Compositional Simulation of Carbonated Waterfloods in Naturally Fractured Reservoirs

This paper presents a compositional simulation of imbibition carbonated waterfloods in naturally-fractured reservoirs using a 3-dimensional, 3-phase, dual-porosity, compositional simulator (COMABS). The simulator is developed as a part of multi-disciplinary study to improve the oil recovery from low-permeability, naturally-fractured reservoirs such as Austin chalk trend. Laboratory imbibition carbonated waterfloods data using chalk cores are available for this study. The COMABS allows the partitioning of CO2 from the injected water phase into the oil phase based upon the CO2 solubility in each phase. The partitioning of CO2 is assumed to reduce oil phase viscosity and increases oil density; the transmissibilities are updated as a function of CO2 concentration.

Two grid systems are used in a cross-sectional, dual-porosity modeling of the laboratory tests. For simplicity, three dual-porosity gridblocks are used to represent the laboratory laboratory flow test systems. The carbonated water imbibes into the matrix blocks and causes the counter-current flow of oil from the matrix to the fracture. Then, fifteen dual-porosity gridblocks are used. In this system, a higher fracture permeability value is assigned for the gridblocks corresponding to the fracture in the laboratory flow test system. The simulator is capable of matching the laboratory imbibition oil recoveries. The effect of the carbonation of injected water on oil recoveries are examined with computed oil saturation, oil viscosity, oil density and CO2 concentration distributions.

A hypothetical two-dimensional field imbibition carbonated waterflood is used to demonstrate the use of COMABS for field-scale applications. The application of the simulator for field-scale imbibition carbonated waterflood may provide some insights on the impacts of imbibition and compositional variation on imbibition CO2-enriched waterflood recovery.