RESUMO
Low liquid-loading flow frequently occurs during the transport of gas products in various industries, such as in the Oil & Gas, the Food, and the Pharmaceutical Industries. Even small amounts of liquid can have a significant effect on the flow conditions inside the pipeline, such as increased pressure loss, pipe wall stresses and corrosion, and liquid holdup along the pipeline. However, most studies that analyze this type of flow only use atmospheric pressures and horizontal 1-in or 2-in pipes, which do not accurately represent the range of operating conditions present in industrial applications. Therefore, this study focused on modeling low liquid-loading flow in medium-sized (6-10 in) pipes, using CFD simulations and experimental data from the University of Tulsa, and then applying it to real operating conditions from a Colombian gas pipeline. An acceptable difference was observed between experimental and CFD data, both for the liquid holdup (18%) and for the pressure drop (12%). Variables like pressure drop and wall shear stress increase with phase velocity, operating pressure, and pipe inclination. Liquid holdup increases with liquid velocity but decreases with all other factors. The relation of flow variables with phase velocities is of particular interest: Doubling the gas velocity decreased holdup 70% and increased pressure drop tenfold. On the other hand, the presence of the liquid phase seems to be more influential on process variables than its exact flowrate; the introduction of the liquid phase to a single-phase gas causes an increase in pressure loss by a factor of three, but doubling the liquid velocity only increases the pressure loss by a further 30%.
RESUMO
To avoid gas hydrate formation during oil and gas production, companies usually employ thermodynamic inhibitors consisting of hydroxyl compounds, such as monoethylene glycol (MEG). However, these inhibitors may cause other types of fouling during production such as inorganic salt deposits (scale). Calcium carbonate is one of the main scaling salts and is a great concern, especially for the new pre-salt wells being explored in Brazil. Hence, it is important to understand how using inhibitors to control gas hydrate formation may be interacting with the scale formation process. Multiple regression and design of experiments were used to mathematically model the calcium carbonate scaling process and its evolution in the presence of MEG. It was seen that MEG, although inducing the precipitation by increasing the supersaturation ratio, actually works as a scale inhibitor for calcium carbonate in concentrations over 40%. This effect was not due to changes in the viscosity, as suggested in the literature, but possibly to the binding of MEG to the CaCO3 particles' surface. The interaction of the MEG inhibition effect with the system's variables was also assessed, when temperature' and calcium concentration were more relevant.