Experimental Study on High Viscosity Oil/Water Flow in Horizontal and Vertical Pipes

Abstract

Abstract The average crude oil produced around the world becomes heavier every year. High viscosity oil multiphase pipe flows are experienced during the production and transportation of heavy oils at normal temperatures or conventional oil at low temperatures. Heavy oil is normally produced with low GOR but considerable water cut due to cognate or enhance oil recovery reasons. Since high viscosity oil-water two-phase flows were not well understood, an experimental study of high viscosity oil-water flows in horizontal and vertical pipes with a 50.8-mm ID has been conducted to investigate the effect of high oil viscosity on flow pattern, pressure gradient and water holdup. The observations and measurements of flow pattern, pressure gradient and water holdup were obtained over the ranges of oil and water superficial velocities from 0.1 to 1m/s for horizontal and vertical upward flows. The pressure was maintained at 2 MPa using compressed Tulsa City natural gas. Non-additive Lubsoil ND 50 was used as test oil and filtered tap water as water phase. Oil viscosities varied from 0.22 to 1.07 Pa.s. The flow patterns and oil-water mixing status were observed through a sapphire window and the images were recorded using high speed and high definition video cameras. The flow patterns were mostly dispersion of oil in water and water layer (DO/W&W) for horizontal flows and core annular flow for vertical flows. Extensive measurements of water holdups and pressure gradients at different superficial velocities, viscosities and inclinations were acquired and analyzed. Introduction The global heavy oil reserve is approximately 2 trillion barrels, more than twice of conventional light crude oil. As the conventional oil recourses are being depleted worldwide, vast heavy oil reserve available in various parts of the world becomes more and more important as a future energy source. Accurate prediction of high-viscosity oil multiphase flow behavior is needed to produce and transport high-viscosity oil economically and safely. The current empirical correlations and mechanistic models used for multiphase flow pressure drop, holdup and flow regime predictions were developed for low viscosity oils. There have been numerous theoretical and experimental studies on multiphase pipe flow, with the majority focused on gas-liquid two-phase pipe flow. The following literature review summarizes the studies on oil-water two-phase flows. Russell and Charles (1959) studied about pressure gradient reduction in an oil pipeline by injection of water. They derived a general mathematical model for two immiscible liquids flowing in two layers between wide parallel plates, and concentrically in a circular pipe. Two equations were used for the two immiscible Newtonian liquids flowing in laminar motion. These equations can be solved to predict the reductions in pressure gradient when a less viscous liquid is introduced between the more viscous liquid and the stationary boundaries of the flow area. Russell et. al. (1959) examined the flow characteristics of oil-water in a horizontal 2.05-cm (0.8057-in) inner diameter (ID) pipe. They used oil with the viscosity of 0.018-Pa.s (18.0 cp), specific gravity of 0.834 at 25 °C (77 °F). The flow behaviors were investigated over a range of input oil-water volume ratios from 0.1 to 10 at different superficial water velocities ranging from 0.035 to 1.08 m/s (0.116 ft/s to 3.55 ft/s). The experimental data were correlated to their theoretical model of the laminar flow of two immiscible liquids between wide parallel plates. Three flow patterns were observed including bubble, stratified and mixed flows. He found that pressure drop data shows good agreement with their correlation in laminar region and the holdup is a function of liquid input ratio and viscosity.