Summary: Wettability is a fundamental parameter significantly influencing fluid distributions, saturations, and relative permeability in porous media. Despite the availability of several wettability measurement techniques, obtaining consistent wettability index results, particularly in tight reservoirs, remains a challenge. Nevertheless, obtaining accurate wettability indices is crucial for gaining a more profound understanding of rock properties and precisely identifying and evaluating oil recovery processes. This study adapts T1-T2 nuclear magnetic resonance (NMR) in twin plugs (cores cut in half from the middle) style wettability measurement for different reservoirs. The fluid typing in different lithologies by T1-T2 NMR is proved to be effective by introducing D2O with a modified pressurization saturation process. Therefore, demarcating the regions requires multiple experiments, including sole brine, sole oil phase, and D2O imbibition processes, to define oil and water distribution regions. Such fluid typing ability enables better accuracy in wettability characterization. The weighing method shows good agreement with the T2 spectrum but lacks the ability to differentiate fluids. It is observed that the same fluid in various porous media displays different divisions of T1/T2 ratios. The wettability index of sandstone, tuff, and shale measured by weighing and T1-T2 NMR method are compared and studied to demonstrate the applicability of different methods. The weighing method and the NMR method, as modified-Amott methods, share the same fundamental principle but differ in their measurement techniques. This study’s T1-T2 NMR wettability indices are −0.52, 0.06, and 0.14, whereas the weighing wettability indices are −0.63, 0.07, and 0.34 of sandstone, tuff, and shale, respectively. In addition to the difference in shale wettability index, there are also differences in shale porosity measured by methods with/without the ability to differentiate the fluid types. The T1-T2 NMR method is more accurate in measuring the wettability of shale because it can distinguish among free water in pores, structural water, and clay-bound water in smectitic clay minerals. If the clay-related water is not treated properly, the hydrophilicity of the shale will be overestimated. Ultimately, four types of pores (water-wet, oil-wet, mixed-wet, and unconnected pores) are classified and quantified by the proposed NMR method.

As kerogen is the main organic component in shale, the adsorption capacity, diffusion and permeability of the gas in kerogen plays an important role in shale gas production. Based on the molecular model of type II kerogen, an organic nanoporous structure was established. The Grand Canonical Monte Carlo (GCMC) and Molecular Dynamics (MD) methods were used to study the adsorption and diffusion capacity of mixed gas systems with different mole ratios of CO₂ and CH₄ in the foregoing nanoporous structure, and gas adsorption, isosteric heats of adsorption and self-diffusion coefficient were obtained. The selective permeation of gas components in the organic pores was further studied. The results show that CO₂ and CH₄ present physical adsorption in the organic nanopores. The adsorption capacity of CO₂ is larger than that of CH₄ in organic pores, but the self-diffusion coefficient of CH₄ in mixed gas is larger than that of CO₂. Moreover, the self-diffusion coefficient in the horizontal direction is larger than that in the vertical direction. The mixed gas pressure and mole ratio have limited effects on the isosteric heat and the self-diffusion of CH₄ and CO₂ adsorption. Regarding the analysis of mixed gas selective permeation, it is concluded that the adsorption selectivity of CO₂ is larger than that of CH₄ in the organic nanopores. The larger the CO₂/CH₄ mole ratio, the greater the adsorption and permeation selectivity of mixed gas in shale. The permeation process is mainly controlled by adsorption rather than diffusion. These results are expected to reveal the adsorption and diffusion mechanism of gas in shale organics, which has a great significance for further research.

In some low-permeable reservoirs, the miscibility pressure is far higher than the formation pressure, which makes it not feasible to have a CO₂ miscible displacement. In this study, an oil-soluble surfactant, CAE, was designed and synthesized to reduce interfacial tension (IFT) and CO₂-oil minimum miscible pressure (MMP), making it possible to release miscible displacement increasing oil recover. Experiment results showed that oil soluble surfactant can be dissolved in supercritical CO₂ but not soluble in water. It is also found that the CAE preslug displacement has the higher displacement efficiency than displacement with the CAE dissolved in CO₂. Based on a series of CAE preslug displacement experiments with varying CAE concentrations, the optimal injection concentration of CAE is 0.2%. Moreover the MMP determined under the CAE concentration of 0.2% is 6.1 MPa lower than that of pure CO₂ displacement. It reduces the MMP more than liquid gas preslug displacement (3.2 MPa) when the same volume of liquid gas is used with the CAE used in CAE preslug displacement test.

Flue gas flooding is one of the important technologies to improve oil recovery and achieve greenhouse gas storage. In order to study multicomponent flue gas storage capacity and enhanced oil recovery (EOR) performance of flue gas water-alternating gas (flue gas–WAG) injection after continuous waterflooding in an oil reservoir, a long core flooding system was built. The experimental results showed that the oil recovery factor of flue gas–WAG flooding was increased by 21.25% after continuous waterflooding and flue gas–WAG flooding could further enhance oil recovery and reduce water cut significantly. A novel material balance model based on storage mechanism was developed to estimate the multicomponent flue gas storage capacity and storage capacity of each component of flue gas in reservoir oil, water and as free gas in the post-waterflooding reservoir. The ultimate storage ratio of flue gas is 16% in the flue gas–WAG flooding process. The calculation results of flue gas storage capacity showed that the injection gas storage capacity mainly consists of N₂ and CO₂, only N₂ exists as free gas phase in cores, and other components of injection gas are dissolved in oil and water. Finally, injection strategies from three perspectives for flue gas storage, EOR, and combination of flue gas storage and EOR were proposed, respectively.