The impetus for this work stems from the need to predict the field performance of a class of heavy oil reservoirs described as "foamy oil" reservoirs. Foamy oil reservoirs exhibit better than expected primary performance. Foamy oil reservoirs deliver greater primary recovery with less reservoir pressure decline and with lower GOR's than what is predicted by reservoir simulators using conventional black oil fluid properties.
One mechanism theorized to account for the observed performance is that the oil from these foamy oil reservoirs entrains the solution gas liberated when the reservoir pressure falls below the thermodynamic equilibrium bubble point pressure, i.e., they form a foam. Finite time is required for the entrained gas to disengage and form a continuous flowing gas phase. The presence of entrained gas increases the effective compressibility of the oil phase and prevents gas from rushing to the wellbore in proportion to its large viscosity contrast with the oil. Thus, the foamy oil behaves as if it has an "effective" or "pseudo-" bubble point pressure below what is measured in a PVT cell in the laboratory. This paper describes a "pseudo-bubble point" fluid property model and develops a methodology that can be used to calculate "foamy oil" fluid properties from conventional laboratory PVT data which can be used in a simulator to model the performance of a foamy oil reservoir. The pseudo-bubble point pressure is an adjustable parameter in this fluid property description.
A technique is presented to alter normal laboratory PVT data to "foamy oil" fluid property data which if used in a simulator will account for the production anomalies observed in the field. The method is illustrated for a typical Albertan foamy oil. The foamy oil characterization is then used in SSl's thermal simulator, THERM, to illustrate the effect on predicted model performance.
Several authors have reported on the anomalously good primary performance of certain Canadian solution gas drive heavy oil reservoirs. In 1986 G.E. Smith1 described the better than expected performance of wells in the L10ydminster area of Alberta, Canada. He theorized thai the anomalous field performance is due to the formation of "wormholes" created by producing formation sand and the formation of a highly compressible mobile liquid phase consisting of true liquid and very tiny entrained gas bubbles, i.e., a "foamy oil." Smith defined a heavy oil pseudo-pressure function and used it in Darcy's radial flow equation 10 account for the effects of an enhanced liquid phase compressibility.
Maini, Sarma, and George2 presented laboratory experimental results which provide experimental verification of the in-situ formation of a non-aqueous "foamy oil" under solution gas drive conditions. Their experimental results show that the foamy oil retards the formation of a continuous mobile gas phase and provides a natural pressure maintenance mechanism. These effects result in higher primary oil recovery.
Loughhead and Saltuklarogu3 discussed their attempts to history match the performance of wells in Mobil's Celtic Field.
