ABSTRACT

Characterizing fluid flow in carbonate reservoirs is difficult because of the robust mixture of pore types found in carbonates. Pore types that contribute most to permeability are interparticle and touching vug. Permeability from interparticle porosity is related to pore-size distribution, which can be linked to rock-fabric descriptions. Separate vugs may add to flow capacity, but their contribution has been shown to be small. Core analysis and wireline logs measure total porosity, which in most carbonates combines interparticle and separate-vug porosity. In order to predict permeability from porosity, core and log measurements must be separated into interparticle and separate-vug porosity.

Samples from Alabama Ferry field were used to quantify the relationship between separate-vug porosity, intergrain porosity, and permeability. Thin sections were made from 22 perm-plugs of skeletal/ooid grainstone having varying amounts of grain molds and intragrain microporosity. Porosity and permeability data do not plot in the grainstone field of Lucia (1995) using total porosity. However, when interparticle porosity, determined by subtracting separate-vug porosity from total porosity, is used, the data plot in the grainstone field. Scatter does not decrease, however, because of the sampling bias of the thin sections. MRI scans of the perm-plugs show that porosity due to large pores is highly variable within the perm-plugs. Permeability values calculated by using the rock-fabric approach capture important high-permeability values, whereas those calculated by the simple petrophysical approach do not.