The relation between the depositional and diagenetic facies within a carbonate reservoir may affect the success of a secondary-recovery project in terms of the residual oil saturation following displacement of oil by water. Recognition of facies control on the evolution of porosity and permeability aids in the prediction of reservoir performance. Displacement tests, performed on vugular carbonate cores, illustrate this point.

Strongly wetting countercurrent imbibition tests, conducted on full-diameter cores from the Meekwap field in Alberta, reveal the effects of secondary porosity on the displacement of a nonwetting oil phase. In Amphipore sp. wackestones, dolomitization and dissolution of Amphipore segments have produced a random distribution of small moldic pores that are matrix connected. During water-wet displacement tests, poor displacement efficiency is realized in the high moldic porosity wackestones. Visual observations indicate that the nonwetting oil phase is preferentially trapped in the moldic pores. Reef-core boundstones, composed of a laminar stromatoporoid and algal assemblage, have a pore structure dominated by tabular vugs linked by vertical fractures. In contrast to the moldic pore syste , displacement efficiency is maximized in the high porosity intervals as buoyancy forces allow oil to migrate through the vug-fracture system. Visual differentiation of the end-member pore systems will allow the development of a reservoir model that can predict oil recovery within various depositional facies within the reservoir.

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