Marcelo Souza Castro

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.

Summary: Polymer solutions are essential in enhanced oil recovery (EOR) for flooding applications but are susceptible to mechanical degradation, which severely impacts its rheological behavior. In this study, we examine the degradation of sulfonated polyacrylamide (SPAM) in a flow loop simulating an oil production system with an electrical submersible pump (ESP). The effects of the non-Newtonian fluid on ESP performance were analyzed under different operational conditions of flow rate and rotational speed. The results identified that the ESP was not the primary contributor in the tested conditions, with the globe valve differential pressure as the most relevant contributor. The ESP exhibited a significant head reduction due to the solution’s effective viscosity. However, the required shaft power remained unchanged, as strong shear rates on the impeller’s external surface reduced viscosity due to the shear-thinning behavior of the solution. A model based on the first Newtonian plateau viscosity successfully estimated ESP performance and provided the shear rates within the pump. The head losses were attributed to low shear rates in the ESP diffuser and impeller channels, which can be associated with the increment of viscosity and friction losses.

This study presents an experimental investigation of the hydrodynamic behavior of multiphase flows (water–air and oil–air) through needle and globe valves. The experiments were conducted at the Center for Petroleum Studies (CEPETRO) of the University of Campinas (UNICAMP), using an acrylic test section with an internal diameter of 19 mm installed in a horizontal configuration. The objective was to characterize the localized head loss, represented by the localized head-loss coefficient (K), under different multiphase flow patterns: annular and elongated bubbles. The transparent valves enabled direct visualization of flow structures, such as recirculation zones, as well as the formation of flow patterns upstream and downstream. The results showed that the needle valve consistently exhibited higher head-loss coefficients than the globe valve, particularly at low opening ratios and low Reynolds numbers. For both the annular and elongated-bubble patterns in water–air flow, the globe valve displayed (K) values significantly lower (typically between 1.8 and 7) than those of the needle valve (ranging from 4.95 to 27.0), highlighting the effect of a smoother internal geometry. The use of oil–air flow increased localized losses compared to water–air, reflecting stronger viscous effects and lower mixture Reynolds numbers. Additionally, flow visualization confirmed low-pressure regions and strong recirculation zones inside the valves in the restriction region (the plug area of the needle and globe valves).