The reliable predictions of liquid holdup and pressure drop are essential for pipeline design in oil and gas industry. In this study, the drift-flux approach is utilized to calculate liquid holdups. This approach has been widely used in formulation of the basic equations for multiphase flow in pipelines. Most of the drift-flux models have been developed on an empirical basis from the experimental data. Even though, previous studies showed that these models can be applied to different flow pattern and pipe inclination, when the distribution parameter is flow pattern dependent. They are limited to a set of fluid properties, pipe geometries and operational conditions. The objective of this study is to develop a new drift-flux closure relationship for prediction of liquid holdups in pipes that can be easily applied to a wide range of flow conditions. The developed correlation is compared with nine available correlations from literatures, and validated using the TUFFP (Fluid Flow Projects of University of Tulsa) experimental datasets and OLGA (OiL and GAs simulator supplied by SPTgroup) steady-state synthetic data generated by OLGA Multiphase Toolkit. The developed correlation performs better in predicting liquid holdups than the available correlations for a wide range of flow conditions.

An experimental study has been conducted to investigate high-viscosity oil/water flow in inclined pipes. The pipe inside diameter (ID) is 50.8 mm and pipe inclination angles are -2°, 0°, 5° and 10° from horizontal. The fluids are a mineral oil with a viscosity range of 0.2 -1.1 Pa·s corresponding to temperatures 60 -100 °F and filtered tap water. Tulsa city natural gas was used to pressurize the facility to 250 (+20) psig. Superficial oil velocity ranged from 0.1 to 1 m/s and superficial water velocity ranged from 0.1 to 0.5 m/s. Experimental measurements obtained are pressure gradient and water holdup. Pipe viscometer was used to obtain live oil viscosity measurements. Flow patterns were observed through a sapphire window and recorded with a high speed video system. The experimental measurements and observations are used to compare with mechanistic model predictions to identify the deficiencies in the models.

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Summary Understanding the behavior of two-phase flow is a key parameter for a proper oil/gas-production-system design. Mechanistic models have been developed and tuned to model the entire production system. Most existing two-phase-flow models are derived from experimental data with low-viscosity liquids (μL < 20 mPa·s). However, behavior of two-phase flow is expected to be significantly different for high-viscosity oil. The effect of high liquid viscosity on two-phase flow is still not well-studied in vertical pipes. In this study, the effect of high oil viscosity on upward two-phase gas/oil-flow behavior in vertical pipes was studied experimentally and theoretically. A total of 149 air/high-viscosity-oil and 21 air/water experiments were conducted in a vertical pipe with an inner diameter (ID) of 50.8 mm. Six different oil viscosities—586, 401, 287, 213, 162, and 127 mPa·s—were considered. The superficial-liquid and -gas velocities were varied from 0.05 to 0.7 m/s and from 0.5 to 5 m/s, respectively. Flow pattern, pressure gradient, and average liquid holdup were measured and analyzed in this study. The experimental results were used to evaluate different flow-pattern maps, mechanistic models, and correlations for two-phase flow. Significant discrepancies between experimental and predicted results for pressure gradient were observed.