The oil industry has become more and more aware that reservoirs exhibit complex variations of reservoir continuity, in particular of pore space-related properties such as porosity, permeability, and capillary pressure. These variations reflect the original depositional process and subsequent diagenetic and tectonic changes. Simple models are often inadequate for predicting reservoir performance and designing a field production management scheme that optimizes recovery. It is becoming increasingly apparent to reservoir engineers that the optimization of recovery is crucially dependent on the quality of the reservoir under water injection where the recovery factor is very sensitive to reservoir heterogeneity. Therefore, an accurate knowledge of vertical and lateral permeability distribution is essential.

This paper represents results of a research project aimed at determining vertical permeability from in-situ horizontal permeability in shaly reservoirs. This is accomplished by considering the microscopic and macroscopic features; such as the type of shale (Kaolinite, Chlorite, and Illite) and grain size. In-situ vertical permeability correlations are derived by using various water saturation correlations for Shaly-Sand formation.

Several vertical permeability relationships were obtained as function of horizontal permeability, hydraulic mean radius grain size, and the amount and/or type of shale. Generalized models were developed and were applied to real oil field data for calculating vertical and horizontal permeabilities.


Permeability is one of the most important of all formation parameters that petroleum engineers use. It is used to determine whether a well should be completed and brought on line, or abandoned. Vertical permeability is also essential in overall reservoir management and development, e.g., for the optimal drainage points and production rate, optimization completion and perforation design, and planing EOR patterns and injection conditions.

Extensive research on permeability has been conducted on clean formations for decades. Vertical permeability in shaly sand formations has long been viewed as a problem. Formation with shale and/or different pore geometry constitutes the majority of heterogeneous reservoirs. In this case, reservoir heterogeneity is no longer viewed as a problem but rather a potential for recovering more oil.

In early studies of reservoir engineering, the reservoirs are assumed to be homogeneous and isotropic, but also non-uniform. In recent studies, however the porositypermeability transform has been used for a better description of the reservoir having some complex geological continuity. Clark1 showed that if the rock grains are large and flat uniformly arranged with the longest dimension, then, the horizontal permeability (Kh) would be higher than the vertical one. Clark1 also showed that if the rock were composed mostly of large and uniformly rounded grain, its permeability would be considerably high and almost equal in both horizontal and vertical directions. Generally, vertical permeability is lower than horizontal permeability, especially, if the sand grains are small and have irregular shape. Most petroleum reservoirs are in this category.

Neasham2 studied the effect of clay on permeability. He showed that the clay morphology of the highest air permeability is predominantly the discrete particle. Dispersed clay morphology for samples in the intermediate air permeability range is predominantly of a pore-lining variety.

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