Summary
We imaged an intermediate-wet sandstone in three dimensions at high resolution (1–3.4 µm3) with X-ray microcomputed tomography (micro-CT) at various saturation states. Initially the core was at connate-water saturation and contained a large amount of oil (94%), which was produced by a waterflood [recovery factor Rf = 52% of original oil in place (OOIP)] or a direct gas flood (Rf = 66% of OOIP). Subsequent waterflooding and/or gasflooding (water-alternating-gas process) resulted in significant incremental-oil recovery (Rf = 71% of OOIP), whereas a substantial amount of gas could be stored (approximately 50%)—significantly more than in an analog water-wet plug. The oil- and gas-cluster-size distributions were measured and followed a power-law correlation N ∝ V−τ , where N is the frequency with which clusters of volume V are counted, and with decays exponents τ between 0.7 and 1.7. Furthermore, the cluster volume V plotted against cluster surface area A also correlated with a power-law correlation A ∝ Vp, and p was always ≈ 0.75. The measured τ- and p-values are significantly smaller than predicted by percolation theory, which predicts p ≈ 1 and τ = 2.189; this raises increasing doubts regarding the applicability of simple percolation models. In addition, we measured curvatures and capillary pressures of the oil and gas bubbles in situ, and analyzed the detailed pore-scale fluid configurations. The complex variations in fluid curvatures, capillary pressures, and the fluid/fluid or fluid/fluid/fluid pore-scale configurations (exact spatial locations also in relation to each other and the rock surface) are the origin of the well-known complexity of three-phase flow through rock.
In situ characterization of immiscible three-phase flow at the pore scale for a water-wet carbonate rock
