CO2-Brine Drainage in Berea (20 C, 10.3 MPa)

• https://doi.org/10.1002/ghg.1650
• DOI:10.1002/ghg.1650

Abstract — We measure CO2-brine relative permeability by performing five steady-state primary drainage experiments in a 116 mD Berea sandstone core at 20 °C and 10.34 MPa. We use a long (60.8 cm) core and four pressure taps to study and minimize end effects that can plague CO2-brine relative permeability measurements, and we obtain in-situ saturation profiles using a medical X-ray Computed Tomography (CT) scanner. We find that entrance and exit effects propagated ~5 cm into the core, but the center sections of the core had uniform saturation. From the saturations and pressure drops, we obtained both CO2 and brine relative permeability in the center sections. We also obtained CO2 relative permeability at the entrance section where the brine saturation was lower and not uniform. The 15-cm long exit section of the core had nonuniform saturation and a measured pressure drop that was on the order of the capillary pressure and hence is unreliable for calculating relative permeability. We find that the CO2 and brine relative permeabilities determined in five experiments were consistent with each other and followed two simple Corey-type models that are similar to those seen in oil-brine relative permeability measurements. We discuss why end effects are much greater in the CO2-brine system than in oil-brine systems, and how this is a possible explanation of the low CO2 relative permeabilities recently reported for the CO2-brine systems.

• http://hdl.handle.net/2152/46115

Abstract — CO2 relative permeability is the key parameter in modeling CO2 geological storage and CO2 enhanced oil recovery. However, the literature CO2 relative permeability data are often inconsistent and smaller than the actual values. This is because the traditional methods only obtain the global values of the three key parameters in relative permeability determinations: pressure drop, saturation and phase flux. These global values are often different from the local values due to capillary effects. This work develops new steady-state and unsteady-state methods to determine relative permeabilities. The new methods obtain the local values of the three key parameters, hence they have the advantage of experimentally avoiding capillary effects, which is crucial for gas and supercritical phase, such as CO2. The new methods give more accurate relative permeability data that are up to 50% higher than the traditional methods. This work uses the new methods to determine two-phase relative permeabilities for CO2-brine in Berea sandstone at different conditions (20-60 °C and 8-12 MPa). The key finding is two-phase CO2 relative permeability does not depend on temperature or pressure within my experimental uncertainty. This finding advocates the use of a single relative permeability curve to model CO2 plume migration at different temperatures and pressures. This work also obtains three-phase CO2 and decane relative permeabilities at 70 °C and 8 MPa when water is immobile. The key findings are: (1) the three-phase relative permeability of CO2 is higher than that of decane by one order of magnitude, which is consistent with CO2 being more non-wetting than decane in water-wet rocks; and (2) the three-phase CO2 relative permeability is lower than the two-phase CO2 relative permeability by another order of magnitude, which is consistent with CO2 becoming less non-wetting and getting similar to decane at high pressure. Thus when modeling water-oil-CO2 three-phase flows, the CO2 relative permeability curve can vary significantly with temperature and pressure since thermodynamics affects the wettability.