The Impact of Reservoir Conditions on Capillarity, Multiphase Flow and Hysteresis for CO2-brine Systems

Abstract

The multiphase flow properties of the CO2-brine-rock system, capillary pressure, relative permeability, hysteresis and residual trapping, are essential input parameters for modeling CO2 storage and gas injection enhanced oil recovery processes. Due to the nature of CO2 the thermophysical properties of the system, mobility and interfacial tension, change widely across the range of temperature, pressure and brine salinity observed in subsurface systems around the world. This makes the observation of these properties difficult in a laboratory setting and also raises the question as to how, if at all, reservoir conditions impact on the multiphase flow properties for this system. In this work we report the results of a comprehensive set of experiments observing multiphase flow properties, capillary pressure, relative permeability and residual CO2 trapping in sandstone rocks, Berea and Bentheimer sandstones. Each of these properties is observed in the same rock sample at several different conditions of pressure, temperature and brine salinity varied so as to identify the impact that reservoir conditions have on the suite of multiphase flow properties. Experimental conditions are varied systematically across the range 8-25 MPa, 35-120˚C and 0-5 mol kg-1, representative of the range subsurface conditions worldwide. The observations demonstrate definitively that (1) the CO2-brine system is strongly water wet, (2) the multiphase flow properties of this system are invariant across the range of pressure, temperature and brine salinity in subsurface reservoirs worldwide, (3) the sensitivity of CO2 thermophysical properties to reservoir conditions significantly complicates the measurement of these properties and (4) residual trapping will be a major source of immobilisation for CO2-storage.