Pore-Scale Analysis of Residual Oil in a Reservoir Sandstone and Its Dependence on Water Flood Salinity, Oil Composition, and Local Mineralogy

Abstract

Core-flooding of clay-containing reservoir sandstones can yield substantial tertiary recovery by reducing the flood brine salinity, associated with a shift toward water-wetting. Spontaneous imbibition experiments, in which this salinity-induced shift is the main driver for additional recovery, can provide insight into the extent and source of the wettability change, especially when combined with pore-scale imaging of changes in residual oil configurations using micro-CT. Spontaneous imbibition experiments were performed on two sister mini-plugs of a reservoir sandstone. To explore the influence of crude oil composition, each mini-plug used a different oil, of similar density and viscosity and of low asphaltene content, but primarily distinguished by their total acid number (TAN) of 3 and <0.1 mg KOH/g oil. Mini-plugs were imaged by micro-CT after each experiment. Additional insight into the origins of the apparent shift to more water-wetting were obtained by preparing polished embedded sections of the mini-plugs for higher resolution SEM imaging and SEM-EDS mineral mapping. These 2D images were registered into the corresponding cross-section of the 3D tomograms of each mini-plug. In this way the salinity-induced release of oil could be overlain and directly compared to the mineral originally contacting it at each location. Results show that the low TAN oil exhibited much less tertiary recovery compared to the high TAN oil. The local mineralogical analysis revealed that oil removal by low salinity brine was less favored from kaolinite than from silicate grains (quartz, K-feldspar, and Na-plagioclase). Nanoscale imaging of grain surfaces also showed that asphaltene films from the high TAN oil were less prevalent on the rock surfaces than for the low TAN oil.