Capillary Force |
AUTHOR/EDITOR
Pattanan Thamrujikul
|
Relative permeability and capillary pressure defined capillary pressure as the difference in pressure across the interface between two phases. Similarly, it has been defined as the pressure differential between two immiscible fluid phases occupying the same pores caused by interfacial tension between the two phases that must be overcome to initiate flow. This page discusses capillary pressure forces.
Capillary pressure concepts can be used by geologists, petrophysicists, and petroleum engineers to evaluate the following:
Capillary pressure concepts can be used by geologists, petrophysicists, and petroleum engineers to evaluate the following:
- Reservoir rock quality
- Pay versus nonpay
- Expected fluid saturations
- Seal capacity (thickness of hydrocarbon column a seal can hold before it leaks)
- Depth of the reservoir fluid contacts
- Thickness of the transition zone
- An approximation of the recovery efficiency during primary or secondary recovery.
Capillary pressure equation
With Laplace’s equation, the capillary pressure Pcow between adjacent oil and water phases can be related to the principal radii of curvature R1 and R2 of the shared interface and the interfacial tension σow for the oil/water interface:
The relationship between capillary pressure and fluid saturation could be computed in principle, but this is rarely attempted except for very idealized models of porous media. Methods for measuring the relationship are discussed in Measurement of capillary pressure and relative permeability.
The relationship between capillary pressure and fluid saturation could be computed in principle, but this is rarely attempted except for very idealized models of porous media. Methods for measuring the relationship are discussed in Measurement of capillary pressure and relative permeability.
Capillary pressure behavior
Capillary pressure behavior
Wettability of a solid with respect to two phases is characterized by the contact angle. Popular terminology for saturation changes in porous media reflects wettability:
Wettability of a solid with respect to two phases is characterized by the contact angle. Popular terminology for saturation changes in porous media reflects wettability:
- "Drainage" refers to the decreasing saturation of a wetting phase
- "Imbibition" refers to the increasing wetting-phase saturation
Wettability of porous material
the wettability of the porous material is an important factor in the shape of capillary pressure relationships. 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.
Treiber et al. reported a study of wettabilities of 55 oil reservoirs. Twenty-five of the reservoirs were carbonate, and the others were silicic (28 sandstone, 1 conglomerate, and 1 chert). To characterize wettability, they used the following ranges for the oil/water/solid contact angle as measured through the water phase:
0 to 75° = water-wet 75 to 105° = intermediate-wet 105 to 180° = 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.
Treiber et al. reported a study of wettabilities of 55 oil reservoirs. Twenty-five of the reservoirs were carbonate, and the others were silicic (28 sandstone, 1 conglomerate, and 1 chert). To characterize wettability, they used the following ranges for the oil/water/solid contact angle as measured through the water phase:
0 to 75° = water-wet 75 to 105° = intermediate-wet 105 to 180° = oil-wet
Drainage and imbibition for a strongly wet system
Heterogeneity
ost naturally occurring porous media are heterogeneous, having laminations, fractures, vugs, and so forth. Such heterogeneities give rise to "bumps" in a capillary pressure relationship
Wettability
- When strongly water-wet, Sor is approximately 14%.
- When intermediate-wet, Sor rises to approximately 35%.
- When strongly oil-wet, Sor returns to approximately 15%.
Nomenclature
po =pressure in the oil phase, m/Lt 2, psi
pw =pressure in the water phase, m/Lt 2, psi
Cow =capillary pressure between oil and water phases, m/Lt2, psi
R1, R2 =principal radii of curvature, L
σow =oil/water interfacial tension, m/t 2, dyne/cm
po =pressure in the oil phase, m/Lt 2, psi
pw =pressure in the water phase, m/Lt 2, psi
Cow =capillary pressure between oil and water phases, m/Lt2, psi
R1, R2 =principal radii of curvature, L
σow =oil/water interfacial tension, m/t 2, dyne/cm
Reference
- Muskat, M. 1949. Calculation of Initial Fluid Distributions in Oil Reservoirs. Trans. of AIME 179 (1): 119-127. http://dx.doi.org/10.2118/949119-G
- Jump up Morrow, N.R. and Melrose, J.C. 1991. Application of Capillary Pressure Measurements to the Determination of Connate Water Saturation. In Interfacial Phenomena in Petroleum Recovery, 257-287, ed. N.R. Morrow. New York City: Marcel Dekker Inc
- Jump up Salathiel, R.A. 1973. Oil Recovery by Surface Film Drainage in Mixed-Wettability Rocks. J Pet Technol 25 (10): 1216–1224. SPE-4104-PA. http://dx.doi.org/10.2118/4104-PA
- Jump up to: 4.0 4.1 4.2 Treiber, L.E. and Owens, W.W. 1972. A Laboratory Evaluation of the Wettability of Fifty Oil-Producing Reservoirs. SPE J. 12 (6): 531–540. SPE-3526-PA. http://dx.doi.org/10.2118/3526-PA
- Jump up to: 5.0 5.1 Morrow, N.R., Cram, P.J., and McCaffery, F.G. 1973. Displacement Studies in Dolomite with Wettability Control by Octanoic Acid. SPE J. 13 (4): 221–232. SPE-3993-PA. http://dx.doi.org/10.2118/3993-PA
- Jump up to: 6.0 6.1 Bethel, F.T. and Calhoun, J.C. 1953. Capillary Desaturation in Unconsolidated Beads. J Pet Technol 5 (8): 197-202. SPE-953197-G. http://dx.doi.org/10.2118/953197-G
- Jump up Morrow, N.R. 1970. Irreducible wetting-phase saturations in porous media. Chem. Eng. Sci. 25 (11): 1799–1818. http://dx.doi.org/10.1016/0009-2509(70)80070-7
- Jump up Chatzis, I., Morrow, N.R., and Lim, H.T. 1983. Magnitude and Detailed Structure of Residual Oil Saturation. SPE J. 23 (2): 311–326. SPE-10681-PA. http://dx.doi.org/10.2118/10681-PA
- Jump up to: 9.0 9.1 Jerauld, G.R. and Rathmell, J.J. 1997. Wettability and Relative Permeability of Prudhoe Bay: A Case Study In Mixed-Wet Reservoirs. SPE Res Eng 12 (1): 58–65. SPE-28576-PA. http://dx.doi.org/10.2118/28576-PA
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