Interfacial tension relative permeabilities

The optimnm phase type needs to be determined from core floods using reservoir cores. The phase type with the highest oil recovery factor is the optimnm salinity type. It is not necessarily type III. Meanwhile, the optimum salinity is determined. It is not necessarily the middle salinity of type III or a salinity in type III. Core flood experiments take into account all parameters snch as interfacial tension, relative permeability, phase trapping, and so on, becanse these experiments are essentially a replication of the flooding process that wonld occnr dnring the FOR process in the field. Practically, we cannot afford to rnn many core floods to identify the optimum type, but we can run simulations to preselect the type. 

Blends of sodium hypochlorite with 15% HC1 and with 12% HCl/3% HF have been used to stimulate aqueous fluid injection wells(143). Waterflood injection wells have also been stimulated by injecting linear alcohol propoxyethoxysulfate salts in the absence of any acid (144). The oil near the well bore is mobilized thus increasing the relative permeability of the rock to water (145). Temperature effects on interfacial tension and on surfactant solubility can be a critical factor in surfactant selection for this application (146). 

Migration of free-phase NAPLs in the subsurface is governed by numerous properties including density, viscosity, surface tension, interfacial tension, immisci-bility, capillary pressure, wettability, saturation, residual saturation, relative permeability, solubility, and volatilization. The two most important factors that control their flow behavior are density and viscosity. 

The surfactant has two important roles in CO2 foam. First, it increases the apparent viscosity of CO2 so that brine and oil are displaced in a stable manner. Second, the surfactant lowers the interfacial tension between CO2 and brine which promotes brine displacement. Reducing the brine saturation below S c allows bulk-phase CO2 to completely access the oil-filled pore network. A high-saturation brine bank also retards CO2 mobility by relative permeability effects. The brine bank carries surfactant and allows oil reconnection and mobilization ahead of the bulk CO2 phase because of the favorable partitioning of CO2 from brine into oil. 

It also appears that interfacial tension lowering between the CO2 and brine is beneficial. This allows brine displacement below Swc which provides additional mobility control by relative permeability effects without requiring large pressure drops. 

This chapter covers the fundamentals of surfactant flooding, which include microemulsion properties, phase behavior, interfacial tension, capillary desaturation, surfactant adsorption and retention, and relative permeabilities in surfactant flooding. It provides the basic theories for surfactant flooding and presents new concepts and views about capillary number (trapping number), relative permeabilities, two-phase approximation of the microemulsion phase behavior, and interfacial tension. This chapter also presents an experimental study of surfactant flooding in a low-permeability reservoir. 

In surfactant-related processes, the interfacial tension is reduced. As IFT is reduced, the capillary number is increased, leading to reduced residual saturations. Obviously, residual saturation reduction directly changes relative permeabilities. A number of authors reported their research results, as reviewed by Amaefule and Handy (1982) and Cinar et al. (2007). The general observations were that the relative permeabilities tend to increase and have less curvature as the IFT decreases or the capillary number increases. However, Delshad et al. (1985) observed that even at IFT of 10 mN/m, k, curves showed significant curvature. 

From the previons sensitivity resnlts and discnssions, we can see that phase type is very important in determining the hnal oil recovery. Table 8.16 lists some advantages and disadvantages of three types of microemulsion systems. The highest oil recovery conld be from a type II(-), type III, or type II(+) system. Not only IFT, bnt many parameters, especially relative permeabilities, individnally or in combination, may make any of type II(-), type HI, and type II(+) microemnlsion systems the optimnm type. This is different from the conventional approach that focnses on interfacial tension as the determining parameter and conseqnently that the optimum phase type is, necessarily, type III. 

Amaefule, J.O., Handy, L.L., 1982. The effect of interfacial tension on relative oil and water permeabilities of consolidated porous media. SPEJ (June), 371-381. 

The decreases in the water relative permeabilities of the high pH/high salt alkaline floods are directly contrasted with the increases in the relative permeabilities to water at the end of the moderate pH/high salt flood (compare the end point relative permeabilities column in Table 2). The increased permeability to water is believed to be caused by the formation of rigid interfacial films (which increases the resistance to flow in oil filled pores) and by the oil-wet conditions (under which water flows in the less restrictive flow paths). Such a reduction in permeability, which has been used to indicate the existence of a low tension mechanism (18), is not a valid low tension index since the interfacial tension minimum is only 3.5 dynes/cm and the capillary number is 1 x 10" for the buffered alkali/salt-oleic acid system. 

Here, fa is dimensionless time, f is time, is porosity, k is permeability, Oo/w is interfacial tension, IFT, fi , is viscosity of water, and L is block dimension (length). They assumed that gravity effects are negligible, and that the shape of the matrix blocks, wettability, initial fluid distributions, relative permeabilities, and capillary pressures are the same. From equation 4 it is seen that the imbibition rate decreases if interfacial tension decreases. 

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