Summary
This study probes experimentally the mechanisms of heavy-oil solution gas drive through a series of depletion experiments employing two heavy crude oils and two viscous mineral oils. Mineral oils were chosen with viscosity similar to crude oil at reservoir temperature. A specially designed aluminum coreholder allows visualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition, a visualization cell was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior vs. pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation vs. pressure. Both depletion rate and oil composition affect the size of mobile bubbles. At a high depletion rate (0.035 PV/hr), a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. Conversely, at a low depletion rate (0.0030 PV/hr), foam-like flow is not observed in the less viscous crude oil; however, foam-like flow behavior is still found for the more viscous crude oil. No foam-like flow is observed for the mineral oils. In-situ imaging shows that the gas saturation distribution along the sandpack is not uniform. As the pattern of produced gas switches from dispersed bubbles to free gas flow, the distribution of gas saturation becomes even more heterogeneous. This indicates that a combination of pore restrictions and gravity forces significantly affects free gas flow. Additionally, results show that solution-gas drive is effective even at reservoir temperatures as great as 80°C. Oil recovery ranges from 12 to 30% OOIP; the higher the depletion rate, the greater the recovery rate.
Introduction
Solution gas drive has shown unexpectedly high recovery efficiency in some heavy-oil reservoirs. The mechanisms, however, that have been proposed are speculative, sometimes contradictory, and do not explain fully the origin of high primary oil recovery and slow decline in reservoir pressure. Smith (1988) first identified this effect. He hypothesized that gas bubbles smaller than pore constrictions are liberated from the oil, but are not able to form a continuous gas phase and flow freely. Instead, the gas bubbles exist in a dispersed state in the oil and only flow with the oil phase. Smith stated that oil viscosity is reduced significantly, resulting in high recovery performance. Later, many researchers focused on so-called foamy-oil behavior. Claridge and Prats (1995) hypothesized that heavy-oil components (such as asphaltenes) concentrate at the interfaces between oil and gas bubbles, thereby preventing bubbles from coalescing into a continuous gas phase. Bubbles are assumed to be smaller than pore dimensions. Claridge and Prats stated that the concentration of heavy-oil components at the interfaces results in a reduction of the viscosity of the remaining oil. Bora et al. (2000) discussed the flow behavior of solution gas drive in heavy oils. Based on their studies, they found that dispersed gas bubbles do not coalesce rapidly in heavy oil, especially at high depletion rate. They stated that the main feature of the gas/oil dispersion is a reduced viscosity compared to the original oil. Models to explain the experimental results were also established (Sheng et al. 1994, 1996, 1999, 1995).