Solubility of Flue Gas or Carbon Dioxide-Nitrogen Gas Mixtures in Water and Aqueous Solutions of Salts: Experimental Measurement and Thermodynamic Modeling

Mass Transport Limitations in Electrochemical Conversion of CO2 to Formic Acid at High Pressure

Mass transport of different species plays a crucial role in electrochemical conversion of CO2 due to the solubility limit of CO2 in aqueous electrolytes. In this study, we investigate the transport of CO2 and other ionic species through the electrolyte and the membrane, and its impact on the scale-up process of HCOO−/HCOOH formation. The mass transport of ions to the electrode and the membrane is modelled at constant current density. The mass transport limitations of CO2 on the formation of HCOO−/HCOOH is investigated at different pressures ranges from 5–40 bar. The maximum achievable partial current density of formate/formic acid is increased with increasing CO2 pressure. We use an ion exchange membrane model to understand the ion transport behaviour for both the monopolar and bipolar membranes. The cation exchange (CEM) and anion exchange membrane (AEM) model show that ion transport is limited by the electrolyte salt concentrations. For 0.1 M KHCO3, the AEM reaches the limiting current density more quickly than the CEM. For the BPM model, ion transport across the diffusion layer on either side of the BPM is also included to understand the concentration polarization across the BPM. The model revealed that the polarization losses across the bipolar membrane depend on the pH of the electrolyte used for the CO2 reduction reaction (CO2RR). The polarization loss on the anolyte side decreases with an increasing pH, while, on the cathode side, it increases with increasing catholyte pH. With this combined model for the electrode reactions and the membrane transport, we are able to account for the various factors influencing the polarization losses in the CO2 electrolyzer. To complete the analysis, we simulated the full cell polarization curve and fitted with the experimental data.

Measurements and Modelling of Vapour–Liquid Equilibrium for (H2O + N2) and (CO2 + H2O + N2) Systems at Temperatures between 323 and 473 K and Pressures up to 20 MPa

Understanding the phase behaviour of (CO2 + water + permanent gas) systems is critical for implementing carbon capture and storage (CCS) processes, a key technology in reducing CO2 emissions. In this paper, phase behaviour data for (H2O + N2) and (CO2 + H2O + N2) systems are reported at temperatures from 323 to 473 K and pressures up to 20 MPa. In the ternary system, the mole ratio between CO2 and N2 was 1. Experiments were conducted in a newly designed analytical apparatus that includes two syringe pumps for fluid injection, a high-pressure equilibrium vessel, heater aluminium jacket, Rolsi sampling valves and an online gas chromatograph (GC) for composition determination. A high-sensitivity pulsed discharge detector installed in the GC was used to measure the low levels of dissolved nitrogen in the aqueous phase and low water levels in the vapour phase. The experimental data were compared with the calculation based on the γ-φ and SAFT-γ Mie approaches. In the SAFT-γ Mie model, the like parameters for N2 had to be determined. We also obtained the unlike dispersion energy for the (H2O + N2) system and the unlike repulsive exponent and dispersion energy for the (CO2 + N2) system. This was done to improve the prediction of SAFT-γ Mie model. For the (H2O + N2) binary system, the results show that the solubility of nitrogen in the aqueous phase was calculated better by the γ-φ approach rather than the SAFT-γ Mie model, whereas SAFT-γ Mie performed better for the prediction of the vapour phase. For the (CO2 + H2O + N2) ternary systems, both models predicted the experimental data for each phase with good agreement.

Modeling solubility of CO2–N2 gas mixtures in aqueous electrolyte systems using artificial intelligence techniques and equations of state

Determining the solubility of non-hydrocarbon gases such as carbon dioxide (CO₂) and nitrogen (N₂) in water and brine is one of the most controversial challenges in the oil and chemical industries. Although many researches have been conducted on solubility of gases in brine and water, very few researches investigated the solubility of power plant flue gases (CO₂–N₂ mixtures) in aqueous solutions. In this study, using six intelligent models, including Random Forest, Decision Tree (DT), Gradient Boosting-Decision Tree (GB-DT), Adaptive Boosting-Decision Tree (AdaBoost-DT), Adaptive Boosting-Support Vector Regression (AdaBoost-SVR), and Gradient Boosting-Support Vector Regression (GB-SVR), the solubility of CO₂–N₂ mixtures in water and brine solutions was predicted, and the results were compared with four equations of state (EOSs), including Peng–Robinson (PR), Soave–Redlich–Kwong (SRK), Valderrama–Patel–Teja (VPT), and Perturbed-Chain Statistical Associating Fluid Theory (PC-SAFT). The results indicate that the Random Forest model with an average absolute percent relative error (AAPRE) value of 2.8% has the best predictions. The GB-SVR and DT models also have good precision with AAPRE values of 6.43% and 7.41%, respectively. For solubility of CO₂ present in gaseous mixtures in aqueous systems, the PC-SAFT model, and for solubility of N₂, the VPT EOS had the best results among the EOSs. Also, the sensitivity analysis of input parameters showed that increasing the mole percent of CO₂ in gaseous phase, temperature, pressure, and decreasing the ionic strength increase the solubility of CO₂–N₂ mixture in water and brine solutions. Another significant issue is that increasing the salinity of brine also has a subtractive effect on the solubility of CO₂–N₂ mixture. Finally, the Leverage method proved that the actual data are of excellent quality and the Random Forest approach is quite reliable for determining the solubility of the CO₂–N₂ gas mixtures in aqueous systems.

Thermodynamic Characteristics of the Hydrogen Sulfide Sorption Process by Ferromanganese Materials

The work analyzes hydrogen sulfide sorption from model gas mixtures containing H₂S from 1.25 × 10^-3 to 1.28 × 10^-4 mol/L under static conditions at temperatures 253 and 298 K on the raw manganese ore of the Ulu-Telyak deposit (Bashkortostan, Russia), manganese(IV) oxide, and manganese(IV) and iron(III) oxide mixtures. The thermodynamic models for calculating the equilibrium constants and Gibbs energy changes were analyzed. The sorption isotherms were described by the Langmuir, Freundlich, Temkin, and Dubinin-Radushkevich models. The value of enthalpy of hydrogen sorption on the ore was -68.98 ± 3.45 kJ/mol and those on model mixtures Mn₄ + Fe₂O₃ and MnO₄ were ±12.20 kJ/mol and -103.826 ± 5.19 kJ/mol, respectively, and the entropies of the hydrogen sulfide sorption process on three manganese materials at 253 K were calculated. The limiting capacity values of manganese materials at 253 and 298 K were obtained. The morphological analysis of the ore samples, Mn₄ + Fe₂O₃, and MnO₄, before and after hydrogen sulfide sorption, was carried out at 253 K. The obtained thermodynamic parameters determine the advantage of using the raw manganese ore over pure oxides, which characterizes its effective practical application in the desulfurization process.

Thermodynamic Modeling of Mutual Solubilities in Gas-Laden Brines Systems Containing CO2, CH4, N2, O2, H2, H2O, NaCl, CaCl2, and KCl: Application to Degassing in Geothermal Processes

With the growing interest in geothermal energy as a renewable and sustainable energy source, nowadays engineers and researchers are facing technological and environmental challenges during geothermal wells’ operation or energy recovery improvement by optimizing surface installations. One of the major problems encountered is the degassing of geothermal brines which are often loaded with dissolved gases, resulting in technical problems (scale formation, corrosion, reduced process efficiency, etc.) and environmental problems through the possible emission of greenhouse gases (CO2, CH4 and water vapor) into the atmosphere. In this work, a method to predict, from readily available information such as temperature and GLR, the bubble point pressure of geothermal fluids as well as the GHG emission rate depending on the surface conditions is presented. This method is based on an extended version of the Soreide and Whitson model with new parameters optimized on the solubility data of several gases (CO2, CH4, N2, O2 and H2) in brine (NaCl + CaCl2 + KCl). The developed approach has been successfully used for the prediction of water content of different gases and their solubilities in different types of brines over a wide temperature and pressure range, and has been applied for the prediction of bubble point pressure and GHG emissions by comparing the results with available industrial data of geothermal power plants including the Upper Rhine Graben sites.

Physical Simulation Experimental Technology and Mechanism of Water Invasion in Fractured-Porous Gas Reservoir: A Review

In the development process for a fractured-porous gas reservoir with developed fracture and active water, edge water or bottom water easily bursts rapidly along the fracture to the production well, and the reservoir matrix will absorb water, reducing the gas percolation channel and increasing the gas phase percolation resistance of the reservoir matrix, therefor reducing the stable production capacity and recovery efficiency of the gas reservoir. For this reason, this paper investigates physical simulation experimental technology and mechanisms as reported by both domestic and foreign scholars regarding water invasion in fractured-porous gas reservoirs. In this paper, it is considered that the future trend and focus of water invasion experiments will be to establish a more realistic three-dimensional physical model on the basis of fine geological description, combined with gas reservoir well pattern deployment and production characteristics, and to fully consider the difference between horizontal and vertical water invasion along the reservoir side; at the same time, dynamic parameters such as model pressure field and water saturation field can be obtained in real time. Based on this understanding of the water invasion mechanism of fractured-porous gas reservoirs, we propose the next research direction and the development countermeasures such as water controls, drainage, and dissolved water seals and water locks to combat water invasion in reservoirs, along with the injection of gas to replenish formation energy, etc., so as to slow down and control the influence of water invasion.

Insights into the climate-driven evolution of gas hydrate-bearing permafrost sediments: implications for prediction of environmental impacts and security of energy in cold regions

The present study investigates the evolution of gas hydrate-bearing permafrost sediments against the environmental temperature change. The elastic wave velocities and effective thermal conductivity (ETC) of simulated gas hydrate-bearing sediment samples were measured at a typical range of temperature in permafrost and wide range of hydrate saturation. The experimental results reveal the influence of several complex and interdependent pore-scale factors on the elastic wave velocities and ETC. It was observed that the geophysical and geothermal properties of the system are essentially governed by the thermal state, saturation and more significantly, pore-scale distribution of the co-existing phases. In particular, unfrozen water content substantially controls the heat transfer at sub-zero temperatures close to the freezing point. A conceptual pore-scale model was also proposed to describe the pore-scale distribution of each phase in a typical gas hydrate-bearing permafrost sediment. This study underpins necessity of distinguishing ice from gas hydrates in frozen sediments, and its outcome is essential to be considered not only for development of large-scale permafrost monitoring systems, bus also accurate quantification of natural gas hydrate as a potential sustainable energy resource in cold regions.

Effects of Waxes and the Related Chemicals on Asphaltene Aggregation and Deposition Phenomena: Experimental and Modeling Studies

Solid deposition during production, transport, and storage of crude oils leads to significant technical problems and economic losses for the oil and gas industry. The thermodynamic equilibrium between high-molecular-weight components of crude oil, such as asphaltenes, resins, and waxes, is an important parameter for the stability of crude oil. Once the equilibrium is disturbed due to variations in temperature, pressure, and oil composition during production, the solubility of high-molecular-weight waxes decreases. This results in a decrease in the wax appearance temperature (WAT) and the deposit of wax onto solid surfaces. On the other hand, under these conditions, asphaltenes do not interact sufficiently with the resins/waxes and tend to flocculate among themselves and form asphaltene nanoaggregates. The role of waxes during the asphaltene aggregation and deposition has not been appropriately explained yet. The objective of this research study is to describe the interaction of asphaltenes and waxes and subsequently address the specific example of an asphaltenic oil commingled with a wax inhibitor-containing oil during the combination of different oil streams. It is a crucial building block for the development of a suitable and cost-effective strategy for the handling of wax/asphaltene associated flow assurance problems. In this work, the quartz crystal microbalance (QCM) technique has been used for the first time to investigate the effect of waxes and related chemicals, which are used to mitigate wax deposition, on asphaltene aggregation and deposition phenomena. Asphaltene onset point and asphaltene deposition rate have been monitored using QCM at high pressure-high temperature (HPHT) conditions. This study confirms that the different wax inhibitor chemistries result in significant differences in the pour point decrease and viscosity profiles in crude oil. Different wax inhibitors also showed different outcomes regarding the asphaltene deposition tendency. A comprehensive modeling study has also been conducted for mechanistic investigation of experimental results. In this regard, the perturbed chain statistical associating fluid theory equation of state (PC-SAFT EoS) was utilized to model the systems.

Gas hydrates in sustainable chemistry

This review includes the current state of the art understanding and advances in technical developments about various fields of gas hydrates, which are combined with expert perspectives and analyses.

An Experimental Investigation on the Kinetics of Integrated Methane Recovery and CO2 Sequestration by Injection of Flue Gas into Permafrost Methane Hydrate Reservoirs

Large hydrate reservoirs in the Arctic regions could provide great potentials for recovery of methane and geological storage of CO₂. In this study, injection of flue gas into permafrost gas hydrates reservoirs has been studied in order to evaluate its use in energy recovery and CO₂ sequestration based on the premise that it could significantly lower costs relative to other technologies available today. We have carried out a series of real-time scale experiments under realistic conditions at temperatures between 261.2 and 284.2 K and at optimum pressures defined in our previous work, in order to characterize the kinetics of the process and evaluate efficiency. Results show that the kinetics of methane release from methane hydrate and CO₂ extracted from flue gas strongly depend on hydrate reservoir temperatures. The experiment at 261.2 K yielded a capture of 81.9% CO₂ present in the injected flue gas, and an increase in the CH₄ concentration in the gas phase up to 60.7 mol%, 93.3 mol%, and 98.2 mol% at optimum pressures, after depressurizing the system to dissociate CH₄ hydrate and after depressurizing the system to CO₂ hydrate dissociation point, respectively. This is significantly better than the maximum efficiency reported in the literature for both CO₂ sequestration and methane recovery using flue gas injection, demonstrating the economic feasibility of direct injection flue gas into hydrate reservoirs in permafrost for methane recovery and geological capture and storage of CO₂. Finally, the thermal stability of stored CO₂ was investigated by heating the system and it is concluded that presence of N₂ in the injection gas provides another safety factor for the stored CO₂ in case of temperature change.