Foamy oil flow is believed to be an important factor in providing higher than expected primary recovery factors in Canadian heavy oil reservoirs exploited with the cold heavy oil production (CHOP) technology. It is widely accepted that, under field conditions used in CHOP, the gas released from solution starts to flow while remaining dispersed in oil. However, our understanding of the events that occur between the nucleation of gas bubbles and the start of dispersed gas flow is incomplete. The objective of this work was to examine these events using a variety of experimental tools including an etched glass micro-model, Magnetic Resonance Imaging (MRI) and depletion tests in long sand-packs.

An etched glass micro-model was used to visually examine the formation of gas bubbles when pressure is reduced and gas starts coming out of solution. These tests showed that the gas release does not always start in the part where the pressure would be expected to be lower, i.e. near the production end.

A special MRI apparatus was used for in-situ measurement of the gas saturation along the length of a core, during a depletion test, in which one end of the core was open to flow, while the other end remained closed. Two comparative tests were carried out with a viscous heavy crude oil and a mineral oil of low viscosity, using the same porous medium and same pressure decline rate. A comparison of the results for these two systems showed that unlike the non-foamy system, in the foamy heavy oil test, the first bubbles appeared near the closed end and the intensity of gas release slightly decreased from closed end towards the production end.

The initial pressure response of a 2-meter long sandpack to fast depletion was measured at several different locations in the sand-pack. The recorded pressures show a rapid decline in pressure followed by a substantial bounce back. Three different oils were used in this work and the results are discussed in the light of information obtained from the micromodel tests and the MRI tests.


Several recent papers have noted that often the solution gas drive process operates differently in heavy oil reservoirs compared to the conventional oil systems(1–5). This is specially true in Canadian heavy oil reservoirs when the so-called cold heavy oil production (CHOP) process, which involves production of substantial volume of sand with the oil is used. Both the oil production rate and the oil recovery factor are much higher when the sand is produced into the wells and transported to surface with the oil. Oil production rates have been reported to be more than ten times the flow rate predicted by Darcy's law and the projected recovery factors are two to three times higher than what would be predicted by the conventional solution gas drive theory(6). It is believed that the sand production increases the fluid mobility in the near well zone by increasing the permeability in the affected zone(7).

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