Quantification of secondary mineralization or cementation within natural fractures has not been considered in previous petrophysical dual porosity models. This is however of paramount importance as morphology of the fractures indicates that they can be open, partially or completely mineralized.

If cementation with secondary minerals is complete the recovery of hydrocarbons will be generally very small. If secondary mineralization is partial, production rates and recoveries could be quite significant as the secondary minerals would play the role of natural proppant agents helping to maintain the fractures open as the reservoir is depleted. If the fractures are initially open, production rates and recoveries could be large or small dependent on the orientation of the natural fractures and in-situ stresses.

These observations lead to the key objective of this paper: to develop an analytical dual porosity model for quantifying secondary mineralization (cementation) and tortuosity in natural fractures. The method further allows estimating matrix and fracture porosities, and fracture compressibility based on the amount of secondary mineralization.

Use of the new dual porosity model is explained with two core data sets drawn from tight gas formations in the United States and Canada. A comparison is made with results of current dual porosity models that do not take into account secondary mineralization within the natural fractures and tortuosity.

The conclusion is reached that the proposed dual porosity model provides a valuable new quantitative tool for petrophysical evaluation of naturally fractured reservoirs. In addition, the methodology allows estimating fracture compressibility, a usually elusive parameter needed for estimating original petroleum in place in naturally fractured reservoirs. Although the methodology is explained using data from tight sandstones it also has application in other types of reservoirs and lithologies.

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