Whenever two or more fluids co-exist in a system of capillaries, the combination of surface tension and curvature due to the capillaries causes the two phases to experience different pressures. As the relative saturations of the phases change, it has been found that these pressure differences also change. The difference between the pressures of any two phases is referred to as the capillary pressure. Capillary pressures can be determined for any two fluid phases; of interest to the oil industry are those for gas-brine, gas-oil and oil-brine systems.

Capillary pressure data is used directly in numerical simulation programs and to calculate fluid distributions in reservoirs. The residual and irreducible fluid saturations, determined when measuring capillary pressures, can be used to help estimate the amount of recoverable oil and the expected connate water saturations. In any porous material with two fluid phases present, the wetting phase will always have the lower pressure. Therefore, capillary pressure curves can also be used to determine the wetting characteristics of reservoir rocks. Capillary pressures are commonly measured with one of two instruments: porous plate desaturation cells or centrifuges. Because of the shorter test times, the centrifuge is the preferred testing technique. The ultra-centrifuge allows testing at temperatures of up to 150°C. Techniques exist for determination of capillary pressures on both consolidated and unconsolidated cores.