Apparent permeability model for shale oil with multiple mechanisms

Feng, Qihong; Xu, Shiqian; Wang, Sen; Yuyao, Li; Gao, Fangfang; Xu, Yajuan

doi:10.1016/j.petrol.2019.01.038

Cited by 36 publications

(19 citation statements)

References 50 publications

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“…The new semi-analytical method is demonstrated to provide an accu- nanopores can be categorized into digital cores simulation, experimental or molecular dynamic simulation, and formula derivation. 55 However, most of these studies are performed for single-phase water or oil flow in organic and inorganic nanopores, and scarce research has been done on the two-phase transport with the multiple mechanisms considered. This study, as a preliminary attempt, is based on the formula derivation of apparent two-phase permeability.…”

Section: Discussion and Recommendationsmentioning

confidence: 99%

Semianalytical method of two‐phase liquid transport in shale reservoirs and its application in fracture characterization

Zhang

Emami-Meybodi

2021

AIChE Journal

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This study presents a new semi-analytical method to simulate the two-phase liquid transport in hydraulic fractures (HF) and matrix system, which can be applied to characterize HF attributes and dynamics using the flowback data from hydraulically fractured shale oil wells. The proposed approach includes a fracture model for HF properties calculation and a matrix model capable of considering multiple liquid transport mechanisms in shale nanopores. The proposed method is first validated with the numerical simulation then applied to a field example in Eagle Ford shale. The numerical validation confirms that our method can accurately characterize fracture attributes and closure dynamics by closely estimating the initial fracture permeability, pore-volume, compressibility, and permeability modulus. Furthermore, the analysis results from numerical simulation and a field example both indicate a clear flow enhancement and deficit for oil and water transport, respectively, due to the slippage effect and variation of fluid properties inside nanopores.

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Section: Discussion and Recommendationsmentioning

confidence: 99%

Semianalytical method of two‐phase liquid transport in shale reservoirs and its application in fracture characterization

Zhang

Emami-Meybodi

2021

AIChE Journal

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“…Experimental study of oil and brine transport in mixedwet limestones shows that the wetting phase can slip in mixed-wet rock, and that the slip length increases with a decreasing pore size (Christensen and Tanino 2017). Recent studies attempted to model the apparent liquid permeability of shale rocks by applying the aforementioned flow enhancement models (Cui 2019;Cui et al 2017;Fan et al 2019a;Feng et al 2019;Wang et al 2019a;Wang and Cheng 2019;Yang et al 2019;Zhang et al 2017). Cui et al (2017) studied liquid slippage and adsorption in hydrophobic organic pores of shales and highlighted the importance of the adsorption layer for oil flow in organic pores of size 500 nm.…”

Section: Authorsmentioning

confidence: 99%

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

2020

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Apparent liquid permeability (ALP) in ultra-confined permeable media is primarily governed by the pore confinement and fluid–rock interactions. A new ALP model is required to predict the interactive effect of the above two on the flow in mixed-wet, heterogeneous nanoporous media. This study derives an ALP model and integrates the compiled results from molecular dynamics (MD) simulations, scanning electron microscopy, atomic force microscopy, and mercury injection capillary pressure. The ALP model assumes viscous forces, capillary forces, and liquid slippage in tortuous, rough pore throats. Predictions of the slippage of water and octane are validated against MD data reported in the literature. In up-scaling the proposed liquid transport model to the representative-elementary-volume scale, we integrate the geological fractals of the shale rock samples including their pore size distribution, pore throat tortuosity, and pore-surface roughness. Sensitivity results for the ALP indicate that when the pore size is below 100 nm pore confinement allows oil to slip in both hydrophobic and hydrophilic pores, yet it also restricts the ALP due to the restricted intrinsic permeability. The ALP reduces to the well-established Carman–Kozeny equation for no-slip viscous flow in a bundle of capillaries, which reveals a distinguishable liquid flow behavior in shales versus conventional rocks. Compared to the Klinkenberg equation, the proposed ALP model reveals an important insight into the similarities and differences between liquid versus gas flow in shales.

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“…Advances in hydraulic fracturing and horizontal drilling technologies have sparked a surge of interest in exploring and exploiting shale oil (Honarpour et al 2012;Hou et al 2016;Zheng and Sharma 2020). Permeability, the most critical property for evaluating the capability of oil flow in shale strata, is essential for the development of shale oil reservoirs (Feng et al 2019). However, precisely determining oil permeability is challenging, largely due to the shale's various components, their multi-scale pore structure and the special flow mechanisms defying Darcy's law (Tahmasebi et al 2015a;Zheng et al 2021).…”

Section: Introductionmentioning

confidence: 99%

“…They modeled the OM with squares randomly dispersed in inorganic matrix for the first time. Followed by Cao et al (2017), Xu et al (2019) and Feng et al (2019) extended the 2D model to 3D, and the OM shape was correspondingly extended to block. However, these models did not distinguish the various minerals in iOM.…”

Section: Introductionmentioning

confidence: 99%

Stochastic-based liquid apparent permeability model of shale oil reservoir considering geological control

Wang

Ma³

et al. 2021

J Petrol Explor Prod Technol

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Shale is a complex porous medium composed of organic matter (OM) and inorganic minerals (iOM). Because of its widespread nanopores, using Darcy’s law is challenging. In this work, a two-fluid system model is established to calculate the oil flow rate in a single nanopore. Then, a spatial distribution model of shale components is constructed with a modified quartet structure generation set algorithm. The stochastic apparent permeability (AP) model of shale oil is finally established by combining the two models. The proposed model can consider the effects of various geological controls: the content and grain size distribution of shale components, pore size distribution, pore types and nanoconfined effects (slip length and spatially varying viscosity). The results show that slip length in OM nanopores is far greater than that in iOM. However, when the total organic content is less than 0.3 ~ 0.4, the effect of the OM slip on AP increases first and then decreases with the decrease in mean pore size, resulting in that the flow enhancement in shale is much smaller than that in a single nanopore. The porosity distribution and grain size distribution are also key factors affecting AP. If we ignore the difference of porosity between shale components, the error of permeability estimation is more than 200%. Similarly, the relative error can reach 20% if the effect of grain size distribution is ignored. Our model can help understand oil transport in shale strata and provide parameter characterization for numerical simulation.

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Apparent permeability model for shale oil with multiple mechanisms

Cited by 36 publications

References 50 publications

Semianalytical method of two‐phase liquid transport in shale reservoirs and its application in fracture characterization

Semianalytical method of two‐phase liquid transport in shale reservoirs and its application in fracture characterization

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

Stochastic-based liquid apparent permeability model of shale oil reservoir considering geological control

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