Experimental study on the performance of foamy oil flow under different solution gas–oil ratios

Abstract

Foamy oil flow has been widely accepted as an explanation for the high oil recovery observed in certain heavy oil reservoirs, and a number of studies have been conducted to understand the mechanisms involved. However, insufficient information is available on the effects of the initial gas–oil ratio on the foamy oil flow. The effects of the solution gas–oil ratio were investigated based on sandpack and visualization experiments for solution gas drive with the foamy oil from the Carabobo reservoir. As the solution gas–oil ratio decreases, the differences in the bubble point and pseudo-bubble point pressure (markers for the foamy oil production period) decrease, resulting in an obvious reduction of the oil recovery efficiency. The effects of the solution gas–oil ratio on the foamy oil flow in porous media can be explained by higher interfacial tension, lower interfacial dilational viscoelasticity, higher live oil viscosity, and lower elastic energy under lower solution gas–oil ratios. A lower limit of the solution gas–oil ratio should exist for foamy oils with different properties, which is believed to be approximately 5.0 Sm³ m⁻³ for the Carabobo reservoir, according to experimental results. For reservoirs with foamy oil cold production, the solution gas can be separated from the produced oil and injected into the formation to increase the solution gas–oil ratio, extend the foamy oil production time, and improve the oil recovery efficiency. The experimental results provide theoretical support for foamy oil production.