutdown on hydrogen cloud evolution and deflagration risk. The results show that an increase in leakage diameter significantly increases the flammable hydrogen volume and Q9 peak value. Large-scale leakage is prone to local accumulation under the influence of blast walls and obstacles, resulting in a 780 m3 combustible volume and 14.7 m3 Q9; medium-scale leakage has a longer duration, whereas small-scale leakage presents the lowest risk. Under natural wind conditions, crosswind provides better dilution, reducing Q9 by 53%. Mechanical ventilation can effectively reduce the value of Q9 by 36%, with ventilation layout exerting a more significant influence than wind speed. The combined use of mechanical ventilation and emergency shutdown can further reduce the 42% flammable volume and shorten the duration of high concentration hydrogen clouds. The findings can provide guidance for the safety layout, ventilation design, and emergency protection of hydrogen energy storage stations. Unlike conventional CFD-based leakage consequence analyses, this study couples hydrogen dispersion simulation with Q9-based deflagration risk assessment and a hierarchical safety strategy involving natural, mechanical ventilation, and emergency shutdown.
Hydrogen is increasingly recognised as one of the leading pathways for decarbonising the maritime sector. Proton exchange membrane fuel cell (PEMFC) hybrid propulsion is emerging as a promising low-emission technology; however, its safe deployment depends on marine engineers being trained to interpret and manage coupled hydrogen, fuel cell, battery, and electric propulsion systems. However, a critical training gap remains. Alternative fuel guidance identifies hazards and safety barriers, but does not consistently translate hydrogen PEMFC–LFP operation into observable competence assessment evidence and implementation pathways. This paper develops a demonstrator-anchored and regulatory-grounded competency framework for marine engineers operating compressed hydrogen PEMFC-lithium iron phosphate (LFP) battery–electric propulsion systems. A structured purposive narrative synthesis combined prototype vessel testing evidence with regulatory safety training, and competency framework literature. The experimental operational data, including compressed hydrogen supply, pressure regulation, PEMFC charging, battery buffering, propulsion current demand, voltage sag, state-of-charge response, monitoring tasks, alarms, and emergency isolation, were used as operational anchors rather than calibrated performance validation evidence. The analysis identified six competency domains. Compared with IGF/LNG model course training, the largest hydrogen-specific competence gaps concerned compressed hydrogen handling, PEMFC purge and shutdown logic, battery-buffered propulsion monitoring, integrated emergency shutdown, and communication during abnormal operation. These findings were translated into assessable learning outcomes, a provisional 40 h training module, instructor prerequisites, practical assessment evidence, a proposed digital twin/VR supplement, and a staged implementation roadmap. The proposed framework provides a structured pilot pathway. It translates operational testing evidence into assessable maritime education and training. It also establishes a foundation for future competency development and certification for commercial vessels.
Associated gas in the Permian Basin is a methane-rich but spatially fragmented and intermittently available feedstock. Methane pyrolysis can convert hydrocarbons to hydrogen and solid carbon without forming process CO2 in the reactor, but its practical value depends on the captured-gas capacity factor, feed composition, high-temperature heat supply, product purification, continuous carbon withdrawal, carbon offtake, and transparent greenhouse-gas accounting. This study presents an implemented screening model for a modular 1 million standard cubic feet per day (MMSCFD) Permian associated-gas unit. A representative Permian composition is evaluated with hydrocarbon cracking stoichiometry, catalytic and thermal conversion envelopes, a net hydrogen recovery assumption, an energy-duty allocation, a levelized-cost model, and a well-to-gate carbon-intensity model. The catalytic base case produces 3.78 t/d of saleable H2 after 90% pressure-swing adsorption (PSA) recovery and 14.27 t/d of solid carbon; the thermal near-complete conversion bound produces 4.31 t/d of saleable H2 and 16.15 t/d of solid carbon. At a 0.85 capacity factor, $10 million installed capital expenditure (CAPEX), 8% real discount rate, 20-year life, 10 kWh per kg H2 energy intensity, and $0.06 per kWh electricity, the deterministic plant-gate levelized cost of hydrogen (LCOH) is $1.81 per kg H2 at zero carbon value and $1.05 per kg H2 at a net realized carbon value of $0.20 per kg C. Monte Carlo analysis over capacity factor, CAPEX, energy intensity, electricity price, carbon value, feed/capture cost, and yield uncertainty gives levelized cost of hydrogen values at the 10th, 50th, and 90th percentiles (P10/P50/P90) of $1.32/$1.91/$2.57 per kg H2. The corresponding screening carbon-intensity distribution is 2.34/4.11/5.89 kg carbon dioxide equivalent (CO2e) per kg H2, dominated by electricity carbon intensity and upstream methane loss. Geothermal or waste-heat preheat is treated quantitatively as a partial offset to low- and mid-temperature duties, not as a replacement for high-grade 900–1200 °C trim heat. The pathway is benchmarked against steam methane reforming, autothermal reforming with carbon capture and storage, electrolysis, small-scale liquefied natural gas, and gas-to-liquids conversion. Reported LCOH values are plant-gate production costs; separate hydrogen-logistics and negative-carbon-value stress tests identify conditions under which remote delivery or carbon disposal can erode the apparent economic advantage.
Industries seeking to reduce carbon emissions are considering hydrogen as an alternative fuel or reductive reagent. However, the addition of hydrogen into new and existing infrastructure has triggered concerns for materials compatibility, forming a significant barrier to its implementation. Hydrogen is known to damage and embrittle metals, and despite growing efforts to generate compatibility data for structural materials under hydrogen environments, there is no consensus on how hydrogen degrades such material. This is due to the complex mechanisms in which hydrogen interacts with metals but more so the lack of standardised testing methods. Electrochemical methods are being used increasingly to generate hydrogen materials compatibility data. However, for industries to use electrochemical methods the conditions must be representative of those of gaseous hydrogen environments. Currently, when comparing mechanical properties by samples produced under gaseous and electrochemical environments, results show inconstancies in the mechanical properties produced and reliability issues. In this work, methods of electrochemical hydrogenation are reviewed in comparison to those under gaseous environments. Differences in the charging fugacity, surface effects and damage mechanisms are assessed between gaseous and electrochemical charging that may contribute to the disparities seen in the literature. Based on this comparative assessment, we identify key knowledge gaps and provide an approach for future research to address existing uncertainties.
Green hydrogen—hydrogen produced from renewable electricity—is central to global decarbonization strategies. However, despite their fragile governance, damaged infrastructure, water scarcity, and limited investment security, conflict-affected developing economies remain largely absent from hydrogen research. This study addresses that gap by developing and validating a multi-evidence strategic framework for green-hydrogen (GH2) adoption in fragile institutional environments, using Palestine as a challenging test case. Methodologically speaking, the framework integrates four evidence streams—barrier prioritization by 45 Palestinian experts using the Analytic Hierarchy Process (AHP); structural modeling of barrier–adoption–sustainability relationships using partial least squares structural equation modeling (PLS-SEM); strategic-pathway ranking using the Technique for Order of Preference by Similarity to Ideal Solution (TOPSIS); and an original Sustainable Development Goal (SDG) Contribution Index—externally validated by an independent panel of 120 energy experts across 18 Middle East and North Africa (MENA) countries. Three findings stand out. Firstly, expert perception and structural evidence diverge: technical barriers receive the highest expert weight (56.2%) yet show the weakest structural effect on adoption (β = −0.230), whereas social barriers, weighted lowest by experts (4.8%), rank second in predictive power (β = −0.310). Secondly, Small-Scale Community Production is the most robust deployment pathway, ranked first under every weighting scenario tested. Thirdly, government policy quality acts as a governance multiplier, raising the sustainability returns of adoption by 20.2%, with benefits concentrated in SDGs 7, 13, 8, and 9. Practically speaking, the framework yields seven strategic goals and a phased 2026–2040 roadmap for fragile developing economies.
