Abstract
The reservoir rock cuttings can be characterized using mercury intrusion porosimetry (MIP). MIP tests do not yield the permeability of the sample directly; however, MIP results could be used to estimate permeability using empirical equations. Such effort has been attempted in several researches. Most of them have been performed on sandstones or carbonates solely. Therefore, a comprehensive study accounting for both types of reservoir rocks is missing. In the current research, MIP data of 187 sandstone, limestone, and dolomite samples with a wide range of permeability (from 0.001 to 2000 mD), and porosity (from 1 to 32%) taken from 8 Iranian gas and oil fields were used to develop a new generalized equation for estimating uncorrected gas permeability. We have concluded that in addition to the porosity, pore throat radii corresponding to a mercury saturation of 35% (r35) has the highest correlation with the permeability of the samples. The proposed equation was validated by data from another 21 carbonate and 9 sandstone rock samples. A comparison between our equation and other commonly used similar empirical equations showed the proposed equation has the highest precision in the estimation of permeability of all rock types. The findings of this study can be used to predict reservoir rock permeability from easily accessible and inexpensive drill cutting with acceptable precision. Additionally, the proposed equation is applicable in well-log interpretations and reserve determinations.
Highlights
Permeability is the flow capacity of a reservoir
While well testing and core analysis measure the permeability directly, the response of well logging tools gives an estimation of the reservoir permeability
Since mercury intrusion porosimetry (MIP) test could be performed on inexpensive drill cuttings samples, several researchers have attempted to derive permeability from MIP results
Summary
Permeability is the flow capacity of a reservoir. Without accurate measurement of rock permeability, valid predictions of reservoir performance cannot be achieved. Data from 50 samples are not enough to derive a correlation covering such a wide range of rock properties Their equation requires 3 parameters Lc, Lmax, and S(Lmax) to be specified prior to permeability calculation. Pittman (1992) tried to improve Winland’s work by performing regression on permeability, porosity, and MIP data of 202 sandstone samples He stated that the following equation presents the best correlation: log Kair = −1.221 + 1.512 log r25 + 1.415 log (6). Equation (1) assumes porous media behaves like a bundle of cylindrical tubes with different radiuses, while in porous media, the pore/throat shapes are irregular, and there are more parameters (e.g., aspect ratios and coordination number) which affect the capillary pressure-injected mercury volume relationship. A constant value of 130 degrees for rockmercury contact angle was considered
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