CO₂ fracturing is a promising technology for oil field development in tight, continental deposits, with potential advantages of enhanced oil recovery (EOR), CO₂ sequestration, and water conservation. Compared with CO₂-EOR techniques, such as CO₂ huff and puff and CO₂ flooding, CO₂ can interact with reservoir rock and fluid under higher pressure conditions during fracturing, resulting in CO₂ stimulation and sequestration effects that differ from those that occur during conventional CO₂-EOR. In this paper, the CO₂ interactions between CO₂ and reservoirs in continental tight oil reservoirs under fracturing conditions are systematically studied through laboratory experiments. The results show that under high pressure, CO₂ effectively changes the pore structure through the extraction of hydrocarbons, dissolution of the rock matrix, and migration of minerals. CO₂ dissolution of the rock matrix can significantly increase the number and complexity of fractures. Furthermore, CO₂ has a higher solubility in formation fluid under high-pressure conditions. Given the higher pressures, CO₂ forms a miscible phase with crude oil, diffuses more deeply into the formation, and reacts fully with the reservoir minerals and fluid during CO₂ fracturing. Accordingly, CO₂ can improve the permeability of the reservoir and flowability of crude oil significantly. Hence, CO₂ fracturing can enhance oil recovery and CO₂ sequestration more effectively. Core displacement experiments indicate that oil recovery of CO₂ soaking process after CO₂ fracturing is 36%, which is 12% and 9% higher than those of CO₂ huff and puff and CO₂ flooding with 5 pore volume, respectively. Field tests show that average oil production after CO₂ fracturing is 1.42 times higher than that after CO₂ flooding, which further validates the advantage of CO₂ fracturing and demonstrates its huge application potential.

The low permeability of shale matrices necessitates overcoming a threshold pressure gradient to initiate hydrocarbon flow, which poses a major constraint on recovery efficiency. However, the microscopic mechanisms underlying the threshold pressure gradient, particularly the roles of interfacial interactions and pore confinement, remain unclear. A comprehensive understanding of the threshold pressure gradient is essential for enhancing recovery strategies and improving shale oil extraction efficiency. This study provides a comprehensive analysis of the interfacial and size effects on the threshold pressure gradient within kerogen, quartz, and portlandite pores using molecular dynamics simulations. A method for assessing molecular thermal motion and quantifying the threshold pressure gradient was developed using molecular dynamics simulations. The results indicate that the threshold pressure gradient decreases in the order of kerogen, quartz, and portlandite pores. The adsorption characteristics of shale oil components at the interface were clarified through density distribution and molecular behavior analysis, and the factors contributing to the threshold pressure gradient were identified. It was found that the threshold pressure gradient is significantly influenced by the strength of interfacial interactions between the polar shale oil components and the solid matrix. Additionally, an analytical model was proposed to predict the correlation between the threshold pressure gradient and the pore size, which can extend the prediction of the threshold pressure gradient to a larger scale of thousands of nanometers. These findings offer insights into shale oil recoverability in nanopores and provide theoretical guidance for its extraction. Document Type: Original article Cited as: Cui, F., Meng, S., Jin, X., Qian, J., Liu, H., Wu, H., Wang, F. Cross-scale analysis on shale oil initiation in nanopores: Insights into threshold pressure gradient. Advances in Geo-Energy Research, 2025, 16(2): 131-142.https://doi.org/10.46690/ager.2025.05.05

CO₂ pre-injection fracturing is a promising technology for shale reservoirs development, with multiple advantages for improving the complexity of fractures, the production of crude oil, and the sequestration of CO₂. Previous research mostly focused on the CO₂ effect on macroscopic mechanical properties of shale. However, there are many phenomena closely related to shale micro mechanical behavior. Therefore, this study presents a systematic investigation into the effects of CO₂ on both macro and micro mechanical properties, as well as pore-fracture structures during CO₂ pre-injection fracturing in shale reservoirs. The results show that CO₂ can significantly decrease the tensile strength, uniaxial compressive strength, and elastic modulus of shale. With the increasing CO₂ treatment time, the macro mechanical properties of shale decrease gradually. The microscopic experiments show that this significant decrease may be due to two mechanisms. The first is the significant decrease in the micro-mechanical properties of shale. The results of indentation analysis show that the microscopic elastic modulus and hardness of shale decrease by 51.3% and 63.3% after CO₂ treatment. The second is the changes of the original shale framework. Pore-fractures structure analysis showed that after CO₂ treatment, a large number of dissolution pores are generated in the shale matrix. Meanwhile, there are propagation of original fractures and opening of structural weak planes, which lead to the form of new fractures. Under the action of these two mechanisms, the macro mechanical strength of shale is reduced significantly. Therefore, in the field application, proper soaking following CO₂ injection could lead to a significant overall reduction in mechanical strength, potentially lowering formation breakdown pressure, easing the requirements for treatment equipment, and enhancing fracturing effects.

Smart hydrogels, owing to their exceptional viscoelastic and deformable capacity in response to environmental stimulation involving temperature and pH, have been successfully applied in oilfields for purposes such as water and/or gas shutoff treatments. However, the CO₂ breakthrough problem in low permeability reservoirs has not been well solved. In this work, a rheological method-based Avrami dynamics model and Dickinson dynamics model were employed to investigate the dynamic gelation process of thermo-/pH-dual-sensitive PEG/PAMAM nanogels to further our understanding of the microstructure of their gelation and pertinence plugging application. Plugging experiments were performed by alternating injections of CO₂ and hydrogel solution in a slug type on three fractured low permeability cores with a backpressure of 13 MPa. The nanogels presented a secondary growth pattern from three to one dimension from micrometer to nanometer size with a morphological transformation from a sphere to an irregular ellipsoid or disk shape. The phase transition temperature was 50 °C, and the phase transition pH was 10. If both or either were below these values, the hydrogel swelled; otherwise, it shrank. Plugging results show that the plugging efficiency was higher than 99%. The maximum breakthrough pressure was 19.93 MPa, and the corresponding residual pressure remained 17.64 MPa for a 10 mD core, exhibiting great plugging performance and high residual resistance after being broken through by CO₂.