Multiscale Studies on the Transport Behavior of Nitrogen Foam for Improving Oil Recovery in Homogeneous and Heterogeneous Carbonate Reservoirs

This paper presents the viability of utilizing foam to enhance oil recovery in carbonate reservoirs, characterized by medium temperatures (55 °C) and formation salinity. The foam tests first examined the effects of foam quality, injection velocity, surfactant concentration, and permeability on foam strength and incremental oil recovery on Indiana Limestone on a laboratory scale. Over 8% of the water-gas-flooded residual oil was extracted following the coinjection of a 2.5 total pore volume of nitrogen and 0.3 wt % APG surfactant (in synthetic formation brine) at a foam quality of 70% (4 ft./d). The modeling parameters for the foam dry-out effect, surfactant-dependent function, flow rate-dependent function, and oil destabilization effect were derived from history matching of gas/surfactant coinjection tests conducted at different foam qualities, surfactant concentrations, and injection rates. The viability of foam for EOR is evaluated by using two-dimensional synthetic homogeneous and heterogeneous models at the field scale. Enhancing the surfactant concentration in the surfactant-alternating-gas (SAG) slugs can significantly improve the foam efficiency, effectively redirecting gas injection into unswept regions. The numerical modeling results indicate that the APG foam possesses significant potential to improve oil recovery in both homogeneous and heterogeneous oil-wet carbonate reservoirs. It is also found that the water-top-gas-bottom (WTGB) injection strategy can successfully alleviate gravity segregation in a multizone completion wellbore by leveraging the buoyant force of the gas and the gravitational force of the aqueous phase.