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Carbonate Pore System Influence on Displacement Behavior


Pore system heterogeneity has a profound influence on hydrocarbon displacement and ultimate recovery. Due to the homogenous nature of the micro-pore system, the ratio of micro-pores to other pore types, especially interparticle pore space, is a useful metric for representing pore system heterogeneity. Thin section image analysis was used to quantify pore type distributions (PTD) across samples with a broad range in porosity and permeability. PTD information was integrated with capillary pressure data from centrifuge experiments and relative permeability data from steady-state core flood experiments. The ratio of micro-pore space to interparticle pore space is a first-order control on capillary pressure and relative permeability for the samples included in this study. Rocks with a higher proportion of microporosity (> 80% - micro-pore dominated) have systematically lower negative capillary pressure and lower relative permeability to water at a given water saturation than rocks with a lower proportion of microporosity (50-80% - mixed pore system). This difference in pore type abundance translates to more favorable displacement for rocks dominated by microporosity despite significantly lower permeability. A flow-through micro-CT apparatus was designed to directly image the evolution of fluid distribution within both micro-pore dominated and mixed pore system rocks during waterflood. Oil was doped with Xenon to provide contrast for distinguishing oil from water in the core flood experiment. The homogenous nature of the micro-pore system results in piston-like displacement behavior while the more heterogeneous mixed pore system exhibits significant bypass at the core plug scale. These results have implications for asset assessment, field development planning, and maximizing ultimate recovery.