The Impact of Reservoir Conditions and Rock Heterogeneity on CO2-Brine Multiphase Flow in Permeable Sandstone
- Samuel Krevor (Imperial College London) | Catriona Reynolds (Imperial College London) | Ali Al-Menhali (Imperial College London) | Ben Niu (Imperial College London)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- Publication Date
- February 2016
- Document Type
- Journal Paper
- 12 - 18
- 2016. Society of Petrophysicists & Well Log Analysts
- 2 in the last 30 days
- 191 since 2007
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Capillary strength and multiphase flow are key parameter inputs for modeling CO2-injection processes for enhanced oil recovery and CO2 storage. Experimental observations of the flow properties reported over the past 10 years have raised important questions about the impact of reservoir conditions on flow through effects on wettability, interfacial tension, and fluid-fluid mass transfer. We report the results of an investigation aimed at resolving many of these questions for flow in sandstone rocks. The capillary pressure, relative permeability, and residual trapping characteristic curves have been characterized in Bentheimer and fired Berea sandstone rocks across a pressure range 5 to 20 MPa, temperatures 25 to 90°C and brine salinities 0 to 5 M NaCl. In total, over 30 reservoir condition coreflood tests were performed evaluating these properties with techniques including the steady-state relative permeability test, the semidynamic capillary pressure test and a novel test for the rapid construction of the residual trapping initial-residual (IR) curve. Test conditions were designed to isolate effects of interfacial tension, viscosity ratio, density ratio and salinity. The results show unequivocally that reservoir conditions have little impact on relative permeability and residual trapping, consistent with continuum scale multiphase flow theory for water-wet systems. The invariance of the characteristic curves is observed across the range of conditions and in comparison with N2-brine systems. Variations in capillary pressure curves are explained by corresponding changes in IFT. As with gas-brine systems, the low viscosity of CO2 at certain conditions results in sensitivity to rock heterogeneity. We show that (1) heterogeneity is the likely source of much of the uncertainty around relative permeability observations for this system, and (2) that appropriate scaling of the driving force for flow by a quantification of capillary heterogeneity allows for the selection of coreflood parameters that eliminate this effect. Alternatively this scaling can be used to approximate the effect of small-scale heterogeneity on flow for real reservoir systems.
Fluid flow during CO2-injection processes for enhanced oil recovery and CO2 storage is governed by the multiphase flow properties, i.e., capillary pressure, relative permeability, hysteresis and residual trapping. A sketch of fluid flow during buoyant CO2 migration in a reservoir is shown in Fig. 1. The leading edge and upper portions of a plume maintain high capillary pressures and CO2 saturation is high in these regions—leading to high values of relative permeability. In the lower and distal sections of the plume a capillary fringe will appear as saturation tapers to the residual. The disconnection of CO2 ganglia results in hysteresis in the multiphase flow functions.
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