Determination of Asmari Reservoir Pore Types Using Velocity Deviation and NMR Log in One of Iran Southwestern Oil Fields

In hydrocarbon reservoirs (especially in carbonate rocks)، the variation of pore type and size is influenced by diagenesis effects. Hence pore type distribution and capillary pressure in the reservoir rock is the main factor controlling fluid flow in porous media. In other words، the determination of pore type/size and capillary pressure has an important role in understanding petrophysical features، optimizing the number of wells in the field، and forecasting the recoverable hydrocarbon. In this paper، pore types in the mixed carbonate-siliciclastic Asmari formation is divided by velocity deviation log into three classes (positive، zero، and negative deviation) and eight subclasses. Six subclasses are related to carbonate part (interaparticle or interafossil، moldic or vuggy، microporosity، interparticle، intercrystalline، and fracture) and two subclasses are related to clastic part (intergranular and shale microporosity). After identifying pore types، pore size and pseudo capillary pressure are continuously determined in each subclasses throughout the well bore by using NMR log. Pore size and pseudo capillary pressure are compared by mercury injection capillary pressure curves. The results of this study show that intergranular porosity is the main factor for production in calstic intervals; however، fracture، interparticle، and intercrystalline porosities play an important role in carbonate intervals. The distributions of each four pore types are continuously determined along the well bore.