DETERMINING CO2/BRINE RELATIVE PERMEABILITY FOR RESERVOIRS WITH CO2 SEQUESTRATION POTENTIALS USING STEADY AND UNSTEADY STATE TECHINQUES

In recent years, capturing carbon dioxide (CO2) from power plants and other sources of its emissions and injecting it into deep geologic formations for permanent storage purposes has become an important area of research. Some of the good formation candidates for CO2 sequestration are deep saline aquifers because of their high storage capacity, and their availability in different parts of the world. The depleted oil and gas reservoirs are also considered for CO2 storage as their behaviors are known through many years of production history. Laboratory based tests are needed to improve our understanding of multi-phase flow and trapping of CO2 in saline aquifers and to effectively take advantage of their large storage capacity. In this work the CO2-brine relative permeability behavior of composite cores was investigated from two Paleozoic saline formations from the Michigan and Illinois basins, the Knox and the St. Peter. Full core samples were obtained and several plugs were cut from each along the proposed flow direction. Three plugs from each formation were used to form composite cores in order to conduct experimental drainage CO2-brine relative permeability measurements by implementing the steady and unsteady state techniques at reservoir conditions.
For comparison, steady and unsteady state relative permeability (kr) measurements were conducted under the same conditions. Contrasting the results of the two methods helped in assessing the impact of test methodology, capillary end effects, heterogeneity, and gravity segregation, through the use of X-ray CT-scanning. The results indicate that drainage CO2 end point relative permeability ranged from 0.036 to 0.13, which is much lower than what is expected for a non wetting fluid. The low kr endpoints may be attributed to rock heterogeneity as indicated by the saturation distribution determined from the CT images. Such low relative permeabilities would tend to decrease injectivity while increasing displacement efficiency. This was reflected in the residual brine saturations, which ranged from 0.34 to 0.45, indicating moderate free phase storage capacity for the formations investigated.