Surfactant flooding injection effect

A study of the effect of pore geometry on foam formation mechanisms shows that snap-off" bubble formation is dominant in highly heterogeneous pore systems. The morphology of the foams formed by the two mechanisms are quite different. A comparison of two foam injection schemes, simultaneous gas/surfactant solution injection (SI) and alternate gas/surfactant solution injection (GDS), shows that the SI scheme is more efficient at controlling gas mobility on a micro-scale during a foam flood. 

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. 

Macroemulsion and Microemulsion Flooding If a suitable surfactant is injected into the reservoir, it can form macroemulsions and/or microemulsions with the reservoir oil depending on the composition and reservoir conditions. Several articles have been published on the recovery of oil by microemulsion and macroemulsion flooding processes.Among various factors, the most important factor of surfactant flooding in the form of an emulsion is the lowering of the interfacial tension (IFT) at the oil/water interface. Microemulsions are more effective in oil displacement as compared to macroemulsions because microemulsions can provide low IFT systems. 

The reports of the enhanced oil recovery projects concluded that the reservoir heterogeneities is the most frequent cause for failure of enhanced oil recovery processes which involve foam and surfactant flooding. It was deserved that the reservoir heterogeneity was much more dominant than expected. Geologic and permeability heterogeneities were the most probable cause of the low recovery efficiency realized by Goodrich and Watson The wettability of the pore surface affects the recovery efficiency, but this effect is poorly understood because it is almost impossible to determine which portions of the surface are oil-wet and which ones are water-wet in the subsurfaces. The wettability of the reservoir rocks can be influenced by the injection of surfactant solution for foam flooding. 

Acid flooding can be successful in formations that are dissolvable in the particular acid mixture, thus opening the pores. Hydrochloric acid is common, in a concentration of 6% to 30%, sometimes also with hydrofluoric acid and surfactants added (e.g., isononylphenol) [130,723]. The acidic environment has still another effect on surfactants. It converts the sulfonates into sulfonic acid, which has a lower interfacial tension with oil. Therefore a higher oil forcing-out efficiency than from neutral aqueous solution of sulfonates is obtained. Cyclic injection can be applied [4,494], and sulfuric acid has been described for acid treatment [25,26,1535]. Injecting additional aqueous lignosulfonate increases the efficiency of a sulfuric acid treatment [1798]. 

The effectiveness of alkaline additives tends to increase with increasing pH. However, for most reservoirs, the reaction of the alkaline additives with minerals is a serious problem for strong alkalis, and a flood needs to be operated at the lowest effective pH, approximately 10. The ideal process by which alkaline agents reduce losses of surfactants and polymers in oil recovery by chemical injection has been detailed in the literature [1126]. 

Formation damage caused by clay migration may be observed when the injected brine replaces the connate water during operations such as water-flooding, chemical flooding including alkaline, and surfactant and polymer processes. These effects can be predicted by a physicochemical flow model based on cationic exchange reactions when the salinity decreases [1665]. Other models have also been presented [345,1245]. 

Conventional pump-and-treat techniques are not very effective in restoring aquifers impacted by DNAPLs. This ineffectiveness is a result of the relatively low solubility of the DNAPL and the large capillary forces that immobilize the nonaqueous phase. Over the past decade, several innovative and experimental strategies have been tested for more effective recovery of DNAPLs. These strategies include the more conventional use of surfactants, and thermally enhanced extraction or steam injection. Other more experimental approaches include cosolvent flooding and density manipulations. Each of these approaches is discussed below. 

In the water-flooding process, mixed emulsifiers are used. Soluble oils are used in various oil-well-treating processes, such as the treatment of water injection wells to improve water injectivity and to remove water blockage in producing wells. The same method is useful in different cleaning processes with oil wells. This is known to be effective since water-in-oil microemulsions are found in these mixtures, and with high viscosity. The micellar solution is composed essentially of hydrocarbon, aqueous phase, and surfactant sufficient to impart micellar solution characteristics to the emulsion. The hydrocarbon is crude oil or gasoline. Surfactants are alkyl aryl... 

To evaluate the effects of cosolvent on surfactant delivery and PCE recovery, Box B was flushed with 4% Tween 80 + 5% EtOH at a Darcy velocity of 4.8 cm/hr. The surfactant/cosolvent mixture, which had a density of 0.994 g/cm3, was also representative of a neutral buoyancy flood solution (Shook et al, 1998). It is important to recognize that "neutral buoyancy" refers to density of flushing fluid after solubilization of the DNAPL. Thus, the initial density of the surfactant formulation must be less than that of the resident aqueous phase. Figure 5b shows the location and shape of the 4% Tween 80 + 5% EtOH front after flushing Box B with 0.5 pore volumes of solution. The lower density of the 4% Tween 80 + 5% EtOH solution (0.994 g/cm3) relative to the density of resident pore water (0.998 g/cm3) caused the injected solution to flow preferentially along the top of Box B (Figure 5b). This effect can become severe at low flow rates (Taylor, 1999). The... 

The surfactant did not cause viscous forces to dominate during immiscible tertiary carbon dioxide injection. Apparently, the unmobilized oil reduced the foam stability while the surfactant reduced the interfacial tension and therefore the COj-brine capillary pressure sufficiently to allow gravity effects to dominate the flood.(9)... 

Tertiary oil was increased up to 41% over conventional CO2 recovery by means of mobility control where a carefully selected surfactant structure was used to form an in situ foam. Linear flow oil displacement tests were performed for both miscible and immiscible floods. Mobility control was achieved without detracting from the C02-oil interaction that enhances recovery. Surfactant selection is critical in maximizing performance. Several tests were combined for surfactant screening, included were foam tests, dynamic flow tests through a porous bed pack and oil displacement tests. Ethoxylated aliphatic alcohols, their sulfate derivatives and ethylene oxide - propylene oxide copolymers were the best performers in oil reservoir brines. One sulfonate surfactant also proved to be effective especially in low salinity injection fluid. 

P7-28i An understanding of bactoria transport in porous media is vital to the efficient operation of the watar flooding of petroleum reservoirs. Bacteria can have both beneficial and harmful effects on the reservoir. In enhanced microbial oil recovery, EMOR, bacteria are injected to secrete surfactants to reduce the interfacia] tension at the oil-water interface so that the oil will flow out more easily. However, under some circumstances the bacteria can be harmful, by plugging the pore space and thereby block the flow of water and oil. One bacteria that has been studied, Leuconostoc mesentroides, has the unusual behavior that when it is injected into a porous medium and fed sucrose, it greatly... 

A 0.1% selected surfactant was then added to the injection water. The core flood experiments showed that injection pressure was reduced by 26.6%, and that the oil recovery was increased by 6.7%. This effect was a result of wettability alteration to more water-wet, reduced immobile water and oil saturations, and increased oil and water relative permeabilities. The data are shown in Table 7.11. 

Another serious problem that arises in all C02 floods, and must be considered here, is corrosion. As is well known, solutions of C02 in water dissociate to form carbonic acid. This is a weak acid and does not cause much trouble in fresh water floods. However, in brine instead of pure water, C02 does become much more corrosive, and the particular composition of the brine has a great effect. These difficulties can be made worse by the presence of surfactant that can remove coatings emplaced by corrosion inhibitors. This difficulty could occur in both the injection as well as in the production facilities. In many fields, special metallurgy has been needed in critical elements of the hardware. Not much in the way of general principles can be given, except that, in designing a C02 flood, the modification of existing problems is to be expected. 

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