Pore-scale imaging and characterization of mixed-wet carbonate reservoir rock using X-ray microtomography at subsurface conditions

Abstract

More than a trillion barrels of oil may be extracted from carbonate reservoirs in the Middle East. Oil recovery is known to be controlled by wettability (distribution of contact angles) that determines the pore-scale fluid configuration. However, these contact angles have not hitherto been measured in situ at reservoir conditions for reservoir rock that is saturated with crude oil. We use high resolution three-dimensional non-destructive imaging techniques (X-ray micro-tomography) combined with high-pressure high-temperature flow apparatus to study multiphase flow of crude oil and brine in complex mixed-wet carbonate reservoir rocks at subsurface conditions. The raw X-ray pore-scale images acquired were processed and used to measure oil and brine saturation and to study the in situ pore-scale properties controlling mulitphase flow in permeable media.

The first part of this work used X-ray micro-tomography to image the in situ wettability, the distribution of contact angles, at the pore scale in carbonate cores from a producing hydrocarbon reservoir at subsurface conditions. The contact angle was measured at hundreds of thousands of points for three samples after twenty pore volumes of brine flooding. We found a wide range of contact angles with values both above and below 90°. The hypothesized cause of wettability alteration by an adsorbed organic layer on surfaces contacted by crude oil after primary drainage was observed with Scanning Electron Microscopy (SEM) and identified using Energy Dispersive X-ray (EDX) analysis. However, not all oil-filled pores were altered towards oil-wet conditions, which suggests that water in surface roughness, or in adjacent micro-porosity, can protect the surface from a strong wettability alteration.

The lowest oil recovery was observed for the most oil-wet sample, where the oil remained connected in thin sheet-like layers in the narrower regions of the pore space. The highest recovery was seen for the sample with an average contact angle close to 90°, while an intermediate recovery was observed in a more water-wet system, where the oil was trapped in ganglia in the larger regions of the pore space.

In the second part of this work, we have used differential X-ray imaging combined with a steady-state flow apparatus to elucidate the displacement processes during waterflooding. We simultaneously measured relative permeability and capillary pressure on another mixed-wet carbonate sample from the same giant producing oil field. We used the pore-scale images of crude oil and brine to measure the interfacial curvature from which the local capillary pressure was calculated; the relative permeability was found from the imposed fractional flow at eight points fw= 0, 0.15, 0.3, 0.5, 0.7, 0.85, 0.95, 1), the image-measured saturation, and the pressure differential measured across the sample.

The measured relative permeabilities indicated favourable oil recovery with a cross-over saturation above 60%. Below this saturation water relative permeability is low, while above it oil still flows through thin layers resulting in additional recovery for the mixed-wettability conditions. The pore-scale images showed that brine started to flow through pinned wetting layers and micro-porosity and then filled the centre of the larger pores. Oil was drained to low saturation through connected oil layers. The brine relative permeability remained low until brine invaded a connected pathway of smaller throats, or restrictions in the pore space, at a high brine saturation. The interface between the oil and brine had a small average curvature, indicating a low capillary pressure, but we observed a remarkable saddle-type shape with nearly equal but opposite curvatures in orthogonal directions. This implies good oil phase connectivity, consistent with the favourable recovery and low residual oil saturation attained in the experiments.

This work illuminated displacement processes from both macro-pores and micro-pores which have important implications on improved oil recovery and, potentially, on carbon storage. In future, the measured in situ contact angle, relative permeability, capillary pressure and pore-scale fluid distribution could be used to benchmark and validate pore-scale models.