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As the world's demand for oil increases, more heavy oil reservoirs are being discovered, drilled and produced. However, heavy oil production brings new challenges. One of the challenges is the formation of emulsions. Emulsions can cause high pressure losses, resulting in transportation and pumping problems and separation. The inversion point, at which continuous and dispersed phases in an emulsion changes, needs to be studied to improve knowledge of heavy oil-water emulsions. A new mathematical model was developed in this study using fundamental thermodynamics and conservation of mass laws to predict the inversion point of an emulsion system. Simulation results indicate that the properties of surfactant, emulsion droplet size and standard chemical potentials of the liquid phases play very important role in controlling the inversion point of an emulsion system. The model proposed in this paper can help predict inversion point of an emulsion system. Estimation of inversion point of emulsions helps improve the existing emulsion viscosity correlations and develop new models when necessary. The improved heavy oil-water emulsion viscosity models can be used in design and operation phases of heavy oil fields. Introduction The viscosity of heavy oil-water emulsion can be several orders of magnitude higher than the pure oil viscosity at certain conditions. Therefore, it is crucial to estimate the viscosity of emulsions for the operating flow conditions. One of the earliest studies of viscosities of suspensions and solutions is that of Einstein (1906, 1911). He proposed an emulsion viscosity correlation based on the ratio of emulsion viscosity to the viscosity of continuous phase. The proposed correlation is: Equation (1) where ?r is the ratio of viscosity of the emulsion to viscosity of the continuous phase, and fint is the volume fraction of the dispersed or internal phase. The equation is valid for dispersed phase volume fractions up to 0.2. Therefore, it can only indicate the trend at the origin. Brinkman (1952) presented a very simple method to estimate the viscosity of concentrated suspensions and solutions. He studied the change in viscosity by adding incremental amount of spherical molecules to the pure solvent. He proposed a correlation for viscosity of concentrated suspensions and emulsions as follows: Equation (2) Dougherty and Krieger (1972) assumed that maximum packing of droplets occurs at the inversion point of the emulsion, and proposed the following correlation for emulsion viscosity ratio: Equation (3) where fpack is the volume fraction of the dispersed phase at close packing.

As the world's demand for oil increases, more heavy oil reservoirs are being discovered, drilled, and produced. However, heavy oil production brings new challenges. One of the challenges is the formation of emulsions. Emulsions can cause high pressure losses, resulting in transportation and pumping problems and separation. The inversion point, at which continuous and dispersed phases in an emulsion changes, needs to be studied to improve knowledge of heavy oil-water emulsions.A new mathematical model was developed in this study using fundamental thermodynamics and conservation of mass laws to predict the inversion point of an emulsion system. Simulation results indicate that the properties of surfactant, emulsion droplet size, and standard chemical potentials of the liquid phases play a very important role in controlling the inversion point of an emulsion system. The model proposed in this paper can help predict inversion point of an emulsion system. Estimation of inversion point of emulsions helps improve the existing emulsion viscosity correlations and develop new models when necessary. The improved heavy oil-water emulsion viscosity models can be used in design and operation phases of heavy oil fields.

A hilly-terrain pipeline consists of horizontal, upward inclined and downward inclined sections. The lack of understanding of how three-phase slug flow characteristics change in hilly-terrain pipelines may lead to inaccurate modeling of the phenomenon and thus poor pipeline and downstream facility designs. Although several slug tracking models are available, their performance has not been thoroughly tested against gas-oil-water data in hilly-terrain pipelines due to the scarcity of such data.Three-phase gas-oil-water slug flow evolution in hilly-terrain pipelines was studied experimentally. The constructed experimental facility was a 69-m long, 50.8-mm ID outdoor facility with ±5° inclination angle for a valley configuration. Threephase slug flow developments in the hilly-terrain section were observed and analyzed with the measured pressure drop, average liquid holdup, phase distributions and slug characteristics. This study improves the current understanding of gas-oil-water flow behavior in hilly-terrain pipelines and the effect of water cut on slug flow characteristics. This understanding will improve the existing slug tracking models or can be used to develop new models when, necessary, for the proper design and safe operation of three-phase pipeline systems. Seven three-phase slug flow patterns were identified based on oil-water mixture in the upstream horizontal section of the hilly-terrain unit. These flow patterns were analyzed and compared with slug dissipation in the downhill section of the hilly-terrain unit. When these flow patterns were compared with two-phase slug dissipation behavior, no water cut effect was observed. For moderate and high flow rates, slugs with different oil-water mixing status had differences in slug frequencies and lengths. However, the evolution of liquid slug length distributions for 20% and 80% water cuts in the upstream horizontal section and upward inclined section did not show any significant dependence on water cut.

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