Estimation of the Water–Oil Relative Permeability Curve from Radial Displacement Experiments. Part 2: Reasonable Experimental Parameters

Hou, Jirui; Luo, Fuquan; Wang, Daigang; Li, Zhenquan; Bing, Shaoxian

doi:10.1021/ef3005866

Cited by 8 publications

(6 citation statements)

References 14 publications

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“…Permeability to fluid flow in porous media is a key parameter to be considered in many fields − including soil science, fuel cells, textile engineering, reservoir engineering, subsurface environmental engineering, and chemical engineering. Past investigations − have shown that the transport processes in porous media are very complex and dependent on the complexity of the microstructure of porous media. Many parameters such as porosity, size of pore, tortuosity of capillaries, and capillary pressure are very important for the permeability of porous media.…”

Section: Introductionmentioning

confidence: 99%

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Prediction of Relative Permeability of Unsaturated Porous Media Based on Fractal Theory and Monte Carlo Simulation

2012

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Mass transport through porous media is an important subject to engineers and scientists in various areas including oil engineering, fuel cells, soil science, textile engineering, etc. The relative permeability and capillary pressure are the key parameters that affect liquid transport through porous media. In this paper, the Monte Carlo technique is applied to predict the relative permeability of unsaturated porous media, considering the effect of capillary pressure and tortuosity of capillaries. The relative permeability is expressed as a function of porosity, area fractal dimension of pores, fractal dimension of tortuous capillaries, degree of saturation, and capillary pressure. It is found that the phase fractal dimensions (D f,w and D f,g ) strongly depend on porosity. Besides, it is shown that the capillary pressure increases with the decrease of saturation, and at low saturation the capillary pressure increases sharply with the decrease of saturation. There is no empirical constant in the proposed model, and each parameter in the model has a clear physical meaning. The predicted relative permeability obtained by the present Monte Carlo simulation is shown to have a good agreement with the experimental results reported in the literature. The proposed model improved the understanding of the physical mechanisms of liquid transport through porous media.

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Section: Introductionmentioning

confidence: 99%

“…Modeling the permeability of unsaturated porous media therefore presents a great challenge. So far, a number of experimental techniques − have been developed to measure the permeability of porous media. Experiments are, however, generally expensive and time-consuming.…”

Section: Introductionmentioning

confidence: 99%

Prediction of Relative Permeability of Unsaturated Porous Media Based on Fractal Theory and Monte Carlo Simulation

2012

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“…7 compares the simulation runs used by the LM-FD and LM-SP-2 methods, in which the segments are set as 4, 5, 6, 7, 8 (i.e. the unknown controlling knots are 7,9,11,13,15). Since the simulations needed to approximate Jacobian is proportional to the number of controlling knots in the LM-FD method, the total computational cost increases rapidly as the segments increase.…”

Section: Results and Analysesmentioning

confidence: 99%

“…The secant version of the LM method is intended for this problem. The most widely used method is to 3 replace the elements of original Jacobian by finite difference approximations (Hou et al, 2012a(Hou et al, , 2012b. For simplicity, the LM method with finite difference Jacobian approximation is denoted as the LM-FD method.…”

Section: Introductionmentioning

confidence: 99%

Estimation of relative permeability curves using an improved Levenberg-Marquardt method with simultaneous perturbation Jacobian approximation

Zhou

Hou

et al. 2017

Journal of Hydrology

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Relative permeability controls the flow of multiphase fluids in porous media. The estimation of relative permeability is generally solved by Levenberg-Marquardt method with finite difference Jacobian approximation (LM-FD). However, the method can hardly be used in large-scale reservoirs because of unbearably huge computational cost. To eliminate this problem, the paper introduces the idea of simultaneous perturbation to simplify the generation of the Jacobian matrix needed in the Levenberg-Marquardt procedure and denotes the improved method as LM-SP. It is verified by numerical experiments and then applied to laboratory experiments and a real commercial oilfield. Numerical experiment indicates that LM-SP uses only 16.1% computational cost to obtain similar estimation of relative permeability and prediction of production performance compared with LM-FD. Laboratory experiment also shows the LM-SP has a 60.4% decrease in simulation cost while a 68.5% increase in estimation accuracy compared with the earlier published results. This is mainly because LM-FD needs 2n (n is the number of controlling knots) simulations to approximate Jacobian in each iteration, while only 2 simulations are enough in basic LM-SP. The convergence rate and estimation accuracy of LM-SP can be improved by averaging several simultaneous perturbation Jacobian approximations but the computational cost of each iteration may be increased. Considering the estimation accuracy and computational cost, averaging two Jacobian approximations is recommended in this paper. As the number of unknown controlling knots increases from 7 to 15, the saved simulation runs by LM-SP than LM-FD increases from 114 to 1164. This indicates LM-SP is more suitable than LM-FD for multivariate problems. Field application further proves the applicability of LM-SP on large real field as well as small laboratory problems.

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“…There is still ambiguity about the sum of relative permeabilities in reservoirs. The relative permeability of oil-water two-phase flow in sand column and rock core were studied and show that the sum of the relative permeability of oil and water phases is less than 1 [8][9][10]. However, Odeh reported that the relative permeability of oil phase can reach 2.4.…”

Section: Introductionmentioning

confidence: 99%

Study of Oil-Water Two-Phase Stratified Flow in Horizontal Fractures

Huang

Sun

et al. 2020

E3S Web Conf.

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The relative permeability of oil-water two-phase flow is an important parameter in fractured petroleum reservoirs. It is widely accepted that the sum of relative permeabilities is less than 1. In this study, a series of experiments have been conducted on six rectangular fractures for oil-water two-phase flows. Analytical investigations of the effects of flow rate, aspect ratio, and fracture size on the relative permeability of oil-water two-phase are analysed. Basic fluid flow equations are combined to develop a new analytical model for water-oil two-phase flow in a horizontal fracture. The simulation results predicted by this model are in good agreement with the experimental data. The relative permeability is a function of flow ratio, viscosity ratio, aspect ratio and saturation. It increases as aspect ratio increases if the fracture depths are the same, while it decreases as aspect ratio increases if the fracture widths are identical. Both experiment and model indicate that the sum of relative permeabilities of oil and water is greater than 1 in some cases, different from the accepted view.

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Estimation of the Water–Oil Relative Permeability Curve from Radial Displacement Experiments. Part 2: Reasonable Experimental Parameters

Cited by 8 publications

References 14 publications

Prediction of Relative Permeability of Unsaturated Porous Media Based on Fractal Theory and Monte Carlo Simulation

Prediction of Relative Permeability of Unsaturated Porous Media Based on Fractal Theory and Monte Carlo Simulation

Estimation of relative permeability curves using an improved Levenberg-Marquardt method with simultaneous perturbation Jacobian approximation

Study of Oil-Water Two-Phase Stratified Flow in Horizontal Fractures

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