Coupling X-ray µCT, BSE, and QEMSCAN imaging to unravel details of water saturation and oil trapping in a Brazilian Pre-salt carbonate under oil-wet conditions

The study of fluid saturation and oil entrapment in reservoirs is of great importance for understanding and characterizing multiphase flow, with economically significant implications. In this context, we examine the fluids configuration under oil-wet conditions in particulate carbonate reservoirs of the Brazilian Pre-salt, which host large quantities of oil. Hence, we conducted drainage and imbibition cycles on a grainstone carbonate sample from the Barra Velha Formation of Brazil’s Pre-salt integrating X-ray tomography, backscattered electrons (BSE), and QEMSCAN (quantitative evaluation of minerals by scanning electron microscopy) to understand fluid saturation and oil trapping under oil-wet conditions at pore-scale. The integration of µCT imaging with BSE and QEMSCAN significantly enhances our understanding of fluid saturation within the pore system, particularly in regions where X-ray imaging alone encounters limitations. QEMSCAN imaging, beyond resolving microporosity, provides critical insights into the mineralogical factors influencing fluid distribution, offering a deeper perspective on the saturation controls. Following the drainage and aging cycles, oil effectively displaced nearly all brine within the interparticle macropores, relegating the brine to small, isolated droplets formed through snap-off processes. Additionally, a significant proportion of intraparticle micro and macroporosity was occupied by oil after drainage, with further oil saturation occurring during aging, demonstrating the rock’s oil-wet affinity. Post-forced imbibition imaging revealed that nearly all the oil initially present in the interparticle macropores had been replaced by water, with only minor traces of oil remaining as thin films on mineral surfaces. Conversely, the intraparticle macro and micropores, which are typically less connected, retained most of the oil, highlighting the porous medium’s tendency to trap fluids in poorly connected regions. Finally, our experiments did not reveal any substantial effect of mineralogical variations on fluid saturation during any phase of the cycles. This suggests that the observed oil-wet condition is independent of relative mineralogical variations, particularly given the sample's dominance of calcite and dolomite. These results, although obtained from a facies type common in the Brazilian Pre-salt, elucidate the behavior in oil-wettable reservoirs, a common condition in various reservoirs around the world.