The impact of reservoir conditions and rock heterogeneity on multiphase flow in CO2-brine-sandstone systems

Thursday, 17 December 2015
Poster Hall (Moscone South)
Samuel C Krevor, Imperial College London, Department of Earth Science & Engineering, London, SW7, United Kingdom, Catriona Anne Reynolds, Imperial College London, Department of Earth Science and Engineering, London, SW7, United Kingdom, Ali Al-Menhali, Imperial College London, Department of Earth Science & Engineering, London, United Kingdom and Ben Niu, Imperial College London, Department of Chemical Engineering, London, SW7, United Kingdom
Capillary strength and multiphase flow are key for modeling CO2 injection for COstorage. Past observations of multiphase flow in this system have raised important questions about the impact of reservoir conditions on flow through effects on wettability, interfacial tension and fluid-fluid mass transfer. In this work we report the results of an investigation aimed at resolving many of these outstanding questions for flow in sandstone rocks.

The drainage capillary pressure, drainage and imbibition relative permeability, and residual trapping [1] characteristic curves have been characterized in Bentheimer and Berea sandstone rocks across a pressure range 5 – 20 MPa, temperatures 25 – 90 C and brine salinities 0-5M NaCl. Over 30 reservoir condition core flood tests were performed using techniques including the steady state relative permeability test, the semi-dynamic capillary pressure test, and a new test for the construction of the residual trapping initial-residual curve. Test conditions were designed to isolate effects of interfacial tension, viscosity ratio, density ratio, and salinity.

The results of the tests show that, in the absence of rock heterogeneity, reservoir conditions have little impact on flow properties, consistent with continuum scale multiphase flow theory for water wet systems. The invariance of the properties is observed, including transitions of the CO2 from a gas to a liquid to a supercritical fluid, and in comparison with N2-brine systems. Variations in capillary pressure curves are well explained by corresponding changes in IFT although some variation may reflect small changes in wetting properties. The low viscosity of CO2at certain conditions results in sensitivity to rock heterogeneity. We show that (1) heterogeneity is the likely source of uncertainty around past relative permeability observations and (2) that appropriate scaling of the flow potential by a quantification of capillary heterogeneity allows for the selection of core flood parameters that eliminate this effect. This scaling can also be used to approximate the effect of heterogeneity on flow for real reservoir systems.

[1] Niu, B. Al-Menhali, A., Krevor, S. (2015) The impact of reservoir conditions on the residual trapping of carbon dioxide in Berea sandstone. Water Resources Research 51, 4, 2009-2029.