Carbonate reservoirs are difficult to characterize as they exhibit heterogeneities at all the scales encountered in exploration and development operations. The recovery processes are poorly understood because of the storage and movement of the fluids across different porosities (primary, secondary and tertiary) and scales (micro-, meso- and macro-). Hence, the dominant flow regime, critical to the overall field development, is poorly understood. Conventionally, laboratory measurements of porosity, permeability, capillary pressure, and relative permeability are used for reservoir characterization. However, due to limited core inventory and experimental cost, these measurements are rarely acquired. Digital Rock Physics provides a platform to simulate digitized rock volumes with the physical mechanisms to understand the dominant flow regimes and simulate ultimate recovery. We present quantitative estimates of total porosity and its size fractionation using digital rock workflows. The porosity fractions were categorized into three sizes: micro, meso and macro pore types based on the modified classification system in carbonates from Lonoy (2006). This porosity partitioning allows us to understand dominant flow regimes in complex reservoirs and determine fluid flow regimes (continuum to statistical (free molecule) based on the calculated Knudsen number (KN) for gas reservoirs.
Presentation Date: Tuesday, October 13, 2020
Session Start Time: 1:50 PM
Presentation Time: 1:50 PM
Location: Poster Station 4
Presentation Type: Poster
