Summary
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.
Introduction
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).
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
26 August 2005
- Meeting paper published:
1 November 2005
- Revised manuscript received:
3 January 2007
- Manuscript approved:
8 February 2007
- Version of record:
20 August 2007
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