The Effect of Microscopic Core Heterogeneity on Miscible Flood Residual Oil Saturation

Abstract

Abstract Much effort has been devoted to understanding the mechanisms responsible for the variation of CO2 flood residual oil saturations found both in the laboratory and in the field-Some of the many possible explanations are the detailed nature of CO2/oil phase behavior, trapping of oil by mobile water, viscous fingering, and bypassing of oil due to the micro-pore structure of a given porous medium. The purpose of this study was to investigate the influence of rock characteristics alone on misciblє displacement behavior through a combination of displacement testing and modeling. Modeling was used to characterize the displacements and to extrapolate the observed phenomena to untestable conditions. The displacement tests were used to calibrate the model and to test the model's predictive capabilities. A number of stabilized CO2 displacements and xylene displacing iso-octane tests were conducted in both outcrop sandstones and San Andres reservoir carbonate core samples. By flooding with xylene displacing iso-octane, phase behavior complications and viscous fingering were avoided. Such an idealized displacement represented the "best case" laboratory miscible displacement. Effluent concentration profiles for the xylene displacing iso-octane floods were matched to the capacitance-dispersion model of Coats and Smith1 to estimate the magnitude of axial dispersion and so-called "dead-end" pore volume or capacitance. The latter quantity was found to be essentially zero in outcrop sandstones but quite variable in the highly heterogeneous San Andres carbonates, attaining values as high as 50%. Axial dispersion followed similar trends. The carbonates displayed more variable and larger axial dispersion than the sandstones. First contact and CO2 miscible flooding residual oil saturations were compared in the same core samples. Both measures of residual oil saturation were in agreement and depended on the particular sample. These data suggest microscopic heterogeneity is a primary determinant of residual oil saturation to miscible flooding when viscous fingering is controlled. Microscopic heterogeneity resulting from a non-uniform pore structure was characterized by the level of dispersion and capacitance in the rock sample. In addition, both laboratory data and model prediction showed that the effect of dispersion and capacitance on residual oil saturation decreased as the displacement was extrapolated to reservoir rates and system lengths of a few feet. This implies that microscopic heterogeneity is more important in laboratory systems than in field displacements.