Chemical Reaction Equilibrium Theory - A Novel Approach to Estimate Shale Reservoir Fluid Compositions

Abstract

Shale reservoirs are characterized by having low permeability which prevents the fluid components from moving freely in the reservoir. Shale producers therefore often face challenges getting representative fluid samples. This paper shows the composition of fluids in a low permeability reservoir can be estimated using the theory of chemical reaction equilibria, and in some cases can replace the need for a physical sample. It is assumed that chemical equilibrium determines the relative stability of carbon number (CN) fractions in a shale fluid and that the distribution of components can be calculated by solving a reaction equilibrium. Known fluid compositions are used to establish Gibbs’ energy of formation as a function of temperature for each CN fraction across the fluids. Given this trained Composition Estimation Model, only temperature, pressure and GOR (gas-oil ratio) are required to estimate a fluid composition. The method has been tested on US shale fluids. Fluids from the Eagle Ford and Permian Basin fields have been used to train the model, making it possible to predict other Eagle Ford and the Permian Basin shale fluid compositions. The model was also evaluated on a fluid from another tight formation in the Texas area. The fluid samples cover reservoir temperatures between 160-320°F, and the fluid GORs range from 2,400 to 8,200 Scf/Stb and saturation pressures from 3,700 to 5,600 psia.