The ability of a formation to retain water is an important reservoir property and is a function of capillary sizes , rock texture, wettability, fluid properties, density differences between fluid pairs and formation saturation history. Capillary pressures in a reservoir determine the saturation distribution, and hence the total in-situ volumes of fluids (oil/water/gas).
- Centrifuge capillary pressure: provides laboratory data which can be inverted to derive capillary pressure curves at laboratory conditions using an inversion procedure, which is uncertain and gives non-unique capillary pressure curves.
- Semi-permeable membrane (porous plate): the method is used to determine capillary pressure curves and saturation relationships on cylindrical rock samples of either 1" or 1.5" diameter at ambient conditions or high confining pressures .
- Mercury–air (mercury injection): This analysis gives capillary pressure data, pore throat distribution and pore level heterogeneity in a short time frame. Combined with petrography, the data can be used to investigate cap rock sealing capacity. Other parameters derived from mercury injection are theoretical permeability, reservoir quality and mercury entrapment.