A Fractal Model for Oil Transport in Tight Porous Media

Huang, Shuqing; Yao, Yuedong; Zhang, Shuang; Ji, Jinghao; Ma, Ruoyu

doi:10.1007/s11242-017-0982-1

Cited by 34 publications

(14 citation statements)

References 32 publications

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“…Subsequently, Xu et al (2013) took capillary pressure into account to predict the relative permeability of wetting phase. Based on the capillary bundle model and the fractal theory, a new nonlinear seepage equation was deduced, and a further fractal permeability model was obtained for oil transport in tight porous media by considering the effect of the boundary layer (Huang et al, 2017). Compared with Brooks-Corey models (Brooks et al, 1966), a good agreement was presented.…”

Section: Introductionmentioning

confidence: 98%

A study of relative permeability for transient two-phase flow in a low permeability fractal porous medium

Duan

Fang

et al. 2018

Adv. Geo-Energy Res.

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In this paper, a relative permeability prediction method considering the effects of capillary pressure and threshold pressure gradient in a low permeability fractal porous medium is established and analyzed based on the fractal approximation model that porous medium consist of a bundle of tortuous capillaries. With this method, every parameter has clear physical meaning without empirical constants, and the model's predictions have a good agreement with experimental data. In addition to this, it makes some discussions that how the characteristic parameters (such as tortuosity fractal dimension, pore fractal dimension, ratio of minimum-maximum capillaries diameters and threshold pressure gradient) influence the relative permeability. This study may be conducible to a better understanding of the mechanism for transient two-phase flow in the low permeability fractal porous medium.

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Section: Introductionmentioning

confidence: 98%

A study of relative permeability for transient two-phase flow in a low permeability fractal porous medium

Duan

Fang

et al. 2018

Adv. Geo-Energy Res.

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“…Wang et al [33] and Huang et al [34] built fractal permeability models for oil transport in tight reservoirs by considering the effect of the boundary layer, and they found that the permeability was related to the fluid viscosity, pore structure, driving pressure, etc. The reason for this scenario is that the thickness of the boundary layer in their works was related to the fluid viscosity, pore structure, and driving pressure, etc.…”

Section: Introductionmentioning

confidence: 99%

A Fractal Permeability Model of Tight Oil Reservoirs Considering the Effects of Multiple Factors

Cui

Yang

et al. 2022

Fractal Fract

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The prediction of permeability and the evaluation of tight oil reservoirs are very important to extract tight oil resources. Tight oil reservoirs contain enormous micro/nanopores, in which the fluid flow exhibits micro/nanoscale flow and has a slip length. Furthermore, the porous size distribution (PSD), stress sensitivity, irreducible water, and pore wall effect must also be taken into consideration when conducting the prediction and evaluation of tight oil permeability. Currently, few studies on the permeability model of tight oil reservoirs have simultaneously taken the above factors into consideration, resulting in low reliability of the published models. To fill this gap, a fractal permeability model of tight oil reservoirs based on fractal geometry theory, the Hagen–Poiseuille equation (H–P equation), and Darcy’s formula is proposed. Many factors, including the slip length, PSD, stress sensitivity, irreducible water, and pore wall effect, were coupled into the proposed model, which was verified through comparison with published experiments and models, and a sensitivity analysis is presented. From the work, it can be concluded that a decrease in the porous fractal dimension indicates an increase in the number of small pores, thus decreasing the permeability. Similarly, a large tortuous fractal dimension represents a complex flow channel, which results in a decrease in permeability. A decrease in irreducible water or an increase in slip length results in an increase in flow space, which increases permeability. The permeability decreases with an increase in effective stress; moreover, when the mechanical properties of rock (elastic modulus and Poisson’s ratio) increase, the decreasing rate of permeability with effective stress is reduced.

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“…Tight sandstone oil and gas, with its huge resources, has become a hotspot in the unconventionals sector [1][2][3][4][5]. In recent years, many scholars have conducted research on enhanced oil recovery in tight sandstone reservoirs [6][7][8][9]. The permeability of tight reservoir permeability is one of the most important reservoir physical parameters in the gas reservoir development process [10,11].…”

Section: Introductionmentioning

confidence: 99%

Applicability Analysis of Klinkenberg Slip Theory in the Measurement of Tight Core Permeability

Zou

Yue

et al. 2019

Energies

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The Klinkenberg slippage theory has widely been used to obtain gas permeability in low-permeability porous media. However, recent research shows that there is a deviation from the Klinkenberg slippage theory for tight reservoir cores under low-pressure conditions. In this research, a new experimental device was designed to carry out the steady-state gas permeability test with high pressure and low flowrate. The results show that, unlike regular low-permeability cores, the permeability of tight cores is not a constant value, but a variate related to a fluid-dynamic parameter (flowrate). Under high-pressure conditions, the relationship between flowrate and apparent permeability of cores with low permeability is consistent with Klinkenberg slippage theory, while the relationship between flowrate and apparent permeability of tight cores is contrary to Klinkenberg slip theory. The apparent permeability of tight core increases with increasing flowrate under high-pressure conditions, and it is significantly lower than the Klinkenberg permeability predicted by Klinkenberg slippage theory. The difference gets larger when the flowrate becomes lower (back pressure increases and pressure difference decreases). Therefore, the Klinkenberg permeability which is obtained by the Klinkenberg slippage theory by using low-pressure experimental data will cause significant overestimation of the actual gas seepage capacity in the tight reservoir. In order to evaluate the gas seepage capacity in a tight reservoir precisely, it is necessary to test the permeability of the tight cores directly at high pressure and low flowrate.

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A Fractal Model for Oil Transport in Tight Porous Media

Cited by 34 publications

References 32 publications

A study of relative permeability for transient two-phase flow in a low permeability fractal porous medium

A study of relative permeability for transient two-phase flow in a low permeability fractal porous medium

A Fractal Permeability Model of Tight Oil Reservoirs Considering the Effects of Multiple Factors

Applicability Analysis of Klinkenberg Slip Theory in the Measurement of Tight Core Permeability

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