Carbonate reservoirs often contain a complex mixture of pore sizes. In Bul Hanine field, Arab-DIII reservoir is almost entirely microporous throughout the field. Microporosity affects log responses and fluid flow properties. Proper identification and quantification of different porosity classes and their influence on the petrophysical parameters is crucial to accurately calculate hydrocarbon saturation. This paper presents the results of a multi-disciplinary workflow employed to identify and quantify the different porosity classes in the Arab-D reservoir.

The workflow consists of core- and log-based analysis. The core-based analysis includes laser scanning confocal microscopy of thin sections from different reservoir facies, analysis of mercury injection data, and 3D pore network modeling. Confocal microscopy (0.25 micron resolution) quantified microporosity that cannot be seen or assessed through conventional petrography, while 3D pore network modeling helped evaluate the effect of the microporosity on the electrical parameters of the different reservoir facies. The log-based analysis includes analysis of Nuclear Magnetic Resonance logs (NMR) through spectral decomposition, interpretation of borehole images to evaluate the effects of diagenesis on the different reservoir facies, and other standard logs.

Confocal microscopy demonstrated that pores smaller than 10 microns in diameter (micropores) in wackestone to packstone facies commonly comprise almost 100% of the total porosity. Burrowed, heterogeneous packstones and wackestones have 38 to 95% microporosity. Accurate quantification of microporosity from core using confocal microscopy permitted the computation of a continuous microporosity log using primarily NMR spectral decomposition and alternatively borehole images when NMR data is not available. After image to core calibration, rock fabric analysis using borehole images identified different bioturbation intensities with variable burrow sizes and varying burrow infill textures. Permeability enhancement can develop when burrowing architectures are well developed and filled with more permeable sediment, but diagenesis can also alter the porosity and permeability. The evaluation of electrical properties yielded insights into more effective rock property parameters, indicating that water saturation in these microporous networks may be lower than previously calculated. Pore network modeling showed that the microporosity fraction influences Archie's saturation exponent ("n"). By including a variable "n" value, weighted by the fraction of microporosity, water saturation computations can be reduced by 20%, therefore increasing volumetric and original oil in place.

This workflow provides an innovative technique to characterize different porosity classes in heterogeneous carbonate reservoirs and quantify its impact on reservoir properties. It also provides a novel technique to calculate water saturation after correcting the effects of the microporosity presence in the different reservoir facies. This technique can be used in most of the microporous carbonate reservoirs.

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