The critical capillary number is the point at which the residual oil saturation begins to reduce, while the second critical capillary number is the point at which the residual oil saturation starts to rise again. An optimized capillary number range is proposed for chemical flooding in low permeability reservoirs.We use cookies to help provide and enhance our service and tailor content and ads.

Several other theoretical researches about the moving contact line in a capillary driven by gravity (body force) were investigated[9][10].Hocking[11] derived a critical capillary number prediction equation based on a body force driven model. Symbol 1 represents the end point of the desaturation process shown in Figure  , Pore-scale modeling of capillary trapping in water-wet porous media: A new cooperative pore-body filling model, Pore to pore validation of pore network modelling against micromodel experiment results, Digital rock analysis for accurate prediction of fractured media permeability, Cleat-scale characterisation of coal: An overview, Pore-scale capillary pressure analysis using multi-scale X-ray micromotography, Pore-Scale Characterization of Two-Phase Flow Using Integral Geometry, Industrial applications of digital rock technology, Dynamics of snap-off and pore-filling events during two-phase fluid flow in permeable media, X‐ray Microtomography of Intermittency in Multiphase Flow at Steady State Using a Differential Imaging Method, Visualizing and quantifying the crossover from capillary fingering to viscous fingering in a rough fracture, Wettability impact on supercritical CO2 capillary trapping: Pore‐scale visualization and quantification, The Pathway‐Flow Relative Permeability of CO2: Measurement by Lowered Pressure Drops, Modeling Forced Imbibition Processes and the Associated Seismic Attenuation in Heterogeneous Porous Rocks, Direct Measurement of Static and Dynamic Contact Angles Using a Random Micromodel Considering Geological CO2 Sequestration, Model Study of Enhanced Oil Recovery by Flooding with Aqueous Solutions of Different Surfactants: How the Surface Chemical Properties of the Surfactants Relate to the Amount of Oil Recovered, Viscoelastic polymer flows and elastic turbulence in three-dimensional porous structures, How Viscoelastic-Polymer Flooding Enhances Displacement Efficiency, Micro-scale experimental investigation of the effect of flow rate on trapping in sandstone and carbonate rock samples, Fast laboratory-based micro-computed tomography for pore-scale research: Illustrative experiments and perspectives on the future, A phase-field method for the direct simulation of two-phase flows in pore-scale media using a non-equilibrium wetting boundary condition, Abu Dhabi International Petroleum Exhibition & Conference, Impact of the scale factor on mobilization of residual oil: A laboratory experiment, Influence of Wettability on Residual Gas Trapping and Enhanced Oil Recovery in Three-Phase Flow: A Pore-Scale Analysis by Use of Microcomputed Tomography, Imaging and image-based fluid transport modeling at the pore scale in geological materials: A practical introduction to the current state-of-the-art, Pore‐scale displacement mechanisms as a source of hysteresis for two‐phase flow in porous media, 4-D imaging of sub-second dynamics in pore-scale processes using real-time synchrotron X-ray tomography, Multi-Physics Pore-Network Modeling of Two-Phase Shale Matrix Flows, Experimental characterization of nonwetting phase trapping and implications for geologic CO2 sequestration, Prediction of empirical properties using direct pore-scale simulation of straining through 3D microtomography images of porous media, Model Study of Enhanced Oil Recovery by Flooding with Aqueous Surfactant Solution and Comparison with Theory, Statistical mechanics of unsaturated porous media, Mechanism of anomalously increased oil displacement with aqueous viscoelastic polymer solutions, The Imaging of Dynamic Multiphase Fluid Flow Using Synchrotron-Based X-ray Microtomography at Reservoir Conditions, Modelling capillary trapping using finite-volume simulation of two-phase flow directly on micro-CT images, The effect of pore morphology on microbial enhanced oil recovery, CO 2 –brine displacement in heterogeneous carbonates, A Multi-Scale Investigation of Pore Structure Impact on the Mobilization of Trapped Oil by Surfactant Injection, Efficiently engineering pore-scale processes: The role of force dominance and topology during nonwetting phase trapping in porous media, SPE Asia Pacific Enhanced Oil Recovery Conference, Impact of interfacial tension on residual CO2 clusters in porous sandstone, Modeling the velocity field during Haines jumps in porous media, Pore‐by‐pore capillary pressure measurements using X‐ray microtomography at reservoir conditions: Curvature, snap‐off, and remobilization of residual CO2, Capillary bridge rupture in dip-pen nanolithography, Subsecond pore‐scale displacement processes and relaxation dynamics in multiphase flow, The critical capillary number is the point at which the residual oil saturation begins to reduce, while the second critical capillary number is the point at which the residual oil saturation starts to rise again. Critical Capillary Number of Interfacial Film Displacement in a Capillary Tube .

Desaturation studied with fast X- ray computed microtomography. In this work, through the use of a newly designed experimental apparatus for the measurement of the dynamic capillary pressure in low permeability formations, chemical flooding experiments on sandstone core samples (1–10 mD) were conducted to investigate the effects of high capillary numbers (0.001–2). By Changfei Yan and Huihe Qiu.

subsurface flow, the correct definition for the balance of viscous and capillary forces, the so-called capillary number (Ca), which predicts the mobilization of nonwetting phase, has been a long-standing controversy. The role of surface tension and wettability in the dynamics of air-liquid interfaces during immiscible fluid displacement flows in capillary tube driven by pressure has been investigated. (c) Relative permeability values simulated from the pore‐scale images.