Experimental and mathematical modeling studies on foamy oil stability using a heavy oil–CO2 system under reservoir conditions

Abstract

This study experimentally and mathematically investigated the foamy oil stability of a heavy oil–CO2 system. Experimentally, a new test method employing a gas cap was applied to avoid the effect of oil coating. In total, seven experiments were carried out for the heavy oil–CO2 system, using the constant composition expansion process in a pressure/volume/temperature cell under different pressure depletion rates (1, 2, 4, 8, 16, 24, and 32 kPa/min). Foamy oil stability was monitored for each test, and phase behavior differences were analyzed among the different pressure depletion rates. Experimental results indicate that pseudo-bubble-point pressure decreases with increased pressure depletion rate, and the maximum relative volume of foamy oil increases with increased pressure depletion rate. This work further performed a mathematical modeling study, developing a new dynamic reaction rate model to history-match the foamy-oil-stability experimental results. A First-order Reaction was applied for the both gas transfer processes (solution gas transfers to dispersed gas and dispersed gas transfers to free gas). The mathematical model was developed to simulate changes of foamy oil volume, the reaction rate constants k1 (indicating gas phase transfer rate from solution gas to dispersed gas) and k2 (indicating gas phase transfer rate from dispersed gas to free gas) were determined using the developed model, and trends were identified for the reaction rate constants changing with pressure depletion rates. The mathematical modeling study shows that (1) reaction rate constants k1 and k2 increase with increased pressure depletion rate on the order of 0.001 min−1; (2) k2 is much more sensitive than k1; and (3) pressure depletion rate can be optimized to achieve more stable foamy oil behavior.