Petroleum companies are familiar with the problems caused by the formation of water-in-crude oil emulsions, especially with those related to the increment of the crude oil apparent viscosity and their impact on the oil production. Many studies have been conducted to establish the existing relationship between the crude oil emulsions apparent viscosity and their water content. However, there is a lack of information in the literature concerning the actual impact of the emulsions on the pressure drop trough pipelines and on its consequence, the reduction of crude oil production.
The thermo-hydraulic calculation of a producing oil stream is usually based on black-oil models for PVT properties and on multiphase flow correlations or models suitable for pressure drop prediction. These models and correlations demand the knowledge, amongst other parameters, of the viscosity of the liquid phase as an input data. Usually, the values of this property are measured with rheometers using standardized procedures. However the thermo-hydraulic calculation becomes more complex in the case of water-in-oil emulsions. The question is how to get a correct viscosity to use for the pressure drop calculation and thus, how to prepare a synthetic fluid that represents the actual emulsion. The objective of this study was to understand the state of the art relative to the emulsion formation and rheology. The main rheological models that are applicable to emulsions are presented, as well as the methodologies for the determination of its parameters in the laboratory. This paper also investigates the usual correlations applied for the flow of gas and water-in-oil emulsions through pipelines. Actual data from field were used to allow the evaluation of the results obtained through the simulations using the proposed procedure. This information is relevant to establish how the presence of water-in-crude oil emulsions can interfere with the technical and economical viability studies.
Water-in-oil (W/O) emulsions are very common in the petroleum industry in particular at the upstream operations. They form naturally during the crude oil production and the water content can be as high as 60% by volume.
The presence of W/O emulsions may have a strong impact on the crude oil production, especially in offshore conditions. In such kind of systems the temperature of the crude oil varies widely along the flow from the reservoir to the platform storage tanks. For example in Campos basin, where most of the Brazilian crude oil is produced, typically the temperature of the oil gradually decreases from 80 °C at the bottom of the well-bore, located 3,000 m below the seabed, to about 60 °C at the top of the well-bore, located 1,000 m below the sea level, where the sea water temperature may vary from 4 °C to 10 °C. In order to reach the storage tank, the crude oil has to flow for several hundreds meters through a pipeline in a cold environment. The contact with the cold seawater imposes a major decrease in the crude oil temperature; hence crude oil arrival temperatures below 30 °C have been frequently reported at Campos Basin.
