Many heavy oil reservoirs under solution gas drive show abnormally high final recoveries. One of the mechanisms to explain these phenomena is the foamy oil flow effect which occurs under certain operating conditions. It has been studied extensively, yet remains poorly understood and difficult to model. The objective of this work was to investigate the effect of different parameters on foamy oil behaviour and the performance of solution gas drive in heavy oil reservoirs.;The first part of this study was aimed at investigating the issue of foamy oil viscosity by measuring the foamy oil viscosity under varied conditions. The effects of several parameters, such as shear/flow rate, foaminess and gas volume fraction and type of viscometer employed, on foamy oil viscosity were experimentally evaluated. Three different viscosity measurement techniques, including Cambridge viscometer, capillary tube as well as a slim tube packed with sand, were used to measure the apparent viscosity of gas-in-oil dispersions. The results show that the type of measuring device used has a significant effect. The results obtained with Cambridge falling needle viscometer correlate reasonably well with the observed behaviour in the slim tube. The capillary viscometer results were significantly different from those of the other two viscometers. Also, unlike live oils, the apparent viscosity of foamy oils was flow rate dependent. Overall, the value of foamy oil viscosity was found to be similar to live oil viscosity for a large range of gas volume fraction. The results obtained also showed that the presence of an added foaming agent had only a minor impact on the apparent viscosity of foamy oil, especially at higher volume fractions of gas. Also, at the same volume fraction of gas, the apparent viscosity was higher at higher flow rate. Overall, the presence of a foaming agent resulted in enhanced dispersed flow of gas, as evidenced from the size of bubbles being produced and the observed pressure fluctuations;The second part of this study was aimed at developing an improved understanding of the effect of oil foaminess on solution gas drive performance and examining ways of recovering additional oil from pressure depleted foamy oil reservoirs. Typically only 5-10% of the OOIP is recovered by primary recovery. Therefore, the need to find a follow-up process is paramount. Using CO2 or a mixture of CO2 and a light hydrocarbon solvent injection to re-pressurize the reservoir for enhanced recovery appears to be a promising option.;In this part of the study, depletion tests were carried out in a 2-meter long sand-pack to evaluate the effects of oil foaminess, rate of depletion and the flow orientation (vertical versus horizontal) on solution gas drive recovery. Some of the depletion tests were followed by one or two cycles of solvent injection to examine the feasibility of additional oil recovery.;The results show that the presence or absence of the foaming agent had only a minor effect on solution gas drive recovery. The rate of depletion, which controls the pressure gradient that develops in the sand-pack, was the most important factor in determining the performance. The recovery factor was correlated with the average pressure gradient in the sand-pack during the depletion and found to depend strongly on this parameter with only a minor variation due to oil foaminess and flow orientation.;The cyclic solvent injection into pressure depleted sand-packs gave very encouraging results, especially when the original solution gas drive recovery was low. The overall recovery after two cyclic of CO2 injection was around 30%.
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