Water-in-Oil emulsions: flow in porous media and EOR potential
- Xuebing Fu (BP America Inc) | Robert H. Lane (Texas A&M University) | Daulat Debataraja Mamora (Mamora and Associates)
- Document ID
- Society of Petroleum Engineers
- SPE Canadian Unconventional Resources Conference, 30 October-1 November, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 5.3.1 Flow in Porous Media, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4.3.4 Scale, 5.2 Reservoir Fluid Dynamics, 5.3.9 Steam Assisted Gravity Drainage, 5.1.5 Geologic Modeling, 4.1.2 Separation and Treating, 5.3.2 Multiphase Flow, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.2.3 Rock properties, 5.4.1 Waterflooding, 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 1.6.9 Coring, Fishing, 5.4.6 Thermal Methods, 4.2 Pipelines, Flowlines and Risers
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High water content (>50%) water-in-oil (W/O) emulsions have been suggested as a drive fluid for recovery of heavy oil in high permeability reservoirs. High emulsion viscosity can provide sufficient mobility control and its oil-external nature enables a semi-miscible process while displacing crude oil. Initially crude oil itself was suggested as base oil for generating this type of emulsion, and both laboratory experiments and field pilot have demonstrated its high efficiency in recovering heavy crude. Recently used engine oil was suggested as a candidate for generating W/O emulsions for the same purpose, because of its better stability and more favorable viscosity.
In this work a stable emulsion was generated by mixing used engine oil (40%) and brine (60%) under high shear. Then this emulsion was injected into sandstone cores (400 ~ 2400 md, 0.5 or 1 ft in length) at several different rates for periods of several days, to characterize its stability and flow properties while passing through porous media. Small amounts of water breakout were observed in the emulsion effluents. Higher values of water breakout were observed in lower permeability rock, at higher injection rate, and with longer core lengths. The the emulsion was also injected into sand-packed slimtubes (~8000 md) of 3-ft and 6-ft lengths, and less than 1% of free water was observed from the effluents at moderate injection rates, verifying good stability of this emulsion passing through high-permeability porous media. Pressure drops were found to be quite stable at any constant rate of injection for all corefloods, indicating no plug-off effect from the soot particles in the emulsion.
Numerical simulations on emulsion flooding a homogeneous heavy oil reservoir were also conducted by simulating the emulsion as single-phase oil, and the breakdown of emulsion as a co-injection of water together with this oil. Results indicated significant improvement of displacement pattern and oil recovery compared to water flooding.
Heavy oil deposits in Canada, Venezuela and the United States comprise up to several trillion barrels(Chopra and Lines, 2008). Compared to light oil, the principal difficulty of the recovery of heavy oil is the high oil viscosity that impedes its flow. Thermal methods target lowering oil viscosity by application of hot water (Harmsen, 1971), steam (Liebe and Butler, 1991; Owens and Suter, 1965) or in situ combustion (Joseph N. Breston, 1958). Among those methods, steam injection is the most successful and has been widely applied in heavy oil fields. However, many reservoirs are not suitable for thermal methods due to thin formation (< 10 m) or large depth (> 1000 m) which would lead to excessive heat loss (Selby et al., 1989). For such reservoirs, non-thermal recovery methods may be employed.
Water flooding is the most commonly used technique after primary recovery even in heavy oil reservoirs. The primary recovery from heavy oil reservoirs is generally low and water flooding is usually quite inefficient due to unfavorable mobility ratio which results in severe channeling and early water breakthrough. In the Lloydminster area the primary recovery was estimated to be 3-8% of the original oil in place (OOIP), and water flooding, which was carried out in most major reservoirs in this area, added only an additional 1-2% of OOIP to the primary recovery (Adams, 1982). Because of the simplicity and low cost of water flooding, it is still widely applied despite its poor performance.
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