Capillary Number in Heavy Oil Solution Gas Drive and Its Relationship with Gas-Oil Relative Permeability Curves

Abstract

Abstract Many heavy oil reservoirs under solution gas drive show a significant increase in productivity. Different mechanisms have been postulated to explain the high recovery factors observed in the field. Lately, a widely accepted cause of this increase in productivity is the foamy oil flow, which dramatically decreases the gas relative permeability. However, it still remains inadequately understood. It has been reported that the foamy flow effects observed in the laboratory depletion tests are strongly affected by depletion rate. This observed rate effect has been attributed to the influence of the pressure depletion rate on bubble nucleation. However, the researchers have mostly overlooked the capillary number, which increases significantly with increasing depletion rate. The goal of this study was to examine this capillary number effect in heavy oil reservoirs and its relationship with gas-oil relative permeability curves. A number of experiments were carried out on a two-meter long sand-pack to determine the conditions required to produced more oil under solution gas drive. The experimental data were matched on a commercial black oil simulator to determine the relative permeability curve under varying flow conditions and at different capillary number. The experimental results show that the oil produced was a unique function of capillary number and beyond a critical capillary number no additional improvement in the recovery factor was observed. An examination of the changes of capillary number during the test provides insight into the gas-phase build up during solution gas drive and the resulting production behavior. It was also found that oil relative permeability increases and gas relative permeability decreases with increasing capillary number. At high capillary number, relative permeability ratio remains very low up to higher value of gas saturation. The results from this research suggest that the conventional correlations of gas-oil relative permeability should incorporate the effect of capillary number in order to improve the prediction of foamy oil flow mechanism. Introduction The utility of relative permeabilities in describing multiphase flow of fluids through a porous medium has necessitated the development of a number of methods of measuring this property of the rock-fluid systems. All the methods of relative permeability attempt to minimize the significant effect of boundary or end effect on small core plugs1. Most of these studies have also been done for light oil reservoirs and the two-phase relative permeabilities have been found to depend on various parameters such as saturation, saturation history, wettability, and pore structure but not on fluid viscosities, densities, or flow rates2. Many of these parameters have been studied individually. The relative permeability curves obtained from solution gas drive and external gas drive can be different. In the depletion-drive process, the live oil becomes supersaturated with gas. Gas bubbles form after a supersaturation threshold has been exceeded. These bubble then grow by diffusion and expansion. The critical gas saturation is reached when a connected gas phase is developed. Its value can be affected by rate if the number of bubbles nucleated changes with the level of supersaturation and when the processes of gas bubble growth changes from local capillary control to viscous fingering3. In an external gas drive process, gas is injected into a liquid-filled core. The lowest gas saturation in the core at which continuous gas flow occurs is assumed to be the critical gas saturation4,5. However this technique has some undesirable effects such as viscous fingering6 and very long time required to reach the residual oil saturation7. Maini8 suggested that these parameters should be obtained from solution gas drive tests if these data are needed for solution gas drive simulation. Tang and Firoozabadi9 reported measurements of oil-gas relative permeability for cold production in heavy oil reservoirs using solution gas drive process. They used heavy crude oil of 10,000 mPa.s at 35°C for their depletion tests and reported that oil relative permeability is in the range of light oils and gas relative permeability is very low, around 10−5 over a gas saturation of 5.5 to 12%. Gas relative permeability is several times less than in light oil systems and its increase with the evolved gas saturation is very slow. The low gas mobility was quantified by Pooladi-Darvish and Firoozabadi10.