A number of heavy oil reservoirs under solution gas drive show anomalously good primary performance. Foamy oil behaviour is believed to be one of the reasons. Several previous investigators have developed numerical models to simulate the foamy oil fiow. These models account for the presence of foamy oil effects by modifying the equilibrium properties of the rock-fluid system, such as the PVT characteristics and relative permeability. Their approach does not account for the time (or rate) dependent changes in foamy oil characteristics. This paper proposes a methodology for including the non-equilibrium processes in calculating the foamy oil properties. The basic foundation of this model rests on theories of bubble nucleation and bubble growth. However, several simplifying assumptions have been used to keep the mathematical treatment tractable and to maintain consistency with reported experimental observations. The model is verified by matching our calculated results with the experimental data. The results calculatedfrom this model show how the foamy oil properties vary with pressure and time. The volumes and compressibilities of foamy oil increase to their maximum values before they decrease with time. The maximum values strongly depend on the amount of the gas that can be entrained in the liquid oleic phase. The amount of entrained gas is a key parameter in foamy oil flow. This method of calculating foamy oil properties provides the basics for developing numerical simulation models of foamy oil flow. The results from this model may also be useful for well testing analysis in foamy oil reservoirs.