Modelling of 3D viscous fingering: Influence of the mesh on coreflood experiments

Pinilla, Andrés; Ramírez, Liliana Galindo; Asuaje, Miguel; Ratkovich, Nicolás Ríos

doi:10.1016/j.fuel.2020.119441

Cited by 13 publications

(7 citation statements)

References 54 publications

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“…A previous study demonstrated that CFD codes could explicitly simulate heavy oil-water flow, even emulating VF and its characteristic dynamics in coreflood experiments [ 53 ]. For the current study, the numerical model was extrapolated to a heavy-oil production well to study the bottom aquifer’s unstable displacement and breakthrough event near the wellbore.…”

Section: Methodsmentioning

confidence: 99%

“…A previous study proposed a methodology for simulating unstable displacements considering VF at the continuum scale based on CFD models [ 53 ]. This methodology suggested an average Courant-Friedrichs-Levy (CFL) number of 0.25 for the flow measured in the reservoir rock with fair agreement against experimental data for oil recovery, along with the qualitative description of the VF dynamics and topologies in 3D.…”

Section: Methodsmentioning

confidence: 99%

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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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Section: Methodsmentioning

confidence: 99%

Section: Methodsmentioning

confidence: 99%

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

Pinilla

Asuaje²,

Pantoja

et al. 2021

PLoS ONE

Self Cite

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“…The finite volume method is used to study the oil and water two-phase flow at pore scale because of its good conservation and applicability for complex geometry [6], mainly including volume of fluid (VOF) methods [20][21][22][23], level set methods [24], and phase field (PF) method [25,26]. Iyi et al used a volume of fluid model to simulate the transport process of oil and water two phases in pore channels and considered the effects of temperature, contact angle, and surface tension.…”

Section: Introductionmentioning

confidence: 99%

“…Pinilla et al used the CFD (computational fluid dynamics) method to simulate the oil and water two phases in porous media by the VOF model and compared it with the experimentally measured recovery efficiency. Their results show that the absolute error is below 7% [20]. Wang et al simulated the water flooding process at the pore scale in a nonuniform wettability rock model and analyzed the effects of the critical capillary number on relative permeability, remaining oil recovery efficiency, and immiscible displacement efficiency [17].…”

Section: Introductionmentioning

confidence: 99%

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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“…In this study, a numerical solution of the Navier-Stokes equations is proposed for simulating VF in great detail in 3D. The CFD commercial software STAR-CCM+ was used, implementing an Eulerian-Volume of Fluid (VOF) solution for simulating the multiphase flow in porous media using a polyhedral unstructured mesh based on the findings of a previous study [21]. The numerical model was validated against experimental data found in the literature [22] of coreflood experiments for three different viscosity ratios, 60, 1440, and 10500.…”

Section: Introductionmentioning

confidence: 99%

Modelingof Viscous Fingering based on the numerical solution of the Navier-Stokes Equations in 3D.

Pinilla¹,

Ramírez²,

Asuaje³

et al. 2021

Proceedings of the 6th World Congress on Momentum, Heat and Mass Transfer

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The prediction of multiphase flow in porous media is of great interest in several fields like Oil & Gas, 2 sequestration, geothermal energy, among others. Subsurface modeling is challenging due to the difficulties in predicting microscopic phenomena like Viscous Fingering that manifest at the macroscale in channellings, affecting displacement efficiency. Viscous Fingering is characterized for causing finger-like patterns that channels the phase with the lowest viscous resistance in the porous media. This phenomenon is the root cause of heavy oil production inefficiency, causing excessive water production, increasing costs, and energy consumption. This study proposes a numerical model based on the complete set of the Navier-Stokes equations in 3D to predict this natural phenomenon. The numerical model, developed using commercial CFD software, is based on an Eulerian-VOF solution to simulate immiscible multiphase flow in porous media in 3D. To verify the numerical model, it was compared against experimental data for oil recovery on three different viscosity ratios, ranging from 10 1 to 10 3 . The deviation against the experimental data was below 10%, achieving a successful prediction on the oil recovery while qualitatively predicting Viscous Fingering in 3D in great detail. Several differences between the studied viscosity ratios were found too. Not only regarding the oil recovery but also noticeable differences between the fingering dynamics were found too. The numerical solution proposed in this study could be helpful for scientists interested in subsurface modeling in great detail, where the prediction of multiphase flow in porous media is of great interest to improve subsurface processes.

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Modelling of 3D viscous fingering: Influence of the mesh on coreflood experiments

Cited by 13 publications

References 54 publications

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

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

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

Modelingof Viscous Fingering based on the numerical solution of the Navier-Stokes Equations in 3D.

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