Mechanisms of Microscopic Displacement During Enhanced Oil Recovery in Mixed-Wet Rocks Revealed Using Direct Numerical Simulation

Akai, Takashi; Alhammadi, Amer M.; Blunt, Martin J.; Bijeljic, Branko

doi:10.1007/s11242-019-01336-5

Cited by 14 publications

(4 citation statements)

References 43 publications

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“…A microscopic residual oil distribution law after water flooding in the layer is more dispersion [9][10][11]. Akai et al [12] used direct numerical simulation to study the mechanism of microscopic displacement during enhanced oil recovery in mixed-wet rocks. Heydari-Farsani et al [13][14][15][16] proposed that the characteristics of reservoirs and structures can affect the location and migration direction of hydrocarbons.…”

Section: Nomenclaturementioning

confidence: 99%

Experimental Research on the Millimeter-Scale Distribution of Oil in Heterogeneous Reservoirs

Yu¹

2023

Fluid Dynamics &Amp; Materials Processing

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Oil saturation is a critical parameter when designing oil field development plans. This study focuses on the change of oil saturation during water flooding. Particularly, a meter-level artificial model is used to conduct relevant experiments on the basis of similarity principles and taking into account the layer geological characteristics of the reservoir. The displacement experiment's total recovery rate is 41.35%. The changes in the remaining oil saturation at a millimeter-scale are examined using medical spiral computer tomography principles. In all experimental stages, regions exists where the oil saturation decline is more than 10.0%. The shrinkage percentage is 20.70% in the horizontal well production stage. The oil saturation reduction in other parts is less than 10.0%, and there are regions where the oil saturation increases in the conventional water flooding stage.

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Section: Nomenclaturementioning

confidence: 99%

Experimental Research on the Millimeter-Scale Distribution of Oil in Heterogeneous Reservoirs

Yu¹

2023

Fluid Dynamics &Amp; Materials Processing

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“…While finalizing the revision of our manuscript, we learned that Weishaupt (2020) has further extended 10.1029/2020WR028510 their modeling framework to two-phase flow conditions to simulate heat transfer and water evaporation (using Henry's law) at the interface between free flow and air-water two-phase flow in a porous medium. Finally, we note that more advanced local rules may be introduced to enable our PNM to model more complex pore-scale two-phase flow physics, such as the recently reported intermittent flow under steady-state conditions and dynamic two-phase flow in mixed-wet media (Akai et al, 2019;Gao et al, 2020;Scanziani et al, 2020;Zhang et al, 2020).…”

Section: Extension To Model More Complex Physical Processesmentioning

confidence: 99%

Fully Implicit Dynamic Pore‐Network Modeling of Two‐Phase Flow and Phase Change in Porous Media

Chen

Qin

Guo

2020

Water Resources Research

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Dynamic pore-network model (PNM) has been widely used to model pore-scale two-phase flow. Numerical algorithms commonly used for dynamic PNM including IMPES (implicit pressure explicit saturation) and IMP-SIMS (implicit pressure semi-implicit saturation) can be numerically unstable or inaccurate for challenging flow regimes such as low capillary number (Ca) flow and unfavorable displacements. We perform comprehensive analyses of IMPES and IMP-SIMS for a wide range of flow regimes under drainage conditions and develop a novel fully implicit (FI) algorithm to address their limitations. Our simulations show the following: (1) While IMPES was reported to be numerically unstable for low Ca flow, using a smoothed local pore-body capillary pressure curve appears to produce stable simulations. (2) Due to an approximation for the capillary driving force, IMP-SIMS can deviate from quasi-static solutions at equilibrium states especially in heterogeneous networks. (3) Both IMPES and IMP-SIMS introduce mass conservation errors. The errors are small for networks with cubic pore bodies (less than 1.4% for IMPES and 1.2% for IMP-SIMS). They become much greater for networks with square-tube pore bodies (up to 45% for IMPES and 46% for IMP-SIMS). Conversely, the new FI algorithm is numerically stable and mass conservative regardless of the flow regimes and pore geometries. It also precisely recovers the quasi-static solutions at equilibrium states. The FI framework has been extended to include compressible two-phase flow, multicomponent transport, and phase change dynamics. Example simulations of two-phase displacements accounting for phase change show that evaporation and condensation can suppress fingering patterns generated during invasion.

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“…The presented model utilizes an adsorption model for a single component to change the wetting state, implicitly considering the ion transport in thin water films covering the grain surfaces. They showed the advantages of their methodology compared to those presented by Aziz et al and Akai et al, considering only the contact angle of a grid block was altered as a function of grid salinity. An et al also suggested that the diffusion through thin films may be the controlling process for the dynamics of wettability alteration.…”

Section: Introductionmentioning

confidence: 98%

Pore-Scale Modeling of Heterogeneous Carbonate Rock Subjected to Modified Salinity Waterflooding

Farhadzadeh,

Bonto,

Nick

2024

Energy Fuels

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We developed a pore-scale reactive multicomponent twophase flow and transport numerical model to study the pore-level dynamics of water injection in carbonate rocks. The model utilizes direct numerical simulation of Navier−Stokes equations and a newly tuned surface complexation model (SCM) for brine−calcite interactions. An SEM image of chalk mimicking the heterogeneous pore network of the rock is initially saturated with oil and brine and then flooded with brine. With the SCM, we calculate the ζ-potential at the calcite surface under different chemical conditions. The change in the ζ-potential triggered by the shift in the chemical conditions is then related to the variation in the contact angle. We then used the developed coupled model to explore the impact of varying brine compositions, injection sequences, matrix connectivity, and injection rates on the pore-filling sequence and sweep efficiency. Our results demonstrate how the changes in the contact angle, injection rate, and pore connectivity control the displacement process and the ultimate recovery. Injection of modified salinity water results in a later breakthrough time than formation waterflooding. Further, our results confirm that the tertiary mode injection of modified salinity brine is less effective than the secondary mode of modified salinity brine flooding.

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Mechanisms of Microscopic Displacement During Enhanced Oil Recovery in Mixed-Wet Rocks Revealed Using Direct Numerical Simulation

Cited by 14 publications

References 43 publications

Experimental Research on the Millimeter-Scale Distribution of Oil in Heterogeneous Reservoirs

Experimental Research on the Millimeter-Scale Distribution of Oil in Heterogeneous Reservoirs

Fully Implicit Dynamic Pore‐Network Modeling of Two‐Phase Flow and Phase Change in Porous Media

Pore-Scale Modeling of Heterogeneous Carbonate Rock Subjected to Modified Salinity Waterflooding

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