Relative Permeability of CO2 in a Low-permeability Rock: Implications for CO2 Flow Behavior in Reservoirs with Tight Interlayers

Abstract

In many of the underground CO2 storage sites, the sedimentary reservoirs are not petrologically uniform. Reservoir formations usually comprise high-permeability layers and low-permeability interbeds. Such sedimentary structure has been observed in CO2 storage reservoirs; for example, the Utsira formation, Sleipner, Norway, and also in the Haizume formation, Nagaoka, Japan. During the upward migration of CO2 plume from lower to upper layers, CO2 flow is inevitably affected by these tight interlayers. Therefore, it is important to know the CO2 relative permeability in these layers to predict CO2 flow behaviour. However, measurements of CO2 relative permeability in low-permeability rocks are rare in literature. The reason is perhaps due to the difficulty in controlling saturation and specific conditions for measuring relative permeability in low-permeability rocks using conventional techniques. In this study, we designed a new quasi-steady state approach for the measurement of CO2 relative permeability in a low-permeability sandstone cored from an underground formation of a CO2 storage site. The rock sample is characterized by a low permeability (approximately 0.16 mD) and relatively strong heterogeneity in subcore scale. The low-permeability characteristics make the conventional steady-state way impractical, because a very long time is necessary for building each steady-state saturation profile. Furthermore, the spatial heterogeneity also leads to that it is unsuitable for using unsteady state methods, e.g. JBN method, which is limited to the application in the displacement with uniform fluid distribution. Rock heterogeneity in the sample may lead to an incorrect estimation of relative permeability. In our new method, we use X-ray CT imaging technique to monitor the CO2 saturation changes and formation of fluid flow path during pressure adjustments. Considering the formation of CO2 flow path, we initially injected CO2 at a considerable high pressure drop until the saturation reaches a targeted value, to create the flow path. Then we lowered the pressure drop (so as to flow rate) and let the saturation profile reach a quasi-steady state and stop to increase. The saturation and fluid flow path during this operation have almost no change in the sample. Then we repeated the operation of lowering pressure drop several times and measured pressures and flow rates. If the relative permeability of CO2 has no change, the plot of pressure drop with respect to flow rate should give a linear relationship with a constant slope. Using this method, the saturation at quasi-steady states in relative permeability measurement can be controlled and the operation time can be significantly reduced. The results show a linear relationship between the pressure drop and flow rate at several quasi-steady states as expected. The results indicate the relative permeability of CO2 in low-permeability rocks can be still high as in high-permeability rocks (e.g. Berea sandstone). The changes of CO2 relative permeability are greatly dependent on the formation of CO2 flow path and the effective area of CO2 flow path in pore space as shown by the X-ray CT images. Our results are essential for understanding the behaviour of CO2 migration and trapping in CO2 storage reservoirs with low-permeability tight interbeds and the transition part of caprocks. The measurement results give important constraint in reservoir simulations for CO2 storage.