It has been well established that the primary production of heavy oil, exhibits higher that expected recovery due to the production of sand and the foamy oil mechanisms. In the literature, there has been much work done in the past to investigate the solution gas drive mechanisms that cause this behavior, in the absence of sand production. The aim of this work is to perform pressure depletion experiments on packings of different scales of length and diameters, ranging from 0.5 m to over 18 m in length and diameters of 0.02 m to 0.08 m. The experimental results combine the production, pressure and saturation data from three different scales with the same depletion rate. An attempt is made to compare and relate the results from the different scales.
Investigations of heavy oil solution gas drive, at the laboratory scale, rely on high depletion rates to reproduce the behavior seen at much lower depletion rates in the field. In addition, altering the depletion rates results in different critical gas saturations, gas relative permeabilities and overall recovery (1,2). The high depletion rate is important at early times when the gas is nucleating and growing; however, at late times the pressure gradient is dominant in mobilizing the fluid(3). Therefore, a high depletion rate experiment may represent near wellbore behavior and a slow depletion rate represents mechanisms further from the well.
Andarcia et al. (4) commented on the difficulty in determining the influence that the depletion rate and the spatial size have on the gas and oil relative permeability. Scaling the experimental results to represent reservoir mechanisms is complex.
There is very little information regarding the effect of experimental sand pack length in the literature. Sheng et al.(5) used the dynamic kinetic model they developed to predict the effect of length for sand packs of three different lengths. They determined that the length of the sand pack is associated with the pressure gradient; in the long sand packs, high-pressure gradients do not develop in the regions far from the wellbore. Therefore, even though the high depletion rate at the production end was the same as the shorter packs, the average pressure decline is slower, resulting in lower recoveries.
Wall and Khurana(6) found that the gas saturation that develops as the pressure of a saturated liquid declines in a porous medium generates low values of relative permeability. They noted that the gas relative permeability is an irreversible function of gas saturation, with the added problem that even at relatively high gas saturations there is zero permeability to gas. Kennedy and Olson(7) observed that variations in gas distribution in the reservoir account for different relative permeabilities for the same gas saturation. Pooladi-Darvish and Firoozabadi(8) also stated high bubble densities and discontinuous gas accounts for the reduced gas mobility. Tang and Firoozabadi(9) assumed that gas and oil flow in pseudo steady state, the gas saturation across the core is uniform, and flow is one dimensional, in order to develop a mathematical model to calculate oil and gas relative permeabilities.
