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Natural gas foam flooding has good fluid control and formation blockage capabilities, but the high-temperature, high-pressure, and high-salinity environment puts forward higher requirements for the comprehensive performance of natural gas foam. The impact of different gas types on the overall performance of the foam system was evaluated via a high-temperature, high-pressure visual foam stirrer. It is found that nitrogen foam systems have strong stability but weak foaming ability, while carbon dioxide foam systems exhibit strong foaming ability but poor stability. The methane foam system showed relatively better and balanced foaming ability and stability, making it more suitable to oil fields. Ten surfactants were screened and the results indicated that α-olefin sodium sulfonate (AOS14, AOS12) and sodium dodecyl sulfate formed natural gas foam systems with better overall performance with methane. The effects of temperature, pressure, surfactant concentration, and foam stabilizers on the comprehensive performance of the methane-AOS14 foam system were investigated. With increase in the surfactant concentration, the foaming ability and stability of the methane-AOS14 foam system first increase and then decrease. Higher temperatures reduced the viscosity of the surfactant solution and decreased the interfacial tension between solution molecules, weakening the overall performance. Increased pressure facilitated the generation of denser foam with smaller diameters, slowing the liquid loss from foam films and enhancing the overall performance. Under high-temperature, high-pressure, and high-salinity conditions, polymer-based foam stabilizers enhanced the stability of the methane-AOS14 foam system by forming a spatial network structure on the foam film, with higher molecular weight yielding better effects. [ABSTRACT FROM AUTHOR]

To solve the problem that scale in oilfields can lead to a reduction of formation permeability and blockage of wellbore and production system pipelines, through the scale inhibitor-formation water compatibility experiment and the minimum effective scale inhibitor concentration experiment, three different types of surfactants are selected as adsorption promoters. Three different types of surfactants were selected as adsorption–desorption accelerators through dynamic core adsorption–desorption experiments. The results of the indoor experiment show that the three types of scale prevention agents selected can meet the environmental protection requirements of the sea area. The static scale prevention rate at high temperature (>120 °C) exceeds 80%, and the minimum effective concentration is less than 3.5 mg L−1. The preferred cation Gemini surfactant has a stable adsorption enhancement effect of the scale inhibitor under different water-bearing conditions and can effectively extend the squeezing life under complex formation conditions. The results improve the comprehensive economic benefits of the field and provide technical feasibility to significantly improve the scale prevention efficiency of the field. [ABSTRACT FROM AUTHOR]

Aiming at low permeability, high water content light reservoir with a recovery rate higher than 20%, an improved air injection enhanced heat flooding technology is applied by combining the combustion reaction flow and flue gas flooding mechanism. The method involves the injection of air into the reservoir, which reacts with the crude oil at temperatures ranging from 220 to 300 °C. This reaction consumes part of the oil, enabling effective evaporation and flow of the remaining oil. This process combines combustion reaction flow with flue gas flooding, using high-temperature oxidation reactions to mobilize residual oil. Experimental results from combustion tube tests demonstrate stable reaction fronts, peak temperatures reaching up to 550 °C, and a significant increase in recovery rates, reaching 73.8% in some cases. Field applications of this technology require maintaining high air flux and burning rates in low-permeability zones to ensure effective heat-driven evaporation. The geological model of the well group shows that the recovery factor of the target block can be increased by more than 20% by air injection based on the water drive recovery factor of 28%–30%. The oil exchange ratio can be less than 4000 sm3/m3 by optimizing the air injection rate and oxygen content. The research results provide technical feasibility for heat flooding to significantly improve oil flow and recovery in low-permeability light oil reservoirs. [ABSTRACT FROM AUTHOR]