Many factors need to be considered in the evaluation of tight conglomerate reservoirs, including the microscopic pore-throat structure, pore connectivity, lithology, porosity, permeability, and clay mineral content. The contents and types of clay minerals reflect the mineral evolution process during the deposition of the reservoir and can reflect the reservoir’s physical properties to a certain extent. In this study, cores from the Baikouquan Formation in Mahu were used to comprehensively analyze the effects of the clay mineral content on the physical properties of a tight conglomerate reservoir, including field emission scanning electron microscopy (FE-SEM), casting thin section observations, X-ray diffraction (XRD), interface property testing, high-pressure mercury injection, low temperature N2 adsorption, and nuclear magnetic resonance (NMR)-movable fluid saturation testing. The results revealed that differences in different lithologies lead to differences in clay mineral content and pore structure, which in turn lead to differences in porosity and permeability. The interface electrification, adsorption, and specific surface area of the reservoir are positively correlated with the clay mineral content, which is mainly affected by the smectite content. As the clay mineral content increases, the proportion of nanoscale pore throats increases, and the core becomes denser. The saturation of the movable fluid controlled by the >50 nm pore throats in the .tight conglomerate ranges from 8.7% to 33.72%, with an average of 20.24%. The clay mineral content, especially the I/S (mixed layer of Illite and montmorillonite) content, is negatively correlated with the movable fluid. In general, the research results clarified the relationship between the lithology and physical properties of clay minerals and the microscopic pore structure of the tight conglomerate reservoirs in the Baikouquan Formation in the Mahu area.

The precise characterization of a tight glutenite reservoir’s microscopic pore structure is essential for its efficient development. However, it is difficult to accurately evaluate using a single method, and its microscopic heterogeneity is not fully understood. In this study, a combination of X-ray diffraction, casting thin section observations, scanning electron microscopy, high-pressure mercury injection, constant-speed mercury injection, X-ray computed tomography, and the advanced mathematical algorithms in the AVIZO 8.0 visualization software was used to construct the three-dimensional digital core of a glutenite reservoir at the study site, and the parameters of the pore network model were extracted. The overall microscopic pore structure characteristics were quantitatively investigated from multiple scales. Based on this, the mineral quantitative evaluation system (QEMSCAN) examined the microscopic heterogeneity of the glutenite reservoir and its impact on seepage. The results show that the glutenite reservoir in the study block can be classified into three categories based on lithology and capillary pressure curve characteristics. The type I reservoir samples have large and wide pore throats, low threshold pressure, and high reservoir quality; type Ⅱ reservoir samples are characterized by medium-sized pore throat, medium threshold pressure, and moderate reservoir quality; and the small and narrow pore throat, high threshold pressure, and poor reservoir quality are characteristics of type III reservoir samples. The various pore throat types and mineral distributions are due to the differences in dissolution, compaction, and cementation. The continuous sheet pores have good connectivity, which is related to the interconnection of primary intergranular pores and strip fractures, while the connectivity of isolated pores is significantly poor, which is related to the development of intragranular dissolved pores and intercrystalline pores. This suggests the deterioration of physical properties and pore throat connectivity, reduced average pore radius, and decreased pore sorting as decreasing permeability. The tight glutenite pores range in size from 5 nm to 80 μm and primarily feature Gaussian and bimodal distribution patterns, and submicron–micron pores contribute more to seepage. The effective pores were found to be attributed to the slowing effect of abnormally high pressure on the vertical stress, and the protective effect was positively correlated with the high-pressure strength. Notably, there is strong microscopic heterogeneity in the distribution of the reservoir matrix minerals and the pore throat size. As a result, the injected fluid easily flows along the preferential seepage channel with pore development and connectivity. This study provides new insights into the exploration and development of similar tight reservoirs.

High-pressure air injection (HPAI) is one of the effective methods to improve shale oil recovery after the primary depletion process. However, the seepage mechanisms and microscopic production characteristics between air and crude oil are complicated in porous media during the air flooding process. In this paper, an online nuclear magnetic resonance (NMR) dynamic physical simulation method for enhanced oil recovery (EOR) by air injection in shale oil was established by combining high-temperature and high-pressure physical simulation systems with NMR. The microscopic production characteristics of air flooding were investigated by quantifying fluid saturation, recovery, and residual oil distribution in different sizes of pores, and the air displacement mechanism of shale oil was discussed. On this basis, the effects of air oxygen concentration, permeability, injection pressure, and fracture on recovery were studied, and the migration mode of crude oil in fractures was explored. The results show that the shale oil is mainly found in <0.1 μm (small pores), followed by 0.1–1 μm (medium pores), and 1–10 μm (macropores); thus, it is critical to enhancing oil recovery in pores less than 0.1 and 0.1–1 μm. The low-temperature oxidation (LTO) reaction can occur by injecting air into depleted shale reservoirs, which has a certain effect on oil expansion, viscosity reduction, and thermal mixing phases, thereby greatly improving shale oil recovery. There is a positive relationship between air oxygen concentration and oil recovery; the recoveries of small pores and macropores can increase by 3.53 and 4.28%, respectively, and they contribute 45.87–53.68% of the produced oil. High permeability means good pore-throat connectivity and greater oil recovery, and the production degree of crude oil in three types of pores can be increased by 10.36–24.69%. Appropriate injection pressure is beneficial to increasing the oil–gas contact time and delaying gas breakthrough, but high injection pressure will result in early gas channeling, which causes the crude oil in small pores to be difficult to produce. Notably, the matrix can supply oil to fractures due to the mass exchange between matrix fractures and the increase of the oil drainage area, and the recoveries of medium pores and macropores in fractured cores increased by 9.01 and 18.39%, respectively; fractures can act as bridges for matrix crude oil migration, which means that proper fracturing before gas injection can make the EOR better. This study provides a new idea and a theoretical basis for improving shale oil recovery and clarifies the microscopic production characteristics of shale reservoirs.