Hydrate-based CO₂ sequestration is a novel approach that can not only realize permanent CO₂ sequestration but can also form an artificial cap to prevent its upward migration. In this work, a self-developed large-scale 3D apparatus was employed to investigate hydrate formation characteristics in hydrate-based CO₂ sequestration at a constant liquid CO₂ injection rate through a vertical well for the first time. Temperature and pressure evolutions in the sediment were analyzed in detail. Key indicators, including cumulative sequestered CO₂, CO₂ in hydrate and liquid phases, the instantaneous hydrate conversion, and liquid CO₂ retention rates, were calculated. The results show that hydrate continuously forms with increased CO₂ injection and exhibits strong heterogeneity due to the variation in hydrate formation rate and quantity. Severe liquid CO₂ heterogeneous figuring phenomena occur since hydrate deteriorates the effective pore structure and topology, resulting in relatively small cumulative sequestered CO₂ when a large amount of CO₂ is released from the outlet. Meanwhile, the instantaneous hydrate conversion and liquid CO₂ retention rates have large fluctuations owing to water consumption and variation in the effective contact area between liquid CO₂ and water. However, hydrate formation does not cause blockage of wellbore and formation nearby under given experimental conditions, which is beneficial for hydrate formation in deeper sediment. This study provides insights into hydrate formation and liquid CO₂ immigration regularity during hydrate-based CO₂ sequestration and demonstrates its feasibility at a field scale.

Steam flooding is easily induced to transverse flow, with a limited swept area and low displacement efficiency. Therefore, chemical agents have been used to assist in steam flooding for heavy oil extraction. However, research into the driving mechanisms and modes of occurrence of residual oil is insufficient. In this work, a flooding simulation was conducted to understand the occurrence mechanism of residual oil during the flooding process in heavy oil reservoirs. First, the foam properties of a novel DES (Deep Eutectic Solvent) and CTAB (Cetyltrimethyl Ammonium Bromide) composite system with ultra-low interfacial tension were tested. The optimal concentration and gas–liquid ratio of the foam agent solution were determined. Secondly, the NFAS (N₂ foam-assisted steam flooding) was carried out after steam flooding, and the flow behavior of crude oil at different flow pathway zones was researched. In the end, the remaining oil morphology and distribution characteristics under different displacement times were analyzed, determining the mode of remaining oil occurrence during NFAS flooding. The results show that (1) the novel DES and CTAB system has good foam properties. The best concentration is 0.5 wt%, and the optimal ratio of gas to liquid is 1:1. (2) In the steam flooding stage, the columnar remaining oil in the narrow hole near the flow pathway increases, and the cluster remaining oil in the far flow channel changes into film and columnar. (3) During NFAS displacement, the residual oil primarily presents a state of fully mixing the O/W emulsion formed after blending and dispersing with oil, gas, and water. (4) After the NFAS flooding stage, the remaining oil was distributed in each throat. The remaining oil in the near passage is mostly blocked by foam in large holes with a pore coordination number of 4 and 5. The residual oil in the distant runner is distributed in the thick and middle throats. (5) NFAS flooding outperforms steam flooding by significantly decreasing residual oil in narrow passages of the main flow channel and near flow channels, resulting in a substantial 44.9% increase in overall recovery rate.

The aim of this study was to determine the influence of four inorganic salts, KCl, NaCl, KBr and NaBr, on the thermodynamic conditions of methane hydrate formation. In order to achieve this, the vapor–liquid water-hydrate (VL_WH) equilibrium conditions of methane (CH₄) hydrate were measured in the temperature range of 274.15 K–282.15 K by the isothermal pressure search method. The results demonstrated that, in comparison with deionized water, the four inorganic salts exhibited a significant thermodynamic inhibition on CH₄ hydrate. Furthermore, the inhibitory effect of Na⁺ on methane hydrate is more pronounced than that of K⁺, where there is no discernible difference between Cl⁻ and Br⁻. The dissociation enthalpy ($∆H_{diss}$) of CH₄ hydrate in the four inorganic salt solutions is comparable to that of deionized water, indicating that the inorganic salt does not participate in the formation of hydrate crystals. The Chen–Guo hydrate model and N–NRTL–NRF activity model were employed to forecast the equilibrium conditions of CH₄ hydrate in electrolyte solution. The absolute relative deviation (AARD) between the predicted and experimental values were 1.24%, 1.08%, 1.18% and 1.21%, respectively. The model demonstrated satisfactory universality and accuracy. This study presents a novel approach to elucidating the mechanism and model prediction of inorganic salt inhibition of hydrate.

Natural gas hydrate (NGH) is a clean resource characterized by abundant potential reserves, clean combustion, and high energy density. Although significant progress has been made in the development of NGH resources all around the world, challenges still exist that hinder commercial exploitation, such as a low daily gas production rate and short steady production periods. One significant reason lies in the complex gas–liquid–solid phase transitions occurring within the formation during production, which lead to changes in flow capacity. Understanding the phase change mechanism of NGH reservoirs will help to further reveal the production increase mechanism. To address the phase transitions’ effect on production, this paper establishes a numerical simulation model for the depressurization exploitation of natural gas hydrates in order to investigate phase transition characteristics at the field scale. First, the phase equilibrium calculation method is presented and the phase equilibrium curve is modified by considering the capillary effect, soluble salt, and surface adsorption. Then, the phase transition model is successfully characterized in a simulation and the numerical simulation model is established based on the first test project parameters in the Shenhu area. The production characteristics of different sediment types (montmorillonite, South China Sea sediments, kaolin, and silt) are analyzed under the effects of water content and salinity. It is shown that lower initial water content and higher salinity result in higher gas production. The results provide a better understanding of the effects of phase transition parameters on NGH production at the field scale.

Phase transition in gas hydrate reservoirs has a significant effect on the fluid flow dynamic when performing test production, which should be carefully studied. This study systematically investigates the phase transition characteristics of natural gas hydrates during the depressurization extraction process through laboratory-scale numerical simulations. First, a laboratory-scale numerical simulation model is established with dimensions of 1 m × 1 m × 1 m. In the simulation, the nanoscale and microscale effect on phase transition is considered. Then, the analysis of how different sediment types and their properties affecting gas production dynamics is presented. The results show that hydrate dissociation and formation are significantly influenced by factors such as the pore scale, salinity, and water content. In particular, montmorillonite had the most significant effect, leading to a 525.25% increase in gas production, while the impact of silty soil was relatively smaller. The increase in salinity inhibited hydrate formation but promoted dissociation, resulting in a significant increase in gas production, especially when the salinity reached to 3.5%, where gas production increased by 590.21%. An increase in water content led to a significant decrease in production. Through monitoring temperature and pressure changes during the extraction process, the different physical fields are analyzed, providing important theoretical support and practical guidance for the efficient extraction of natural gas hydrates.