The CO₂ sequestration capacity evaluation of reservoirs is a critical procedure for carbon capture, utilization, and storage (CCUS) techniques. However, calculating the sequestration amount for CO₂ flooding in low-permeability reservoirs is challenging. Herein, a method combining numerical simulation technology with artificial intelligence is proposed. Based on the typical geological and fluid characteristics of low-permeability oil reservoirs in the Liaohe oilfield, the CMG 2020 version software GEM module is used to establish a model for CO₂ flooding and sequestration. Meanwhile, a calculation method for the effective sequestration coefficient of CO₂ is established. We systematically study the sequestration rules in low-permeability reservoirs under varying conditions of permeability, reservoir temperature, and initial reservoir pressure. The results indicate that, as the permeability and sequestration pressure of the reservoir increase, oil recovery gradually increases. The proportion of structurally bound sequestration volume increases from 55% to 60%. Reservoir temperature has minimal impact on both the recovery rate and the improvement in sequestration efficiency. Sequestration pressure primarily improves sequestration efficiency by increasing the dissolution of CO₂ in the remaining oil and water. The calculation chart for the effective sequestration coefficient, developed using artificial intelligence algorithms under multi-factor conditions, enables accurate and rapid evaluation of the sequestration potential and the identification of favorable sequestration areas in low-permeability reservoirs. This approach provides valuable technical support for CO₂ flooding and sequestration in pilot applications.

As one of the leading technologies for chemical enhanced oil recovery (cEOR), surfactant–polymer (SP) flooding technology has long attracted the interest of petroleum scientists and engineers. However, most of its application scenarios are based on the five-spot well pattern. The EOR potential in an inverted seven-spot well pattern is seldom ever recorded. The applicability of the SP system in the inverted seven-spot well pattern was examined based on the physical characteristics of Karamay Oilfield in China. The numerical simulation and the one-dimensional core flooding experiment were used to compare the sweep intensities and EOR abilities of the two well patterns. The migration law and the EOR ability of the SP system were assessed by a specially made one-third inverted seven-spot configuration. The main controlling factors and compatibility charts of SP flooding development in the inverted seven-spot well pattern were obtained. Results show that 61% of the region is represented by a weak swept state in the inverted seven-spot well pattern. The effective swept area is greatly increased by appropriately raising the viscosity and slug size of the SP system. Compared to constant viscosity injection, step-down viscosity injection further increases the sweep range and oil recovery. The inverted seven-spot well pattern has a greater swept area of the SP system than the five-spot one, but a weaker strength. Polymer concentration is the most effective factor of SP flooding in the inverted seven-spot well pattern, followed by oil viscosity and surfactant concentration. The study can broaden the application of the SP system in the inverted seven-spot well pattern.

The transport process of two-phase fluids in porous media significantly affects groundwater seepage and carbon capture, utilization, and storage, as well as oilfield development. Due to limitations in analytical methods, the dynamic mechanisms controlling pore-scale flow processes remain insufficiently understood. Based on image analysis technology, this research elucidates flow instabilities triggered by the competition between capillary and viscous forces and clarifies their underlying mechanisms. Displaced-phase microcapillary number is introduced to provide a comprehensive analysis of the two-phase flow behavior. The results indicate that as Camicro increases, crude oil recovery factor declines, and the displacement process transforms from stable to unstable, with a critical Camicro of 10−4.09. When Camicro = 10−4.33, viscous force dominates the flow process through Saffman–Taylor instability, exhibiting channeling with an extremely low recovery factor. When Camicro = 10−3.70, capillary force dominates the flow process. The rapid rebound of the local pressure causes a capillary burst, which makes the oil–water interface selection not follow the lowest threshold pressure rule. The sequential breakthrough effect, driven by the interaction between Saffman–Taylor instability and capillary burst, results in reduced residual oil in the swept area. As displacement progresses, the influence of viscous forces on oil–water distribution gradually weakens, while the impact of capillary forces becomes increasingly dominant. This transition is reflected in the weakening of the dynamic wetting effect and the formation of residual oil due to the Jamin effect.