Hydrogen wettability in carbonate reservoirs: Implication for underground hydrogen storage from geochemical perspective

Hydrogen has been considered as a promising renewable source to replace fossil fuels to meet energy demand and achieve net-zero carbon emission target. Underground hydrogen storage attracts more interest as it shows potential to store hydrogen at large-scale safely and economically. Meanwhile, wettability is one of the most important formation parameters which can affect hydrogen injection rate, reproduction efficiency and storage capacity. However, current knowledge is still very limited on how fluid-rock interactions affect formation wettability at in-situ conditions. In this study, we thus performed geochemical modelling to interpret our previous brine contact angle measurements of H₂-brine-calcite system. The calcite surface potential at various temperatures, pressures and salinities was calculated to predict disjoining pressure. Moreover, the surface species concentrations of calcite and organic stearic acid were estimated to characterize calcite-organic acid electrostatic attractions and thus hydrogen wettability. The results of the study showed that increasing temperature increases the disjoining pressure on calcite surface, which intensifies the repulsion force of H₂ against calcite and increases the hydrophilicity. Increasing salinity decreases the disjoining pressure, leading to more H₂-wet and contact angle increment. Besides, increasing stearic acid concentration remarkably strengthens the adhesion force between calcite and organic acid, which leads to more hydrophobic and H₂-wet. In general, the results from geochemical modelling are consistent with experimental observations that decreasing temperature and increasing salinity and organic acid concentration increase water contact angle. This work also demonstrates the importance of involving geochemical modelling on H₂ wettability assessment during underground hydrogen storage.     

Thermodynamic characterization of H2-brine-shale wettability: Implications for hydrogen storage at subsurface

Large-scale underground hydrogen storage (UHS) appears to play an important role in the hydrogen economy supply chain, hereby supporting the energy transition to net-zero carbon emission. To understand the movement of hydrogen plume at subsurface, hydrogen wettability of storage rocks has been recently investigated from the contact angles rock-H₂-brine systems. However, hydrogen wettability of shale formations, which determines the sealing capacity of the caprock, has not been examined in detail. In this study, semi-empirical correlations were used to compute the equilibrium contact angles of H₂/brine on five shale samples with various total organic content (TOC) at various pressures (5–20 MPa) and at 343 K. The H₂ column height that can be securely trapped by the shale and capillary pressures were calculated. The shale's H₂ sealing capacity decreased with increasing pressure, increasing depth and TOC values. The CO₂/brine equilibrium contact angles were generally higher than H₂/brine equilibrium, suggesting that CO₂ could be used as favorable cushion gas to maintain formation pressure during UHS. The utmost height of H₂ that can be safely trapped by shale 3 (with TOC of 23.4 wt%) reduced from 8950 to 8750 M while that of shale 5 (with TOC of 0.081 wt%) reduced slightly from 9100 M to 9050 M as the pressure was increased from 5 to 20 MPa. The capillary entry pressure decreased with increasing depth and shale TOC, implying that the capillary trapping effect, as well as the over-pressure required to move brines from the pores by hydrogen displacement, reduces with increasing depth, and shale TOC. However, the shales remained at strongly water-wet conditions, having an equilibrium contact angles of not more than 17° at highest pressure and TOC. The study suggests that the increasing contact angles with increasing pressure and shale TOC, as well as decreasing column height and capillary pressure with increasing depth for H₂-brine-shale systems might not be sufficient to exert significant influence on structural trapping capacities of shale caprocks due to low densities of hydrogen.     

Interfacial tension and contact angle measurements for hydrogen-methane mixtures/brine/oil-wet rocks at reservoir conditions

In this study, we measured the interfacial tensions (IFTs) of brine/hydrogen-methane (H₂–CH₄) mixtures. We also measured the static contact angles of H₂–CH₄ mixtures in contact with brine and oil-wet sandstone and limestone rocks at reservoir conditions. The measurements were conducted using pendant drop and rising/captive bubble techniques. The techniques were first validated for pure gas/brine IFT and contact angle systems. Then, the impacts of temperature and H₂–CH₄ mixture fraction in contact with oil-wet rocks were investigated systematically. IFT values of H₂–CH₄ mixture/brine diminished with increasing temperature and decreasing hydrogen fraction. It is revealed that, under the studied conditions, H₂–CH₄ mixtures exhibit comparable weakly water-wet behavior on oil-wet sandstone and limestone rocks with contact angles ranged within [52.42°-71.1°] independent of temperature. The results also indicated that IFT of H₂–CH₄ mixture/brine decreases with increased temperature and methane fraction. Finally, the mechanisms accountable for the observed rock-fluid interaction behaviors at different conditions were discussed.     

In-situ hydrogen wettability characterisation for underground hydrogen storage

Hydrogen storage in subsurface aquifers or depleted gas reservoirs represents a viable long-term energy storage solution. There is currently a scarcity of subsurface petrophysical data for the hydrogen system. In this work, we determine the wettability and Interfacial Tension (IFT) of the hydrogen-brine-quartz system using captive bubble, pendant drop and in-situ 3D micro-Computed Tomography (CT) methods. Effective contact angles ranged between 29° and 39° for pressures 6.89–20.68 MPa and salinities from distilled water to 5000 ppm NaCl brine. In-situ methods, novel to hydrogen investigations, confirmed the water-wet system with the mean of the macroscopic and apparent contact angle distributions being 39.77° and 59.75° respectively. IFT decreased with increasing pressure in distilled water from 72.45 mN/m at 6.89 MPa to 69.43 mN/m at 20.68 MPa. No correlation was found between IFT and salinity for the 1000 ppm and 5000 ppm brines. Novel insights into hydrogen wetting in multiphase environments allow accurate predictions of relative permeability and capillary pressure curves for large scale simulations.     

Initial and residual trapping of hydrogen and nitrogen in Fontainebleau sandstone using nuclear magnetic resonance core flooding

Hydrogen is among a few promising energy carriers of the future mainly due to its zero-emission combustion nature. It also plays an important role in the transition from fossil fuel to renewable. Hydrogen technology is relatively immature and serious knowledge gaps do exist in its production, transport, storage, and utilization. Although the economical generation of hydrogen to the scale required for such transition is still the biggest technical and environmental challenge, unlocking the large-scale but safe storage is similarly important. It is difficult to store hydrogen in solid and liquid states and storing it in the gaseous phase requires a huge volume which is just available in subsurface porous media. Sandstone is the most abundant and favourable medium for such storage as carbonate rock might not be suitable due to potential geochemical reactions.It is well established in the literature that interaction of the host rock-fluid and injected gas plays a crucial role in fluid flow, residual trapping, withdrawal, and more generally storing capacity. Such data for the hydrogen system is extremely rare and are generally limited to contact angle measurements, while being not representative of the reality of rock-brine-hydrogen interaction(s). Therefore, we have conducted, for the first time, a series of core flooding experiments using Nuclear Magnetic Resonance (NMR) to monitor hydrogen (H₂) and Nitrogen (N₂) gas saturations during the drainage and imbibition stages under pressure and temperature that represent shallow reservoirs. To avoid any geochemical reaction during the test, we selected a clean sandstone core plug of 99.8% quartz (Fontainebleau with a gas porosity of 9.7% and a permeability of 190 mD).Results show significantly low initial and residual H₂ saturations in comparison with N₂, regardless of whether the injection flow rate or capillary number were the same or not. For instance, when the same injection flow rate was used, H₂ saturation during primary drainage was 4% and it was <2% after imbibition. On other hand, N₂ saturation during the primary drainage was 26% and it was 17% after imbibition. However, when the same capillary number of H₂ was utilised for the N₂ experiment, the N₂ saturation values were ～15% for initial gas saturation and 8% for residual gas saturation. Our results promisingly support the idea of hydrogen underground storage; however, we should emphasise that more sandstone rocks of different clay mineralogy should be investigated before reaching a conclusive outcome.     

Wettability alteration of carbonate reservoir rock using amphoteric and cationic surfactants: Experimental investigation

The objective of this study is to prove that altering the wettability of reservoir rocks by two surfactants (hexadecyl amino benzene sulfonic acid [HABSA] and cationic hexa decyl trimethyl ammonum bromide [CTAB]). Changing the wettability to preferentially water-wet condition will reduce the residual oil saturation (S_or). Because of reducing S_or, the percentage of recovered oil is increased. All surfactants were tested for their ability to alter the wettability of reservoir rocks. This alteration was measured based on the contact angle methods. Results of this study show that both amphoteric HABSA and CTAB surfactants alter the wettability of carbonate rocks from oil-wet to water-wet, while CTAB alters the wettability from oil-wet to water-wet more than HABSA. Also, recovery factor in CTAB injection was more than HABSA injection. Ultimately, the results show that the CTAB surfactant is more effective than HABSA surfactant to alter the wettability and improve oil recovery from carbonate reservoirs.     

Hydrogen wettability of clays: Implications for underground hydrogen storage

This study investigates the ability of hydrogen (H₂) to wet clay surfaces in the presence of brine, with implications for underground hydrogen storage in clay-containing reservoirs. Rather than measuring contact angles directly with hydrogen gas, a suite of other gases (carbon dioxide (CO₂), argon (Ar), nitrogen (N₂), and helium (He)) were employed in the gas-brine-clay system under storage conditions (moderate temperature (333 K) and high pressures (5, 10, 15, and 20 MPa)), characteristic of a subsurface environment with a shallow geothermal gradient. By virtue of analogies to H₂ and empirical correlations, wettabilities of hydrogen on three clay surfaces were mathematically derived and interpreted. The three clays were kaolinite, illite, and montmorillonite and represent 1:1, 2:1 non-expansive, and 2:1 expansive clay groups, respectively. All clays showed water-wetting behaviour with contact angles below 40° under all experimental set-ups. It follows that the presence of clays in the reservoir (or caprock) is conducive to capillary and/or residual trapping of the gas. Another positive inference is that any tested gas, particularly nitrogen, is suitable as cushion gas to maintain formation pressure during hydrogen storage because they all turned out to be more gas-wetting than hydrogen on the clay surfaces; this allows easier displacement and/or retrieval of hydrogen during injection/production. One downside of the predominant water wettability of the clays is the upstaged role of biogeochemical reactions at the wetted brine-clay/silicate interface and their potential to affect porosity and permeability. Water-wetting decreased from kaolinite as most water-wetting clay over illite to montmorillonite as most hydrogen-wetting clay. Their wetting behaviour is consistent with molecular dynamic modelling that establishes that the accessible basal plane of kaolinite's octahedral sheet is highly hydrophilic and enables strong hydrogen bonds whereas the same octahedral sheet in illite and montmorillonite is not accessible to the brine, rendering these clays less water-wetting.     

Investigation of the effects of low-salinity waterflooding for improved oil recovery in carbonate reservoir cores

Water injection for both pressure maintenance and oil displacement is the most important secondary recovery method in sandstones. It has also been implemented with success in a few carbonate reservoirs, but because the most carbonate reservoirs worldwide are characterized as neutral to preferential oil-wet, normal waterflooding is usually not successful as an enhanced oil recovery (EOR) technique. It has been proved that seawater can be used as an EOR fluid for hot, fractured carbonate oil reservoirs since it is able to modify the wetting conditions and to enhance the oil recovery. The potential determining ions in seawater such as Ca²⁺, Mg²⁺, and SO₄^2- played a crucial role in altering the wettability from oil-wet to more water-wet condition because of their reactivity towards the carbonate surface. In this paper, the potential of low-salinity brine to enhance the oil recovery has been studied. Four flooding tests were conducted on both limestone cores containing anhydrite and chalk core containing no sulfate. It is observed that low-salinity brine had only effect on rocks containing anhydrite. The dissolution of anhydrite, CaSO₄, which is the source for SO₄^2-, is depending on salinity/composition of brine and the temperature. The dissolution of anhydrite normally increases as the temperature decreases. Lowering the salinity of injection brine increases the reactivity of the surface-active ions SO₄^2- and Ca²⁺.     

Hydrogen separation from blended natural gas and hydrogen by Pd-based membranes

Hydrogen separation membranes based on a heated metal foil of a palladium alloy, offer excellent permeability for hydrogen as a result of the solution-diffusion mechanism. Here, the possibility to separate hydrogen from the mixture of Natural Gas (NG) and hydrogen (NG+H₂) with various NG concentrations using Pd, PdCu₅₃ and PdAg₂₄ hydrogen purification membranes is demonstrated. Hydrogen concentrations above ∼25% (for Pd and PdCu₅₃) and ∼15% (for PdAg₂₄) were required for the hydrogen separation to proceed at 400 °C and 5 bar pressure differential. Hydrogen permeability of the studied alloys could be almost fully recovered after switching the feed gas to pure hydrogen, indicating no significant interaction between the natural gas components and the membranes surface at the current experimental condition. Hydrogen flux of the membranes at various pressure differential was measured and no changes in the hydrogen permeation mechanism could be noticed under (NG 50%+H₂) mixture. The hydrogen separation capability of the membranes is suggested to be mainly controlled by the operating temperature and the hydrogen partial pressure.     

Impact of wettability on storage and recovery of hydrogen gas in the lesueur sandstone formation (Southwest hub project,Western Australia)

Geological storage has been proposed as a new technology to temporarily store significant amounts of hydrogen (H₂) gas in depleted gas reservoirs, underground salt caverns, or saline aquifers. Often, such subsurface reservoirs naturally contain trace amounts of organic acids, and these compounds can considerably alter the wettability of reservoir rocks, causing them to become less water-wet. We carried out Molecular Dynamics (MD) simulations of contact angles in a quartz-brine-H₂ system to evaluate wettability in realistic subsurface situations. MD simulations suggest that Humic acid makes quartz more hydrophobic, which can affect the overall behaviour of the storage reservoir. For the first time, this effect was experimentally investigated for a natural sandstone reservoir from the South West Hub Project, i.e., the Lesueur Sandstone (LS) formation. Multi-stage core flooding experiments were conducted on the same LS plug to investigate the impact of wettability alteration on initial and residual hydrogen saturation/trapping at depth. First, consecutive brine-H₂ drainage-imbibition cycles were carried out on the natural sample; the result indicated that the rock-brine-H₂ system was essentially water-wet. Then, the sample was aged in Humic acid with a molarity of 10⁻² M for 42 days at 5 °C and 0.1 MPa. The wettability of the storage system shifted toward a less water-wet state, i.e., more hydrophobic. As a result of Humic acid ageing, the initial hydrogen saturation reduced from 29% to 15%, and the residual hydrogen trapping reduced from 23% to 11%. This is attributed to a change induced in the capillary force (i.e., snap-off) controlled by wettability and pore size. In addition, the wettability change induced by Humic acid increased the hydrogen recovery rate from 20.7% to 26.7%.     

Experimental simulations of hydrogen migration through potential storage rocks

In the framework of future decarbonization of the energy industry, the safe and effective storage of hydrogen is an important approach to add to a climate-friendly energy system. Until the development of sufficiently large electrical storage systems, the storage of hydrogen in the order of GWh to TWh is envisaged in salt caverns or porous geological formations with a gas-tight covering of salt or claystone. In order to calculate gas losses from these H₂ storage facilities, the H₂ diffusivity of the storage and cap rocks must be known. To determine the hydrogen diffusion rates in these rocks, an experimental set-up was designed, constructed and tested. The set-up comprises two gas chambers, separated by the rock sample under investigation with an exposed area of approximately 7 cm². The driving force for gas migration through the rock sample from the hydrogen-containing feed gas chamber to the hydrogen-free permeate chamber is the chemical potential (concentration) gradient. With respect to hydrogen migration behaviour, hydrogen breakthrough times and hydrogen diffusion coefficients were determined for dry and wet Bentheimer sandstone, Werra rock salt and Opalinus clay samples. Breakthrough times varied between less than 1 h and 843 h. Based on concentration changes at the permeate side, hydrogen diffusion coefficients were derived ranging from 10⁻⁹ to 10⁻⁸ m²/s. The differences between the materials and the effect that wetted or water-saturated samples have higher hydrogen retention due to closed pores and microcracks were clearly shown. The experimental set-up proves to be a suitable approach to determine site-specific rock characteristics such as hydrogen diffusion coefficients and breakthrough times for natural geomaterials.     

Flow process and energy release of hydrogen in fluorine

Hydrogen is a clean energy source and fluorine is a strong oxidant. The chemical reaction between the two will make the utilization of hydrogen energy significantly improved, which is a new way to develop and utilize hydrogen energy. In this study, the ANSYS Fluent software is used to solve the reaction kinetics process, which has great advantages in the simulation of combustion and chemical reaction flow, and Computational fluid dynamics (CFD) adopts numerical methods to solve the Navier-Stokes (N–S) partial differential equation. Here, the CFD code ANSYS Fluent is performed to calculate the two-dimensional compressible reaction flow, therefore, we use the methods to explore the flow process and reaction energy release of hydrogen in fluorine and a new ways of hydrogen energy development is explored. The initial stage of the explosion for F₂ filling into H₂/air in the pipeline is volatile. Chemical reactions for F₂ filling into H₂/air in the pipeline interact with flows for F₂ filling into H₂/air in the pipeline. Energy release of hydrogen in fluorine depends on the flow and mixing process. When F₂ is filled into a premixed H₂/air in the pipeline with a length of 0.9 m and a diameter of 0.1 m, the explosion pressure reaches 0.307MPa–0.408 MPa and the explosion temperature reaches 2698 K–3107 K. The explosion reaction is very rapid and only takes about 40 ms to reach equilibrium. The higher the incident pressure at the pressure inlet, the smaller the peak pressure and temperature are, when the reaction reaches equilibrium.     

Combined Hydrogen,Heat and Power (CHHP) pilot plant design

The Combined Hydrogen, Heat and Power (CHHP) system consists of a molten carbonate fuel cell, DFC300. DFC300 consumes biogas, and produces electricity and hydrogen. The high temperature flue gas can be recovered for useful purposes. During the hydrogen recovery process, the anode exhaust gas (37.1% H₂O, 45.9% CO₂, 5.7% CO, and 11.2% H₂) is sent through a water gas shift (WGS) reactor to increase the hydrogen and carbon dioxide composition, and then water is removed in a vapor–liquid separator. The remaining hydrogen and carbon dioxide mixture gas is separated using a 2-adsorber pressure swing adsorption unit under 1379 kPa. Resulting hydrogen can achieve 99.99% purity, and it can be stored in composite hydrogen storage tanks pressurized at 34,474 kPa. Hydrogen is produced at a rate of 2.58 kg/h. The produced hydrogen is filled into transportable hydrogen cylinders and trucked to a residential community 7.5 km away from the CHHP site. The community is powered by fuel cells to supply electricity to approximately 51 apartments. A heat recovery unit to produce steam and hot water recovers hot air exhaust from the DFC300, having a total heating value of 405 MJ/h. The greenhouse employs a two-phase steam heating system. Hot water supply is mainly needed for the CHHP education center. DFC300 produces electricity at a maximum capacity of 280 kW. A substation is built to set up the interconnections. Power poles and power lines are built to distribute electricity to the CHHP system, the education center, and the greenhouse. The overall electricity consumption of the CHHP system is 86 kW, and the greenhouse consumes 40 kW. Therefore, an aggregate of 154 kW of power can be used to provide power to the UC Davis campus.     

Hydrogen storage in gas reservoirs: A molecular modeling and experimental investigation

Hydrogen is one of the clean energy sources that can be used instead of fossil fuel sources to reduce greenhouse emissions. However, hydrogen supply intermittency significantly reduces the deployment and reliability of this energy resource. Therefore, this work investigates the underground storage of hydrogen in depleted gas reservoirs to avoid seasonal fluctuations in hydrogen supply and assure long-term energy security. The obtained results from molecular simulation (Density Functional Theory) revealed hydrogen is adsorbed physically on calcite (104) and silica (001) surfaces on different adsorption configurations. This conclusion is supported by low adsorption energies (?0.14 eV for calcite and ?0.09 for silica) and by Bader charge analysis, which showed no indication of charge transfer. The experimental results illustrated that hydrogen has a very low adsorption affinity toward carbonate and sandstone rocks in the temperature range of 50–100 °C and pressure up to 20 bar. These results show the potential of depleted gas reservoirs to store hydrogen for s is useful in hydrogen recovery as no hydrogen will be adsorbed to the rock surface of conventional gas reservoirs.     

Strengthening external magnetic fields with activated carbon graphene for increasing hydrogen production in water electrolysis

The presence of External Magnetic Field (EMF) increases Hydrogen production in water electrolysis. A catalyst addition is proficient for multiplying the EMF effect to increase hydrogen production during electrolysis. In this study, the magnetic potential and the electric charge on the Algal#Activated Carbon Graphene (AACG) surface are manipulated to boost EMF effect in water electrolysis. EMF strengthened by AACG accelerates the electron spin and changes the H₂O spin-isomer from para to ortho which decreases the surface tension. Furthermore, the mobility of NaCl ions as electric charge carriers is augmented. On the other hand, electric charges on AACG surface bind Hydroxide ions (OH⁻) in water which increases the Hydrogen ion (H⁺) concentration. Then, the solution became acidic and easily conducts electric current. As a result, the AACG addition has doubled the Hydrogen production.     

Under-expansion jet flame propagation characteristics of premixed H2/air in explosion venting

In premixed H₂/air explosion venting, an under-expansion jet may be caused by the pressure difference between the inside and outside of the explosion vent. Based upon the under-expansion jet, studying the structure of the under-expansion jet flame and the factors influencing its formation is essential to hydrogen safety in explosion venting. This study explored the basic characteristics of the under-expansion jet flame in premixed H₂/air explosion venting, and discussed the formation of two under-expansion structures (Mach disk and diamond shock wave) of such jet flames by conducting a premixed H₂/air explosion venting experiment. The influences of hydrogen fraction, explosion venting diameter, and duct length on the structure of under-expansion jet flames were evaluated. The results showed that after successful explosion venting, the under-expansion jet flame would be generated when the hydrogen fractions were 30–60 vol.%, and as the hydrogen fractions were 30–50 vol.%, the lengths of the venting duct were 30 and 50 cm. The duration of under-expansion jet flame was the longest when the hydrogen fraction was 40 vol.%. With the explosion venting diameter and hydrogen fraction increased, the spacing between under-expansion jet flame structures (S) increased. However, an increase in duct length led to the attenuation of the S. During the explosion venting, the under-expansion jet caused a pressure imbalance near the explosion vent and high-intensity convection forms on both sides of a jet, which can generate two or more explosions. Therefore, understanding the basic characteristics of under-expansion jet flame can aid the effective development of measures to prevent, mitigate, and protect against premixed H₂/air explosions.     

An assessment of electrolytic hydrogen production from H2S in Black Sea waters

In the deeper parts of the Black Sea basin, water is anoxic. Hydrogen sulfide (H₂S) occurs naturally, and its concentration is nearly constant, around 9.5 mg/L at 1500 m depth. Its high solubility, and the existing chemical environment facilitate its accumulation and containment in the seawater, and its extraction poses a challenge.Possibility of hydrogen and sulfur production from H₂S contained in the waters of Black Sea is investigated conceptually. A multistage process is considered which involves extraction of seawater, adsorption of H₂S, electrochemical production of hydrogen and polysulfides; fresh water production by desalination of seawater and further hydrogen production from the resulting salty solution through chlorine-alkaline electrolysis. Some consideration is included regarding the economic and environmental aspects of the process.     

Hydrogen storage in Majiagou carbonate reservoir in China: Geochemical modelling on carbonate dissolution and hydrogen loss

Underground hydrogen storage (UHS) appears to be promising means for large-scale hydrogen storage. Carbonate reservoirs can play an important role in hydrogen storage in particular in Western China and Middle East region. However, little work has been done to address the potential risks and uncertainties associated with carbonate dissolution and hydrogen loss as a result of hydrogen-brine-carbonate geochemical reactions. We thus performed geochemical modelling to assess the potential of UHS in Majiagou carbonate formation, China. Kinetic models of the dissolution/precipitation of calcite, dolomite and quartz were developed to characterize hydrogen loss, mineral dissolution and water chemistry variations up to 500 years.The results show that the percentage of hydrogen loss due to fluid-rock interactions is only 6.6% for the first year, but could increase to 81.1% at the end of 500 years during UHS in Majiagou formation, indicating that carbonate reservoirs is suitable for hydrogen seasonal storage but may not be a good candidate for long-term storage. Meanwhile, totally 0.0646% of calcite would dissolve into formation brine over 500 years, bringing potential risks on caprock and wellbore stability and formation integrity. Besides, we observed a considerable amount of methane generated along with H₂-brine-carbonate interactions. Our works provide a framework to assess the hydrogen storage capacity of carbonate reservoirs using geochemical modelling, and can be also applied to other types of storage deposits.     

Hydrogen tightness evaluation in bedded salt rock cavern: A case study of Jintan,China

Hydrogen is regarded as one of the most important energy sources for the future. Safe, large-scale storage of hydrogen contributes to the commercial development of the hydrogen industry. Use of bedded salt caverns for natural gas storage in China provides a new option for underground hydrogen storage (UHS). In this study, the physical properties of multicomponent gases in UHS and salt rock are reviewed and discussed, along with the flow of hydrogen in the surrounding salt rock. Mathematical models of the two-phase multicomponent flow of the gas–brine system in the UHS were established. A numerical model of a simplified elliptical salt cavern was built to simulate the migration of the gas–brine system in the UHS. The hydrogen tightness of the UHS was evaluated through simulation with different storage strategies, salt rock and interlayer permeabilities, and gas components. The results indicate that: (1) Cyclic injection and withdrawal facilitate hydrogen leakage, which is accelerated by increasing the frequency. (2) The huff-n-puff of hydrogen gas in the injection and withdrawal cycles forces the gas into pore space and enhances the relative permeability of the gas phase. The migration of hydrogen and brine weakens the hydrogen tightness. Brine saturation is an important index for evaluating the hydrogen tightness of UHS. (3) The leakage rate of UHS increases with an increase in the permeability of the salt rock and interlayer and the total thickness of the interlayers. The average permeability K_wa weighted by the thickness of layers for the bedded salt formation is proposed to integrate three variables to facilitate field application of the simulation results. The critical K_wa is less than 3.02 × 10⁻¹⁷ m² if the recommended annual hydrogen leakage rate is less than 1%. (4) The difference between hydrogen and other gas species is another important factor in the leakage rate and should be considered. This study provides theoretical guidance for evaluating the feasibility of UHS in salt caverns and site selection in China.     

Application of aspen plus to renewable hydrogen production from glycerol by steam reforming

Steam reforming is the most favored method for the production of hydrogen. Hydrogen is mostly manufactured by using steam reforming of natural gas. Due to the negative environmental impact and energy politics, alternative hydrogen production methods are being explored. Glycerol is one of the bio-based alternative feedstock for hydrogen production. This study is aimed to simulate hydrogen production from glycerol by using Aspen Plus. First of all, the convenient reactor type was determined. RPlug reactor exhibited the highest performance for the hydrogen production. A thermodynamic model was determined according to the formation of byproduct. The reaction temperature, water/glycerol molar feed ratio as reaction parameters and reactor pressure were investigated on the conversion of glycerol and yield of hydrogen. Optimum reaction parameters are determined as 500 °C of reaction temperature, 9:1 of water to glycerol ratio and 1 atm of pressure. Reactor design was also examined. Optimum reactor diameter and reactor length values were determined as 5 m and 50 m, respectively. Hydrogen purification was studied and 99.9% purity of H₂was obtained at 25 bar and 40 °C. The obtained results were shown that Aspen Plus has been successfully applied to investigate the effects of reaction parameters and reactor sizing for hydrogen production from glycerol steam reforming.