Density and Viscosity of “Live” Water-in-Heavy-Oil Emulsions under Reservoir/Production Conditions: Experimental and Modeling Approaches

Abstract

Water-in-heavy-oil (W/O) emulsions represent significant flow assurance challenges in the oil and gas industry, affecting oil recovery, energy consumption, and equipment integrity. Understanding their physical properties under reservoir and production conditions is essential, as these properties directly influence fluid flow behavior. This study evaluates the density and viscosity of heavy oil emulsion recombined with methane (5 m3·m–3) over a range of pressures (40–250 bar), temperatures (323.15–368.15 K), and water cut (3–30 wt %). Measurements were performed using a U-tube oscillation densimeter and a capillary viscometer above the bubble point pressure. Density and viscosity were modeled using Soave–Redlich–Kwong (SRK) and Peng–Robinson (PR) cubic equations of state (EoS) coupled with an emulsion viscosity formulation. The experimental results indicate that increasing temperature significantly reduces density and viscosity due to thermal expansion and enhanced molecular mobility, whereas pressure intensifies intermolecular interactions, which leads to higher values of these properties. Increasing water cut promotes stronger droplet–droplet interactions and microstructural organization within the emulsion. Density variations remained below 3%, while viscosity exhibited changes of up to 80%, which underscores the dominant role of interfacial and multiscale phenomena. All EoS provided satisfactory predictions, with average deviations below 1.46% for density and 9.30% for viscosity; SRK showed better overall agreement than PR and PR78, while the use of PR78 did not lead to systematic improvements over the conventional PR formulation. Overall, the results provide new insights into heavy oil emulsion behavior and support the development of improved thermodynamic models and flow assurance strategies under realistic conditions.