Viscosity is a critical fundamental property required in many petroleum reservoir applications, including the estimation of reserves, the calculation of flow rates in porous media or wellbores, and the determination of the mobility ratio of a displacement process. Direct viscosity measurements for every encountered fluid at all conditions of interest are not only expensive and time-consuming but also extremely difficult, particularly at extreme conditions of temperature and pressure. Viscosity models and correlations are an alternative approach to obtain viscosity data. Because the hydrocarbons produced from ultra-deep reservoirs experience significant decreases in temperature and pressure during production, it is highly desirable to employ viscosity models that are reliable and accurate over wide ranges of temperatures and pressures. In this work, viscosity models for pure hydrocarbons are comprehensively reviewed. The models assessed in this study are suitable for use in reservoir simulators and are capable of estimating the viscosity of multi-component mixtures with changing composition. The performance of several selected viscosity models representative of various predictive and correlative approaches is discussed and evaluated by comparison to experimental viscosity data at ambient and extremely high-temperature, high-pressure (HTHP) conditions up to 300 oC and 300 MPa, conditions that are typically encountered in ultra-deep petroleum reservoirs, such as those found beneath the Gulf of Mexico. The applicability of each method is discussed and recommended models and approaches are identified.

Viscosity models for hydrocarbons at extreme conditions: A review and comparative study

254th National Meeting (2017)

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