This paper was prepared for the 3rd Numerical Simulation of Reservoir Performance Symposium of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Jan. 10–12, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.


This paper describes a new method for simulating gas-condensate reservoirs. The simulator accounts for both retrograde condensation and vaporization of condensed liquid as well as arbitrary field shapes, well patterns and heterogeneities. The formulation of the simulator is based upon a formation volume factor or Beta-type analysis which is analogous to that used in black-oil simulation models. In the gas-condensate analogy, mass transfer between the gas and liquid hydrocarbon phases is handled by an rs term which has units of STB liquid/MCF dry gas and is similar to the Rs term in black-oil simulation.

Fluid properties for back-oil simulation models are usually obtained from laboratory PVT cell depletion data. This type of model is of questionable reliability only in special cases such as volatile-oil reservoirs where the reservoir pressure and temperature are close to the critical pressure and temperature of the oil. It is reasonable to assume, therefore, that reservoir fluids on the other side of the critical point (e.g., gas-condensate fluids) could be treated in an analogous manner. In other words, one would expect that gas-condensate reservoirs could be treated by a formation volume factor approach with fluid properties determined from laboratory depletion data. The simulator described in this paper employs such an approach.

The simulator handles three phases and consists of numerical solution of the continuity or mass balance equations for gas, liquid hydrocarbon and water in one, two and three dimensions.


The proposed method assumes a condensate-gas to be a pseudo two-component system. The two pseudo-components are, at standard conditions pseudo-components are, at standard conditions of pressure and temperature, a dry gas and a hydrocarbon liquid. Each pseudo-component is itself a pseudo-component is itself a multi-component hydrocarbon fluid. The water phase, if present, constitutes a third "component".

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