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Journal of Porous Media
Fator do impacto: 1.49 FI de cinco anos: 1.159 SJR: 0.43 SNIP: 0.671 CiteScore™: 1.58

ISSN Imprimir: 1091-028X
ISSN On-line: 1934-0508

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Journal of Porous Media

DOI: 10.1615/JPorMedia.v18.i2.20
pages 99-111


Farshid Torabi
Petroleum Systems Engineering, Faculty of Engineering and Applied Science, University of Regina, Regina, SK, S4S 0A2, Canada; Department of Petroleum Engineering, School of Chemical and Petroleum Engineering, Shiraz University, Iran
Manoochehr Akhlaghinia
Faculty of Engineering, University of Regina, Regina, Saskatchewan, Canada S4S 0A2
Christine W. Chan
Faculty of Engineering, University of Regina, Regina, Saskatchewan, Canada S4S 0A2


Three-phase relative permeabilities play a crucial role in simulation of thermal heavy oil recovery processes. Obtaining such data is considerably challenging due to the tedious nature of experiments and accuracy of the results. A simulated annealing technique was used to estimate three-phase relative permeabilities in the form of isoperms by utilizing two-and three-phase displacement experiments conducted with a Berea core/heavy oil/brine/CO2 system. After validation of the technique using results obtained from steady-state experiments, the effect of oil viscosity on the three-phase relative permeability was investigated. Results of this study showed that, in a ternary diagram, the three-phase flow zone shifted toward the higher saturations of oil, while no significant change in the size of the three-phase flow zone occurred. Different curvatures were observed for relative permeability isoperms of each phase, indicating dependency of relative permeability to saturation of all phases. Increasing oil viscosity from 1174 to 2658 cP resulted in a decrease in the relative permeability in each phase. Results also indicated that, due to significant difference between the viscosity of the phases, oil relative permeability values are higher than those of brine and CO2 on the order of magnitude of three and five, respectively.