Numerical Modeling of Gas and Water Flow in Shale Gas Formations with a Focus on the Fate of Hydraulic Fracturing Fluid

Edwards, Ryan W.J.; Doster, Florian; Celia, Michael A.; Bandilla, Karl W.

doi:10.1021/acs.est.7b03270

Cited by 36 publications

(20 citation statements)

References 92 publications

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“…Multiphase flow in rock fractures is relevant to many subsurface engineering applications including geological carbon sequestration (Teng & Zhang, 2018;Ulven et al, 2014), enhanced oil/gas recovery (Lake, 1989;Morrow & Mason, 2001), and hydraulic fracturing (Song et al, 2019). For such flow of multiple immiscible fluids, fluid-fluid interface instability is a key factor that affects the CO 2 storage capacity, the oil recovery efficiency, and the flow-back (and the disappearance) of fracturing fluids (Edwards et al, 2017). This instability is a classic problem and has been long studied since Hele-Shaw's work over a century ago (Hele-Shaw, 1898).…”

Section: Introductionmentioning

confidence: 99%

Roughness Control on Multiphase Flow in Rock Fractures

Zhou

et al. 2019

Geophysical Research Letters

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The roughness of rock fractures induces irregular flow passages and significantly affects the displacement front. Previous studies focus on displacement instabilities in porous media, but how roughness controls displacement patterns in rock fractures remains unclear. Here, we derive a theoretical model that describes the two transitions of drainage displacement patterns from capillary fingering to the crossover to viscous fingering as functions of roughness. The phase diagram predicted by this model exhibits excellent agreement with our experimental results, showing that increasing roughness index λb destabilizes displacement fronts. We further find that in capillary fingering regime the percentage of dissipated energy to the total external work increases from 39% to 61% as λb increases from 0.082 to 0.245. Our work elucidates the mechanism of roughness control on multiphase flow in fractures and provides a basis for developing a rigorous upscaling methodology that relates Darcy‐scale flow behavior to the local fluid displacements via energy dissipation.

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Section: Introductionmentioning

confidence: 99%

Roughness Control on Multiphase Flow in Rock Fractures

Zhou

et al. 2019

Geophysical Research Letters

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“…The presence of low-permeability overburden rocks [4,18], production from the horizontal well [11,13,17], fracturing fluid imbibition into the shale reservoir [19,20], and mixing or other dilution processes during the transport [17,21] limit the vertical extent of fracturing fluid, thus reducing the contamination threat to shallow groundwater. Osborn et al [22] analyzed water samples from water wells in aquifers overlying northeastern Pennsylvania (active HF region) and New York (HF is currently not allowed).…”

Section: Introductionmentioning

confidence: 99%

Nonlinear Autoregressive Neural Networks to Predict Hydraulic Fracturing Fluid Leakage into Shallow Groundwater

Taherdangkoo

Tatomir

Taherdangkoo

et al. 2020

Water

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Hydraulic fracturing of horizontal wells is an essential technology for the exploitation of unconventional resources, but led to environmental concerns. Fracturing fluid upward migration from deep gas reservoirs along abandoned wells may pose contamination threats to shallow groundwater. This study describes the novel application of a nonlinear autoregressive (NAR) neural network to estimate fracturing fluid flow rate to shallow aquifers in the presence of an abandoned well. The NAR network is trained using the Levenberg–Marquardt (LM) and Bayesian Regularization (BR) algorithms and the results were compared to identify the optimal network architecture. For NAR-LM model, the coefficient of determination (R2) between measured and predicted values is 0.923 and the mean squared error (MSE) is 4.2 × 10−4, and the values of R2 = 0.944 and MSE = 2.4 × 10−4 were obtained for the NAR-BR model. The results indicate the robustness and compatibility of NAR-LM and NAR-BR models in predicting fracturing fluid flow rate to shallow aquifers. This study shows that NAR neural networks can be useful and hold considerable potential for assessing the groundwater impacts of unconventional gas development.

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“…The flow of two or more fluids in fractured media is an important process involved in many industrial and environmental applications in the subsurface with examples spanning from contaminant transport to petroleum recovery and from geological storage of CO 2 to geothermal energy exploitation. In unconventional reservoirs, two‐phase flow in hydraulic fractures plays a key role in the recovery of gas and the flow‐back (and the disappearance) of fracturing fluids (Edwards et al, ). In groundwater formations, fractured rocks contaminated by nonaqueous phase liquids have been identified as the most difficult category of sites for remediation and management (NRC, ).…”

Section: Introductionmentioning

confidence: 99%

Modeling Immiscible Two‐Phase Flow in Rough Fractures From Capillary to Viscous Fingering

Yang

Méheust

Neuweiler

et al. 2019

Water Resources Research

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We develop an efficient computational model for simulating fluid invasion patterns emerging in variable aperture fractures. This two‐dimensional model takes into account the effect of capillary force on the fluid‐fluid interfaces and viscous pressure drop in both fluid phases. The pressure distribution is solved at each time step based on mass balance and local cubic law, considering an imposed pressure jump condition at the fluid‐fluid interface. This pressure jump corresponds to the Laplace pressure which includes both terms related to the out‐of‐plane (aperture‐spanning) curvature and to the in‐plane curvature. Simulating a configuration that emulates viscous fingering in two‐dimensional random porous media confirms that the model accounts properly for the role of viscous forces. Furthermore, direct comparison with previously obtained experimental results shows that the model reproduces the observed drainage patterns in a rough fracture reasonably well. The evolutions of tip location, the inlet pressures, and the invading phase fractal dimensions are analyzed to characterize the transition from capillary fingering to viscous fingering regimes. A radial injection scenario of immiscible invasion is also studied with varying modified capillary number and viscosity ratio, showing displacement patterns ranging from capillary fingering to viscous fingering to stable displacement. Such simulations using two contact angles show that the invading phase becomes more compact when the wetting condition changes from strong to weak drainage, as already observed in 2‐D porous media. The model can be used to bridge the gap in spatial scales of two‐phase flow between pore‐scale modeling approaches and the continuum Darcy‐scale models.

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Numerical Modeling of Gas and Water Flow in Shale Gas Formations with a Focus on the Fate of Hydraulic Fracturing Fluid

Cited by 36 publications

References 92 publications

Roughness Control on Multiphase Flow in Rock Fractures

Roughness Control on Multiphase Flow in Rock Fractures

Nonlinear Autoregressive Neural Networks to Predict Hydraulic Fracturing Fluid Leakage into Shallow Groundwater

Modeling Immiscible Two‐Phase Flow in Rough Fractures From Capillary to Viscous Fingering

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