As the second most widely used artificial lift method in the petroleum industry, electrical submersible pumps (ESPs) maintain or increase flow rates by converting the kinetic energy to hydraulic pressure. As oilfields age, water is invariably produced with crude oil. The increase of water cut generates oil‐water emulsions due to the high-shearing effects inside a rotating ESP. Emulsions can be stabilized by natural surfactants or fine solids existing in the reservoir fluids. The formation of emulsions during oil production creates a high viscous mixture, resulting in costly problems and flow assurance issues, such as increasing pressure drop and reducing production rates. This paper, for the first time, proposes a new rheology model to predict the oil‐water emulsion effective viscosities and establishes a link of fluid rheology and its effect with the stage pressure increment of ESPs.

Based on Brinkman's (1952) correlation, a new rheology model, accounting for ESP rotational speed, stage number, fluid properties, and so on, is developed, which can also predict the phase inversion in oil‐water emulsions. For the new mechanistic model to calculate ESP boosting pressure, a conceptual best-match flow rate (QBM) is introduced. QBM corresponds to the flow rate whose direction at the ESP impeller outlet matches the designed flow direction. Induced by the liquid flow rates changing, various pressure losses can be derived from QBM, including recirculation losses, and losses due to friction, leakage, sudden change of flow directions, and so on. Incorporating the new rheology model into the mechanistic model, the ESP boosting pressure under oil‐water emulsion flow can be calculated.

To validate the proposed model, the experimental data from two different types of ESPs were compared with the model predictions in terms of ESP boosting pressure. Under both high-viscositysingle-phase fluid flow and oil‐water emulsion flow, the model predicted ESP pressure increment matches the experimental measurements well. From medium to high flow rates with varying oil viscosities and water cuts, the prediction error is less than 15%.

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