Analytical model of gas transport in heterogeneous hydraulically-fractured organic-rich shale media

Fan, Dian; Ettehadtavakkol, Amin

doi:10.1016/j.fuel.2017.06.105

Cited by 36 publications

(11 citation statements)

References 37 publications

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“…Zhang et al (2017) modeled liquid slippage in inorganic pores and liquid adsorption in organic pores and showed that the wettability difference of these two pores leads to the fact that the apparent permeability of inorganic pores can be four orders of magnitude more than that of organic pores. Differences in pore structures of inorganic versus organic matters with regards to pore size, pore size distribution, and surface roughness, also impact transport behaviors (Fan and Ettehadtavakkol 2017a). The average size of organic pores is usually at least one order of magnitude less than that of inorganic pores.…”

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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Section: Authorsmentioning

confidence: 99%

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

2020

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“…Decline curves of some tight gas wells show that linear flow can last for 20 years, and the boundary flow is directly reached without experiencing pseudo-radial flow (Wattenbarger et al 1998). Stright and Gordon (1983) also reported that the long-term production of fractured low-permeability gas wells can be Fan and Ettehadtavakkol (2017) and Kang et al (2011) 2 This is a kerogen and inorganic matrix parallel flow model without kerogeninorganic matrix inter porosity flow He et al (2016) 3 The parallel flow model ignores the kerogen and inorganic matter mass exchange. The contribution from kerogen in pure inorganic matrix blocks is ignored for the combination of series and parallel flow.…”

Section: Fracture and Reservoir Modelsmentioning

confidence: 99%

“…And the unstimulated vertical well is not suitable for shale reservoir development. Some other analytical and semi-analytical quadruple-porosity models (Sheng et al 2015;Guo et al 2015;He et al 2016;Fan and Ettehadtavakkol 2017;Zeng et al 2019b) seem to be versatile enough to deal with the predominant flow behavior of fractured shale formations. However, they also utilized the source term method or slab matrix blocks.…”

Section: Introductionmentioning

confidence: 99%

Shale gas reservoir modeling and production evaluation considering complex gas transport mechanisms and dispersed distribution of kerogen

Zeng

Liu

et al. 2020

Pet. Sci.

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Stimulated shale reservoirs consist of kerogen, inorganic matter, secondary and hydraulic fractures. The dispersed distribution of kerogen within matrices and complex gas flow mechanisms make production evaluation challenging. Here we establish an analytical method that addresses kerogen-inorganic matter gas transfer, dispersed kerogen distribution, and complex gas flow mechanisms to facilitate evaluating gas production. The matrix element is defined as a kerogen core with an exterior inorganic sphere. Unlike most previous models, we merely use boundary conditions to describe kerogen-inorganic matter gas transfer without the instantaneous kerogen gas source term. It is closer to real inter-porosity flow conditions between kerogen and inorganic matter. Knudsen diffusion, surface diffusion, adsorption/desorption, and slip corrected flow are involved in matrix gas flow. Matrix-fracture coupling is realized by using a seven-region linear flow model. The model is verified against a published model and field data. Results reveal that inorganic matrices serve as a major gas source especially at early times. Kerogen provides limited contributions to production even under a pseudo-steady state. Kerogen properties' influence starts from the late matrix-fracture inter-porosity flow regime, while inorganic matter properties control almost all flow regimes except the early-mid time fracture linear flow regime. The contribution of different linear flow regions is also documented.

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“…Unfortunately, the gas diffusion rate is relatively low in kerogen in terms of diffusion coefficient and total dissolved gas content. Fick's Second Diffusion Law [41] is usually applied to model gas diffusion in the kerogen matrix: [31], Fan et al [38] and Chong et al [39]). [31] and Chong et al [38]).…”

Section: Kerogen Diffusionmentioning

confidence: 99%

Gas Multiple Flow Mechanisms and Apparent Permeability Evaluation in Shale Reservoirs

Feng

Zhao

et al. 2019

Sustainability

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Gas flow mechanisms and apparent permeability are important factors for predicating gas production in shale reservoirs. In this study, an apparent permeability model for describing gas multiple flow mechanisms in nanopores is developed and incorporated into the COMSOL solver. In addition, a dynamic permeability equation is proposed to analyze the effects of matrix shrinkage and stress sensitivity. The results indicate that pore size enlargement increases gas seepage capacity of a shale reservoir. Compared to conventional reservoirs, the ratio of apparent permeability to Darcy permeability is higher by about 1–2 orders of magnitude in small pores (1–10 nm) and at low pressures (0–5 MPa) due to multiple flow mechanisms. Flow mechanisms mainly include surface diffusion, Knudsen diffusion, and skip flow. Its weight is affected by pore size, reservoir pressure, and temperature, especially pore size ranging from 1 nm to 5 nm and reservoir pressures below 5 MPa. The combined effects of matrix shrinkage and stress sensitivity induce nanopores closure. Therefore, permeability declines about 1 order of magnitude compare to initial apparent permeability. The results also show that permeability should be adjusted during gas production to ensure a better accuracy.

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Analytical model of gas transport in heterogeneous hydraulically-fractured organic-rich shale media

Cited by 36 publications

References 37 publications

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

Shale gas reservoir modeling and production evaluation considering complex gas transport mechanisms and dispersed distribution of kerogen

Gas Multiple Flow Mechanisms and Apparent Permeability Evaluation in Shale Reservoirs

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