Heavy-Oil Recovery by In-Situ Emulsion Formation
- Rahul Kumar (The University of Texas at Austin) | Eric Dao (The University of Texas at Austin) | Kishore Mohanty (The University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- June 2012
- Document Type
- Journal Paper
- 326 - 334
- 2012. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 2.4.3 Sand/Solids Control, 5.2.1 Phase Behavior and PVT Measurements, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4.1 Waterflooding
- viscous oil production, in-situ emulsion formation, heavy oil production, alkaline surfactant flooding
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The aim of this work is to evaluate alkaline/surfactant (AS) methods to improve recovery from heavy-oil reservoirs. Alkali/surfactant/oil phase-behavior experiments were conducted to determine conditions under which oil-in-water (O/W) emulsions form. The viscosity (and its shear dependence) was measured for some of these emulsions. Reservoir sand was assembled in sandpacks. Waterflood and AS floods were conducted at several salinities. Several relatively hydrophilic surfactants were identified, which formed O/W emulsions with the reservoir oil at a low concentration in the presence of sodium carbonate. O/W emulsions were favored at low salinity and high water/oil ratio (WOR). Viscosity of these emulsions was low compared with the oil viscosity. Waterflood recovery was on the order of 25 to 40% of the original oil in place (OOIP) in corefloods, and it decreased as the injection rate increased. Following the waterflood, the AS flood gave an incremental oil recovery of 10 to 35% of OOIP. The incremental post-breakthrough oil recovery during the waterflood is likely because of the imbibition of the water from viscous fingers into the unswept oil-saturated zone; this recovery is directly proportional to the square root of time.
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