Experimental study of three-phase flow in porous media

The concurrent flow of three fluid phases, e.g., oil, gas, and brine, occurs frequently in petroleum reservoirs and during non-aqueous phase liquid migration in aquifers thereby warranting detailed studies of the process. In this study, three-phase flow is experimentally investigated using a unique, world-class three-phase flow and computed tomography experimental apparatus specifically designed for three-phase flow studies under full fluid re-circulation. We first investigate the effect of different saturation histories relevant to various oil displacement processes (including secondary and tertiary gas injections) on steady-state three-phase gas/oil/brine relative permeabilities, the stability of spreading oil layers, and residual oil saturation. The rock-fluid system consists of water-wet Bentheimer sandstone and brine/Soltrol 170/nitrogen. Fluid and fluid-fluid properties including viscosities, densities, and interfacial tensions are measured using equilibrated phases at experimental conditions. It is found that three-phase water (wetting phase) relative permeability is primarily a function of water saturation and shows no dependency upon saturation history. Three-phase gas (non-wetting phase) relative permeability is also a function of gas saturation as well as the direction of gas saturation change. Three-phase relative permeability to oil (intermediate-wetting phase) appears to depend on all phase saturations, and saturation history has no significant impact on it. Independency of oil relative permeability to saturation history in a water-wet medium is ascribed to the narrow pore size distribution of Bentheimer sandstone. In addition, three-phase relative permeability to oil shows weak sensitivity to initial oil saturation prior to gas injection. The functional forms of oil relative permeability with saturation, particularly at low oil saturations, are also examined. It is observed that, at high oil saturations where networks of oil-filled elements govern oil flow, oil relative permeability exhibits a quartic form with oil saturation (kro alpha So4), whereas at low oil saturations where flow is controlled by layer drainage, it shows a quadratic form (kro alpha So2). The quadratic form of three-phase oil relative permeability is consistent with the theoretical interpretation of layer drainage at the pore scale. It is also observed that waterflood residual oil saturation substantially reduces during gas injection. This is believed to have taken place due to reconnection of trapped oil ganglia, formation of spreading oil layers, and oil drainage through the connected layers. In the second part, we present the results of a series of experimental displacements in which liberation of CO2 gas from CO2-saturated brine, as a result of pressure reduction, is employed to recover trapped oil left by waterflooding in a water-wet Berea core. It is shown that this novel process recovers more than 50% of the original trapped oil. The core-flooding system is used to perform a two-stage flow experiment with a different level of CO2 saturation in brine at each stage. The core, which is first saturated with fresh brine, is subjected to primary drainage by oil leading to 31.6% initial water saturation and then to a fully fresh brine flood leading to 41% trapped residual oil saturation. Subsequently, brine saturated with CO2 at 90.0 psig is introduced into the core at a constant inlet pressure. A sophisticated back pressure regulation system is utilized to tightly control and gradually reduce the outlet pressure of the core. The gradual increase in pressure drop across the system leads to liberation of CO2 from brine, three-phase flow and mobilization of oil ganglia. The process is continued until the outlet pressure reaches 2 psig, at which oil saturation decreases down to 20%. The study is continued by repeating the above process at a higher level of CO 2 saturation in brine. To do so, the pressure in the sample is first increased to 180 psig to re-dissolve the CO2 into the brine followed by injection of new brine, saturated with CO2 at 180 psig, twice the level used in the first stage. The remaining oil saturation is further reduced to 17.3%, resulting in a cumulative recovery factor of 74.7%; 34.7% additional recovery of original oil in place (OOIP) compared to the initial waterflood. Parallel pore-scale visualization studies using transparent glass micromodels and high-resolution micro-computed tomography imaging indicate that the effectiveness of the above approach is linked to the interaction between a flowing, disconnected gas phase and oil ganglia (three-phase ganglion dynamics).