3D imaging and characterization of the pore space of carbonate core; implications to single and two phase flow properties

The ability of a rock to store and flow fluids is dependent upon the pore volume, pore geometry and its connectivity. Carbonate rocks are inherently heterogeneous having been laid down in a range of depositional environments and having undergone significant diagenesis. They are particularly difficult to characterise as the pore sizes can vary over orders of magnitudes and connectivity of pores of different scales can impact greatly on flow properties. For example, separate vuggy porosity in a underlying matrix pore system can increase the porosity, but not the permeability and lead to large residual oil saturations due to trapping in vugs. A touching vug network can have a dramatic effect on permeability and lead to higher recoveries. In this paper we image a set of carbonate core material from outcrops and reservoirs in 3D via micro Computed Tomography (μCT). The morphology of the pore space from different core material exhibits a broad range of topology and connectivity. Images at lower resolution (larger sample size) allow one to deduce the size, shape and spatial distribution of the (disconnected) vuggy porosity. Higher resolution images (down to 2 micron resolution) on subsets of the core allow one to probe the 3D intergranular porosity. The delineation of regions with submicron porosity is achieved via a differential contrast technique in the μCT. Experimental MICP measurements performed on the imaged core material are in good agreement with image-based MICP simulations. These results indicate the quality of the imaging method allowing one to probe the spatial distribution of the vuggy / macro / micro porosity contributions across several orders of magnitude in scale. High resolution numerical simulations of single phase flow and solute transport are undertaken on the resolved digital image data. A hybrid numerical scheme is developed to include the contribution of microporosity to the overall core permeability. These results show in many cases, the dominance of a few flow paths in dictating the permeability of the core material. The role of microporosity in the flow fields is illustrated via 3D visualisation, measurement of local flow velocities and solute transport results. Pore network models generated from the images illustrate the large variations in topology and geometry observed in carbonate samples. Both the visual appearance and quantitative details of the pore network show dramatic differences. Resultant two phase imbibition residual saturations are shown to be strongly dependent on the different topological and structural properties of the pore network. Laboratory measured rate dependent residual saturations for clastic and carbonate cores are compared with numerical simulations with encouraging results. These results illustrate differences in the petrophysical characteristics of the different cores when classified by core descriptive parameters (Lucia, 1999), porosity permeability, MICP (Skalinski et al., 2005) and relative permeability (Hamon, 2003). 3D imaging and analysis may assist in the integration of different rock-typing methods.