Carbonate reservoir rocks are often highly complex,exhibiting extreme heterogeneity in the size,shape,connectivity and wettability of the pore space. In turn this variability strongly impacts the behavior of the capillary pressure and relative permeability and hence the oil recovery. Special core analysis cannot describe or separate these effects since the measurements are limited in the number of samples that can be handled,as well as the displacement cycles and wettabilities that can be considered. We study 16 samples from two large Middle Eastern carbonate reservoirs(both limestones and dolomites). Static and dynamic properties of these rocks were determined through a combination of nano to cm scale sample selection and imaging to capture microporosity,macro-porosity and vugs,and multi-scale generalized network modeling and upscaling to capture the four orders of magnitude variation in pore size. The pore-scale distribution of contact angle was tuned to match one set of waterflood capillary pressure curves,which indicated mixed-wet characteristics with a tendency to be weakly oil-wet. On benchmark samples,the measured waterflood relative permeability was compared successfully to the predicted results. Samples with the widest range of connected pore sizes – principally the limestones with a mix of micro-,macro-and vuggy-porosity – tended to display oil-wet type waterflood behavior,implying poor recovery,whereas the dolomite samples with a more restricted range of pore size showed mixed-wet characteristics in their flow response with more favorable recoveries. This study shows the value of digital rock technology,which aids the identification of multiphase flow rock types and quantifies how the pore size distribution,connectivity,mineralogy and wettability impact local displacement efficiency.
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