Core-scale experimental study of relative permeability properties of CO2 and brine in reservoir rocks

• Published in: Energy procedia Vol. 1; no. 1; pp. 3515 - 3522
• Main Authors: Perrin, Jean-Christophe, Krause, Michael, Kuo, Chia-Wei, Miljkovic, Ljuba, Charoba, Ethan, Benson, Sally M.
• Format: Journal Article
• Language: English
• Published: Elsevier Ltd 01.02.2009
• Subjects: Carbon Dioxide; Relative Permeability; Sequestration; X-Ray CT scanning; X-Ray CT scanning; Relative Permeability; Carbon Dioxide; Sequestration
• ISSN: 1876-6102; 1876-6102
• DOI: 10.1016/j.egypro.2009.02.144

Experimental studies of both drainage and imbibition displacements are needed to improve our fundamental understanding of multi-phase flow and trapping in CO2-brine systems and effectively take advantage of the large storage capacity of saline aquifers. Very few relative permeability measurements have been made and even fewer with in situ saturation measurements. Two new sets of steady state relative permeability measurements have been made in two different rock samples, and over a range of injection flow rates. These studies show that multi-phase brine displacement efficiency is strongly affected by the heterogeneity of the core. Moreover, we observe that, at any given fractional flow, different flow rates result in different CO2 saturations. Similarly, different flow rates lead to different relative permeability curves. Numerical simulations of two phase displacement are performed on one sample, and at one fractional flow of CO2. Numerical simulations demonstrate that some of the features of the saturation distributions can be qualitatively replicated. However, improvements in the correlations between porosity, saturation and capillary pressure will be needed to replicate the saturation distributions measured in the experiments.