Carbon dioxide has been successfully used in more than 80 enhanced oil recovery (EOR) operations in North America, and the number of such operations may increase significantly around the world if CO2 becomes available at reasonable costs. On the other hand, geological storage in deep saline aquifers and hydrocarbon reservoirs of large amounts of CO2, captured from large stationary sources is one method that is under consideration for reducing greenhouse gas emissions into the atmosphere on a worldwide basis. In both cases of CO2-EOR and CO2 capture and geological storage (CCGS), the containment of CO2 within the injection unit and leakage avoidance are essential. Effective CO2 containment is achieved by the overlying tight caprock that is initially highly saturated with formation brine, which prevents CO2 migration into uphole intervals and potentially into shallow freshwater aquifers and ultimately to the atmosphere. The confining properties of the caprock are due to its very low permeability and to relative permeability and capillary pressure effects that prevent the penetration of CO2 into, and significant flow through the caprock. Essential to the assessment of CO2-EOR and CCGS operations, including numerical simulation, is knowledge about the caprock permeability to brine and CO2. This paper presents results of detailed measurements at full reservoir conditions for permeability to water, primary drainage and secondary imbibition permeability, relative permeability and trapped saturation of supercritical, dense-phase CO2 and brine for three different, regionally-extensive low permeability formations in the Alberta basin, Canada. These formations include Devonian and Cretaceous shales and a Devonian anhydrite whose measured relative permeabilities were found to be in the nano to pico Darcy range.
The methodology used in the test program and the results can be extended to the evaluation of other sealing caprocks for other prospective CO2-EOR or CCGS operations around the world.