The dynamic effect in capillary pressure during the displacement process in ultra-low permeability sandstone reservoirs

Li, Ying; Li, Haitao; Cai, Jianchao; Ma, Qirui; Zhang, Jianfeng

doi:10.26804/capi.2018.02.01

Cited by 14 publications

(4 citation statements)

References 20 publications

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“…Capillary pressure is an important property that can affect multiphase flow during various physical and chemical process such as petroleum recovery and CO 2 storage. [1][2][3][4] During the fluid flow process, fluid viscosity varies caused by the mixing of different kinds of fluids, which can have strong influence on the dynamic capillarity and fluid flow. 5,6 The dynamic capillarity means a dynamic effect on the capillary pressure; that is, P c -S w relationship not only depends on the fluid saturation, but also the time derivative of saturation S w ∕ t. The fluid flow behavior is correspondingly affected by the dynamic capillarity.…”

Section: Introductionmentioning

confidence: 99%

Dynamic capillarity during displacement process in fractured tight reservoirs with multiple fluid viscosities

Luo

et al. 2019

Energy Science & Engineering

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Dynamic capillarity commonly exists for multiphase flow in porous media, during which fluid viscosity varies and has strong influence. Displacement experiments are conducted on water-wet, fractured tight rock at in situ pressure and temperature of an oil reservoir via a specially designed apparatus to investigate the effects of fluid viscosity on the dynamic capillarity. The dynamic effect in the matrix is examined through the measurement and calculation of capillary pressure, the dynamic coefficient, and the fluid flow behavior. The results show that with a higher oil viscosity:(a) both the steady and the dynamic capillary pressures reverse their directions more quickly and behave as larger resistances in the matrix; (b) the difference between the steady and the dynamic capillary pressures becomes around 5%-19% more significant; (c) water saturation changes more slowly corresponding to the lower water relative permeability, while oil relative permeability quickly becomes lower than that during the basic displacement process; and (d) the dynamic coefficient becomes 2-3 times higher, and the dynamic contact angle becomes 10%-25% larger, showing a more variable interface. A contact angle advancement coefficient is proposed to identify the significance of contact angle advancement and the competition between capillary pressure and viscous force. The findings of this study can help for better understanding of multiphase flow in tight reservoirs and enhancing oil recovery.

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Section: Introductionmentioning

confidence: 99%

Dynamic capillarity during displacement process in fractured tight reservoirs with multiple fluid viscosities

Luo

et al. 2019

Energy Science & Engineering

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“…Uniform, constant water content Moreover, it has been shown that the contact angle also changes with centrifugal acceleration and depends on drainage or imbibition and on the flow rate [47][48][49]. The alteration of either the contact angle or interface shape or dynamic effect of the matric potential [50] can change the conductance of the unsaturated pore without changing the amount of water within it, thus altering K in a violation of the DB law. This is a factor to be considered in a test using centrifugal force e.g., [51].…”

Section: Experimental Testing Of the Db Lawmentioning

confidence: 99%

Does the Darcy–Buckingham Law Apply to Flow through Unsaturated Porous Rock?

Turturro

Caputo

Perkins

et al. 2020

Water

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The Darcy–Buckingham (DB) law, critical to the prediction of unsaturated flow, is widely used but has rarely been experimentally tested, and therefore may not be adequate in certain conditions. Failure of this law would imply that the unsaturated hydraulic conductivity is not constant for a given water content, as assumed in nearly all subsurface flow models. This study aims to test the DB law on unsaturated porous rock, complementing the few previous tests, all done on soils. Two lithotypes of calcareous porous rocks were tested. The quasi-steady centrifuge method was used to measure the flux density for different centrifugal driving forces while maintaining essentially constant water content, as required. Any deviations from the direct proportionality of the measured flux and the applied force would indicate a violation of the DB law. Our results show that, for the tested rocks and conditions, no physical phenomena occurred to cause a failure of the DB law.

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“…Capillary pressure plays a vital role in multiphase flow of tight sandstone (Chen et al, 1991;Landry et al, 2014;Tang et al, 2017), it is a generic term that includes dynamic capillary pressure and static capillary pressure (Das et al, 2005;Abidoye et al, 2014;Cai et al, 2014). Recent studies indicate that dynamic capillary pressure is better than static capillary pressure concept for describing transient two-phase flow under dynamic conditions (Hassanizadeh et al, 2002;Dahle et al, 2005;Niasar et al, 2010;Bottero et al, 2011;Diamantopoulos et al, 2016;Li et al, 2018c). To study the mechanism of dynamic capillary pressure, many simulation methods are used to simulate the multiphase flow behaviors in pore-scale, including smooth particle hydrodynamic methods (Tartakovsky and Meakin, 2006;Kunz et al, 2016), fluid volume method (Blunt et al, 2002;Raeini et al, 2014), and lattice Boltzmann method (LBM).…”

Section: Introductionmentioning

confidence: 99%

Dynamic capillary pressure analysis of tight sandstone based on digital rock model

et al. 2020

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In recent studies, dynamic capillary pressure has shown significant impacts on the flow behaviors in porous media under transient flow condition. However, the effect of dynamic capillary pressure effect on tight sandstone is still not very clear. Since lattice Boltzmann method (LBM) is a very promising and widely used method in analyzing flow behaviors, therefore, a two-phase D3Q27 LBM model is adopted in this paper to simulate the flow behaviors and analyze the dynamic capillary pressure effect in tight sandstone. Moreover, a new pore segmentation method for tight sandstone base on U-net deep learning model is implemented in this study to improve the pore boundary qualities of pore space, which is crucial for two-phase LBM simulation of tight sandstone. A total of 3800 3D sub-volume data sets extracted from computed tomography data of 19 tight sandstone samples are selected as ground truth data to train the network and segment the pore space afterward. The simulation results based on the segmented digital rock model, show that nonwetting phase fluid prefer the path with lower dynamic capillary pressure in the seepage process before breaking through the porous model. Furthermore, the increase of injection rate causes the saturation changes more quickly, injection rate also shows apparent positive correlation relationship with capillary pressure, which implies that dynamic capillary pressure effect also exists in tight sandstone, and LBM based two-phase flow simulation could be used to quantitatively analyze such effect in tight sandstone.

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The dynamic effect in capillary pressure during the displacement process in ultra-low permeability sandstone reservoirs

Abstract: The dynamic effect in capillary pressure during the displacement process in ultra-low permeability sandstone reservoirs.

Cited by 14 publications

References 20 publications

Dynamic capillarity during displacement process in fractured tight reservoirs with multiple fluid viscosities

Dynamic capillarity during displacement process in fractured tight reservoirs with multiple fluid viscosities

Does the Darcy–Buckingham Law Apply to Flow through Unsaturated Porous Rock?

Dynamic capillary pressure analysis of tight sandstone based on digital rock model

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