Having reliable and readily accessible relative permeability information is a problem for many reservoir engineers. In the absence of laboratory measured data or in the case when a more general representation of fluid flow in a reservoir is needed, empirical relative permeability correlations become useful. 416 sets of relative permeability data were obtained from published literature and various industry sources, and were modified to fit a common format. The central database thus constructed allows relative permeability data to be easily retrieved and processed. Categorizing and modifying the original data for applicability to similar systems is considered, allowing for variations in connate water, residual oil, and critical gas saturations. Information such as fluid type, wettability, lithology, geographical location, and method of measurement is used to search applicable results. A linear regression model approach is employed to develop prediction equations for water-oil, gas-oil, gas-water, and gascondensate relative permeability from the measured data. Improved equations were developed for water-oil and gas-oil systems based on formation type and wettability. Additionally, general equations for gas-condensate and gas-water systems were formulated. Craig's rule for determining wettability has been modified to include a wider range of relative permeability data. Available data has increased significantly since the last published work in this area. The prediction equations are compared with previously published correlations. The database and prediction equations may be downloaded at no charge from a University of Missouri-Rolla web site.


If a formation contains two or more immiscible fluids, each fluid tends to interfere with the flow of the others. This reduction in the ability of a fluid to flow through a permeable formation is known as the relative permeability effect. Relative permeability, a dimensionless quantity, is the ratio of effective permeability to a base permeability. The effective permeability is a measure of the ability of a single fluid to flow through a rock when the pore spaces of the rock are not completely filled or saturated with the fluid. The base permeability can be absolute air permeability, absolute liquid permeability or effective oil permeability at irreducible water saturation. Relative permeability measurements and concepts become important due to the fact that nearly all hydrocarbon reservoirs contain more than one phase of homogeneous fluid. Relative permeability is a function of fluid distribution, pore geometry, saturation history and wettability1, 2.

Laboratory methods for measuring relative permeability first appeared in 1944. Since then various methods of measuring relative permeability have been developed. In general, these methods can be categorized into two major groups which consist of steady-state and unsteady-state methods. For mixed (intermediate) wettability rocks, steady-state methods are preferred to unsteady-state methods by some researchers3. Unsteadystate methods however, almost always give faster results compared to the steady-state methods due to the nature of processes involved in each method.

Laboratory measurement of relative permeability using either steady-state or unsteady-state methods can be expensive and time consuming. Laboratory measurement is considered a micro process because a single measurement is insufficient to represent the entire reservoir. Therefore several core samples from representative facies in the reservoir must be taken and tested.

This content is only available via PDF.
You can access this article if you purchase or spend a download.