Relative permeability data are one important key to better understanding the interaction of fluids and porous media at the microscopic level. But issues on sampling, scarcity, scale, and wettability concerning these data often affect their application. This necessitates methods on evaluating, improving and even generating relative permeability data in reservoir management studies. Researchers are often confused on the applicability of laboratory and/or correlation data. Based on our years' experience and research work in this area, this paper evaluates, compares current methods (both correlations or/and lab experiments), and provides suggestions on wisely applying relative permeability data to reservoir management study. It will definitely provide a very nice reference for those who are interested in the investigation/application of the relative permeability data to reservoir management.
In 1856, Henry P. Darcy(1)(determined that the rate of water flow through a sand filter could be described by the equation (Dracy's law)
Equation (1) (Available in full paper)
If we define relative permeability as the ratio of effective permeability to absolute permeability, Darcy's law can be restated for reservoir which generally contains three fluid phases as follows:
Equation (2) (Available in full paper)
Equation (3) (Available in full paper)
Equation (4) (Available in full paper)
This Darcy's law is the basis for almost all calculations of fluid within a hydrocarbon reservoir. In order to apply this law to reservoir management, it is necessary to determine the relative permeability of the reservoir rock to each of the fluid phases; this determination must be made throughout the range of fluid saturations that will be encountered.
In sum, relative permeability data are very valuable properties of porous media. They are the key for many reservoir management studies such as to determination of the rock wettability; a particular process modeling (for example, fractional flow, fluid distributions, recovery and predictions); determination of the free water surface (i.e., the level of zero capillary pressure or the level below which production is 100% water); and determination of residual fluid saturations. Reliable relative permeability data may lead to a better decision which results successful development. In order to perform reservoir forecasting in a multi-phase situation, reservoir permeability data have to be specified as accurately as possible.
Although the problems involved in measuring and calculating relative permeability have been studied by many investigators, however, how to generate and manipulate relative permeability data continues to be a headache in the current oil industry. This has been one of the major challenges in reservoir engineering for the past years and we are sure that it will be so in the foreseeable future.
Overall speaking, the relative permeability of rock to each phase can be obtained from three kinds of sources: Measured from core sample in laboratory (Including Steady State, Unsteady State or Centrifuge Method), Analogy Method (Obtained from nearby reservoir in the same formation), and many correlation methods. They all have some weaknesses and strengths. Honarpour((2)(and Du((3)(summarized these methods and evaluated their beauties and weak points, they concluded that no method could replace the others and each method would have its own seat in applications.
