The effect of deformation on two-phase flow through proppant-packed fractured shale samples: A micro-scale experimental investigation

Arshadi, Maziar; Zolfaghari, Arsalan; Piri, Mohammad; Al-Muntasheri, Ghaithan A.; Sayed, Mohammed

doi:10.1016/j.advwatres.2017.04.022

Cited by 57 publications

(20 citation statements)

References 7 publications

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“…3a may serve as a natural analog for flow into hydraulic fractures in shale reservoirs, with the limitation that shale may have different elastic moduli, different petrophysics, grain sizes and most crucially, the fracture aperture width from hydraulic fracturing which is smaller than that in our natural analog presented here. Hydraulic fracture apertures in shale reservoirs are thought to be in the range of 1-5 mm with the majority of (Gale et al 2014;Zolfaghari et al 2016;Arshadi et al 2017). Natural fracture networks created in the rocks of Bidasar due to hydrothermal activity in the earth's crust bears similarity to man-made hydraulic fracture networks that require the use of high pressure fluids and proppants by fleets of pumps and trucks.…”

Section: Natural Examples Of Hydraulic Fracturesmentioning

confidence: 99%

Drained rock volume around hydraulic fractures in porous media: planar fractures versus fractal networks

Nandlal

Weijermars

2019

Pet. Sci.

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This study applies the Lindenmayer system based on fractal theory to generate synthetic fracture networks in hydraulically fractured wells. The applied flow model is based on complex analysis methods, which can quantify the flow near the fractures, and being gridless, is computationally faster than traditional discrete volume simulations. The representation of hydraulic fractures as fractals is a more realistic representation than planar bi-wing fractures used in most reservoir models. Fluid withdrawal from the reservoir with evenly spaced hydraulic fractures may leave dead zones between planar fractures. Complex fractal networks will drain the reservoir matrix more effectively, due to the mitigation of stagnation flow zones. The flow velocities, pressure response, and drained rock volume (DRV) are visualized for a variety of fractal fracture networks in a single-fracture treatment stage. The major advancement of this study is the improved representation of hydraulic fractures as complex fractals rather than restricting to planar fracture geometries. Our models indicate that when the complexity of hydraulic fracture networks increases, this will suppress the occurrence of dead flow zones. In order to increase the DRV and improve ultimate recovery, our flow models suggest that fracture treatment programs must find ways to create more complex fracture networks.

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Section: Natural Examples Of Hydraulic Fracturesmentioning

confidence: 99%

Drained rock volume around hydraulic fractures in porous media: planar fractures versus fractal networks

Nandlal

Weijermars

2019

Pet. Sci.

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“…The experiments show that regular flow pattern is formed between the two corrugated plates, and each specific flow pattern has a strong correlation with pressure drop. In terms of two-phase flow in hydraulic fractures, Arshadi et al (2017) used oil and brine as experimental fluids, split a natural rock into two halves, and filled in the section with proppants of different thicknesses representing hydraulic fractures propped by proppants. Subsequently, oil and brine were injected to observe the saturation distribution of the two-phase fluid within the fractures.…”

Section: Introductionmentioning

confidence: 99%

Simulation of multiphase flow pattern, effective distance and filling ratio in hydraulic fracture

Pei

Zhang

Zhou

et al. 2019

J Petrol Explor Prod Technol

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Hydraulic fracturing is a key measure to increase production and transform oil and gas reservoirs, which plays an important role in oil and gas field development. Common hydraulic fracturing is of inevitable bottlenecks such as difficulty in sand adding, sand plugging, equipment wearing and fracturing fluid damage. To solve these problems, a new type of fracturing technology, i.e., the self-propping fracturing technology is currently under development. Technically, the principle is to inject a self-propping fracturing liquid system constituting a self-propping fracturing liquid and a channel fracturing liquid into the formation. Self-propping fracturing liquid changes from liquid to solid through phase transition under the formation temperature, replacing proppants such as ceramic particles and quartz sand to achieve the purpose of propping hydraulic fractures. The flow pattern, effective distance and filling ratio of the self-propping fracturing liquid system in the hydraulic fracture are greatly affected by the parameters such as the fluid leak-off rate, surface tension and injection velocity. In this paper, a set of mathematical models for the flow distribution of self-propping fracturing liquid system considering fluid leakoff was established to simulate the flow pattern, effective distance, as well as filling ratio under different leak-off rates, surface tensions and injection velocities. The mathematical model was verified by physical experiments, proving that the mathematical model established herein could simulate the flow of self-propping fracturing liquid systems in hydraulic fractures. In the meantime, these results have positive impacts on the research of interface distribution of liquid-liquid two-phase flow.

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“…Experiments using transparent epoxy replicas and analog materials have provided the opportunity to study various aspects of flow through individual fractures that are relevant to gravity‐driven wetting front and infiltration instability (Nicholl et al, ), water film flow and fracture surface transmissivities (Tokunaga & Wan, ), preferential flow paths (Brown et al, ), nonwetting phase trapping (Pyrak‐Nolte et al, ), entrapped phase dissolution (Glass et al, ), displacement of water by air (Amundsen et al, ; Neuweiler et al, ), and the effect of changes in surface wettability on two‐phase saturated flow (Bergslien & Fountain, ). In the last few decades, X‐ray computed tomography (CT) imaging techniques have been utilized to map three‐dimensional internal structure of fractures and saturating fluids in actual fractured rock samples while assuming impermeable rock matrix (Alvarado et al, ; Arshadi et al, ; Bertels et al, ; Karpyn et al, ). In these experiments, it has been observed that fracture aperture geometry, initial saturation conditions, and wettability are the key factors that control snap‐off and trapping of the nonwetting fluid, formation of preferential flow paths, and fluid distribution in the fractures (Karpyn et al, ).…”

Section: Introductionmentioning

confidence: 99%

Pore‐Scale Experimental Investigation of Two‐Phase Flow Through Fractured Porous Media

Arshadi

Khishvand

Aghaei

et al. 2018

Water Resources Research

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We present the results of a systematic pore-scale experimental investigation of two-phase oil/brine flow through a miniature water-wet, fractured sandstone core sample. X-ray microtomography is employed to generate three-dimensional fluid occupancy maps within a rough-walled fracture and its neighboring rock matrix during drainage and imbibition flow experiments. Several different imbibition flow conditions were created by changing brine flow rate, fracture aperture field, and interfacial tension between the fluids. These maps along with steady-state pressure drop data are then used to shed light on the dominant flow mechanisms and preferential flow paths through the matrix and fracture domains as well as fluid transfer between them during the imbibition processes. Depending on the fracture aperture properties and the magnitude of the local capillary pressures that are established under varying flow conditions, transport of the wetting phase across the hybrid matrix-fracture medium is governed by flow through wetting layers of brine on fracture walls (fracture layer flow), center of the fracture (fracture bulk flow), and brine-filled pores within the matrix. The hydraulic conductivity through these conduits is regulated by the medium as it identifies a combined flow path with minimum pressure drop from the inlet to the outlet of the system. The resulting balance determines the magnitude of fluid transfer experienced by the neighboring matrix and ultimate oil recovery as a result.

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The effect of deformation on two-phase flow through proppant-packed fractured shale samples: A micro-scale experimental investigation

Cited by 57 publications

References 7 publications

Drained rock volume around hydraulic fractures in porous media: planar fractures versus fractal networks

Drained rock volume around hydraulic fractures in porous media: planar fractures versus fractal networks

Simulation of multiphase flow pattern, effective distance and filling ratio in hydraulic fracture

Pore‐Scale Experimental Investigation of Two‐Phase Flow Through Fractured Porous Media

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