CO₂ injection into oil reservoirs is expected to achieve enhanced oil recovery along with the benefit of carbon storage, while the application potential of this strategy for shale reservoirs is unclear. In this work, a numerical model for multiphase flow in shale oil reservoirs is developed to investigate the impacts of nano-confinement and oil composition on shale oil recovery and CO₂ storage efficiency. Two shale oils with different maturity levels are selected, with the higher-maturity shale oil containing lighter components. The results indicate that the saturation pressure of the lower-maturity shale oil continues to increase with increasing CO₂ injection, while that of the higher-maturity shale oil continues to decrease. The recovery factor and CO₂ storage rate for higher-maturity shale oil after CO₂ huff-n-puff are 12.02% and 44.76%, respectively, while for lower-maturity shale oil, these are 4.41% and 69.33%, respectively. These data confirm the potential of enhanced oil recovery in conjunction with carbon storage in shale oil reservoirs. Under the nano-confinement impact, a decrease in the oil saturation in the matrix during production is reduced, which leads to a significant increase in oil production and a significant decrease in gas production. The oil production of the two kinds of shale oil is comparable, but the gas production of higher-maturity shale oil is significantly higher. Nano-confinement shows a greater impact on the bubble point pressure of higher-maturity shale oil and a more pronounced impact on the production of lower-maturity shale oil.

Methane adsorption is a critical assessment of the gas storage capacity (GSC) of shales with geological conditions. Although the related research of marine shales has been well-illustrated, the methane adsorption of marine-continental transitional (MCT) shales is still ambiguous. In this study, a method of combining experimental data with analytical models was used to investigate the methane adsorption characteristics and GSC of MCT shales collected from the Qinshui Basin, China. The Ono-Kondo model was used to fit the adsorption data to obtain the adsorption parameters. Subsequently, the geological model of GSC based on pore evolution was constructed using a representative shale sample with a total organic carbon (TOC) content of 1.71%, and the effects of reservoir pressure coefficient and water saturation on GSC were explored. In experimental results, compared to the composition of the MCT shale, the pore structure dominates the methane adsorption, and meanwhile, the maturity mainly governs the pore structure. Besides, maturity in the middle-eastern region of the Qinshui Basin shows a strong positive correlation with burial depth. The two parameters, micropore pore volume and non-micropore surface area, induce a good fit for the adsorption capacity data of the shale. In simulation results, the depth, pressure coefficient, and water saturation of the shale all affect the GSC. It demonstrates a promising shale gas potential of the MCT shale in a deeper block, especially with low water saturation. Specifically, the economic feasibility of shale gas could be a major consideration for the shale with a depth of <800 m and/or water saturation >60% in the Yushe-Wuxiang area. This study provides a valuable reference for the reservoir evaluation and favorable block search of MCT shale gas.

Thermal recovery techniques for producing oil sands have substantial environmental impacts. Surfactants can efficiently improve thermal bitumen recovery and reduce the required amount of steam. Such a technique requires solid knowledge about the interaction mechanism between surfactants, bitumen, water, and rock at the nanoscale level. In particular, oil sands ores have extremely complex mineralogy as they contain many clay minerals (montmorillonite, illite, kaolinite). In this study, molecular dynamics simulation is carried out to elucidate the unclear mechanisms of clay minerals contributing to the bitumen recovery under a steam–anionic surfactant co-injection process. We found that the clay content significantly influenced an oil detachment process from hydrophobic quartz surfaces. Results reveal that the presence of montmorillonite, illite, and the siloxane surface of kaolinite in nanopores can enhance the oil detachment process from the hydrophobic surfaces because surfactant molecules have a stronger tendency to interact with bitumen and quartz. Conversely, the gibbsite surfaces of kaolinite curb the oil detachment process. Through interaction energy analysis, the siloxane surfaces of kaolinite result in the most straightforward oil detachment process. In addition, we found that the clay type presented in nanopores affected the wettability of the quartz surfaces. The quartz surfaces associated with the gibbsite surfaces of kaolinite show the strongest hydrophilicity. By comparing previous experimental findings with the results of molecular dynamics (MD) simulations, we observed consistent wetting characteristics. This alignment serves to validate the reliability of the simulation outcomes. The outcome of this paper makes up for the lack of knowledge of a surfactant-assisted bitumen recovery process and provides insights for further in-situ bitumen production engineering designs.

Utilizing CO₂ to enhance shale oil recovery has a huge potential and thus has gained widespread popularity in recent years. However, the microscopic mechanisms of CO₂ enhancing shale oil recovery remain poorly understood. In this paper, the molecular dynamics simulation method is adopted to investigate the replacement behavior of CO₂ in shale oil reservoirs from a micro perspective. Three kinds of $n$-alkanes are selected as the simulative crude oil in silica nanopores. Molecular dynamics models are established to study the occurrence patterns of different alkanes on the rock surface and the alkane-stripping characteristics of CO₂. The fluid density, mean square displacement and centroid variation are evaluated to reveal the effect of CO₂ on alkanes. The results indicate that different alkanes exhibit varying occurrence characteristics of oil film on the rock surface of the shale reservoir. Specifically, a higher carbon number leads to a thicker oil film. Through the alkane molecular gaps, CO₂ penetrates the alkane molecular system and reaches the rock surface to effectively strip the oil film of different alkane molecules. CO₂ will more readily mix with the stripped oil molecules and displace them from the rock surface when the carbon number is small. The process for CO₂ replacing crude oil on the rock surface can be divided into four typical stages, namely, CO₂ diffusion, competitive adsorption, emulsification and dissolution, and CO₂-alkanes miscible phase (for light alkanes). This study contributes to the improvement of micro-scale enhanced oil recovery mechanisms for shale oil via CO₂ injection and provides a guidance for enhancing shale oil recovery by using CO₂.

Accurate construction of a seepage model for a multifractured horizontal well in a shale gas reservoir is essential to realizing the forecast of gas well production, the pressure transient analysis, and the inversion of the postfracturing parameters. This study introduces a method for determining the fracture control region to characterize the flow area of the matrix within the hydraulic fracture network, distinguishing the differences in the flow range of the matrix system between the internal and external regions caused by the hydraulic fracture network structure. The corresponding derivation and solution methods of the semi-analytical seepage model for fractured shale gas well are provided, followed by the application of case studies, model validation, and sensitivity analysis of parameters. The results indicate that the proposed model yields computational results that closely align with numerical simulations. It is observed that disregarding the differentiation of matrix flow area between the internal and external regions of the fracture network led to an overestimation of the estimated ultimate recovery, and the boundary-controlled flow period in typical well testing curves will appear earlier. Because hydraulic fracture conductivity can be influenced by multiple factors simultaneously, conducting a sensitivity analysis using combined parameters could lead to inaccurate results in the inversion of fracture parameters.

This work summarizes our recent findings on hydraulic fracturing-induced seismicity nucleated in the Duvernay shale reservoirs within the Western Canada Sedimentary Basin. A coupled model of in-situ stress and fracture-fault systems was built to quantify four-dimensional stress and pressure changes and spatiotemporal seismicity nucleation during hydraulic fracturing. Five triggering mechanisms were successfully recognized in seismicity-frequent areas, including a direct hydraulic connection between impermeable faults and hydraulic fractures, fault slip owing to downward pressure diffusion, fault reactivation due to upward poroelastic stress perturbation, aftershocks of mainshock events, and reactivation of natural fractures surrounding the faults. This work shed light on how fracturing operations triggered the induced seismicity, providing a solid foundation for the investigation of controlling factors and mitigation strategies for hydraulic fracturing-induced seismicity.

Tight oil reservoirs are characterized by the ultra-low porosity and permeability, making it a great challenge to enhance oil production. Owing to the fast development in hydraulic fracturing technology of horizontal wells, tight oil has been widely explored in North America. Individual wells have a long term of low production after a rapid production decline. This causes low cumulative production in tight oil reservoirs. A rate decline curve is the most common method to forecast their production rates. The forecast can provide useful information during decision making on future development of production wells. In this paper, a relationship is developed between the parameters of a hyperbolic decline curve and the reservoir/fracture properties when a reservoir simulation model is used based on the data from a real field. Understanding of this relationship improves the application of the hyperbolic decline curve and provides a useful reference to forecast production performance in a more convenient and efficient way.