This is the second paper of a series in which we study heavy oil in porous media. The first paper dealt with an experimental study (Wang et al. 2008), whereas a mathematical and simulation study is presented here. The research program stems from the need to predict the field performance of a class of heavy-foamy-oil reservoirs. These reservoirs show a better-than-expected primary performance: lower production gas/oil ratios (GORs), higher-than-expected production rates, and higher oil recovery. A mechanism used to account for the observed performance is that the liberated solution gas is entrained in the oil when the reservoir pressure falls below the thermodynamic equilibrium bubblepoint pressure. The presence of entrained gas increases the effective compressibility of the oil phase and prevents gas from becoming a free phase. Hence, the foamy oil behaves as if it has a pseudobubblepoint pressure below the usual equilibrium bubblepoint pressure. This paper describes a pseudobubblepoint model and a methodology that can be used to compute foamy-oil fluid properties from conventional laboratory pressure/volume/temperature (PVT) data. The techniques developed are then used to study foamy oil in the Orinoco belt, Venezuela. The present mathematical model is validated by comparing numerical and experimental results.