Abstract
This paper presents results from a study designed to improve effectiveness of CO2 flooding by reducing CO2 mobility. In the course of reaching this objective we (1) screened surfactants for their ability to generate an effective and stable emulsion with CO2 under reservoir conditions, (2) determined the concentration range over which surfactants were effective, (3) examined chemical stability of the surfactants at reservoir conditions, (4) determined the extent to which emulsifying action alters gas and liquid mobilities in carbonate and sandstone cores, (5) determined that surfactant can enhance the production of residual oil from watered-out production of residual oil from watered-out carbonate cores by CO2, and (6) showed that the permeability reduction caused by surfactant can be permeability reduction caused by surfactant can be dissipated.At reservoir conditions required for miscible displacement, carbon dioxide exists in its critical state as a very dense fluid whose viscosity is about oneeighth that of crude oil. Generally, this unfavorable viscosity and mobility ratio produces inefficient oil displacement. This study shows that surfactant reduces CO2 mobility and should improve oil displacement by CO2, presumably by reducing flow through the most permeable zones, thus increasing areal and vertical sweep efficiencies.All three classes of surfactants (anionic, cationic, and nonionic) were found to be stable under conditions encountered during a CO2 flood in limestone formation; however, only a few surfactants had proper adsorption and emulsifying properties. proper adsorption and emulsifying properties. Surfactant generated foams or emulsions with CO2 at reservoir conditions (1,000 to 3,000 psi and 135 degrees F) dramatically reduced CO2 flow through sandstone and carbonate cores. Surfactant reduced the amount of CO2 used to recover a given volume of oil, especially from watered-out cores. The mechanism of tertiary oil production from linear cores appears to be limited to CO2 extraction. Approximately the same oil recovery was obtained either by continuous CO2 injection after a surfactant slug or by alternate slugs of CO2 and surfactant solution. It was found that oil recovery efficiency increased when surfactant was used with CO2 and that efficiency increased with flooding pressure.One anionic surfactant was found to be superior for this purpose. This surfactant emulsified CO2 well, was least adsorbed on carbonate rocks, and greatly reduced CO2 mobility in linear cores at concentrations of 0.1 to 1 %.The study indicates that effectiveness of CO2 miscible flooding can be increased by alternate injection of CO2 and aqueous surfactant slugs into the reservoir.
Introduction
The basic principles of CO2 flooding have been studied for the past 25 years by many investigators. Numerous laboratory studies have demonstrated that CO2, at elevated pressures, can recover oil unrecoverable by conventional methods and that super-critical CO2 develops multicontact miscibility with many crude oils, with a very efficient oil displacement, approaching 100% of the contacted oil. Generally, oil recoveries with CO2 have been much higher in the laboratory than in the field because field conditions are more severe for all oil recovery processes.A principal problem in CO2 flooding is the low viscosity of CO2 compared with that of crude oil. At reservoir conditions, CO2 viscosity is often 10 to 50 times lower than oil viscosity. At these unfavorable viscosity (mobility) ratios, CO2 has a great potential to channel through the oil. potential to channel through the oil. SPEJ
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Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study
