Matrix permeability and pore volume compressibility are fundamentally important characteristics of hydrocarbon reservoirs because they provide measures of reservoir volume and reservoir producibility. In most laboratories these quantities are measured under hydrostatic (isotropic) loads that do not truly reflect the deviatoric stress state that exists in most reservoirs and do not adequately simulate the evolution of stresses in the reservoir as the reservoir is produced. Compression tests on a North Sea sandstone reservoir rock show that both compressibility and matrix permeability vary markedly with stress path (defined as the change in effective horizontal stress/change in effective overburden stress from initial reservoir conditions). Hence, it appears likely that in many reservoirs the direction and magnitude of matrix permeability will be largely controlled by the orientation of the maximum horizontal stress and by the magnitude of the horizontal stress difference at any given stage in the production history of the reservoir. Similarly, accurate measurements of compressibility should be obtained under loading conditions similar to those imposed on the reservoir during production. Optimum reservoir management may require that reservoir stress path be determined by measuring in-situ stresses early in the production history of the reservoir and periodically thereafter as the pore pressure is reduced.


Due to their fundamental importance in reservoir evaluation and management, matrix permeabilities and compressibilities of reservoir rocks are routinely measured in the laboratory using procedures intended to simulate the reservoir environment. The most commonly used procedure is to compress the specimen in a hydrostatic test, in which the sample is subjected to an isotropic stress state (i.e., horizontal stresses equal the overburden stress) by a confining fluid. As the effective confining fluid pressure is increased, changes in the rock pore volume are measured and are used to calculate pore volume compressibility. Similarly, specific permeability is measured at incremental confining pressures by flowing a fluid of known viscosity through the specimen at a known rate and stabilized pressure difference. Matrix permeabilities are then calculated from measured values of specific permeability.

Although simple and convenient to run, the hydrostatic test has a major drawback; hydrostatic (isotropic) loading conditions are rarely encountered in real reservoirs. For example, Warpinski, Branagan, and Wilmer (1985) measured in-situ stresses in a sequence of marine sandstones and shales typical of many hydrocarbon reservoirs. Their measurements show that stresses in the sandstones are distinctly anisotropic, and that minimum horizontal stresses can be predicted from the rock material properties in some but not others.

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