The field experience in Western Canada has shown that the primary depletion behaviour of several heavy oil fields is anomalous and inconsistent with conventional theories. It is believed that at least foamy oil flow effects cause a part of this anomaly. It has been theorised that during primary production, the solution gas released from heavy oil does not disengage from the liquid immediately but remains dispersed in the form of small gas bubbles which tend to flow with the oil. This paper presents an experimental study of solution gas drive in foamy oil systems.

Primary depletion tests were conducted in a two meters long sand-pack using several different oils to evaluate the effects of different process parameters, such as oil viscosity and pressure decline rate. The results show that the performance of solution gas drive depends on the pressure decline rate (or drawdown pressure) imposed on the system. Experiments, in which the pressure at the production port was decreased very slowly, resulted in low recovery factors. When the pressure at the production port was reduced rapidly, high recovery factors were obtained. It was observed that a large pressure gradient developed and persisted in fast decline experiments while in slow decline experiments the pressure gradient remained very small. The results suggest that a different drive mechanism, which may be called foamy solution gas drive, becomes operative in fast depletion tests.

The oil viscosity was found to have only a modest effect on the recovery factors observed in fast pressure decline experiments. However, the critical rate of pressure decline needed to maintain the foamy drive mechanism was viscosity dependent; increasing sharply with decreasing oil viscosity. The results also showed that, other factors being the same, the presence of asphaltenes did not affect recovery factors in high rate solution-gas-drive tests.


Cold production of heavy oil has become an attractive heavy oil production method past few years. Although cold production has been very successful in many heavy oil pools, it is not risk free. The final primary recovery factors differ widely among reservoirs having similar permeability and viscosity characteristics. Even within the same reservoir, some wells are better producers while others perform rathe poorly. The reasons for such performance differences remain obscure. Numerical simulation of primary production (Loughead and Saltuklaroglu; 1992) suggests that the wells, which perform poorly, are showing the normal solution gas drive behaviour while the wells which are prolific producers are anomalous. Several reasons have been suggested for higher than expected productivity and unexpectedly high primary recovery factors. These include formation of wormholes around the well, increased permeability due to sand dilation, and foamy oil flow. The first two appear to be responsible for higher than expected production rates and the foamy oil flow is thought to be the main reason for high primary recovery factors (Maini, Sarma and George; 1993).

Advances in horizontal well technology have removed some of the uncertainty from cold heavy oil production. Long horizontal wells lead to economically attractive (high) production rates even in the absence of wormholes and other unusual effects.

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