Rheology of Heavy-Oil Emulsions
- Hussein Alboudwarej (Schlumberger) | Moin Muhammad (Schlumberger) | Ardeshir K. Shahraki (Schlumberger) | Sheila Dubey (Shell Global Solutions) | Loek Vreenegoor (Shell Global Solutions) | Jamal M. Saleh (Shell Intl. E&P BV)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2007
- Document Type
- Journal Paper
- 285 - 293
- 2007. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 4.2.3 Materials and Corrosion, 4.3.3 Aspaltenes, 4.1.2 Separation and Treating, 4.3 Flow Assurance, 1.8 Formation Damage, 5.3.2 Multiphase Flow, 4.3.4 Scale, 4.1.9 Tanks and storage systems, 5.2 Reservoir Fluid Dynamics, 4.3.2 Precipitates Flow Assurance, 4.1.5 Processing Equipment, 4.1.1 Process Simulation, 5.2.1 Phase Behavior and PVT Measurements, 4.6 Natural Gas
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Water is invariably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path, stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils, where steam is used to reduce the viscosity of heavy oil, or in cases in which submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy-oil production systems, knowledge of the realistic viscosities of the emulsified heavy oil, under the actual production conditions, is necessary. This study is an attempt to investigate the effect of water content, pressure, and temperature (i.e., operating conditions on the viscosity of live heavy-oil emulsions).
Two heavy oil samples from South America were used for this study. The stock tank oil (STO) samples were recombined with the corresponding flash gases to reconstitute the original reservoir oil compositions. Live oil/water emulsions were prepared in a concentric cylinder shear cell using synthetic formation water, under predetermined pressure, temperature, and shear conditions. The stability of live emulsions was investigated using a fully visual pressure/volume/temperature (PVT) cell, while viscosities were measured using a precalibrated, high-pressure capillary viscometer. Viscosities were measured at least in three different flow rates at the testing conditions. In addition to live-oil emulsion studies, the stability and droplet size distribution of STO emulsions were also determined.
Experimental results indicated that the inversion point for the STO emulsions was approximately 60% water cut (volume), and the average droplet size was increasing with water content. For all measured cases, viscosities varied with temperature according to an Arrhenius relation, while viscosities did not indicate any variation with flow rate (shear) within the range of tested flow rates. Measured viscosities also increased as pressure decreased below the bubblepoint of the sample as lighter hydrocarbon components evolved. The measured viscosities increased as much as 500% because of the presence of emulsions before a sharp drop in viscosity beyond the inversion point. The variation of viscosity with water content for live emulsion samples indicated that the inversion point for live emulsions is similar to that of STO samples.
The experimental results are also used to analyze and evaluate the performance of an ESP system when water cut increases and causes emulsion in a well.
As an oilfield ages, the rate of water production increases. With enough shear force (e.g., flow through a downhole pump or a flow restriction such as a choke valve or orifice), a stable emulsion can be formed. Presence of inorganic solids such as sand, clay, and corrosion products, together with surface-active materials such as asphaltenes and naphthenic acids, also enhance the stability of emulsions (Kokal 2005). Because of the presence of these elements, the occurrence of tight emulsions in the production facilities is quite common. In some cases, emulsions may also form in the near-wellbore region, leading to emulsion blockage of porous media (Kokal et al. 2002).
In addition to formation blockage and general difficulty in the separation of oil and water in production facilities, one of the main drawbacks of emulsion formation is an increase in the apparent viscosity of the oil. Viscosity of water-in-oil emulsions increases as the water cut increases before the so-called emulsion inversion point, beyond which the continuous phase changes to water (i.e., water-in-oil emulsion switches to oil-in-water emulsion). It has been shown that the viscosity of the water-in-oil emulsion may increase as much as one order of magnitude or even higher over the viscosity of the dry oil (Singh et al. 2004). In oil-in-water emulsions, viscosity decreases with an increase in water content. Therefore, the maximum apparent viscosity of emulsions occurs at the emulsion inversion point (Szelag and Pauzder 2003).
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