Solution-gas Drive In Heavy Oil Reservoirs
Authors: Pooladi-Darvish M. , Firoozabadi A. 
Published: March 2010

Abstract
Different hypotheses have been made to explain the highly favourable behaviour of some of the heavy oil reservoirs under solution-gas drive. The main reasons however remain unclear. Using experiments in an unconsolidated sandpack, we examined the solution-gas drive process in a light oil and a heavy oil. Pressure and volume measurements and visual observation of the flowing fluid at the in situ pressure for the heavy oil system revealed that: critical gas saturation was low (5% or less), the gas phase was not made of microbubbles flowing with the oil stream, liquid mobility did not improve upon nucleation or growth of the gas bubbles, and supersaturation effects were not dominant. The experimental and simulation results indicate that gas mobility in solution-gas drive in heavy oil is much less than in light oil, leading to improved recovery performance of the former.

Introduction
Production from some of the heavy oil reservoirs in Canada and Venezuela has led to unexpectedly high oil rates and recoveries under solution-gas drive. In an early paper, Smith(1) reported this behaviour in the heavy oil reservoirs of the Lloydminster area, Canada. Analysis of the field data showed production rates much in excess of that predicted by the Darcy law(1). Similarly, Loughead and Saltuklaroglu(2) and Metwally and Solanki(3) reported solution-gas drive oil recoveries as high as 14% and flow rates of one order of magnitude greater than the predictions of the Darcy radial flow. These and other authors reported coproduction of large volumes of sand and the delayed liberation of gas from the wellhead crude samples in open vessels. More recently, similar behaviour was reported in some of the heavy oil reservoirs in Venezuela. Mirabal et al.(4) presented examples of high flow rates under solution-gas drive from one of the heavy oil reservoirs of the Orinoco Belt. In addition to the unexpectedly high production rates, the reservoir pressure was nearly maintained in the 12 years of production history.
The economic advantages of the initial development of many of these reservoirs under solution-gas drive are clear; the high costs involved in the traditional thermal methods are avoided(5–7).
To explain the above behaviour, a number of mechanisms have been suggested which can be divided into two main categories; geomechanical effects such as sand dilation and development of wormholes comprise the first category. The second category, which is the subject of the current research, suggests that the special properties of the flowing fluids, the gas and the heavy oil are the main reasons for high production performance.
The effect of many of the pressure maintenance mechanisms such as an active aquifer and the reservoir compaction have been found small in these reservoirs(1,2,4). Due to production, the pore pressure drops below the bubblepoint pressure to a critical supersaturation pressure, and then gas evolves in the porous medium. Kraus, McCaffrey, and Boyd(8) proposed that below bubblepoint, the evolved gas is retained in the porous media until the pressure reduces to a lower pressure called pseudo-bubblepoint pressure.