A unified phase equilibrium model for hydrogen solubility and solution density

For the transition to a clean and sustainable energy production from renewable sources like solar or wind power, large and secure storage of energy is required to compensate for the intermittent nature of these sources. Hydrogen could be a suitable energy carrier and hydrogen geological storage could provide the large capacities required. During storage hydrogen will be brought in contact with the formation fluids present, resulting in dissolution and possibly inducing geochemical reactions. Therefore in this work an accurate, consistent and reliable hydrogen solubility model is established, which allows to calculate the hydrogen solubility in the formation fluid and the corresponding variation of fluid density. The model accounts for system pressure, temperature and formation fluid salinity as well as the molar fraction, fugacity coefficient, Henry's constant, Poynting factor and activity coefficient of hydrogen. In the range of typical hydrogen geological storage conditions of 273–373 K, 1–50 MPa and 0–5 mol/kg NaCl this model can reproduce all available experimental data and predict hydrogen solubility in the formation fluid and the formation fluid density accurately. The model can predict hydrogen solubility within a maximum relative error of 5% for pure water and 15% for brines within the salinity range considered, which is in the range of uncertainty of measurement data. For realistic hydrogen gas geological storage, the model is extended to represent also H₂-N₂ or H₂-CH₄ mixed gas systems as well as mixed electrolyte solutions containing Na, K, Ca, Mg, Cl or SO₄ and combinations of those. Model derivation, model calculations and implementation as well as an application example are presented to demonstrate the applicability of the developed methods and the model.     

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.     

Modeling phase equilibrium of hydrogen and natural gas in brines: Application to storage in salt caverns

In this work, the e-PPC-SAFT equation of state has been parameterized to predict phase equilibrium of the system H₂ + CH₄ + H₂O + Na⁺Cl^? in conditions of temperature, pressure and salinities of interest for gas storage in salt caverns. The ions parameters have been adjusted to match salted water properties such as mean ionic coefficient activities, vapor pressures and molar densities. Furthermore, binary interaction parameters between hydrogen, methane, water, Na⁺ and Cl^? have been adjusted to match gas solubility data through Henry constant data. The validity ranges of this model are 0–200 °C for temperatures, 0–300 bar for pressures, and 0 to 8 mol_NaCl/kg_H2O for salinities. The e-PPC-SAFT equation of state has then been used to model gas storage in salt caverns. The performance of a storage of pure methane, pure hydrogen and a mixture methane + hydrogen have been compared. The simulations of the storage cycles show that integrating up to 20% of hydrogen in caverns does not have a major influence on temperature, pressure and water content compared to pure methane storage. They also allowed to estimate the thermodynamic properties of the system during the storage operations, like the water content in the gaseous phase. The developed model constitutes thus an interesting tool to help size surface installations and to operate caverns.     

Numerical modelling of H2 storage with cushion gas of CO2 in subsurface porous media: Filter effects of CO2 solubility

The central objective of this study is to improve the understanding of flow behaviour during hydrogen (H₂) storage in subsurface porous media, with a cushion gas of carbon dioxide (CO₂). In this study, we investigate the interactions between various factors driving the flow behaviour, including the underlying permeability heterogeneity, viscous instability, and the balance between the viscous and gravity forces. In particular, we study the impact of CO₂ solubility in water on the level of H₂ purity. This effect is demonstrated for the first time in the context of H₂ storage. We have performed a range of 2D vertical cross-sectional simulations at the decametre scale with a very fine cell size (0.1 m) to capture the flow behaviour in detail. This is done since it is at this scale that much of the mixing between injected and native fluids occurs in physical porous media. It is found that CO₂ solubility may have different (positive and negative) impacts on the H₂ recovery performance (i.e., on the purity of the produced H₂), depending on the flow regimes in the system. In the viscous dominated regime, the less viscous H₂ may infiltrate and bypass the cushion gas of CO₂ during the period of H₂ injection. This leads to a quick and dramatic reduction in the H₂ purity when back producing H₂ due to the co-production of the previously bypassed CO₂. Interestingly, the impurity levels in the H₂ are much less severe in the case when CO₂ solubility in water is considered. This is because the bypassed CO₂ will redissolve into the water surrounding the bypassed zones, which greatly retards the movement of CO₂ towards the producer. In the gravity dominated scenario, H₂ accumulates at the top of the model and displaces the underlying cushion gas in an almost piston-like fashion. Approximately 58% of H₂ can be recovered at a purity level above 98% (combustion requirements by ISO) in this gravity-dominated case. However, when CO₂ solubility is considered, the H₂ recovery performance is slightly degraded. This is because the dissolved CO₂ is also gradually vaporised during H₂ injection, which leads to an expansion of mixing zone of CO₂ and H₂. This in turn reduces the period of high H₂ purity level (>98%) during back-production.     

Interaction of O2, H2O and H2 with proton-conducting oxides based on lanthanum scandates

An interaction of components from the gas phase, containing gaseous oxygen, hydrogen and water, with the La_1–xSr_xScO_3–α oxides in the temperature range of 300–950 °С and partial pressure of 6.1–24.3 kPa 8.1–50.7 kPa has been studied using a high temperature thermogravimetric analysis. The effects of partial pressure of the gaseous oxygen, water and hydrogen on the apparent uptake level of protons with oxides has been found. The studies of incorporation processes of hydrogen from molecular hydrogen atmosphere into the structure of proton-conducting oxides based on strontium-doped lanthanum scandates were performed in the temperature range of 300–800 °C and hydrogen pressure of 0.2 kPa by means of the isotope exchange method with the equilibration of isotope composition in the gas phase. The protons and deuterons concentrations were determined for the La_0.91Sr_0.09ScO_3–α oxide. The existence of proton defects in the structure of studied oxides after the exposure in H₂O and H₂-containing atmospheres was revealed using the ¹Н NMR. The role of oxygen vacancies in the proton incorporation processes is considered in the present work.     

Ab initio study of the molecular hydrogen occupancy in pure H2 and binary H2-THF clathrate hydrates

The hydrogen storage capacity in the clathrate hydrate was studied by ab initio calculations and ab initio molecular dynamics simulations. Thermodynamic and kinetic analysis shows that the cage occupancy in small and large cages is affected by each other, and THF has a stabilization effect on the hydrate structure. For pure H₂ hydrates, small cages can be occupied by single H₂ molecule or double H₂ molecules, while the corresponding occupancy in large cages is four or three H₂ molecules, resulting in a hydrogen storage capacity of ～3.8 wt% and ～4.4 wt%, respectively. For binary H₂-THF hydrates, small cages are likely to be singly occupied with H₂, but large cages can simultaneously accommodate one H₂ molecule and one THF molecule. The hydrogen storage capacity falls in between ～1.6 wt% and ～3.8 wt%. This study highlights the importance of the clathrate hydrates as a hydrogen storage material and also is helpful to understand the controversy about the hydrogen storage capacity in the clathrate structure.     

Enthalpy analysis of Ce–Mg–Ni–H formation based on extended miedema theory: Investigation of selected Ce2MgNi2–H2

In this paper, an extended Miedema's model is constructed to illustrate its applicability to estimating the solid-solution enthalpies of Ce–Mg–Ni–H hydrides, adopting the range of an optimized stoichiometry alloy in the contour map of solid-solution state enthalpy. Ce₂MgNi₂ alloy is designed to investigate its hydrogen storage properties, and its main phase is confirmed with X-ray diffraction characterizations. The alloy shows a good activation ability and the pressure component temperature plateau is extremely flat. The formation enthalpy of Ce₂MgNi₂–H₂ is calculated with the extended Miedema theory, with the least enthalpy value of ?59.1 kJ/mol for the corresponding hydrogen content of 1.64 wt %. Both experimental and theoretical data of the hydrogen-containing alloy confirm that the thermodynamic enthalpy of the quaternary Ce₂MgNi₂–H₂ is consistent with that of the experimental results. When calculating the formation enthalpy of hydrogen and metal, the enthalpy of the elastic contribution between metal and hydrogen was considered, generally improving the versatility and accuracy of the calculation. Moreover, the extended Miedema's model is used to predict the hydrogen storage performance.     

200 NL H2 hydrogen storage tank using MgH2–TiH2–C nanocomposite as H storage material

MgH₂-based hydrogen storage materials are promising candidates for solid-state hydrogen storage allowing efficient thermal management in energy systems integrating metal hydride hydrogen store with a solid oxide fuel cell (SOFC) providing dissipated heat at temperatures between 400 and 600 °C. Recently, we have shown that graphite-modified composite of TiH₂ and MgH₂ prepared by high-energy reactive ball milling in hydrogen (HRBM), demonstrates a high reversible gravimetric H storage capacity exceeding 5 wt % H, fast hydrogenation/dehydrogenation kinetics and excellent cycle stability. In present study, 0.9 MgH₂ + 0.1 TiH₂ +5 wt %C nanocomposite with a maximum hydrogen storage capacity of 6.3 wt% H was prepared by HRBM preceded by a short homogenizing pre-milling in inert gas. 300 g of the composite was loaded into a storage tank accommodating an air-heated stainless steel metal hydride (MH) container equipped with transversal internal (copper) and external (aluminium) fins. Tests of the tank were carried out in a temperature range from 150 °C (H₂ absorption) to 370 °C (H₂ desorption) and showed its ability to deliver up to 185 NL H₂ corresponding to a reversible H storage capacity of the MH material of appr. 5 wt% H. No significant deterioration of the reversible H storage capacity was observed during 20 heating/cooling H₂ discharge/charge cycles. It was found that H₂ desorption performance can be tailored by selecting appropriate thermal management conditions and an optimal operational regime has been proposed.     

Review on using the depleted gas reservoirs for the underground H2 storage: A case study in Niigata prefecture,Japan

Underground hydrogen storage (UHS) in depleted hydrocarbon reservoirs is a prospective choice to store enormous volumes of hydrogen (H₂). However, these subsurface formations must be able not only to store H₂ in an effective and secure manner, but also to produce the required volumes of H₂ upon demand. This paper first reviews the critical parameters to be considered for geological analysis and reservoir engineering evaluation of UHS. The formation depth, the interactions of rock-brine-H₂, the caprock (seal) and well integrity are the most prominent parameters as far as UHS is concerned. In respect of these critical parameters, tentative H₂ storage is screened from the existing gas storage fields in the Niigata prefecture of Japan, and it was revealed that the Sekihara gas field is a suitable candidate for UHS with a storage capacity of 2.06 × 10⁸ m³ and a depth of 1000 m. Then, a series of numerical simulations utilizing CMG software was conducted to find out the extent to which critical parameters alter H₂ storage capacity. The results demonstrated that this field, with a recovery factor of 82.7% in the sixth cycle of production is a prospective site for H₂ storage.     

Modeling hydrogen storage capacities,injection and withdrawal cycles in salt caverns: Introducing the GeoH2 salt storage and cycling app

Salt caverns have been used as hydrogen (H₂) storage solutions in four locations worldwide with refineries and the petrochemical industry relying on these supplies as strategic back-up. The viability of storing H₂ within salt caverns is advantageous given their large volumetric capacities, their flexible operation with large injection and withdrawal rates, and for being a proven technology for the underground storage of a wide variety of gases and liquids. However, to our knowledge, there are no open-source web-based software tools to assess the technical potential of salt caverns for H₂ storage. This work aims to fill that gap by introducing the GeoH₂ Salt Storage and Cycling App, a computer program that models H₂ storage capacities, and injection/withdrawal cycles in salt caverns.The GeoH₂ Salt Storage and Cycling App is a web-based thermodynamic simulator, which consists of the following modules: (a) H₂ physical properties, (b) volumetric, (c) production, (d) injection, and (e) cycling. The physical properties module provides the user with the main thermodynamic, transport, and thermal properties of H₂. The volumetric module allows the user to estimate H₂ storage capacities in salt caverns. The production and the injection modules simulate the withdrawal and the injection of H₂, respectively. Finally, the cycling module models sequential withdrawal and injection processes.This study validates the results of the physical properties and the volumetric modules with real data. We validate the results of the production and the injection modules for synthetic cases using an open-source thermodynamic simulator.This work presents a novel tool suitable to assess the technical potential of H₂ storage, injection, withdrawal, and cycling operations in salt caverns. This application can also be used, along with subsurface geological information, as a first order screening tool to assess H₂ storage capacity at a regional or hub scale.     

Influence of capillary threshold pressure and injection well location on the dynamic CO2 and H2 storage capacity for the deep geological structure

The subject of this study is the analysis of influence of capillary threshold pressure and injection well location on the dynamic CO₂ and H₂ storage capacity for the Lower Jurassic reservoir of the Sierpc structure from central Poland. The results of injection modeling allowed us to compare the amount of CO₂ and H₂ that the considered structure can store safely over a given time interval. The modeling was performed using a single well for 30 different locations, considering that the minimum capillary pressure of the cap rock and the fracturing pressure should not be exceeded for each gas separately.Other values of capillary threshold pressure for CO₂ and H₂ significantly affect the amount of a given gas that can be injected into the reservoir. The structure under consideration can store approximately 1 Mt CO₂ in 31 years, while in the case of H₂ it is slightly above 4000 tons. The determined CO₂ storage capacity is limited; the structure seems to be more prospective for underground H₂ storage. The CO₂ and H₂ dynamic storage capacity maps are an important element of the analysis of the use of gas storage structures. A much higher fingering effect was observed for H₂ than for CO₂, which may affect the withdrawal of hydrogen. It is recommended to determine the optimum storage depth, particularly for hydrogen. The presented results, important for the assessment of the capacity of geological structures, also relate to the safety of use of CO₂ and H₂ underground storage space.     

H2 evolution by water SPLITTING on Rh/La2O3

The physicochemical and electrochemical properties of rhodium catalysts supported on La₂O₃ denoted XRhLa (X = 1 and 5% wt. Rh) prepared by impregnation using RhCl₆H₂O as precursor salt were studied. The solids were characterized by X-ray diffraction (XRD), scanning electron microscopy (SEM), transmission electron microscopy (TEM), thermal analysis (TG/TDA) and hydrogen chemisorption (HC) to evaluate the dispersion of the metal phase. The temperature-programmed reaction with hydrogen (H₂-TPR), carbon monoxide (CO-TPR) or methane (CH₄-TPR) were carried out to elucidate there effects on catalytic reaction. The adsorption and decomposition of H₂O has been investigated on the surface catalysts. The number of reduced centers of lanthanum in Rh/La₂O₃ catalysts was measured by in situ oxidation of these centers at oxydation temperature of water (T_OXtov) by water pulses according to the following reaction (Reduced centers + H₂O→Oxidized center + H₂). The amount of hydrogen Q(H), evolved in the reaction allows us to calculate the number of reduced centers of the support since the Rh metal is not oxidized. The results showed that although the conversion rate of water to H₂ is low, the 5% wt. Rh catalyst is a promising candidate in the water adsorption and dissociation compared to the 1% wt.     

Combustion performance of low-NOx and conventional storage water heaters operated on hydrogen enriched natural gas

Adding renewable hydrogen into natural gas pipeline would bring down the net gas C/H ratio and hence the CO₂ emissions. Also, it can help stabilize electric grids and maximize the renewable output of intermittent energy sources (solar, wind, etc.) via power-to-gas pathway. However, hydrogen differs in its chemical and physical characteristics (flammability range, flame speed, density, adiabatic flame temperature, energy content, etc.) than natural gas. Before transitioning to hydrogen admixing into pipelines, a general agreement on maximum hydrogen tolerance pertaining to end use (residential appliances) operation needs to be established. Focusing on the combustion performance of two representative models of storage water heaters (conventional and low-NO_x) in California, this research addresses how much H₂ content in natural gas can be tolerated without loss of critical performance parameters with reliable operation. Characteristics like flashback, ignition delay, flame structure, and emissions (NO_x, NO, CO, CO₂, UHC, and NH₃) at different concentrations of H₂ admixed with natural gas is investigated. The present study shows <10% H₂ can be added to natural gas without any loss of efficiency for both the low-NO_x and conventional storage water heater. This work also aims to provide a brief review of burner configuration and emission regulation pertaining to water heating owing to a gap in the literature.     

Hydrate-based separation of the CO2 + H2 mixtures. Phase equilibria with isopropanol aqueous solutions and hydrogen solubility in CO2 hydrate

The gas hydrates' ability to preferentially bind one of the components of a gas mixture into a hydrate state makes it possible to consider hydrate-based technology as promising for the separation of gas mixtures. When a hydrate is obtained from a gas mixture, mixed hydrates with a complex composition inevitably occur. Issue of their composition determination stays apart. This a rather difficult task, which is complicated by the dissolution of small molecules such as hydrogen in the hydrate phase. This, in turn, impedes the analysis of the data obtained. In this work, the solubility of hydrogen in carbon dioxide hydrate in the range of 269.7–275.7 K and at partial H₂ pressure up to 4.5 MPa was experimentally determined. Hydrate composition was found to be CO₂·(0.01X)H₂·6.5H₂O at H₂ pressure of X MPa. The equilibrium conditions of hydrates formation in the systems of H₂O – CO₂ – H₂ and H₂O – 2-propanol – CO₂ – H₂ were also determined in a wide range of hydrogen concentrations. Hydrogen seems to be an indifferent diluent gas regarding CO₂ hydrate equilibrium pressure. The compositions of the equilibrium phases have been determined as well. It was shown that isopropanol does not form a double hydrate with СО₂, only sI СО₂ hydrate occurred in the studied systems. The obtained dependencies will be useful in analyzing the process of СО₂ + Н₂ gas mixtures separation by the hydrate-based method.     

Robust hydrogen generation over layered crystalline silicon materials via integrated H2 evolution routes

Hydrogen generation is the initial challenge in utilization of hydrogen energy. In this work, robust hydrogen generation with a high yield of 53,930 μmol g⁻¹ is demonstrated over layered crystalline silicon material derived from topochemical reaction from CaSi₂. The physicochemical properties of the resultant layered crystalline Si material before and after H₂ generation are investigated in detail to illustrate the H₂ generation mechanism. Integrated H₂ evolution routes, including destruction of Si–H bonds, oxidation of Si–Si bonds (hydrolysis of Si) and photocatalytic splitting water, are revealed to be responsible for the robust H₂ generation. This work delivers a facile route to synthesize layered crystalline Si material with promising H₂ generation performance and gives a deeply insight into the H₂ evolution mechanisms of Si-based materials.     

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.     

Comparison of thermochemical conversion processes of biomass to hydrogen-rich gas mixtures

Hydrogen can be produced from biomass materials via thermochemical conversion processes such as pyrolysis, gasification, steam gasification, steam-reforming, and supercritical water gasification (SCWG) of biomass. In general, the total hydrogen-rich gaseous products increased with increasing pyrolysis temperature for the biomass sample. The aim of gasification is to obtain a synthesis gas (bio-syngas) including mainly H₂ and CO. Steam reforming is a method of producing hydrogen-rich gas from biomass. Hydrothermal gasification in supercritical water medium has become a promising technique to produce hydrogen from biomass with high efficiency. Hydrogen production by biomass gasification in the supercritical water (SCW) is a promising technology for utilizing wet biomass. The effect of initial moisture content of biomass on the yields of hydrogen is good.     

The simulator TOUGH2/EWASG for modelling geothermal reservoirs with brines and non-condensible gas

An equation-of-state (EOS) module has been developed for the TOUGH2 simulator, belonging to the MULKOM family of computer codes developed at Lawrence Berkeley National Laboratory. This module, named EWASG (Equation-of-State for Water, Salt and Gas), is able to handle three-component mixtures of water, sodium chloride, and a slightly soluble non-condensible gas (NCG). At present the NCG can be chosen to be air, CO₂, CH₄, H₂, or N₂. EWASG can describe liquid and gas phases, and includes precipitation and dissolution of solid salt. The dependence of density, viscosity, enthalpy, and vapour pressure of brine on salt concentration is taken into account, as well as the effects of salinity on gas solubility in the liquid phase and related heat of solution. The reduction of rock porosity because of salt precipitation is also considered, as well as the related decrease of formation permeability. Vapour pressure lowering (VPL) due to suction pressure is represented by Kelvin's equation, in which the effects of salt are considered whereas those of NCG have currently been neglected.The main assumptions made in developing the EWASG module are described, together with the correlations employed to calculate the thermophysical properties of multiphase H₂ONaClCO₂ mixtures, which can be used to simulate the thermodynamic behaviour of commonly exploited geothermal reservoirs.     

Effects of pre-oxidation on the hydrogen-rich reduction of Panzhihua ilmenite concentrate powder: Reduction kinetics and mechanism

The objective of this study was to investigate the effect of pre-oxidation treatment on the hydrogen-rich reduction of Panzhihua ilmenite concentrate powder on the reduction kinetics and mechanisms. In this study, reduction processes of raw and pre-oxidized ilmenite concentrates reduced by H₂/CO mixtures (H₂/CO = 0.4 and H₂/CO = 2.5) at 950, 1000, and 1050 °C were systematically investigated using a thermal analyzer. The hydrogen-rich reduction rate was accelerated by the pre-oxidation treatment of raw ilmenite concentrate and an increase in H₂ in H₂/CO mixtures. The hydrogen-rich reduction of raw and pre-oxidized ilmenite concentrates can be divided into two stages according to the first derivatives of the reduction process: Fe³⁺ to Fe²⁺ and Fe²⁺ to Fe. The results of the research on the model function demonstrated that the reaction mechanism of raw and pre-oxidized ilmenite concentrates were three-dimensional diffusion models in the first stage. In the second stage, the reaction mechanism of the raw ilmenite concentrate was a phase boundary reaction model, and for the pre-oxidized ilmenite concentrate, it was a chemical reaction model. Furthermore, the apparent activation energies of both raw and pre-oxidized ilmenite concentrates under different reducing atmospheres were determined and compared. It was demonstrated that pre-oxidation treatment could effectively reduce the apparent activation energies of the reduction reaction. It is feasible to combine the advantages of the pre-oxidation treatment and hydrogen-rich reduction with a higher hydrogen ratio for the efficient reduction of Panzhihua ilmenite concentrate.     

Data-driven modeling of H2 solubility in hydrocarbons using white-box approaches

As a result of technological advancements, reliable calculation of hydrogen (H₂) solubility in diverse hydrocarbons is now required for the design and efficient operation of processes in chemical and petroleum processing facilities. The accuracy of equations of state (EOSs) in estimating H₂ solubility is restricted, particularly in high-pressure or/and high-temperature conditions, which could result in energy loss and/or potential safety and environmental problem. Two strong machine learning techniques for building advanced correlation were used to evaluate H₂ solubility in hydrocarbons in this study which were Group method of data handling (GMDH) and genetic programming (GP). For that purpose, 1332 datasets from experimental results of H₂ solubility in 32 distinct hydrocarbons were collected from 68 various systems throughout a wide range of operating temperatures from 98 K to 701 K and pressures from 0.101325 MPa to 78.45 MPa. Hydrocarbons from two distinct classes include alkane, alkene, cycloalkane, aromatic, polycyclic aromatic, and terpene. Hydrocarbons have a molecular mass range of 28.054–647.2 g/mol, which corresponds to a carbon number of 2–46. Solvent molecular weight, critical pressure, and critical temperature, as well as pressure and temperature operational parameters, were used to create the features. With a regression coefficient (R²) which was equal to 0.986 and root mean square error (RMSE) which was 0.0132, the GP modeling approach estimated experimental solubility data more accurately than the GMDH approach. Operating pressure, followed by molecular weight of hydrocarbon solvents and temperature, had the greatest influence on estimation H₂ solubility, according to sensitivity analysis. The GP model shown in this paper is a reliable development that may be used in the chemical and petroleum sectors as a reliable and effective estimator for H₂ solubility in diverse hydrocarbons.