New thermodynamic modeling of reservoir crude oil

Abstract

Downhole fluid analysis data from several deepwater oil wells in the Gulf of Mexico are examined. The primary question addressed is whether there is lateral fluid-flow connectivity of the “A” Sand that spans two wells. The predominant fluid gradient observed in the A Sand is the variable dissolved asphaltene content. To perform thermodynamic modeling of the asphaltene gradients, the Flory–Huggins–Zuo Equation of State is used. This formalism relies on using proposed asphaltene colloidal sizes from the Yen–Mullins Model of asphaltenes. In particular, in the reservoir crude oil in Sand A, asphaltenes were presumed to be dispersed as ∼2nm nanoaggregates, which is typical for corresponding black oils. In this case, the Sand A crude oil was shown to be equilibrated thereby indicating reservoir connectivity, which was subsequently proven in oil production. This new analytic methodology is shown to complement a variety of more traditional analyses and is shown to be superior in analyzing the most important reservoir properties. The combination of new petroleum science and new measurement capabilities is yielding many important advances in reservoir evaluation including understanding of fluid-flow connectivity, viscosity gradients, tar mat formation and large gradients associated with fluid disequilibrium.