Numerical simulation of viscous fingering in porous media

Belotserkovskaya, M. S.; Konyukhov, A. V.

doi:10.1088/0031-8949/2010/t142/014056

Cited by 6 publications

(4 citation statements)

References 6 publications

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“…The displacement pressure can always overcome the viscous force and interfacial tension at a higher injection rate, forming narrow water flooding channels and thus further reduction of the viscous force in the channel (because water has a lower viscosity than oil), more conducive to forward displacement along the channel. This viscous fingering phenomenon has been confirmed by many researchers from experiments and numerical simulations [38][39][40], when the finger splitting rate increased at higher flow rates leading to low sweeping efficiencies [41].…”

Section: Injection Ratementioning

confidence: 53%

Study on Microscopic Water Flooding in Porous Carbonate Reservoirs by Numerical Simulation

Hao

et al. 2022

Geofluids

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The study on the flow behaviors of oil and water two phases in porous media and their influencing factor is very important to adjust the porous carbonate reservoir development strategy and enhance the oil recovery. Based on the CT (computed tomography) scanning of real carbonate reservoir core sample, the micropore structure was reconstructed, and the effects of different factors (injection rate, oil-to-water viscosity ratio, and contact angle) and secondary development methods (higher injection rate and water displacement direction optimization) on the flow behavior of oil and water two phases were explored by numerical simulation in this paper. It is found from the study that the pores in the porous carbonate reservoirs have good structural connectivity. During the displacement process, the oil-water interface mainly resides at the pore throat junction with a large change of pore size, and the Haines jumps exist in the oil-water movement; the areal sweep efficiency of the water phase is jointly affected by the viscosity effect, interfacial tension, pore structure, and injection rate. Under the minimum injection rate and oil-to-water viscosity ratio, the maximum oil recovery can be obtained, and the oil recovery is 52.62% and 57.01%, respectively. The recovery efficiency and swept area are better in a water-wet system than oil-wet system. During the secondary development, the remaining oil is hardly displaced even with the injection rate increased by a factor of 50, and it shows improvement after 250 times of initial injection rate. Changing the position of water inlet and the produced fluid outlet results in better recovery since the remaining oil near the new inlet and outlet can be effectively produced.

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Section: Injection Ratementioning

confidence: 53%

Study on Microscopic Water Flooding in Porous Carbonate Reservoirs by Numerical Simulation

Hao

et al. 2022

Geofluids

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“…Belotserkovskaya [85] developed a numerical model capable of simulating IVF in 3 . The model was based on the assumptions that the displacement had zero hydrodynamic dispersion and high Ca numbers.…”

Section: Modeling Of Immiscible Flowsmentioning

confidence: 99%

“…Modeling of VF in 3D is computationally more expensive and complicated than its 2D counterpart. Belotserkovskaya [ 85 ] developed a numerical model capable of simulating IVF in 3D . The model was based on the assumptions that the displacement had zero hydrodynamic dispersion and high Ca numbers.…”

Section: Modeling Of Vf At the Microscale: 2d And 3d Simulationsmentioning

confidence: 99%

Experimental and computational advances on the study of Viscous Fingering: An umbrella review

Pinilla

Asuaje²,

Ratkovich

2021

Heliyon

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This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

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“…Instead, a value of porosity and permeability is used at each grid cell, similarly to the reservoir codes. Nevertheless, most of the studies using these approaches have been restricted to 2D systems, with few exceptions addressing the 3D dynamics of unstable displacements [ 31 , 38 , 39 , 45 , 51 , 52 ]. Although these models’ advantages are the possibility of explicitly simulating VF, either at the pore and continuum scale for miscible and immiscible displacements, the major drawback is that they have been limited to small length scales and 2D systems.…”

Section: Introductionmentioning

confidence: 99%

CFD study of the water production in mature heavy oil fields with horizontal wells

Pinilla

Asuaje²,

Pantoja

et al. 2021

PLoS ONE

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Excessive water production in mature heavy oil fields causes incremental costs, energy consumption, and inefficiency. Understanding multiphase flows near the wellbore is an alternative to improve production efficiency. Therefore, this study conducts a series of numerical experiments based on the full set of the Navier-Stokes equations in 3D to simulate multiphase flows in porous media for heavy oil production horizontal wells. The solution given by this advanced mathematical formulation led to the description of the movement of the fluids near the wellbore with unprecedented detail. A sensitivity analysis was conducted on different rock and fluid properties such as permeability and oil viscosity, assuming homogeneous porous media. The influence of these parameters on the prediction of the breakthrough time, aquifer movement, and the severity of water production was noticed. Finally, the numerical model was verified against field data using two approaches. The first one was conducting a history match assuming homogeneous rock properties. In contrast, the second one used heterogeneous rock properties measured from well logging, achieving a lower deviation than field data, about 20%. The homogeneous numerical experiments showed that the breakthrough occurs at the heel with a subsequent crestation along the horizontal well. Moreover, at adverse mobility ratios, excessive water production tends to happen in water connings at the heel with an inflow area less than 1% of the total inflow area of the completion liner. Different aquifer movement dynamics were found for the heterogeneous case, like the breakthrough through multiple locations along the horizontal well. Finally, critical hydraulic data in the well, such as the pressure and velocity profiles, were obtained, which could be used to improve production efficiency. The numerical model presented in this study is proposed as an alternative to conducting subsurface modeling and well designs.

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Numerical simulation of viscous fingering in porous media

Cited by 6 publications

References 6 publications

Study on Microscopic Water Flooding in Porous Carbonate Reservoirs by Numerical Simulation

Study on Microscopic Water Flooding in Porous Carbonate Reservoirs by Numerical Simulation

Experimental and computational advances on the study of Viscous Fingering: An umbrella review

CFD study of the water production in mature heavy oil fields with horizontal wells

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