Capillary pressure and permeability relationship counseling

The determination of representative capillary pressure () data and .. capillary pressure/saturation relationships in fractional wettability. For instance, the relative permeability profiles and capillary pressure profiles are generated based on Brooks- Corey correlation using MATLAB. ECLIPSE is. A smooth and flexible correlation for three-phase relative permeability and capillary pressure has been developed and is presented as a.

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However, zero capillary pressure assumption may induce error in the fractional flow equation. The effect of different parameters on capillary pressure gradient in fractional flow is determined with numerical analysis based on the saturation distribution profile. The fractional flow equation is dependent on the relative permeability and relative permeability is a function of saturation. This project presents one- dimensional black oil simulation in core flooding using gas-water system to compare the saturation profile with capillary pressure and without capillary pressure.

A factorial design was established for four 4 different parameters, i. Therefore, eighty-one 81 simulations were conducted and the results were analyzed via Design of Experiments. This study found that porosity, permeability and injection rate has visible effect in the saturation profile due to the negligence of capillary pressure. Due to the limitation of the simulator, the end capillary effect was not captured in this study.

Hence, the capillary pressure has no visible effect towards the core length. Keywords Fractional flow; Capillary pressure gradient; Relative permeability; Two-phase flow Introduction Reservoirs are rarely homogenous. The effect of neglecting the capillary pressure in fractional flow approach faced more problems in heterogeneous properties, multiple spatial dimension and temporal changes.

Although advection flow is highly dominated, diffusion flow existed in some parts of the reservoir. Capillary pressure is a function of pore size distribution factor which is affected by porosity and permeability. In addition, the capillary pressure gradient in the fractional flow equation is influenced by several parameters such as porosity, permeability, length and injection rate.

The objective of this project is to study the effect of the above-mentioned parameters on the induced errors by zero capillary pressure assumption in fractional flow. The scope of this study involved the fundamentals of reservoir engineering such as multiphase flow, immiscible displacement and horizontal displacement.

This study shows how wettability alteration of an initially water-wet reservoir rock to oil-wet affects the properties that govern multiphase flow in porous media, that is, capillary pressure, relative permeability, and irreducible saturation.

Journal of Petroleum Engineering

From the results of these experiments, changing the wettability of the samples to oil-wet improved the recovery of the wetting phase. Introduction Wettability refers to the tendency of one fluid to spread on or adhere to a solid surface in the presence of immiscible fluids as shown in Figure 1 [ 1 ].

In natural porous media, the wettability varies from point to point depending upon the surface roughness [ 2 ], immobile adsorbed liquid layers [ 3 ], and the adsorptive properties of the mineral constituents. Anderson reported that coal, graphite, sulfur, talc, talc-like silicates, and many sulfides are probably neutrally wet to oil-wet [ 4 ].

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On the other hand, most common aquifer materials such as quartz, carbonates, and sulfates are strongly water wet. Wetting fluid water and nonwetting fluid mercury. It is the wettability of the reservoir rock that controls the distribution of oil and water and affects their movement through pore spaces.

Understanding wettability in porous media is, by itself, a difficult problem.

Capillary pressure

Controlling it to modify the behavior of reservoir rock presents a more complex problem. Numerous methodologies for studying, measuring, and altering the wettability of reservoir rocks are found in literature. No satisfactory method exists for in situ measurement of wettability, and therefore it is necessary to estimate the wettability of reservoir rocks from laboratory measurements.

It is known that a porous material can be defined as water-wet, oil-wet, or mixed-wet. The degree to which a reservoir is one or another of these can be determined by considering the capillary pressure curve, or by characterizing it in terms of wettability indices. Several experimental procedures have been proposed to assign quantitative wettability indexes to reservoir rock surfaces. The most recent of these proposals are those of Morrow [ 5 ], Graue et al. These indexes are designed to show a continuous variation from the preferential oil-wet to the preferential water-wet systems.

They require measuring some property of the rock which is a function of surface wettability. The quantities are measured on unaltered core material and compared with values obtained for known oil-wet and water-wet extremes on the same material. These methods are useful but are semiempirical in nature. They have the disadvantage that the measured quantities may be functions of other variables in addition to surface wettability. Referring to Figure 2the Amott indices are defined as If the material is completely water-wet, then and.

If the material is strongly oil-wet then and. For connected pathways of oil and water then both indices can be greater than zero.

Capillary pressure diagram used to characterize wettability. This index is based on the ratio of the two areas representing forced imbibition in Figure 2: The range is from for a completely water-wet material to for a completely oil-wet material.

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, [3] 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.

Capillary pressure -

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. Table 1 Drainage and imbibition for a strongly wet system An example of capillary pressure relationships during drainage and imbibition for an unconsolidated dolomite powder is shown in Fig. The imbibition curve remains above zero capillary pressure, similar to the typical form of Fig.

After Morrow et al.