What Sandpack Flooding and Coreflood Micro-CT Imaging Reveal About Pore-Scale Oil Mobilization

Sandpack flooding and coreflood micro-CT imaging reveal pore-scale oil mobilization mechanisms during MEOR by generating sub-micron three-dimensional visualizations of fluid distributions inside reservoir rock samples, proving that biosurfactant flooding deforms trapped oil droplets, alters contact angles, and coalesces isolated ganglia into continuous flowing oil banks.

For decades, enhanced oil recovery research evaluated displacement efficiency purely through macroscopic mass-balance measurements: injecting fluids into one end of a cylindrical rock core and measuring the volume of oil produced at the effluent end. While macroscopic recovery curves confirm whether an EOR formulation increases cumulative oil recovery, they treat the internal rock pore network as a complete ‘black box.’ Macroscopic measurements cannot determine where residual oil remains trapped, how individual oil droplets interact with pore throats, whether microbes adhere uniformly to grain surfaces, or how contact angles shift dynamically under flowing conditions. To design optimized microbial formulations and accurately calibrate field-scale reservoir simulators, petroleum scientists must observe fluid-fluid and fluid-rock interactions directly at the pore scale under reservoir temperature and pressure.

Sandpack flooding systems and advanced Coreflood Micro-Computed Tomography (Micro-CT) provide this revolutionary pore-scale window. Intact cylindrical sandstone or carbonate core plugs (typically 2.5 to 3.8 cm in diameter) are placed inside a carbon-fiber or beryllium hyperbaric core holder transparent to X-rays, heated to reservoir temperatures (e.g., 75 degrees Celsius), and pressurized with overburden confining pressures exceeding 200 bar. High-resolution synchrotron X-ray Micro-CT scans the core in three dimensions with spatial resolutions down to one micrometer per voxel. Using contrast-enhancing dopants (such as potassium iodide in the aqueous phase and bromodecane in the oil phase), 3D digital image reconstruction segments rock grains, brine, and crude oil with razor-sharp fidelity. Time-lapse Micro-CT during microbial flooding reveals the precise physical mechanisms: before MEOR, oil is trapped as globular droplets in wide pore bodies behind narrow pore throats; as biosurfactants arrive, the oil-water interface flattens, interfacial tension plummets, and oil droplets stretch into thin, elongated threads that navigate constricted pore throats without snap-off. Furthermore, isolated ganglia coalesce into large continuous oil banks that flow collaboratively, providing indisputable visual proof of microscopic displacement efficiency.

Pore network modeling (PNM) extracts topological pore-throat networks from the 3D images, allowing direct numerical simulation of Navier-Stokes and Cahn-Hilliard phase field equations to predict dynamic relative permeability curves for full-field simulation.

Petrophysics research centers, digital rock physics laboratories, and advanced imaging faculties certified under the National Universities Commission operate high-pressure coreflood Micro-CT scanners, develop machine-learning pore segmentation algorithms, and quantify 3D fluid-fluid contact angles.

Petroleum core evaluation standards, reservoir rock characterization guidelines, and tertiary recovery validation directives governed by the Nigerian Upstream Petroleum Regulatory Commission define standardized core handling protocols (API RP 40), digital rock data validation standards, and regulatory recovery factor verification rules.