Gravity and capillary forces play pivotal roles in the natural capillary-driven spontaneous imbibition process. The opacity of the medium and the intricate pore structure make it challenging to elucidate the influence of gravity force on co-current gas–water imbibition. A series of pore-scale visualization experiments were conducted using capillary tubes of five different diameters (100, 300, 400, 500, and 1000 μm). The vector concept, represented by the interaction angle with the horizontal direction, was employed to quantify the varying levels of gravity force in the imbibition process, and its impact on imbibition recovery was assessed quantitatively. The findings revealed that the primary influence of gravity on gas–water spontaneous imbibition recovery was predominantly observed in the early stage. Due to the water blocking effect, the gas–water spontaneous imbibition process temporarily halted and resumed when the capillary diameter was 300 μm (at an angle of 60°). For capillary diameters between 100 and 500 μm, the water blocking effect induced a wave-like variation in gas–water spontaneous imbibition recovery as the interaction angle increased. Conversely, for a capillary diameter of 1000 μm, imbibition recovery exponentially decreased with the interaction angle, and no water blocking effect was observed. Consequently, the critical range of pore sizes for the water blocking effect in the gas–water spontaneous imbibition process was determined to be between 500 and 1000 μm. This research offers valuable theoretical insights into understanding capillary-driven flow phenomena in porous media.

Surfactant assisted spontaneous imbibition is a feasible method for enhanced oil recovery in the reservoirs. A series of pore-scale visual spontaneous imbibition experiments of surfactant solution in oil-wet capillary tubes with six different diameters (10 μm~60 μm) are thoroughly investigated. The results showed that the final imbibition recovery exhibited a rise and fall tendency in sequence with the increase of capillary tube diameter. The combination of the Marangoni effect and diffusion effect was the dominant power to render the oil be expelled, and the wettability alteration was principally conducive to the migration of expulsion oil. Additionally, emulsification entrainment was beneficial to imbibition recovery.

CO2 huff-n-puff technology has been acknowledged to enhanced oil recovery in tight oil reservoirs by improving oil mobility via CO2 dissolution. Temperature fluctuations induced on the reservoir depth have an impact on oil recovery by altering CO2 dissolution and oil mobility. A microscopic visualization simulation experiment was carried out under 2 MPa condition to observe the interactions between CO2 and crude oil at various temperatures (30, 45, 60, 75, and 90 °C). The contribution of viscosity reduction competition of temperature and CO2 dissolution to the improvement of crude oil mobility was thoroughly evaluated. The findings showed that CO2 dissolution dramatically lowers viscosity at 30–50 °C, facilitating oil mobility. Oil mobility and recovery are reduced by 8.2% as a result of CO2 dissolution decreasing with increasing temperature, while the volume of CO2 gas increases by 1.3 times. At 50–60 °C, the mobility of crude oil improves and the recovery increases significantly with the temperature, when the increment amplitude is about two times of the reduction in amplitude. Temperature-induced viscosity reduction predominates between 60 and 90 °C. Furthermore, the oil recovery is dominated by the matrix region at low temperatures (30–60 °C) and by the fracture region at high temperatures (75–90 °C), with both regions weighing more than 40% of the ultimate recovery. Therefore, CO2 huff-n-puff is more suitable at temperatures in the range of 50–60 °C in the extraction of tight oil reservoirs.

The water blocking phenomenon formed by the retention of fracturing fluid in the pores leads to an increase in the resistances of gas flow, thereby inhibiting the efficient extraction of coalbed methane (CBM) reservoirs. The opaque of the gas and water two-phase migration process and the ambiguity of its distribution characteristics jointly hinders the release of water blocking phenomenon. A visualization experiment for the gas–water two-phase displacement in the pores was implemented at ambient condition, while the porous media was divided into five flow regions based on the distribution characteristics of the seepage velocity field. The results showed there were “Y,” “I”, “L,” and “H” four primary types of water blocking phenomenon depending on the retention morphology of gas and water phases in different pores. The amount of “I” type water blocking phenomenon accounted for the majority in five regions, and the whole amount was five times than that of “H” type. The “Y” type water blocking phenomenon was created under the dual influence of pore radius and intersection angle, while the “I”, “L,” and “H” types manifest the corresponding morphology under the restriction of pore radius. The ratio of the amount of water blocking phenomenon in the main stream region to the upper and lower of transition region and boundary region exhibited a symmetrical distribution of approximately 3:2:1, mainly caused by the seepage velocity field induced by inhomogeneous pore structures. This research can provide a fundamental guidance for elimination of the water blocking damage in the extraction of CBM reservoirs.

Spontaneous imbibition has been considered as a significant method to enhanced oil recovery (EOR) in unconventional reservoirs. The main impediment to comprehending the variation characteristics of spontaneous imbibition at different pore scales was the reservoirs opacity. To this end, a series of spontaneous imbibition experiments of visualized oil-wet microtubes with six different diameters (10μm60μm) were performed, as were the corresponding macroscopic core imbibition tests with six different permeabilities under the same conditions. The results showed that formation brine mostly advanced along the wall surface of a capillary during the imbibition process, and some were even isolated within a capillary. The imbibition recovery in the capillary with a diameter of 10μm was the highest (27.81), which was more than three times that of the capillary with a diameter of 60μm (8.3). There was a good power function decline relationship between capillary diameter and imbibition recovery, and 30μm appeared to be a critical inflection point in both capillary tube and macroscopic core imbibition tests. In addition, the majority of the detained residual oil clusters not only cut off the continuity of formation brine but also increased the imbibition flow resistance, accelerating the imbibition to balance. This research provides a new perspective for comprehending the imbibition characteristics at different pore scales.