High‐pressure high‐temperature fluid displacement by foam injection within a multiblock matrix‐fracture system

Abstract

Foam injection has been suggested and demonstrated as a potential gas‐based solution for enhancing oil recovery from underground reservoirs. While the pore‐scale behavior of foam has been investigated for many years, most of those studies were done at room temperature and pressure. A high‐pressure high‐temperature (HPHT) cell was constructed to relax this contributing simplification and evaluate foam behavior under reservoir conditions. The performance of foam injection into a fractured reservoir was investigated experimentally at vertical and horizontal pathways utilizing a 2D microfluidic device. The results showed foam had a higher lamellae density in the fracture network and could direct fluids to the matrix. This was mainly attributed to the created pressure drop in the fractured media dictated by foam self‐tuning ability, which is a higher viscosity in areas with higher conductivity. Generating a viscous crossflow in horizontal tests leads to enhanced recovery relative to gas injection. But the presence of gravity in the vertical tests causes the drainage of the foam film and the segregation of the gas and surfactant solution due to gravity, which ultimately reduces the stability of the foam. Comparing the performance of gas and foam in the vertical injection scenario reveals that foam injection results in a considerably more enhanced oil recovery. The oleic phase had a detrimental impact on foam strength and reduced fluids diversion from fracture to matrix. The sizes of gas bubbles were also larger in the presence of the oleic phase.