Abstract
A previously defined triple porosity model is used to calculate the cementation exponent (m) of complex carbonate reservoirs in the Middle East using well log data. The cementation exponent is usually affected in carbonate rocks by different types of primary and secondary porosities. A combination of interparticle porosity, non-connected porosity (e.g., vuggy and fenestral) and fractures increases the uncertainty in the estimation of m. Therefore, a well-defined petrophysical approach must start by first understanding the rock's fabric.
Initially, samples are classified into different flow units based on pore throat apertures at 35% cumulative pore volumes (rp35). This classification is then extended to include variations in porosity types based on geological and petrophysical descriptions of each rock. Each sample has different proportions of connected and non-connected porosities. These porosities are defined as matrix, fractures and non-touching vugs (including fenestral porosity). The porosity types are extracted from well logs for the whole reservoir section and are cross-checked against core samples and thin sections.
The value of m in a triple porosity system can be larger, equal, or smaller than the cementation exponent of only the matrix blocks (mb). This variation depends on the relative contribution of natural fractures and non-touching vugs compared to the composite triple porosity reservoir. A continuous curve of m values is obtained using this model. A good comparison has been obtained between the results of this model and m values measured in the laboratory.
Estimation of variable m values within short distances in a given reservoir using the triple model is a significant development in formation evaluation that helps reduce uncertainty in petrophysical calculations. The results increase the confidence level in water saturation and reserves determinations.
