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Shale reservoirs represent a significant untapped source of recoverable oil, and even a slight increase in recovery can yield substantial benefits. In recent years, there has been a growing interest in the development of shale reservoirs due to their vast potential. Shale reservoirs are characterized by their intricate pore structures, ultra-low porosity, and extremely low permeability. Consequently, fluid flow within shale formations is highly complex, and the distribution of shale oil is diverse. There is an urgent need to conduct research into the flow behavior of shale reservoirs and the modes of crude oil occurrence within them, in order to support effective shale oil extraction in the field. In this work, we established a MCMP-MRT-LBM model considering nano-scale confinement effects such as slip and adsorption. The model is employed to simulate single pore channels and blind-end pores to investigate the distinct mechanisms involved in water flooding, CO2 immiscible flooding, and CO2 miscible flooding. Subsequently, the research explores the fluid flow characteristics associated with these three development methods within porous media, as well as the distribution of remaining oil. Then we compared the oil displacement efficiency, swept volume, actual liquid injection volume and displacement front position of the three fluids in porous media. The results reveal that water flooding exhibits superior displacement performance in single pore channels, while CO2 miscible flooding proves to be the most effective method for exploiting oil in blind-end pores. In porous media, CO2 miscible flooding successfully mitigates fingering phenomena and efficiently recovers crude oil located at blind-end and corner regions of the pores. The recovery efficiency achieved through CO2 miscible flooding is approximately 30% higher than that of water flooding and about 10% greater than CO2 immiscible flooding.

Laminar argillaceous limestone continental shale is an important oil reservoir in Jiyang Depression, Bohai Bay Basin of China. Affected by the laminar structure, the spatial propagation morphology of hydraulic fracturing is not clear. To reveal the propagation law of hydraulic fracturing pathway in laminar marl continental shale, the mineral content and basic rock mechanics test are firstly carried out on the cores from the wells in Jiyang Depression. Secondly the similar material cores with standard-size and large-size are manufactured and processed. Finally, combined with physical model experiments, acoustic emission and moment tensor inversion techniques, the hydraulic fracturing experiments on the large-size cores under different stress differences are conducted. The experimental results show that the in situ stress (confining stresses), laminar structure, and lithological distribution jointly affect the propagation mode of fractures. As the horizontal stress difference increases, the stimulated reservoir volume gradually decreases, and the number of shear fractures decreases accordingly. Macroscopically, the pump pressure curve shows obvious fluctuation in the case with lower horizontal stress difference, which is the external performance of hydraulic fracture initiation–obstruction–turning–penetrating–obstruction–turning. The content of brittle and plastic minerals has a significant impact on the fracture complexity, particularly the layers with high argillaceous content have a significant inhibitory effect on fracture propagation. The weakly cemented lamination or bedding plane is easy to capture the fracture and make it propagate along the bedding plane, thereby increasing the complexity of fracture network. The research results are expected to provide a theoretical reference for design and optimization of hydraulic fracturing parameter in continental shale oil exploration and development.

The sandstone yield strength and tensile strength were increased under cyclic loading paths by using the Brazilian splitting method. The experiment shows that (1) the sandstone specimens exhibit multiple penetrating crack damage by cyclic loading, while the tensile strength slightly increases; (2) the sandstone horizontal strain (Exx) concentration area decreases, and the shear strain (Exy) concentration area increases under cyclic loading, and the damage form changes from completely brittle tensile damage to ductile mixed tensile-shear damage; (3) the mechanism of the increase in tensile strength of the specimen under cyclic loading was explained by digital image correlation (DIC) technique. The results indicate that a time lag occurs in the horizontal strain concentration zone, and the area of the penetration zone decreases from the cyclic loading effect, while the reduced stress concentration leads to increased tensile strength of the specimens.

The production capacity of shale oil reservoirs after hydraulic fracturing is influenced by a complex interplay involving geological characteristics, engineering quality, and well conditions. These relationships, nonlinear in nature, pose challenges for accurate description through physical models. While field data provides insights into real-world effects, its limited volume and quality restrict its utility. Complementing this, numerical simulation models offer effective support. To harness the strengths of both data-driven and model-driven approaches, this study established a shale oil production capacity prediction model based on a machine learning combination model. Leveraging fracturing development data from 236 wells in the field, a data-driven method employing the random forest algorithm is implemented to identify the main controlling factors for different types of shale oil reservoirs. Through the combination model integrating support vector machine (SVM) algorithm and back propagation neural network (BPNN), a model-driven shale oil production capacity prediction model is developed, capable of swiftly responding to shale oil development performance under varying geological, fluid, and well conditions. The results of numerical experiments show that the proposed method demonstrates a notable enhancement in R² by 22.5% and 5.8% compared to singular machine learning models like SVM and BPNN, showcasing its superior precision in predicting shale oil production capacity across diverse datasets. [ABSTRACT FROM AUTHOR]

Physicochemical forces exert non-neligible effects on the migration of micro-particles in channels. Experiments, analytical and non-resolved computational fluid dynamics models have failed to decipher the dynamic behaviors of these particles when carried by fluid flow. In this paper, particle-scale numerical simulation is conducted to study the adhesive micro-particle migration process during duct flow in channels with a large characteristic dimension ratio and those with relatively small such ratio based on the coupled lattice Boltzmann method-discrete element method. The interaction between particle and fluid flow is dealt with by the immersed moving boundary condition. For micro-particle migration in duct flow, the effects of hydrodynamic force, adhesive force and particle concentration on the aggregation of particles are investigated. Based on the concept of hydrodynamic and adhesive force ratio, a stable aggregation distribution map is proposed to help analyze the distribution and size of the formed agglomerates. For micro-particle migration in channels with small characteristic dimension ratio, the general particle migration process is analyzed, which includes single particle retention, followed by particle capture, and the migration of large agglomerates. It is concluded that two factors accelerate single particle retention in a curved channel. Moreover, it is established that higher fluid flow rate facilitates the formation of large and compact agglomerate, and blockage by this can cause severe damage to the conductivity of the channel. [ABSTRACT FROM AUTHOR]

The heterogeneity of fractured reservoir is strong due to the heterogeneity of fracture development. The problem of uneven liquid production profile along the horizontal well may exist in the process of exploiting fractured reservoir with horizontal well. ICD technology is a new well completion technology that can inhibit high permeability zone and improve fluid flow in low permeability zone by creating an additional pressure drop between the wellbore and the tubing. In this paper, the distribution of permeability in different heterogeneous reservoirs is obtained by inverse solution of Lorentz curve. Using numerical simulation method, the production performance characteristics and reservoir water flooding rules of horizontal wells using ICD technology in different heterogeneous fractured bottom water reservoirs are studied, and the characteristics of optimal ICD water control intensity under different heterogeneous degrees are analyzed. It is found that ICD technology can better control the liquid production in the high permeability zone, delay the water breakthrough time in the high permeability zone, increase the production degree in the low permeability zone, and improve the development effect of the reservoir. Through case calculation and analysis, it is verified that ICD completion in fractured reservoir can reduce liquid production in high water cut section, increase liquid production in low water cut section, reduce water cut of oil well and increase oil production. The research results provide a new technical idea for water control methods of fractured reservoirs. [ABSTRACT FROM AUTHOR]

Shale is a heterogeneous porous medium with complex pore structures. Therefore, it is of great significance for shale gas exploration and development to study the development characteristics of mineral/clay components and their effects on carbon dioxide adsorption capacity by high-precision experiments. In this paper, the mineral/clay composition and adsorption characteristics of shale were systematically studied by means of X-ray diffraction, low temperature carbon dioxide and nitrogen adsorption methods, and then the influence of CO2 injection on the enhanced oil recovery of shale gas was analyzed. The results show that the non-clay minerals of the 12 shale samples mainly include quartz, plagioclase, iron dolomite, calcite and pyrite. The proportion of calcite and quartz in the shale of well N55 is greater than 85% and that of calcite and quartz in the shale of well T308 is between 70-95%. Moreover, the contents of various clay mineral components in the samples were measured by natural tablets, ethylene glycol saturated tablets and high-temperature tablets in sequence. The results show that the main clay minerals in the shales of Wells N55 and T308 are illite and Aemon mixed layers, and their content is basically the same. The mesoporous pores are the most developed in shale, and the pore volume and specific surface volume of mesoporous shale are 65% and 36%, respectively. The larger the surface is, the more points the methane molecules adsorb, and the greater the adsorption capacity. There is an optimal CO2 injection rate in the process of CO2 stimulation and stimulation, and the shale requires longer injection time to reach the optimal CO2 injection rate. Shale samples with higher quartz content have higher recovery rates. [ABSTRACT FROM AUTHOR]