(505c) Multiphase Flow of CO2 and Water In Reservoir Rocks
Among the different identified target formations for the geological storage of CO2, saline aquifers possess the greatest capacity. Predicting the long-term fate of the injected CO2 requires a thorough understanding of the multiphase properties of CO2 and water in these formations. Continuum-scale rock properties such as relative permeability and capillary pressure-saturation relationships will control the long-term distribution of CO2 in the subsurface and provide therefore important information for reservoir simulators that are used to history match and to design field-scale injection tests [1-3]. However, the current experimental data set is scarce and more experimental observations are needed under different conditions and in different geological settings in order to improve the reliability of reservoir simulations to plan future field tests. Moreover, these properties depend on the fluid saturation, which is in turn influenced by rock heterogeneities observed at the sub-core scale. Understanding the role of these sub-core scale heterogeneities on the fluid distribution in a reservoir rock provides a first step towards the development of appropriate methods for up-scaling laboratory data to predict multiphase flow behavior throughout a reservoir.
In this study, results are presented from steady-state core flooding experiments that have been carried out in an apparatus that accommodates cylindrical rock samples of 2 inches in diameter and of varying length. Additionally, the sample is confined by an external hydrostatic pressure (overburden) and it is kept at a constant temperature by electric heaters . Experiments have been conducted at a temperature of 50°C, by injecting CO2/water mixtures at a pressure of about 1300 psi and by keeping the confining pressure at least 300 psi above the pore pressure level, thus mimicking the conditions encountered in a typical deep reservoir. Simultaneously, fluid distribution inside the core is determined by X-ray CT scanning with a resolution of a few pore volumes, thus providing 3D porosity and CO2/water saturation maps during the experiment. Each sample possesses a distinct rock lithology, thus providing a wide range of conditions in terms of heterogeneity, which is regarded here as the distribution of porosity within the core. In a typical experiment, two-phase drainage and imbibition relative permeability curves, capillary pressure, as well as end-point (100% CO2 injection) and residual (100% water injection) saturations are obtained.
In the experiments, low end-point CO2 saturations (0.4 – 0.5) and CO2 relative permeabilities (< 0.4) have been observed. The former have an impact on the amount of pore space that can be actually filled with the injected CO2, whereas the latter affect the way fluid is distributed inside the cores. Both aspects are analyzed and discussed with respect to their relevance for reservoir simulations. Also, observations of residual CO2 saturation are discussed in the context of the long-term stability of CO2 injected in the subsurface. The data are analyzed with imaging software and statistical analysis to investigate the correlation between porosity and CO2 saturation within the core during drainage and imbibition. The analysis is carried out on multiple scales ranging from about 1 mm3 up to the size of the entire core. Generally, the CO2 saturation within the core is heterogeneous even in rocks with homogeneous lithology. Moreover, its distribution varies significantly between samples of different lithologies, often correlating with distinct features observed in the porosity maps. Low porosity regions tend to correlate with low CO2 saturation, whereas higher porosity regions show higher average CO2 saturations, this trend being more marked for cores showing significant heterogeneities. The distribution of low porosity regions within the core affects significantly the measured end point saturations. A patchy distribution leads to fluid bypass and corresponding high residual water saturation even with 100% CO2 injection. However, a low porosity region that crosses the whole section of the core acts as a capillary barrier, which results in high residual CO2 saturation with 100% water injection.
 Juanes, R. et al. (2006). Impact of relative permeability hysteresis on geological CO2 storage. Water Resources Research, 42, W12418.
 Hovorka S.D. et al. (2006). Measuring permanence of CO2 storage in saline formations: the Frio experiment. Environmental Geosciences, 13 (2), 105-121.
 Doughty, C. (2007). Modeling geologic storage of carbon dioxide: Comparison of non-hysteretic and hysteretic characteristic curves. Energy Conversion and Management, 48(6), 1768–1781.