This work provides a concept for modelling well performance behavior in a gas condensate reservoir using an empirical model for the gas mobility function. This model is given by: k=kmin+(kmaxkmin)[1exp[1r2t]]
This concept model represents the minimum gas permeability (or mobility) near the wellbore and the maximum (or original) gas permeability (or mobility) in the "dry gas" portion of the reservoir, as well as the transition regime. This model was constructed based on observations derived from numerical simulation results where the saturation, effective permeability, and gas mobility are presented as functions of distance in the reservoir.
The utility of this concept is that it can be used to develop a pressure solution for the behavior of the gas phase produced from a gas condensate reservoir. This new solution is validated against numerical simulation and has been presented graphically for use in well test analysis (in the form of "type curves"). The advantage of this solution over the conventional radial composite reservoir solutions is that the evolution of the condensate zone can be represented and evaluated as it occurs in time. The obvious limitation is the simplified form of the kg profile as a function of radius and time, as well as the dependence/appropriateness of the "" coefficient.
Application of this new pressure solution to well test analysis is proposed and comparisons to the radial composite (and other reservoir models) are also presented. Our goal is to demonstrate that the proposed solution has potential utility in the analysis and interpretation of reservoir performance data (most likely, pressure drawdown and pressure buildup test data).
We recognize that the simplicity of this approach may have practical limitations for example, we consider a radially-varying
mobility profile, but we also assume a constant diffusivity this is a potential shortcoming that should be considered in future work.