A Simulator for Solution-Gas Drive in Heavy Oils

Abstract

Abstract Solution-gas drive in heavy oil reservoirs is a complex process, and the mechanisms involved are not fully understood. In the past, these reservoirs have been modelled by altering variables such as critical gas saturation, bubble point pressure, relative permeability curves, fluid properties, and rock properties during sand production. Numerous investigations have shown that gas mobility in heavy oil remains extremely low. Furthermore, experimental observations have suggested that gas mobility depends not only on gas saturation, but also on depletion rate and oil viscosity. It is therefore thought that the viscous forces at the microscopic level affect gas mobility. The dependence of relative permeability to gas on parameters other than gas saturation has been observed previously in processes such as foam flow through porous media, and displacement near miscible conditions, where the ratio of viscous forces to capillary forces is large. In this work, we have developed a numerical simulator where the "apparent" gas relative permeability is a function of rate and gas saturation. The developed model is used to simulate a previously reported set of experiments of solution-gas drive in heavy oils, where the dependence of gas mobility on depletion rate has been observed. It is shown that a model with rate-dependent relative permeability functions can explain many features of solution- gas drive in heavy oil, in particular, its rate-dependent recovery behaviour. Introduction Field experience in many heavy oil reservoirs in Canada and Venezuela have shown that recoveries in the order of 10 - 15% may be achieved under primary depletion(1, 2). Typical observations are high oil production rate, high primary oil recovery, and good pressure maintenance. This behaviour is in contrast with the traditional view of solution-gas drive, where gas flows much faster than oil, leading to high producing GOR, loss of reservoir energy, and low recovery. Many of these reservoirs are produced along with significant amounts of reservoir sand. In addition to the related geomechanical effects, a special fluid flow behaviour is necessary to explain some of the observations, including low producing GOR and high recoveries. There have been very different explanations for the abnormal characteristics observed during solution-gas drive in these heavy oil reservoirs. Smith(1) suggested a simultaneous oil and gas flow in porous media in which the gas is entrained in the oil as tiny bubbles. More recently, Kamp et al.(3) developed a model for the entrained flow of gas in oil, which incorporated a constitutive equation for the viscosity of the bubbly mixture. Maini et al.(4) conducted experiments using unconsolidated sand-packs with heavy oils, and observed high pressure gradients representative of very low gas mobilities. The authors attributed this behaviour to what they called "Foamy Oil Flow." Pooladi-Darvish and Firoozabadi(5) were the first to report quantitative estimates of the phase mobilities under solution-gas drive in heavy oil. They performed depletion experiments in a sand-pack saturated with live oil, and used both light and heavy oil for comparison. Analysis of the data suggested that gas relative permeabilities in heavy oil might be as low as 10−6 - 10−5.