Reservoir Evaluation by DFA Measurements and Thermodynamic Analysis

Abstract

Downhole fluid analysis (DFA ) has enabled the cost-effective measurement in oil wells of a variety of chemical properties of reservoir crude oils. An immediate benefit of DFA is the improvement of the sample quality of the reservoir fluid in the subsurface environment. In addition, this early feedback on the nature of the reservoir fluid aids in understanding key reservoir challenges. DFA also enables the accurate determination of fluid gradients in the reservoir in both vertical and lateral directions. These gradients can then be analyzed in a thermodynamic equation of state (EoS ) context; the gas-liquid properties can be modeled with the cubic EoS and the asphaltene gradients equilibrium can be modeled with the Flory–Huggins–Zuo (FHZ ) EoS with its reliance on the Yen–Mullins model of asphaltenes. Time-dependent processes in geologic time can be modeled by adding appropriate dynamic terms to the EoS. Simple thermodynamic models can then be used to understand distributions of key fluid properties for reservoir crude oils and aid in simulating production. This thermodynamic analysis of the geodynamics of reservoir fluids fills a gap in the industry's modeling of reservoir fluids. Traditional basin modeling predicts what fluids enter the reservoir. This new geodynamic modeling coupled with DFA measurements determines what transpired in geologic time in regards to fluid distributions within the reservoir. The output of this fluid geodynamic modeling can then be used as input for traditional reservoir simulation for production. This new understanding of reservoir fluid geodynamics is made possible by new DFA measurements coupled with new FHZ EoS with the Yen–Mullins model.