Recovery Mechanism of Steam Injection in Carbonate Reservoir

Abstract

Abstract Thermal processes application in carbonate heavy oil reservoir is less successful than sandstone reservoir due to its feature that is naturally fractured and oil-wet condition. The enhanced oil recovery by steam drive in carbonate reservoir is often low because the steam easily bypasses oil which is locked in low permeability matrix. In addition, the recovery mechanism by steam injection is not well understood so far. The research from last decade showed that recovery mechanism is dominated by complicated interactions between oil/brine/rock and mineral heterogeneity. Imbibition and drainage may dominate the heavy oil recovery from fractured carbonate reservoirs when the steam is injected. This work presents an experimental study that was designed to characterize the recovery mechanism of steam injection in heavy oil carbonate reservoir by simulating the reservoir conditions. Several reservoir rock samples with a length of 3 inches and a diameter of 1.5 inches were used for both free and forced imbibitions at elevated temperatures. The crude oil from the same formation has an API gravity of 14 and a viscosity of 5624 cp at room temperature was used as oil phase. The water phase was either synthetic formation brine or 5000 ppm NaCl brine. A high resolution CT scan imaging technology was used for screening core candidates and cutting the core plugs to avoid a significant difference in core properties which may affect recovery mechanism. This study revealed that the oil recovery from carbonate reservoir by steam flooding is mainly dominated by imbibition, viscosity reduction, and in-situ steam generation inside the core. The increase in imbibition oil recovery is strongly dependent on the interaction between the oil/brine/rock which in turn affects the wettability rock. Effluent brine chemistry analysis verified that carbonate dissolution is associated at a temperature above 300°F, which may result in wettability alteration toward water-wetness. The oil recovery by free imbibition increased from around 10% OOIP to 50% OOIP as the temperature is increased from 100 to 400°F. If the pore pressure is suddenly reduced from 350 psi to room atmosphere pressure at 400°F (in-situ flashing process), the oil recovery can be further increased to 60–70% OOIP due to a significant amount of steam is generated in-situ. Correspondingly, the rock compaction is observed during the flashing process. The measured rock compaction is less than 4% of the total pore spaces. Compared with free imbibition, forced imbibition at low temperature gives higher oil recovery at low temperature, but does not show significant increase in oil recovery at high temperature.