In-situ characterization of wettability and pore-scale displacements during two- and three-phase flow in natural porous media

Abstract

We establish a unique approach to measure in-situ contact angle from micro-CT images acquired during two- and three-phase miniature core-flooding experiments in order to overcome the uncertainties associated with conventional contact angle measurement techniques. The measurements are used to quantify the wettability behavior of the rock and explain pore-level displacement events occurring in three-phase flow. Six two-phase experiments are performed on individual core samples with three pairs of fluids, i.e., oil-brine, gas-oil, and gas-brine, and under two thermodynamic conditions: (a) binary-equilibrated, when only the two respective phases are at equilibrium and (b) ternary-equilibrated, when all three phases are equilibrated and only the two desired fluids are injected into the core. A three-phase experiment set is also performed under ternary-equilibrated conditions, which includes gas injection, a waterflood, and an oilflood process. All experiments are performed on Berea miniature core samples using a nonspreading brine-oil-gas fluid system.We measure receding and advancing contact angles at arc menisci and main terminal menisci for the two-phase binary-equilibrated experiments and characterize contact angle hysteresis for each fluid pair. Contact angle hysteresis values are almost identical for all fluid pairs. The results of the two-phase binary- and ternary-equilibrated experiments show similar contact angle distributions for each fluid pair. Contact angle distributions during the three-phase flow experiment are analyzed to develop new insights into relevant complex displacement mechanisms. The results indicate that, during gas injection, the majority of displacements involving oil and water are oil-to-water events. It is observed that, during the waterflood, both oil-to-gas and gas-to-oil displacement events take place. However, the relative frequency of the former is greater. For the oilflood, gas-water interfaces only slightly hinge in pore elements. Pore-scale fluid occupancy maps and the Bartell–Osterhoff constraint verify the above-mentioned findings.