Effect of the Water Content on the Adsorption of CO2 and CH4 in Calcite Slit Nanopores: Insights from GCMC, MD, and DFT.

It is significant to understand the adsorption mechanisms of shale gas (CH4) and CO2 in shale formations to enhance CH4 recovery rates and enable geological CO2 storage. This study provides a comprehensive investigation into the adsorption behaviors of CO2 and CH4 within dry and hydrous calcite nanopores, utilizing a combination of grand canonical Monte Carlo simulations, molecular dynamics simulations, and density functional theory calculations. In dry calcite slits, the calculated results for the adsorption capacity, density profile, and isosteric heat of CO2 and CH4 reveal that CO2 possesses a stronger adsorption affinity, making it preferentially adsorb on the pore surface compared to CH4. In hydrous calcite slits, calculating the adsorption capacity and density profile of CO2 and CH4, the results show that the gas adsorption sites become progressively occupied by H2O molecules, leading to a substantial decrease in the adsorption capacity of CO2 and CH4. Furthermore, by analysis of the adsorption energy and electronic structure, the reason for the reduction of gas adsorption capacity caused by H2O is further revealed. This work has a deep understanding of the adsorption mechanisms of shale gas and CO2 in calcite and can offer valuable theoretical insights for the development of a CO2-enhanced shale gas recovery technology.

Analysis of flow field characteristics of sand removal hydrocyclone applicable to solid fluidization exploitation of natural gas hydrate.

With the development of economy and society, the consumption of fossil energy is gradually increasing. In order to solve the current energy dilemma, Natural gas hydrate (NGH) is considered as an ideal alternative energy. At the same time, solid fluidization exploitation is an ideal method. However, in the process of that, sand and hydrate ore bodies enter the closed pipeline together, which will block the pipeline and increase the difficulty of exploitation. Therefore, the pre-separation of sand by hydrocyclone plays an important role in solid fluidization exploitation. In this study, the numerical simulation method was used to study the internal flow field characteristics of the hydrocyclone, and the effects of different flow rate, different flow ratio, different sand content and different particle diameter on the phase distribution were investigated. The results show that: at the same axial position, the increase of flow rate and sand content makes the sand phase more distributed at the edge of the flow field. Under the same working conditions, the sand gradually migrates to the center of the flow field with the increase of the axial distance. By calculation, it is obtained that under the optimum working condition of the flow rate is 4.83m3/h, the flow ratio is 20%, the sand content is 20%, and sand diameter is 80µm, the maximum Es is 22.1% and the minimum is 86.1%. Finally, a comprehensive analysis of the hydrocyclone in this study shows that this hydrocyclone is only applicable to rough pre-separation of sand in the process of solid fluidization exploitation. Through the study of the internal flow field characteristics and phase distribution law of the hydrocyclone, this study provides a reference for the practical engineering application of sand phase pre-separation in the solid fluidization exploitation of NGH.

Stability Analysis of Anionic-CO2-Soluble Surfactant Di-(2-ethylhexyl) Sodium Sulfosuccinate-Assisted Oily Foam Based on Statistical Analysis of Bubble Dynamic Characteristics.

Currently, oily foam stability in CO2 injection for heavy oil recovery exhibits inadequacies that considerably constrain its extensive application. Some scholars have conducted research demonstrating that CO2-soluble surfactants can assist in inducing heavy oil to form oil-based foams (oily foam). In this study, stability tests for the oily foam were conducted at different surfactant concentrations using a visualized PVT cell. Oily foam stability was assessed by calculating the comprehensive foam index (S) and analyzing the bubble images. The research indicates that AOT can effectively reduce the interfacial tension between oil and gas. At a concentration of 0.1 wt % AOT, the interfacial tension can be effectively reduced from 1.75 to 1.14 mN/m. The concentration of 0.3 wt % AOT represents a turning point, with an S of 16 101.7 mL·min. Beyond this concentration, the increase in S becomes less pronounced. As the concentration of CO2-soluble surfactant is increased from 0.1 to 0.5 wt %, the average bubble radius decreases from 2.74 to 0.43 mm, while the number of bubbles per unit area increases from 5.56 to 81.1 per cm2. With an increasing concentration of the CO2-soluble surfactant, the system generates more and smaller gas bubbles within the oily foam, resulting in a slower bubble coalescence. The findings of this study are poised to play a pivotal role in enhancing heavy oil recovery efficiency.

Predictions of Entropy and Gibbs Energy for Carbonyl Sulfide.

Many chemical and physical equilibrium conditions can be determined from minimizing the Gibbs free energies of the system. Efficient analytical representations of the entropy and Gibbs free energy of carbonyl sulfide remain elusive in the communality of science and engineering. Here, we report two analytical representations of the entropy and Gibbs free energy for carbonyl sulfide, and the prediction procedures only involve six molecular constants of the carbonyl sulfide molecule. In the temperature range from 300 to 6000 K, the average relative deviations of the predicted molar entropy and reduced Gibbs free energy values of carbonyl sulfide from the National Institute of Standards and Technology database are arrived at 0.150 and 0.189%, respectively.

Thermodynamic Properties for Carbon Dioxide.

We first report three reliable analytical expressions of the entropy, enthalpy and Gibbs free energy of carbon dioxide (CO2) and perform predictions of these three thermodynamic quantities on the basis of the proposed analytical expressions and in terms of experimental values of five molecular constants for CO2. The average relative deviations of the calculated values from the National Institute of Standards and Technology database over the temperature range from 300 to 6000 K are merely 0.053, 0.95, and 0.070%, respectively, for the entropy, enthalpy, and Gibbs free energy. The present predictive expressions are away from the utilization of plenty of experimental spectroscopy data and are applicable to treat CO2 capture and storage processes.