Flow Patterns of Viscoelastic Fracture Fluids in Porous Media: Influence of Pore-Throat Structures

Yu, Xiaohua; Li, Yuan; Liu, Yuquan; Yang, Yuqiu; Wu, Yining

doi:10.3390/polym11081291

Cited by 5 publications

(4 citation statements)

References 30 publications

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“…As a polymer solution, PAM fracturing fluid has a reticulated structure. When flowing through porous media at low velocity, the shear effect is weak and the intermolecular forces between polymer molecules are strong, making it difficult to destroy the reticulated structure of the polymer solution [ 28 , 29 ]. As a result, polymer molecules accumulate in the porous media and the retention of fracturing fluid increases.…”

Section: Discussionmentioning

confidence: 99%

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

et al. 2023

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Fracturing fluids are widely applied in the hydraulic fracturing of shale gas reservoirs, but the fracturing fluid flowback efficiency is typically less than 50%, severely limiting the shale gas recovery. Additionally, the mechanism and main influencing factors of fracturing fluid flowback are unclear. In this study, microscopic experiments are conducted to simulate the fracturing fluid flowback progress in shale gas reservoirs. The mechanism and factors affecting fracturing fluid flowback/retention in the fracture zone were analyzed and clarified. Results show that the ultimate flowback efficiency of fracturing fluid is positively correlated with the fracturing fluid concentration and the gas driving pressure difference. There are four kinds of mechanisms responsible for fracturing fluid retention in the pore network: viscous resistance, the Jamin effect, the gas blockage effect and the dead end of the pore. Additionally, the ultimate flowback efficiency of the fracturing fluid increases linearly with increasing capillary number. These insights will advance the fundamental understanding of fracturing fluid flowback in shale gas reservoirs and provide useful guidance for shale gas reservoirs development.

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Section: Discussionmentioning

confidence: 99%

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

et al. 2023

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“…Hydrolyzed polyacrylamide (HPAM) (partially hydrolyzed) was widely used in oilfields as fracturing fluid. , In this paper, the HPAM polymer (AM-SA-C 18 DMAAC) was synthesized by water solution copolymerization with AM, SA, and C 18 DMAAC as monomers in laboratory. The syntheses of HPAMs were referred to in the previous literature, and the molecular structure was shown in Figure .…”

Section: Materials and Methodsmentioning

confidence: 99%

Influence of Nanoparticles and Surfactants on Stability and Rheological Behavior of Polymeric Nanofluids and the Potential Applications in Fracturing Fluids

et al. 2021

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Water-based fracturing fluids are widely used in hydraulic fracturing to stimulate reservoirs. However, a novel fracturing fluid system needs to be developed for use in complex and challenging environments due to the high temperature and pressure reservoir conditions. In this study, the polymeric nanofluid hydrolyzed polyacrylamide (HPAM)/sodium dodecyl sulfate (SDS)/nanoparticles (NPs) was prepared with a polymer acrylamide (AM)-sodium acrylate (SA)-octadecyl dimethyl allyl ammonium chloride (C18DMAAC) and amino modified multiwall carbon nanotubes (CNT-NH2) by hybrid nanotechnology. It was found that this polymeric nanofluid improved the viscosity of the basic polymer solution and still exhibited excellent stability at 90 °C, and the surfactant played an important role in the dispersion of nanoparticles in polymer solution. The rheological studies showed that the synergistic effect of surfactants and nanoparticles improved the viscoelasticity and temperature and shear resistance of the polymeric nanofluids, which showed an increased modulus at 1.0 Pa, and the shear viscosity remained above 70 mPa s at 90 °C. In addition, the addition of nanoparticles altered the wettability of the reservoir rock, thus changing the distribution and flow of fluid in the reservoir. The drag reduction rate of this polymeric nanofluid was up to 60.7%, and the fluid loss coefficient decreased to 1.46 × 10–5 m/min1/2. Therefore, the polymeric nanofluids composed of surfactants, nanoparticles, and polymers hold potential applications in the oilfields to improve the hydraulic performance of fracturing operations.

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“…The multiphase flow in the tiny pore-throat units features low Reynolds and capillary numbers. Consequently, the wettability of the pore wall has a remarkable influence on the peeling-off, transportation, and morphology of crude oil in the matrix. − Thus, reservoir wettability is a crucial parameter in oil development …”

Section: Introductionmentioning

confidence: 99%

Microscale Reservoir Wettability Evaluation Based on Oil–Rock Nanomechanics

Luo

Chu

et al. 2023

Energy Fuels

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Low oil production and rapid production decline epitomize the challenges of unconventional reservoir development. Rocks in the formation with micro-/nanoscale pore-throat units possess an immense surface area. Consequently, the wettability of rocks plays a crucial role in the relative permeability of oil/water, the injection pressure, the distribution and morphology of residual oil, and hence the ultimate oil recovery. Contact angle, as a frequently used method to evaluate wettability, is susceptible to oil-water saturation, imbibition, and surface roughness of rock slices. In addition, the measurement scale (droplet of several millimeters) does not match the flow scale (pore units in micro-or nanoscale). Therefore, this paper established a new wettability evaluation method based on oil−rock interaction. Molecular dynamics simulation results demonstrated that the interaction energy between the oil molecule and walls with different wettabilities shows a distinct discrepancy. Accordingly, nanomechanics by AFM was utilized to measure the oil molecule−pore wall interaction force. It was found that the interaction force increases with the augmented hydrophobicity of the pore wall due to hydrophobic force. In addition, the reservoir rock wettability index was defined using the oil−rock interaction force in the nanoscale. The wettability index has an excellent linear correlation with the intrinsic contact angle. The wettability evaluation method based on the oil−rock interaction force is more direct, facile, and rapid and overcomes the limitation of the traditional contact angle method.

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Flow Patterns of Viscoelastic Fracture Fluids in Porous Media: Influence of Pore-Throat Structures

Cited by 5 publications

References 30 publications

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

Influence of Nanoparticles and Surfactants on Stability and Rheological Behavior of Polymeric Nanofluids and the Potential Applications in Fracturing Fluids

Microscale Reservoir Wettability Evaluation Based on Oil–Rock Nanomechanics

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