Wettability permeability/saturation

Bau and Torrance [128] use a different relative permeability-saturation relation and arrive at a slightly different relation. Jones et al. [129] use a similar treatment and find a relationship for qc, that gives values lower than those predicted by Eq. 9.130 by a factor of approximately 2. It should be noted that these predictions of qCI are estimations and that the effects of wettability, solid matrix structure (all of these studies consider spherical particles only), and surface tension (all of which influence the phase distributions) are included only through the... 

Wettability Effects on Relative Permeability/Saturation Relationships... 

Mafiiematical models of DNAPL subsurface movement require capillary pressure/saturation and relative permeability/saturation constitutive relationships for DNAPL/water/soil systems. Wettability alterations may have a considerable effect on ciqiillary pressure/saturation relationships as discussed in the previous section. They may also have an intact on relative permeability/saturation relationships yet this has received less attention in file literature in large part due to file experimental difficulties associated with measuring these relationships. 

Changing the wettability of reservoir rock surfaces from oil-wet to water-wet, increases the permeability of the formation to oil, decreases the permeability to water, decreases mobility ratio, increases sweep efficiency, increases the flowing fraction of oil at every saturation, and increases oil recovery at the economic limit of the waterflood. 

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 overall gain of the multiphase mixture model approach above is that the two-phase flow is still considered, but the simulations have only to solve pseudo-one-phase equations. Problems can arise if the equations are not averaged correctly. Also, the pseudo-one-phase treatment may not allow for pore-size distribution and mixed wettability effects to be considered. Furthermore, the multiphase mixture model predicts much lower saturations than those of Natarajan and Nguyen - and Weber and Newman even though the limiting current densities are comparable. However, without good experimental data on relative permeabilities and the like, one cannot say which approach is more valid. 

Figure 6.24 (a) and (b) show how the relative permeabilities of oil and water can vary with relative saturation of the pores, and with wettability. This figure also illustrates the fact that the relative permeability of a fluid will become zero while the other fluid still has a finite saturation. This is because a significant amount of either fluid can become immobilized and will not be displaced by the other fluid. The nature and extent of this immobilization depends upon the same factors as just listed for permeability. 

Wettability. Wettability of the porous medium controls the flow, location, and distribution of fluids inside a reservoir (7, 28). It directly affects capillary pressure, relative permeability, secondary and tertiary recovery performances, irreducible water saturations, residual oil saturations, and other properties. 

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. 

Figure 18. Relative permeability to water at residual oil saturation in clean and wettability-modified Berea cores containing different oils, calculated relative to the effective permeability to oil at irreducible water saturation.

Fines Migration in Multiphase Flow. Most of the preceding discussion was concerned with flow of brine at 100% brine saturation. From a petroleum engineering perspective this brine staturation represents a condition that is rarely encountered in the field. A more relevant situation would be flow of brine at residual oil saturation and commingled flow of oil and brine. When fines migration occurs in the presence of two immiscible fluids, additional factors such as the wettability of the medium and that of the fines and the relative permeability characteristics become important. Therefore, it is important to consider the effect of the presence of a second immiscible fluid on fines migration and permeability damage. 

Another interesting result reported by Sarkar and Sharma (55) was that after saturating the core initially with a polar crude oil, the damage ratio was only 1/1.5 and the permeability decline was very slow. Thus, allowing the rock surfaces to come in direct contact with the polar oil did make the rock less susceptible to damage. This effect is apparently related to adsorption of polar components on the rock surfaces and altered wettability of the fines. 

Predictive models based on the capillary pressure/saturation relationships are commonly used to estimate relative permeability in the absence of experimental data 37, 38). One such predictive model, that of Bradford et al. 37), is used in Figure 6 to illustrate the effects of varying wettability on relative... 

With this special mixed wettability condition, it appears that the oil relative permeability can remain finite to very low saturations. 

The core is removed between floods and weighed in order to determine fluid saturations. The saturation is checked against that obtained from the volume of the produced fluids in most cases, the volume determination and the mass determination of saturation differed by only 2 to 3 percent in saturation. The volume-determined saturations were used in the reported results. The emulsion characteristics and recovery efficiencies of alkaline floods discussed are listed in Table 1. The end-point saturations, permeabilities and wettabilities (as inferred from contact angle measurement) are listed in Table 2. The dimensions and properties of the unconsolidated Ottawa sandpacks used in these alkaline floods are listed in Table 3. Neutral pH floods are also listed. The neutral pH floods offer a base line for the recovery efficiencies of the alkaline floods. 

Table 2. End-Point Saturations, Permeabilities and Wettabilities of Alkaline Floods... 

Oil-bearing sedimentary rocks are frequently classified as either water-wet or oil-wet porous media, although categories of intermediate and mixed wettabilities are sometimes also set up. Wettability refers variously to spontaneous imbibition of water or oil, to the shapes of the curves of the relative permeabilities versus saturation (fraction of pore volume occupied by a given fluid) or to an apparent contact angle, i.e. the visually observed angle of intersection of a water-oil meniscus with a smooth surface of the rock or of an ostensibly equivalent solid material. 

CCL operation entails transport of gases, water, electrons, and protons, as well as interfacial transformation of species due to electrochemical reaction and evaporation. Effective parameters that steer the interplay of these processes are proton and electron conductivity diffusion coefficients of oxygen, water vapor, and residual gaseous components liquid water permeability as well as exchange current density and vaporization rate per unit volume. These parameters incorporate information about composition, pore size distribution, pore surface wettability, and liquid water saturation. This section introduces functional relationships between effective properties and structure. 

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