Minimum Miscibility Pressure in Conventional and Unconventional Reservoirs

Abstract

URTeC 1589572 Hydrocarbon and non-hydrocarbon gas injection are generally effective means to enhance oil recovery in conventional reservoirs. In unconventional oil reservoirs gas injection could also improve oil recovery, but it is not proven yet. A key design parameter in any gas injection project is the minimum miscibility pressure (MMP), which is the lowest pressure at which miscibility between the injected gas and reservoir oil is achieved when the interfacial tension between oil and gas vanishes. MMP is generally measured in the laboratory in sand-packed slim-tube flooding equipment, or in a rising bubble apparatus (RBA). In these experimental methods the gas and oil come in contact in a space sufficiently large enough to resemble the large pores in conventional reservoirs; and, such space confinement does not affect the conventional phase behavior. However, in unconventional oil reservoirs the small size of the pore space could significantly affect the thermodynamic phase behavior of contacted fluids because of capillary force and confinement effect on molecules. Hence, the slim tube and RBA measurements may not represent the in-situ MMP and, thus, may require correction. In this paper, we review experimental and numerical modeling methods of MMP determination and utilized the Multiple Mixing Cell (MMC) algorithm in our assessment. To account for the effect of capillary pressure and thermodynamic equilibrium in nanopores (hereafter, confined space), a critical property shift correlation was implemented in the conventional MMC algorithm for MMP determination. Two reservoir oil compositions (synthetic oil and Bakken oil) were used to determine their MMP with CO2 and a mixture of CO2 and CH4. Our results indicate that the MMP can be reduced by up to 600 psi for pore diameters less than 3 nm because of the critical property shift. On the other hand, capillary pressure does not significantly affect the MMP.