Summary
Solution gas drive is effective to recover heavy oil from some reservoirs. Characterization of the relevant recovery mechanisms, however, remains an open question. In this work, we present an experimental study of the solution gas drive behavior of a 9°API crude oil with an initial solution gas/oil ratio (GOR) of 105 scf/STB and live-oil viscosity of 258 cp at 178°F. Constant rate depletions are conducted in a composite core (consolidated) and a sandpack (unconsolidated). The sandpack does not employ a confining pressure, whereas the consolidated core does. The evolution of in-situ gas saturation vs. pressure is monitored in the sandpack using X-ray computed tomography. The two different porous media allow us to develop a mechanistic perspective whereby the effects of depletion rate and overburden pressure on heavy-oil solution gas drive are investigated. The results are striking. They show that the overburden pressure offsets partially the pore-pressure decline. This compaction, in turn, modifies the size and shape of mobile gas bubbles, and as a result the oil and gas relative permeabilies are greater within the confined, consolidated core. Additionally, the supersaturation in the sandpack is markedly larger, but recovery is greatest from the composite core at identical rates as a result of compaction.
Introduction
Solution gas drive in some heavy-oil reservoirs yields unexpectedly large oil recovery. Remarkably, the reservoir pressure declines more slowly than expected and the produced GOR increases slowly below the equilibrium bubblepoint pressure. Since 1988, when Smith identified the phenomenon (commonly referred to as foamy oil), experimental and theoretical studies have aimed to elucidate gas-flow and oil-production mechanisms. Results indicate that the factors governing the efficiency of heavy-oil solution gas drive are oil viscosity (Tang and Firoozabadi 2003, 2005), depletion rate (Tang et al. 2006; Kumar et al. 2000; Sahni et al. 2004), solution GOR (Tang and Firoozabadi 2003), oil composition (Tang et al. 2006; Bauger et al. 2001), and gas-bubble morphology (Li and Yortsos 1995; Tang et al. 2006). Obviously, these factors are not mutually exclusive. Among them, depletion rate as well as the size and shape of bubbles play a key role in recovery. Additionally, the oil composition is important because it plays a determining role in the flowing gas-bubble size that ultimately determines gas-phase mobility (Tang et al. 2006).
Gas bubbles grow as a result of supersaturation (the difference between equilibrium and dynamic pressure) as well as pressure depletion. Gas-bubble nucleation is usually described as progressive or instantaneous (Li and Yortsos 1995; Firoozabadi and Kashchiev 1996), depending on the oil composition and porous medium (Tang et al. 2006; Kumar et al. 2000). Experiments with (El Yousfi et al. 1997; George et al. 2005) and simulation of (Arora and Kovscek 2003) gas nucleation in porous media indicate that the gas phase forms progressively. The period of active bubble nucleation is, however, relatively short compared to the time needed to deplete the sysem. Therefore, the process might be approximated as instantaneous nucleation if the longer time behavior is of interest (El Yousfi et al. 1997).