CO2 Injection in Aquifers and Oil Reservoirs – Relative Permeability, Fines Migration and Oil Recovery

This thesis answers following specific questions: (1) how to determine CO2-water relative permeability free of the effect of fines migration? (2) how to incorporate capillary pressure boundary conditions to improve the estimation of relative permeability? (3) whether fines migration affects CO2 residual trapping? (4) how CO2 injection performs in comparison with N2 and CH4 in terms of tertiary oil recovery during immiscible displacement? To examine the effect of fines migration on CO2-water drainage relative permeability measurements, flooding experiments are performed using sandstone cores and a sintered glass core. Experiments are designed to control the extent of fines migration by changing the amount of CO2-saturated water injected. For sandstone cores, CO2 relative permeability is reduced (by 21% to 48%) during the flooding experiments when CO2-saturated water is injected. Experiments performed on the glass core suggest that the error in CO2 relative permeability caused by the absence of CO2-saturated water is negligible. Therefore, it is proposed that CO2-saturated water be omitted during CO2-water relative permeability measurements. To investigate fines migration as a mechanism for CO2 residual trapping, imbibition experiments are performed on sandstone cores previously flooded with CO2. Residual CO2 saturation after water imbibition is found to be 6 to 7% greater if fines migration occurs. This is attributed to pore plugging caused by fines migration, impeding the imbibing water from displacing CO2 in the plugged pores. Experimental data are further used for modelling to examine the effect of capillary pressure boundary conditions and hysteresis on CO2-water relative permeability. History-matched relative permeability curves are found to be significantly closer to the proposed model estimates than to estimates from conventional methods. Tertiary N2, CH4, and CO2 injection is performed into a sandstone core to compare the oil recovery performances of the three gasses. Tertiary oil recovery for CO2 injection is found to be 23.1% of the original oil in-place, which far exceeds the 7.3% for CH4 injection and 5.3% for N2 injection. For tertiary CO2 injection, mass transfer between oil and CO2 is observed, which is found to lead to more production of the lighter oil after the oil bank production stage