Narrowing the loop for microporosity quantification in carbonate reservoirs

Microporosity quantification is becoming increasingly important to assess the distribution of hydrocarbons and their remaining/residual saturations after water flood (and /or gas flood). Assessing uncertainties and limitations in microporosity estimations of carbonate cores, comprising different reservoir rock types have been a challenge for geoscientists. The advent of Digital Rock Physics (DRP) based measurements allow the pore 3D network images from Micro and Nano - Computed Tomography (CT) scans on selected sub-samples to map representative cores and Reservoir Rock Types (RRT). The DRP based microporosity is rigorously examined and compared with other techniques/tests. Conventional techniques, such as Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), Thin Section (TS) and Backscattered Scanning Electron Microscopy (BSEM) are used for semi-quantitative evaluations of microporosity. Images at different magnitudes (4X, 10X, 40X and 100X) were captured from TS and BSEM, and used to quantify porosity using image analysis software. NMR and MICP measurements acquired through a commercial laboratory were also analyzed to quantify the microporosity. DRP based 3D pore network images have been acquired at different scales of interrogation from Nano to micron meters to define microporosity. Preliminary measurements on carbonate cores from a giant onshore field of Abu Dhabi, reveals an inverse relationship between microporosity and permeability. Microporosity impacts the porosity-permeability correlation. The relationship between porosity and permeability of carbonate reservoirs shows a better correlation when microporosity is deducted from the total porosity of the reservoir. A detailed analysis is presented along with Best Practices in estimating microporosity of carbonates.