Flow simulation considering adsorption boundary layer based on digital rock and finite element method

Yang, Yong; Wang, Ke; Lv, Qian; Askari, Roohollah; Mei, Qing Yan; Ye, Jun; Hou, Jie Xin; Zhang, Kai; Li, Ai Fen; Wang, Chen Chen

doi:10.1007/s12182-020-00476-4

Cited by 22 publications

(12 citation statements)

References 54 publications

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“…32,33 The second one is the boundary layer, which is the liquid adsorption layer on the rock particles surface due to the interface interaction between the solid and the liquid in micronano-scale pores. 34,35 The starting resistance of fluid near the boundary layer is greater than that in the bulk fluid; in addition, the presence of a boundary layer on the solid surface makes the pore throat radius smaller. The thickness of the boundary layer is related to many factors, such as fluid properties, pore throat size, displacement pressure gradient, and so on.…”

Section: Analysis Of Various Effect Factors On the Seepagementioning

confidence: 99%

“…With the decrease in permeability, the average pore throat radius decreases, resulting in an increase in the threshold pressure gradient, and a high displacement pressure is required to allow the fluids to flow. The main pore throat radius distributes at 0.2−0.6 μm for the core permeabilities of 0.34 × 10 −3 and 0.67 × 10 −3 μm 2 , less than 1.0 × 10 −3 μm 2 , but distributes at 0.4−1.1 μm for the core permeabilities of 1.02 × 10 −3 and 2.23 Based on the characteristics and seepage law of fluid in extralow-permeability reservoirs, the nonlinear flow model considering the threshold pressure gradient is established as 35 i k j j j j j y…”

Section: Analysis Of Various Effect Factors On the Seepagementioning

confidence: 99%

“…The threshold pressure gradient becomes very large when the pore throat radius decreases, and the flow of the fluid becomes more difficult. The threshold pressure gradient decreases rapidly with the increase of pore throat radius, and gradually approaches a certain value in the pores with a large pore throat radius. , The second one is the boundary layer, which is the liquid adsorption layer on the rock particles surface due to the interface interaction between the solid and the liquid in micro-nano-scale pores. , The starting resistance of fluid near the boundary layer is greater than that in the bulk fluid; in addition, the presence of a boundary layer on the solid surface makes the pore throat radius smaller. The thickness of the boundary layer is related to many factors, such as fluid properties, pore throat size, displacement pressure gradient, and so on…”

Section: Analysis Of Various Effect Factors On the Seepagementioning

confidence: 99%

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Effect of Displacement Pressure on Oil–Water Relative Permeability for Extra-Low-Permeability Reservoirs

Liu

et al. 2021

ACS Omega

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The oil−water relative permeability is an important parameter to characterize the seepage law of fluid in extra-lowpermeability reservoirs, and it is of vital significance for the prediction and evaluation of the production. The pore throat size of extra-low-permeability reservoirs is relatively small, and the threshold pressure gradient and capillary pressure cannot be negligible. In this study, the oil−water relative permeability experiments with three different displacement pressures were carried out on the same core from the extra-low-permeability reservoir of Chang 4+5 formation in Ordos basin by the unsteady experimental method. The results show that the relative permeability of oil increases, while the relative permeability of water remains unchanged considering the capillary pressure and oil threshold pressure gradient compared with the JBN method. As the displacement pressure enlarges, the relative permeability of oil and water both increases; the residual oil saturation decreases, therefore the range of the two-phase flow zone is improved. Moreover, the isotonic point of water−oil relative permeability curves moves to the upper right region, and the reference permeability improves as well with the increasing pressure.

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Section: Analysis Of Various Effect Factors On the Seepagementioning

confidence: 99%

Section: Analysis Of Various Effect Factors On the Seepagementioning

confidence: 99%

Section: Analysis Of Various Effect Factors On the Seepagementioning

confidence: 99%

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Effect of Displacement Pressure on Oil–Water Relative Permeability for Extra-Low-Permeability Reservoirs

Liu

et al. 2021

ACS Omega

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“…Porosity and permeability are two major parameters for evaluating reservoir quality, and there is usually a good linear correlation between them [1][2][3][4]. However, in unconventional reservoirs (such as tight sandstone reservoir, shale reservoir, tight limestone, and volcanic reservoir), the correlation between porosity and permeability is not as close as that in conventional reservoirs [5][6][7].…”

Section: Introductionmentioning

confidence: 99%

Characteristics of Pore-Throat in Tight Sandstones of the Jurassic Ahe Formation in the Northern Tarim Basin

et al. 2022

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In order to clarify the characteristics of pore-throat in tight sandstone reservoirs in the Dibei area of the Kuqa Depression in the Tarim Basin (Northwest China) and to make clear its impact on reservoir quality and productivity, microscopic observation and quantitative analysis of 310 tight sandstones in the Kuqa Depression are carried out by using various methods. Microscopic observation shows that the shapes of the pores are flat, oval, and long-narrow. A great number of throats connect the nanoscale pores in the form of a network. Quantitative analyses including RCMP (rate-controlled mercury penetration), HPMI (high-pressure mercury injection), NA (nitrogen adsorption), and routine and stress-dependent core analysis show that the peak of pores radius ranges from 125 μm to 150 μm, and the throat radius is in the range of 1 μm-4 μm. The throat space accounts for about 2/3 of the total space of the tight sandstones, which is the major storage space for natural gas. The space shape has a great influence on the reservoir seepage capacity, particularly under the condition of overburden pressure. The pores with throat radius greater than 300 nm have free fluid, and they contribute more than 98% of the reservoir permeability. The pore spaces with throat radius among 300 nm-52 nm can release fluids by reservoir stimulation. The pore-throats with radius < 52 nm cannot release the irreducible hydrocarbon fluids. In addition, formation pressure is easy to destroy tight sandstone reservoir. The research results will provide insights into the efficient recovery of natural gas in tight sandstones.

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“…Compared with medium-or high-permeability media, the fluid flow in tight media shows obvious non-Darcy flow (NDF) behaviors [33,34], which is the flow velocity of fluid being not linearly dependent on the charging pressure gradient. Some researchers [35][36][37] proposed that these NDF behaviors were attributed to the existence of the boundary layer (BL) of water attached to the pore surface where the viscosity is much larger than the fluid in the pore center. The BL with different thicknesses in pores significantly reduces the effective seepage radius, which results in the NDF behaviors in tight media.…”

Section: Introductionmentioning

confidence: 99%

Investigating the Influences of Pore-Scale Characteristics on Tight Oil Migration by a Two-Phase Pore Network Model

Zeng

Ma²,

Liu

et al. 2020

Geofluids

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The migration of expelled hydrocarbon from source rock into unconventional tight reservoirs is subject to different pore-scale fluid transport mechanisms as opposed to the conventional counterparts and therefore plays a crucial role in controlling the hydrocarbon distribution and accumulation in the former. One of the different mechanisms is related to the formation of a more viscous boundary layer (BL) of brine, i.e., wetting phase fluid on pore surfaces, giving rise to the so-called BL effect. In this work, a two-phase pore network model (PNM) that considers this BL effect is developed to study the influences of pore-scale characteristics on the oil migration process, manifested through the BL effect in tight-sandstone media. Good agreements are reached between experimentally derived relative permeability curves and predicted ones, by applying this model to the pore-network networks extracted from the same samples. Then, this validated model was used to evaluate the impacts of the following factors on the oil migration process: pore radius, coordination number, aspect ratio, brine viscosity, and wettability. The results show that all factors can influence the oil migration process but at different magnitudes. The applicability and significance of the developed tight oil migration PNM are discussed in this work.

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Flow simulation considering adsorption boundary layer based on digital rock and finite element method

Cited by 22 publications

References 54 publications

Effect of Displacement Pressure on Oil–Water Relative Permeability for Extra-Low-Permeability Reservoirs

Effect of Displacement Pressure on Oil–Water Relative Permeability for Extra-Low-Permeability Reservoirs

Characteristics of Pore-Throat in Tight Sandstones of the Jurassic Ahe Formation in the Northern Tarim Basin

Investigating the Influences of Pore-Scale Characteristics on Tight Oil Migration by a Two-Phase Pore Network Model

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