Quantification of the Process of Mud-Filtrate Invasion in Heterogeneous Rocks by Combining X- Ray Computed Tomography and Numerical Simulations
Authors:   The University of Texas at Austin, Abdo Mohamad , Schroeder Colin ,   The University of Texas at Austin, Aérens Pierre ,   The University of Texas at Austin, Torres-Verdín Carlos ,   The University of Texas at Austin
Published: September 2024

Understanding the behavior of mud-filtrate invasion and mudcake buildup in permeable rocks is important for the accurate interpretation of borehole measurements such as resistivity, density, neutron, and magnetic resonance. The typical approach is to assume homogeneous formations and piston-like fluid displacement, a situation hardly encountered in the field. For example, in spatially heterogeneous rocks, the invasion depth becomes space-dependent, adding uncertainty to shallow-sensing well logs. Mud-filtrate invasion and fluid flow are often described by simulating radial injection in the borehole, while experimental fluid-fluid interactions are investigated using Cartesian flow. Furthermore, it is rare to find research papers not limited to water-based mud and supported with consistent simulation and experimental results, i.e., radial injection simulation and radial flow experiments. The objective of this paper is to combine observations made with time-lapse X-ray CT images of mud filtrate invading spatially heterogeneous rocks and numerical simulations to quantify flow-dependent petrophysical properties of spatially heterogeneous rocks, such as saturation-dependent capillary pressure, relative permeability, and wettability. We document an improved mud-filtrate invasion experiment using either water-based mud (WBM) or synthetic oil-based mud (SBM) and a 3-in. diameter and 2-in. long cylindrical cores initially saturated with either brine, oil, or air. A 0.5-in. diameter borehole for injecting fluids at constant pressure was drilled in each sample to replicate actual borehole conditions. The resulting invasion process was time-lapse monitored via X-ray scanning. Rock samples used for the experiments varied from homogeneous to heterogeneous rocks with bimodal pore/throat size distributions. Numerical history matching of experimental results was performed by varying saturation-dependent (a) capillary pressure, (b) invading relative permeability, (c) irreducible water saturation, and (d) residual hydrocarbon simulation. By accurately tracking the injected volume of mud filtrate during experiments and the radial advancement of the invasion front, it was possible to estimate saturation-dependent wettability, capillary pressure, and relative permeability via history matching. Estimated Brooks-Corey capillary pressure parameters for layered heterogeneous samples agree with mercury-injection capillary pressure within 11.2%. Imbibition experiments provided sufficient contrast between native and invading fluids to highlight changes in the radial time-lapse evolution of fluid saturations. Petrophysical heterogeneity in laminated samples was emphasized when the samples were presaturated and invaded with an immiscible fluid. The petrophysical properties of each layer were estimated by history-matching invasion experiments with numerical simulations of presaturated laminated samples. On the other hand, invasion fronts in laminated dry rock samples were piston-like due to higher transmissibility between thinner layers. Only the petrophysical properties of the most permeable layers were estimated from the history matching of experimental measurements of invasion in dry rocks. History-matching laboratory experiments of invasion underline the effect of geometrical heterogeneity on fluid flow in porous media and the role played by apparent petrophysical properties. It also provides information on petrophysical properties that vary spatially across relatively large rock samples (i.e., 3 in. wide and 2 in. long). X-ray tomography, combined with numerical multiphase flow simulations, provides unique results with relatively small resolution and a large sampling size. The experimental procedure is dynamic and is less time consuming than laboratory measurements traditionally and commercially used to measure flow-related petrophysical properties.