Surfactant floods

When this pressure drops, it can be built-up again by water flooding. Unfortunately, after these primary and secondary processes, there still remains up to 70% of the oil adsorbed on the porous clays. Consequently, in recent years, there have been tremendous efforts made to develop tertiary oil recovery processes, namely carbon dioxide injection, steam flooding, surfactant flooding and the use of microemulsions. In this latter technique, illustrated in Fig. 1, the aim is to dissolve the oil into the microemulsion, then to displace this slug with a polymer solution, used for mobility control, and finally to recover the oil by water injection ( 1). 

Figure 5 shows the results of a typical surfactant transport study in a 2 ft long Berea sandstone core. The AEGS 25-12 surfactant, injected at 0.05 wt%, had a low loss on Berea sandstone of 0.008 meq/100 gm rock compared to -0.05 meq/100 gm for typical petroleum sulfonates used in chemical flooding. Surfactant breakthrough occurred at 0.62 PV (Sorw =0.38 PV). The surfactant concentration is consistent with about 10% transport with the brine front. Surfactant loss and transport were monitored using the hyamine titration technique. 

When alkaline flooding is combined with other methods, such as polymer flooding, surfactant flooding, hydrocarbon gas injection, or thermal recovery, much better effects will be obtained. 

Consistent with the phase equilibrium concept discussed in this section, there was a considerable difference in the time at which surfactant concentration peaked in the effluent liquids from those two chemical floods. Surfactant lag, brought about by the high salinity formation brine in the one flood, caused surfactant concentration in the effluent liquids to peak about 15 percent pore volume later in the flood with 100 percent SDSW formation brine than in the flood with 20 percent SDSW formation brine. 

Surfactant loss due to phase trapping is minimized if only oil and water phases are present at all times during the flood. Surfactant loss is only related to adsorption onto the mineral surface provided that the surfactant tolerates multivalent cations, i.e. no precipitation. In the following sections we will discuss recent published work which is relevant in reaching this goal. 

In a LTPWF, the concentration of surfactant and polymer is much lower than in a traditional micellar slug flood (surfactant 0.1-0.5 wt% and polymer <500 ppm) and incompatibilities between the chemicals resulting in associative or segregative phase separation are normally not observed even at high salinities [14], It is, however, very important that no association between surfactant and polymer takes place in solution. In the presence of excess polymer, the surfactant monomer concentration will then become lower than the CMC. The monomolecular packing of surfactants at the interface decreases, and the IFT will increase drastically. 

Chemical techniques change the physical properties of either the displacing fluid, or of the oil, and comprise of polymer flooding and surfactant flooding. 

The focus of more recent work has been the use of relatively low concentrations of additives in other oil recovery processes. Of particular interest is the use of surfactants (qv) as CO2 (4) and steam mobiUty control agents (foam). Combinations of older EOR processes such as surfactant-enhanced alkaline flooding and alkaline—surfactant—polymer flooding show promise of improved cost effectiveness. 

Surfactants for Mobility Control. Water, which can have a mobihty up to 10 times that of oil, has been used to decrease the mobihty of gases and supercritical CO2 (mobihty on the order of 50 times that of oil) used in miscible flooding. Gas oil mobihty ratios, Af, can be calculated by the following (22) ... 

The WAG process has been used extensively in the field, particularly in supercritical CO2 injection, with considerable success (22,157,158). However, a method to further reduce the viscosity of injected gas or supercritical fluid is desired. One means of increasing the viscosity of CO2 is through the use of supercritical C02-soluble polymers and other additives (159). The use of surfactants to form low mobihty foams or supercritical CO2 dispersions within the formation has received more attention (160—162). Foam has also been used to reduce mobihty of hydrocarbon gases and nitrogen. The behavior of foam in porous media has been the subject of extensive study (4). X-ray computerized tomographic analysis of core floods indicate that addition of 500 ppm of an alcohol ethoxyglycerylsulfonate increased volumetric sweep efficiency substantially over that obtained in a WAG process (156). 

Gravity override of low density steam leads to poor volumetric sweep efficiency and low oil recovery in steam floods. Nonchemical methods of improving steam volumetric sweep efficiency include completing the injection well so steam is only injected in the lower part of the oil-bearing zone (181), alternating the injection of water and steam (182), and horizontal steam injection wells (183,184). Surfactants frequently are used as steam mobihty control agents to reduce gravity override (185). Field-proven surfactants include alpha-olefin sulfonates (AOS), alkyltoluene sulfonates, and neutralized... 

In the 1990s, the thmst of surfactant flooding work has been to develop surfactants which provide low interfacial tensions in saline media, particularly seawater require less cosurfactant are effective at low concentrations and exhibit lower adsorption on rock. Nonionic surfactants such as alcohol ethoxylates, alkylphenol ethoxylates (215) and propoxylates (216), and alcohol propoxylates (216) have been evaluated for this appHcation. More recently, anionic surfactants have been used (216—230). 

An alternative to this process is low (<10 N/m (10 dynes /cm)) tension polymer flooding where lower concentrations of surfactant are used compared to micellar polymer flooding. Chemical adsorption is reduced compared to micellar polymer flooding. Increases in oil production compared to waterflooding have been observed in laboratory tests. The physical chemistry of this process has been reviewed (247). Among the surfactants used in this process are alcohol propoxyethoxy sulfonates, the stmcture of which can be adjusted to the salinity of the injection water (248). 

Including a surfactant in the caustic formulation (surfactant-enhanced alkaline flooding) can increase optimal salinity of a saline alkaline formulation. This can reduce iaterfacial tension and increase oil recovery (255,257,258). Encouraging field test results have been reported (259). Both nonionic and anionic surfactants have been evaluated in this appHcation (260,261). 

Surfactants evaluated in surfactant-enhanced alkaline flooding include internal olefin sulfonates (259,261), linear alkyl xylene sulfonates (262), petroleum sulfonates (262), alcohol ethoxysulfates (258,261,263), and alcohol ethoxylates/anionic surfactants (257). Water-thickening polymers, either xanthan or polyacrylamide, can reduce injected fluid mobiHty in alkaline flooding (264) and surfactant-enhanced alkaline flooding (259,263). The combined use of alkah, surfactant, and water-thickening polymer has been termed the alkaH—surfactant—polymer (ASP) process. Cross-linked polymers have been used to increase volumetric sweep efficiency of surfactant—polymer—alkaline agent formulations (265). 

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