The black oil model has been used to analyze transient pressure data collected from the laboratory pressure depletion tests. Results indicate that the transient pressure responses above bubble point are successfully simulated; however, the pressure responses below bubble point cannot be reproduced using reasonable oil mobility and compressibility. The anomalous pressure responses below bubble point may attribute to non-thermodynamic equilibrium. Gas evolution from solution gas to free gas is time dependent. As a result, the expansion of reservoir fluid with pressure decline is also pressure-dependent and time-dependent, which leads to a rise in reservoir pore pressure following a rapid pressure drop. A diffusivity equation that includes the time- and pressure dependent expansion is proposed for transient pressure analysis involving solution gas evolution.


Analysis of transient wellbore pressure data is an important tool to calculate reservoir permeability in conventional reservoirs. This technique has been also applied to understand the flow mechanisms in solution gas drive (cold production) of heavy oil reservoirs. The anomalous recovery performance of heavy oil reservoirs poses new challenges for transient pressure analysis1.

Smith2 put forward a foamy oil model to explain the performance of heavy oil reservoirs. He believed that the size of gas bubbles in heavy oil reservoirs was so small that gas bubbles could flow in the porous medium and were not blocked by pore throats. On the basis of this rationale, he postulated that the mobile gas and bitumen flowed as a single-pseudo phase with bubbles entrained in the bitumen. He reported that this simple foamy oil model had successfully predicted the pressure data observed in field.

Loughhead and Saltuklarogu3 attempted to history match the performance of wells in Mobil's Celtic Field. To match the field performance, they introduced a high permeability channel that extended 60 meters into the reservoir, adjusted the trapped gas saturation to 35% and held the reduction in the relative permeability to oil to less than 5% within the gas saturation range of 0 to 35%.

Kraus et. al.1 put forward a pseudo-bubble point model to simulate heavy oil flow. They assumed that all free gas released was entrained in the bitumen and flowed with bitumen when the reservoir pressure was between the bubble point and the pseudo-bubble point. After the pseudo bubble point, the entrained gas decreased linearly with decreasing pressure. In this model, the pseudo bubble point was an adjustable parameter that had to be chosen to match field or laboratory performance. Based on numerical studies, they reported that this model matched three of the anomalous production characteristics observed in foamy oil reservoirs, namely 1) high oil recovery; 2) low producing gas-oil ratio, and 3) natural pressure maintenance.

Previous research has concentrated on history matching of field performance. It is well known that this kind of model validation usually suffers from inadequate data. For example, the properties of reservoir fluids and formations are usually incomplete, and producing gasoil ratios from single wells are rarely measured. It is hard to provide persuasive conclusions from these history matches.

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