Relative permeability and capillary pressure -
Capillary pressure (Pc) is the pressure difference across the interface between two immiscible These capillary forces are surface tension and interfacial tension. The permeability of the reservoir rock can alter the capillary pressure curve. Absolute (Klinkenberg-corrected) gas permeability coefficients (k_(gas_inf) porosity/permeability relationship, critical capillary pressure. prescribed initial saturation is computed according to the capillary pressure 1 According to the relative-permeability – saturation relation to be applied. E+ . For the TOUGH2 calculations the so called TRUST function /Narasimhan et al.
Capillary pressure is often defined as the pressure of the less-dense phase minus the pressure of the more-dense phase.Capillary Pressure
Effective permeability In some discussions, the products of permeability and relative permeability e. Effective permeability of oil at irreducible water saturation, or ko Swiis sometimes used to normalize relative permeabilities in place of absolute permeability. With this normalization, kro Swi equals 1. It is possible for water relative permeability to exceed 1 when ko Swi is the normalizing factor. One must be very careful when using data to note whether absolute permeability or an effective permeability is used for normalizing.
Capillary pressure -
The need for accurate measurement of capillary pressure and relative permeability functions increases with the resolution of reservoir models. With low-resolution models, there is a need for algorithms to "upscale" permeabilities, relative permeabilities, and capillary pressures from the scale of measurement on a small sample of rock to the relatively huge size of blocks in reservoir models.
The results of the averaging processes of upscaling are insensitive to the quality of measurements on small samples. The need for upscaling should diminish as increases in computer power permit higher-resolution models. To obtain accurate measurements of capillary pressure and relative permeabilities, tests with representative samples at representative conditions are critical.
Much of the available data in our industry do not pass this standard. Popular terminology for saturation changes in porous media reflects wettability: Water is the wetting phase.
Comparison Between Capillary Pressure and Relative Permeability
Gas does not penetrate the medium in Fig. As capillary pressure increases beyond this value, the saturation of the water continues to decrease.
Morrow and Melrose  argue that capillary pressure measurements have not reached equilibrium if the capillary pressure trend asymptotically approaches an irreducible water saturation.
As the water saturation decreases during a measurement, the capacity for flow of water rapidly diminishes, so the time needed for equilibration often increases beyond practical limitations.
Hence, a difference develops between the measured relationship and the hypothetical equilibrium relationship, as shown in Fig. After completing measurements of capillary pressure for primary drainage, the direction of saturation change can be reversed, and another capillary pressure relationship can be measured—it is usually called an imbibition relationship.
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Imbibition is often analogous to the waterflooding process. The primary drainage and imbibition relationships generally differ significantly, as shown in Fig. This difference is called capillary pressure hysteresis—the magnitude of capillary pressure depends on the saturation and the direction of saturation change. For imbibition of a strongly wetting phase, the capillary pressure generally does not reach zero until the wetting-phase saturation is large, as shown in Fig. For a less strongly wetting phase, the capillary pressure reaches zero at a lower saturation, as shown in Fig.
Capillary pressure behavior for secondary drainage is also shown in Figs. Wettability of porous material As shown in Figs.
Wettabilities of reservoir systems are categorized by a variety of names. Some systems are strongly water-wet, while others are oil-wet or neutrally wet. Spotty or "dalmation" wettability and mixed wettability describe systems with nonuniform wetting properties, in which portions of the solid surface are wet by one phase, and other portions are wet by the other phase.
Mixed wettability, as proposed by Salathiel,  describes a nonuniform wetting condition that developed through a process of contact of oil with the solid surface.
Salathiel hypothesized that the initial trapping of oil in a reservoir is a primary drainage process, as water the wetting phase is displaced by nonwetting oil. Then, those portions of the pore structure that experience intimate contact with the oil phase become coated with hydrocarbon compounds and change to oil-wet.
The drainage and imbibition terminology for saturation changes breaks down when applied to reservoirs with nonuniform wettability. Rather than using drainage and imbibition to refer to the decreasing and increasing saturation of the wetting phase, some engineers define these terms to mean decreasing and increasing water saturation, even if water is not the wetting phase for all surfaces.
Twenty-five of the reservoirs were carbonate, and the others were silicic 28 sandstone, 1 conglomerate, and 1 chert. At the time of publication init was surprising to readers that two-thirds of the reservoirs were oil-wet.
Previously, reservoirs were believed to be mostly water-wet.