During the development of CO₂ injection in low-permeability reservoirs, carbonated water formed after CO₂ dissolves in water can effectively improve the imbibition effect, and thus improve the reservoir development benefit. By measuring the oil-water interfacial tension, contact angle and imbibition recovery factor, the effect of temperature and pressure on imbibition recovery in low-permeability cores under high-pressure CO₂ was investigated. The results show that increasing temperature and CO₂ pressure can improve oil-water interface characteristics and enhance imbibition recovery. At 8 MPa, the temperature increases from 20 ℃ to 80 ℃, the interfacial tension increases by 2.25 mN·m^-1, and the contact angle decreases by 15.2°. The influence of temperature on oil-water interface characteristics is stronger than that of CO₂ solubility. With the increase of temperature, CO₂ solubility decreases, but the interfacial tension increases, the hydrophilicity of rock enhances, and the fluidity of crude oil increases, so the imbibition efficiency increases. At 80 ℃, the pressure increases from 4 MPa to 10 MPa, the interfacial tension decreases by 3 mN·m^-1, and the contact angle decreases by 18.4°. Pressure mainly affects the oil-water interface characteristics by changing the CO₂ solubility in the liquid phase. With the increase of pressure, the CO₂ solubility increases, the interfacial tension decreases, the hydrophilicity of rock enhances, the fluidity of crude oil also increases, so the imbibition efficiency increases effectively. Heating and pressurization have a certain synergistic effect on improving imbibition efficiency. Under the combined action of the two, although the interfacial tension only slightly decreases, the hydrophilicity of the rock enhances significantly, which accelerates the escape of crude oil in the matrix pore throat and effectively improves the imbibition recovery in low-permeability cores. The research results enrich the imbibition production mechanism, and can provide theoretical reference for CO₂ injection development in low-permeability reservoirs.

The potential of the vertical-horizontal well hybrid SAGD technique for developing shallow heavy oil reservoirs is gradually being realized. However, challenges remain in terms of low thermal efficiency and high carbon emissions in reservoirs with interlayers. Currently, there is limited research on the low-carbon strategy of coupling exhaust gas from steam boilers with the VH-SAGD technique. Herein, considering heterogeneity, a series of flue gas-assisted VH-SAGD experiments were conducted employing a high-performance 2D visualization model. The mechanism of enhanced recovery of flue gas in VH-SAGD and the effect of its injection methods were studied, with a focus on steam chamber development and oil saturation distribution. Crucially, the interlayer length was optimized to enhance oil recovery, providing a new perspective for well location design in heavy oil reservoirs with interlayers. The results showed that flue gas, as an additive, could fully exploit the well-type advantage of VH-SAGD. By supplementing energy at the reservoir top, flue gas effectively promoted steam chamber development, expanded the oil drainage area of VH-SAGD, and increased the oil recovery from 58.9% to 71.7%. The flow channels formed by pre-injection flue gas accelerated the early-stage expansion of the steam chamber while also inducing lateral migration of steam, slowing steam rise, and consequently increasing the heating range within the low-permeability layer. When the distance between the vertical and horizontal wells was set to twice the interlayer length, the negative effects of the interlayer were more effectively turned into advantages. Because when the lateral development distance of the steam chamber in the low-permeability layer slightly exceeds the interlayer, enhanced heating of the lower part of the reservoir occurred through vertical convection of rising steam and returning condensate. The research results contribute to reducing carbon emissions from steam-based heavy oil extraction while advancing the maturity of VH-SAGD.

Aqueous foam is broadly applicable to enhanced oil recovery (EOR). The rheology of foam as a function of foam quality, gas and liquid velocities, and surfactant concentration constitute the foundation of its application. The great variations of the above factors can affect the effectiveness of N₂ foam in EOR continuously in complex formations, which is rarely involved in previous relevant studies. This paper presents an experimental study of foam flow in porous media by injecting pre-generated N₂ foam into a sand pack under the conditions of considering a wide range of gas and liquid velocities and surfactant concentrations. The results show that in a wide range of gas and liquid velocities, the pressure gradient contours are L-shaped near the coordinate axes, but V-shaped in other regions. And the surfactant concentration is a strong factor influencing the trend of pressure gradient contours. Foam flow resistance is very sensitive to the surfactant concentration in both the high- and low-foam quality regime, especially when the surfactant concentration is less than CMC. The foam quality is an important variable to the flow resistance obtained. There exists a transition point from low- to high-quality regime in a particular flow system, where has the maximum flow resistance, the corresponding foam quality is called transition foam quality, which increases as the surfactant concentration increases. The results can add to our knowledge base of foam rheology in porous media, and can provide a strong basis for the field application of foams.