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We conducted measurements of hydrogen adsorption on three coal samples of varying ranks at high pressure (0 to 102 bar) and elevated temperatures (303 K to 333 K) to assess their hydrogen storage potential. The excess adsorption capacity increased with increasing pressure but decreased with increasing temperature irrespective of coal rank. The highest hydrogen adsorption recorded was 0.721 mol/kg for the anthracite coal at 303 K and 102 bar. Furthermore, the hydrogen adsorption capacity correlated positively with coal vitrinite and fixed carbon contents (i.e. the high-rank coal exhibited greater adsorption), while all samples depicted predominantly type-I adsorption behavior for the entire pressure range. Micropore analysis and Fourier-transform infrared spectroscopy measurements were conducted to explore the microstructural and surface chemistry associated with these adsorption trends. The micropore content of the three samples followed the order: anthracite > sub-bituminous > bituminous, while H 2 adsorption followed the trend: anthracite > bituminous > sub-bituminous - i.e., no direct correlation between coal micropore content and its H 2 adsorption capacity - attributable to high clay content of bituminous coal which lowered its micropore content. Moreover, bituminous, and sub-bituminous samples exhibited an abundance of oxygen-containing functional groups, while anthracite coal depicted notable aromatic content - suggesting that the H 2 adsorption capacity is a complex function of coal surface chemistry and micropore content. Overall, high-rank coal seams at high pressure and temperature showed the largest hydrogen adsorption i.e., analogous to CO 2 adsorption potential albeitat lower absolute values. These results, therefore, provide preliminary data on the hydrogen storage potential of coal seams and the associated scientific understanding of the mechanisms causing hydrogen adsorption., Competing Interests: Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2022 Elsevier Inc. All rights reserved.)

Hypothesis: Actualization of the hydrogen (H 2 ) economy and decarbonization goals can be achieved with feasible large-scale H 2 geo-storage. Geological formations are heterogeneous, and their wetting characteristics play a crucial role in the presence of H 2 , which controls the pore-scale distribution of the fluids and sealing capacities of caprocks. Organic acids are readily available in geo-storage formations in minute quantities, but they highly tend to increase the hydrophobicity of storage formations. However, there is a paucity of data on the effects of organic acid concentrations and types on the H 2 -wettability of caprock-representative minerals and their attendant structural trapping capacities., Experiment: Geological formations contain organic acids in minute concentrations, with the alkyl chain length ranging from C 4 to C 26 . To fully understand the wetting characteristics of H 2 in a natural geological picture, we aged mica mineral surfaces as a representative of the caprock in varying concentrations of organic molecules (with varying numbers of carbon atoms, lignoceric acid C 24 , lauric acid C 12 , and hexanoic acid C 6 ) for 7 days. To comprehend the wettability of the mica/H 2 /brine system, we employed a contact-angle procedure similar to that in natural geo-storage environments (25, 15, and 0.1 MPa and 323 K)., Findings: At the highest investigated pressure (25 MPa) and the highest concentration of lignoceric acid (10 -2 mol/L), the mica surface became completely H 2 wet with advancing (θ a = 106.2°) and receding (θ r =97.3°) contact angles. The order of increasing θ a and θ r with increasing organic acid contaminations is as follows: lignoceric acid > lauric acid > hexanoic acid. The results suggest that H 2 gas leakage through the caprock is possible in the presence of organic acids at higher physio-thermal conditions. The influence of organic contamination inherent at realistic geo-storage conditions should be considered to avoid the overprediction of structural trapping capacities and H 2 containment security., Competing Interests: Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2021 The Authors. Published by Elsevier Inc. All rights reserved.)

Gas injection into geological storage sites displaces existing water in rock pore spaces, triggering lateral secondary imbibition. This phenomenon involves the migration of water from areas with higher water saturation to replenish the displaced water. The lateral distance over which this imbibition occurs is critical for understanding injection/withdrawal flow rates and trapped-gas saturation during hydrogen and carbon dioxide geological storage. This study investigates secondary imbibition dynamics in hydrogen and carbon dioxide systems for calcite (representing carbonates) and basalt, considering pressure and temperature effects. Utilizing the modified Lucas-Washburn equation, the results reveal that lateral distance and secondary imbibition rates of water for all gas and rock systems decline with pressure. Additionally, the lateral distance and secondary imbibition rate of water for the hydrogen system at carbonates and basalts, and the carbon dioxide system at carbonates, increase with temperature. However, the lateral distance and secondary imbibition rate of water for the carbon dioxide system at basalts decrease with temperature. This research provides crucial fundamental data with significant implications for underground hydrogen storage and carbon dioxide geological storage. The findings contribute to the understanding of lateral imbibition in carbonate and basaltic rocks, offering valuable insights for enhancing gas retention within pore spaces, thereby influencing residual trapping. [ABSTRACT FROM AUTHOR]

[Display omitted] Hydrogen geo-storage is considered as an option for large scale hydrogen storage in a full-scale hydrogen economy. Among different types of subsurface formations, coal seams look to be one of the best suitable options as coal's micro/nano pore structure can adsorb a huge amount of gas (e.g. hydrogen) which can be withdrawn again once needed. However, literature lacks fundamental data regarding H 2 diffusion in coal. In this study, we measured H 2 adsorption rate in an Australian anthracite coal sample at isothermal conditions for four different temperatures (20 °C, 30 °C, 45 °C and 60 °C), at equilibrium pressure ∼ 13 bar, and calculated H 2 diffusion coefficient (D H 2 ) at each temperature. CO 2 adsorption rates were measured for the same sample at similar temperatures and equilibrium pressure for comparison. Results show that H 2 adsorption rate, and consequently D H 2 , increases by temperature. D H 2 values are one order of magnitude larger than the equivalent D C O 2 values for the whole studied temperature range 20–60 °C. D H 2 / D C O 2 also shows an increasing trend versus temperature. CO 2 adsorption capacity at equilibrium pressure is about 5 times higher than that of H 2 in all studied temperatures. Both H 2 and CO 2 adsorption capacities, at equilibrium pressure, slightly decrease as temperature rises. [ABSTRACT FROM AUTHOR]

Hydrogen is a clean fuel that can potentially revolutionize the energy supply chain and decarbonize fuel consumption. However, a key hurdle that needs to be overcome before a full‐scale hydrogen economy can be established is hydrogen storage which is currently the main limitation. Here, we propose that hydrogen gas can be stored in underground coal seams, where it adsorbs on the coal surface. However, currently, no hard data related to such a procedure exists. We, therefore, demonstrate experimentally that significant amounts of hydrogen gas can be stored via this route. Hydrogen adsorption capacities reached 0.6 moles H2/kg of coal at 14.3 MPa, and adsorption capacity initially increased strongly with pressure (up to ∼4 MPa) and then plateaued out, while temperature only had a very minor influence. This study provides fundamental data for hydrogen storage in coal seams, and thus aids in the industrial implementation of a hydrogen supply chain. Plain Language Summary: Hydrogen is a clean fuel which can potentially revolutionize the energy supply chain and decarbonise fuel consumption. However, a key hurdle which needs to be overcome before a full‐scale hydrogen economy can be established is hydrogen storage which is currently the main limitation. Here, we propose that hydrogen gas can be stored in underground coal seams, where it adsorbs on the coal surface. We demonstrate experimentally that significant amounts of hydrogen gas can be stored via this route. This work provides fundamental data for hydrogen storage in coal seams, and thus aids in the industrial implementation of a hydrogen supply chain. Key Points: Sub‐bituminous coal adsorbs a significant amount of hydrogen gasHydrogen adsorption in coal increases significantly with pressureHydrogen adsorption decreases with temperature only very slightly [ABSTRACT FROM AUTHOR]

Hydrogen is currently assessed as a future clean fuel in a hydrogen economy. However, one key problem with implementing a full‐scale hydrogen economy is hydrogen storage (as hydrogen is highly compressible and volatile). One solution for this problem is hydrogen geo‐storage, where compressed hydrogen is injected into geological formations, and the hydrogen can be withdrawn again at any time. However, there is a serious lack of data for realistic geologic conditions, including for hydrogen‐rock wettability, which is proven to determine injectivities, withdrawal rates, storage capacities, and containment security. We thus measured this parameter at various geo‐storage conditions. For a realistic storage scenario in a deep sandstone aquifer, we found that the rock (quartz) was weakly water‐wet or intermediate‐wet. Increasing pressure, temperature, and organic surface concentration increased hydrogen wettability. This study, thus, provides fundamental data and aids in the industrial‐scale implementation of a future hydrogen economy. Plain Language Summary: Hydrogen is currently assessed as a future clean fuel in a hydrogen economy. However, one key problem with implementing a hydrogen economy is hydrogen storage (as hydrogen is highly compressible and volatile). One solution for this problem is hydrogen geo‐storage, where compressed hydrogen is injected into geological formations; the hydrogen can be withdrawn again at any time. However, there is a serious lack of data from realistic geologic conditions, including hydrogen‐rock wettability, which is a key parameter in this process. We thus, conducted experiments and demonstrate that sandstone is weakly water‐wet to intermediate‐wet. This study, thus, provides fundamental data and aids in the industrial‐scale implementation of a future hydrogen economy. Key Points: Sandstone reservoirs are weakly water‐wet to intermediate‐wet at expected hydrogen storage depthsHydrogen wettability increases with pressure and thus depthOrganic molecules on the sandstone surface strongly increase hydrogen wettability [ABSTRACT FROM AUTHOR]

In this paper, the effects of temperature, hydrostatic pressure and size on optical gain for GaAs spherical quantum dot laser with hydrogen impurity are investigated. For this purpose, the effects of temperature, pressure and quantum dot size on the band gap energy, effective mass, and dielectric constant are studied. The eigenenergies and eigenstates for valence and conduction band are calculated by using Runge-Kutta numerical method. Results show that changes in the temperature, pressure and size lead to the alteration of the band gap energy and effective mass. Also, increasing the temperature redshifts the optical gain peak and at special temperature ranges lead to increasing or decreasing of it. Further, by reducing the size, temperature-dependent of optical gain is decreased. Additionally, enhancing of the hydrostatic pressure blueshifts the peak of optical gain, and its behavior as a function of pressure which depends on the size. Finally, increasing the radius rises the redshifts of the peak of optical gain. [ABSTRACT FROM AUTHOR]

[Display omitted] • Hydrogen wettability increases with pressure, organic surface concentration, and salinity. • Hydrogen wettability decreases with temperature and surface roughness. • Calcite-rich formations have a higher risk than other formations for H 2 geo-storage projects. The mitigation of anthropogenic greenhouse gas emissions and increasing global energy demand are two driving forces toward the hydrogen economy. The large-scale hydrogen storage at the surface is not feasible as hydrogen is very volatile and highly compressible. An effective way for solving this problem is to store it in underground geological formations (i.e. carbonate reservoirs). The wettability of the rock/H 2 /brine system is a critical parameter in the assessment of residual and structural storage capacities and containment safety. However, the presence of organic matters in geo-storage formations poses a direct threat to the successful hydrogen geo-storage operation and containment safety. As there is an intensive lack of literature on hydrogen wettability of calcite-rich formations, advancing (θ a) and receding (θ r) contact angles of water/H 2 /calcite systems were measured as a function of different parameters, including pressure (0.1–20 MPa), temperature (298–353 K), salinity (0–4.95 mol.kg−1), stearic acid (as a representative of organic acid) concentration (10-9 − 10-2 mol/L), tilting plate angle (0° − 45°) and surface roughness (RMS = 341 nm, 466 nm, and 588 nm). The results of the study show that at ambient conditions, the system was strongly water-wet, but became intermediate wet at high pressure. The water contact angle strongly increased with stearic acid concentration making the calcite surface H 2 -wet. Moreover, the contact angle increased with salinity and tilting plate angle but decreased with temperature and surface roughness. We conclude that the optimum conditions for de-risking H 2 storage projects in carbonates are low pressures, high temperatures, low salinity, and low organic surface concentration. Therefore, it is essential to measure these effects to avoid overestimation of hydrogen geo-storage capacities and containment security. [ABSTRACT FROM AUTHOR]

Underground hydrogen (H 2) storage (UHS) and carbon dioxide (CO 2) geo-storage (CGS) are prominent methods of meeting global energy needs and enabling a low-carbon global economy. The pore-scale distribution, reservoir-scale storage capacity, and containment security of H 2 and CO 2 are significantly influenced by interfacial properties, including the equilibrium contact angle (θ E) and solid-liquid and solid-gas interfacial tensions (γ S L and γ S G ). However, due to the technical constraints of experimentally determining these parameters, they are often calculated based on advancing and receding contact angle values. There is a scarcity of θ E , γ S L , and γ S G data, particularly related to the hydrogen structural sealing potential of caprock, which is unavailable in the literature. Young's equation and Neumann's equation of state were combined in this study to theoretically compute these three parameters (θ E , γ S L , and γ S G) at reservoir conditions for the H 2 and CO 2 geo-storage potential. Pure mica, organic-aged mica, and alumina nano-aged mica substrates were investigated to explore the conditions for rock wetting phenomena and the sealing potential of caprock. The results reveal that θ E increases while γ S G decreases with increasing pressure, organic acid concentration, and alkyl chain length. However, γ S G decreases with increasing temperatures for H 2 gas, and vice versa for CO 2. In addition, θ E and γ S L decrease, whereas γ S G increases with increasing alumina nanofluid concentration from 0.05 to 0.25 wt%. Conversely, θ E and γ S L increase, whereas γ S G decreases with increasing alumina nanofluid concentration from 0.25 to 0.75 wt%. The hydrogen wettability of mica (a proxy of caprock) was generally less than the CO 2 wettability of mica at similar physio-thermal conditions. The interfacial data reported in this study are crucial for predicting caprock wettability alterations and the resulting structural sealing capacity for UHS and CGS. [Display omitted] • The equilibrium contact angle (θ E) increases with pressure and organic concentration but decreases with temperature. • The solid-gas interfacial tension (γ S G ) decreases with pressure and organic concentration but increases with temperature. • The solid-liquid interfacial tension (γ S L ) and θ E decreases, whereas γ S G increases with increasing alumina nanofluid concentration. • Mica hydrogen wettability is less than mica CO 2 wettability in all physio-thermal conditions. [ABSTRACT FROM AUTHOR]

[Display omitted] • H 2 /brine/calcite wettability was investigated using stearic acid and alumina nanofluids. • Organic acids in carbonate formations significantly shift the wettability toward H 2 -wet. • Alumina nanofluid restores the water-wet conditions of organic acid-aged calcite substrates. • The optimal alumina nanofluid concentration for wettability alteration is 0.25 wt%. Underground hydrogen storage (UHS) has been recognized as a key enabler of the industrial-scale implementation of a hydrogen-based economy. However, the efficiency and storage capacity of hydrogen (H 2) in carbonate aquifers can be influenced by the presence of organic acids. Nevertheless, the existing literature contains few investigations of H 2 /calcite/brine wettability and the influence of organic acids on H 2 storability in carbonate reservoirs. Therefore, the present study examines the influence of stearic acid on the dynamic H 2 /brine wettability of calcite substrates (as a proxy of carbonate formation) under various geological conditions (0.1–20 MPa at 323 K), equilibrated in 10 wt% NaCl brine. In addition, the application of various alumina nanofluid concentrations (0.05, 0.1, 0.25, and 0.75 wt%) is evaluated under the same experimental conditions for enhancing the organic-aged calcite wettability. The results demonstrate a significant impact of stearic acid on the dynamic (advancing and receding) contact angles of the calcite substrates, thereby resulting in a shift from intermediate water-wet to H 2 -wet conditions, representing an unfavorable state for H 2 geological storage. Conversely, the application of alumina nanofluid on the organic-aged calcite substrate enhances the H 2 /brine/calcite wettability towards an intermediate water-wet state, which is more favorable for H 2 residual trapping in carbonate formations. The optimal concentration of alumina nanofluid for the wettability modification of the organically aged calcite samples is found to be 0.25 wt%. These findings highlight the influence of organic acid contamination and the potential of alumina nanofluid application in enhancing H 2 geo-storage conditions in carbonate reservoirs. [ABSTRACT FROM AUTHOR]

[Display omitted] • H 2 , CH 4 , and CO 2 adsorption isotherms measured for organic-rich source rocks. • TOC in rock influences gas adsorption behavior and storage capacities. • Organics, hydrophobicity, and pores are prominent influencers on adsorption capacity. • Gas adsorption in source rocks increases significantly with pressure. • Adsorption capacities of CO 2 compared to CH 4 indicate a better cushion gas for underground H 2 withdrawal. Hydrogen (H 2) storage in geological formations offers a potential large-scale solution suitable for an industrial-scale hydrogen economy. However, the presence of organic residuals can significantly influence the H 2 storage efficiency, as well as cushion gas performance, such as CO 2 and CH 4, injected to maintain healthy reservoir pressure. Thus, the H 2 storage efficiency and cushion gas selectivity were thoroughly investigated in this work based on H 2 , CO 2 , and CH 4 adsorption measurements using, for the first time, actual organic-rich carbonate-rich Jordanian source rock samples (TOC = 13 % to 18 %), measured at 60 °C temperature and a wide range of pressure (0.1 – 10.0 MPa). Initially, the samples were characterized using various analytical methods. Results demonstrated that H 2 adsorption capacities reached up to 0.47 mol/kg at 9.0 MPa. The measured adsorption of CO 2 was four times higher than H 2. An increase in TOC significantly decreased H 2 adsorption compared to CO 2 and CH 4. Additionally, CO 2 demonstrated preferential behavior as a cushion gas compared to CH 4 , attributed mainly to the calcite content and presence of carboxyl and sulfonyl groups. This study provides fundamental data for understanding H 2 potential storage issues in an organic-rich rock formation and thus aids in the industrial implementation of an H 2 supply chain. [ABSTRACT FROM AUTHOR]

• At constant pressure, IFT declined when the proportion of CO 2 increased from 30% to 70%. • Pressure rise led to IFT reduction at constant temperature, salinity and CO 2 percentage. • IFT decreased with temperature at constant pressure, salinity, and CO 2 percentage. • The addition of salt concentration resulted in linear increase in IFT at constant temperature, pressure, and CO 2 percentage. In hydrogen geological storage, cushion gas has vital role to retain adequate reservoir pressure to keep the hydrogen withdrawal stable. Presence of the cushion gas in the storage reservoir can affect the flow characteristics of hydrogen during injection and production cycles. One of the most crucial parameters that control the fluids flow in porous media is interfacial tension (IFT) between fluids. However, the literature data lacks in terms of IFT between cushion gas mixed with hydrogen and brine at geo-storage conditions. In this study, the pendant drop method was used to measure the IFT of (brine + H 2 + CO 2) system at different CO 2 fractions as cushion gas, reservoir temperature, reservoir pressure, and water salinity. The results showed that the IFT reduced with increasing CO 2 percentage. Moreover, IFT declined when pressure went up gradually. This pattern was almost linear at lower proportion of CO 2 ; however, a non-linear trend was observed at higher percentage of CO 2. In addition, at constant pressure, IFT decreased with temperature. These results also demonstrated that the IFT increases linearly with brine salinity. This work thus presents new dataset for hydrogen geological storage projects, where large-scale hydrogen with CO 2 (as a cushion gas) can be stored in geological formations. [ABSTRACT FROM AUTHOR]

Hydrogen as a clean fuel source compared to hydrocarbons has attracted many attentions to mitigate anthropogenic greenhouse gas emissions and meet global energy demand. However, high volatility and compressibility of hydrogen make a challenge for its storage. In this regard, the surface-based hydrogen storage facilities (e.g. aerospace, cryogenic tanks, high-pressure gas cylinders, etc.) have been in operation for decades. Moreover, H 2 geo-storage is an effective way to store vast volume of hydrogen in deep underground formations where it can be withdrawn again to generate energy when the need arises. The interaction between the injected hydrogen and resident formation fluids (e.g. water), can strongly influence the H 2 -flow pattern and storage capacity. In this regard, interfacial tension (γ) between hydrogen and brine is a key parameter that influences hydrogen displacement within the geological porous medium. As there is a serious lack of literature on this important subject, we measured H 2 -brine interfacial tension at various geo-storage conditions for a wide range of pressure, temperature, and brine salinity, using the pendant drop technique. The results of the study indicate that γ declined linearly with increasing pressure when temperature and salinity are kept constant. Moreover, a linear reduction in γ with increasing temperature was observed under constant salinity and pressure conditions. The results also clearly demonstrate that γ increased linearly with brine molality over the whole range investigated. An empirical equation was also developed with which γ as a function of pressure, temperature, and brine molality can be predicted. The predictions for data points of this work had a maximum deviation of 2.13% from the experimental data. This work thus provides fundamental data for H 2 geo-storage projects, and aids in the implementation of an industrial-scale hydrogen economy. • H 2 −brine interfacial tension declines linearly with increasing pressure (at constant salinity and temperature). • H 2 −brine interfacial tension declines linearly with increasing temperature (at constant salinity and pressure). • H 2 −brine interfacial tension increases linearly with increasing salinity (at constant pressure and temperature). • An empirical equation is provided for predicting H 2 −brine interfacial tension. [ABSTRACT FROM AUTHOR]