A proppant mechanical model in postfrac flowback treatment

Hu, Jinghong; Zhao, Jinzhou; Li, Yongming

doi:10.1016/j.jngse.2014.06.005

Cited by 20 publications

(9 citation statements)

References 4 publications

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“…Proppant flowback has various negative implications, including narrowing the fracture’s diameter, lowering the fracture’s conductivity, and decreasing the treatment’s effectiveness . Furthermore, proppants discharged into the well will erode downhole equipment and surface pipelines and equipment, reducing their service lifetime …”

Section: Introductionmentioning

confidence: 99%

“…21 Furthermore, proppants discharged into the well will erode downhole equipment and surface pipelines and equipment, reducing their service lifetime. 22 In hydraulic fracking, controlling proppant flowback has always been an issue. In the 1980s, Pope et al introduced the curable resin-coated proppant (RCP) to the oil industry for the first time.…”

Section: Introductionmentioning

confidence: 99%

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A Multiwalled Carbon Nanotube-Based Polyurethane Nanocomposite-Coated Sand/Proppant for Improved Mechanical Strength and Flowback Control in Hydraulic Fracturing Applications

et al. 2021

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A novel resin-based nanocomposite-coated sand proppant is introduced to address the issue of proppant flowback in post-fracturing fluid flowback treatments and hydrocarbon production. Self-aggregation in the water environment is the most attractive aspect of these developed proppants. In this work, sand was sieve-coated with 0.1% multiwalled carbon nanotubes (MWCNTs) followed by optimized thin and uniform resin (polyurethane) spray coating in the concentration range of 2 to 10%. Quantitative and qualitative evaluations have been carried out to assess the self-aggregation capabilities of the proposed sand proppants where no flowback was witnessed at 4% polyurethane coating containing 0.1% MWCNTs. This applied resin incorporating MWCNT coating was characterized by field emission scanning electron microscopy, and energy-dispersive X-ray spectroscopy depicted the dispersed presence of MWCNTs into polyurethane resin corroborated by the presence of 38% elemental carbon on the sand substrate. Proppant crushing resistance tests were conducted, including proppant pack stress−strain response, compaction, and fines production. It was found that the proposed sand proppant decreased the proppant pack compaction by ∼25% compared to commonly used silica sand with the ability to withstand high closure stress as high as 55 MPa with less than 10 wt % fines production. The surface wettability was determined by the sessile drop method. The application of resin incorporating MWCNT coating layers changed the sand proppant wetting behavior to oil-wet with a contact angle of ∼124°. Thermogravimetric analyses revealed a significant increment in thermal stability, which reached up to 280 °C due to the addition of MWCNTs as reinforcing nanofillers.

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Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

A Multiwalled Carbon Nanotube-Based Polyurethane Nanocomposite-Coated Sand/Proppant for Improved Mechanical Strength and Flowback Control in Hydraulic Fracturing Applications

et al. 2021

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“…From the perspective of the pore fracture structure, the larger the size of the flow channel, the shallower the invasion depth of the aqueous phase. Therefore, the aqueous phase flowback capacity in a relatively high permeability porous medium is obviously stronger than that with a relatively low permeability one. , The fracturing fluid first enters the formation through fractures. Then, the filtrate enters the matrix under capillary force, and its retention will also seriously reduce the gas transport ability in fractures. , In addition, compared with conventional oil and gas reservoirs, shale gas reservoirs are rich in organic matter, which has a significant influence on the wettability of the pore surface.…”

Section: Introductionmentioning

confidence: 99%

“…Therefore, the aqueous phase flowback capacity in a relatively high permeability porous medium is obviously stronger than that with a relatively low permeability one. 36,37 The fracturing fluid first enters the formation through fractures. Then, the filtrate enters the matrix under capillary force, and its retention will also seriously reduce the gas transport ability in fractures.…”

Section: Introductionmentioning

confidence: 99%

Impact of Aqueous Phase Trapping on Mass Transfer in Shales with Multiscale Channels

et al. 2020

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Large amounts of fracturing fluid retained in a shale reservoir could not only restrict gas production through aqueous phase trapping (APT) but also cause potential contamination of groundwater. In this work, experiments modeling in situ aqueous imbibition and flowback were conducted to quantitatively investigate the APT behavior in shales, including matrix, natural fracture, and artificial fracture. Results show that the forward imbibition process is slower than the reverse imbibition process. The aqueous phase tends to be imbibed through parallel bedding. Permeability reduction rates of matrix, natural fracture, and artificial fracture cores after imbibition could reach 100, 85, and 70%, respectively. Meanwhile, it is demonstrated that the aqueous flowback efficiency depends upon flowback timing, pressure difference, initial permeability, and bedding direction. The flowback efficiencies of matrix, natural fracture, and artificial fracture cores could be less than 7%, less than 30%, and less than 15%, respectively. Additionally, the permeability recovery rates of those could be less than 19%, less than 39%, and less than 67%, respectively. Finally, shale APT mechanisms are analyzed from both geological and engineering aspects. The quantitative investigation of shale APT is conducive to economically and environmentally developing shale gas reservoirs.

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“…The three requirements for proppant flowback were motion initiation, motion maintenance, and infinite conductivity along the return path, and gravity played a very important role on proppant flowback. Hu et al [15] established a proppant mechanical model to predict critical flowback velocity. They concluded that adopting a lower velocity before the fracture closes and a higher velocity after the fracture closes helps to discharge fracturing fluid in time and effectively prevent proppant flowback.…”

Section: Introductionmentioning

confidence: 99%

DEM-CFD Modeling of Proppant Pillar Deformation and Stability during the Fracturing Fluid Flowback

et al. 2018

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In this study, proppant pillar deformation and stability during the fracturing fluid flowback of channel fracturing was simulated with DEM-CFD-(discrete element method-computational fluid dynamics-) coupling method. Fibers were modeled by implementing the bonded particle model for contacts between particles. In the hydraulic fracture-closing period, the height of the proppant pillar decreases gradually and the diameter increases as the closing stress increases. In the fracturing fluid flowback period, proppant particles could be driven away from the pillar by the fluid flow and cause the instability of the proppant pillar. The proppant flowback could occur easily with large proppant pillar height or a large fluid pressure gradient. Both the pillar height and the pillar diameter to spacing ratio are key parameters for the design of channel fracturing. Increasing the fiberbonding strength could enhance the stability of the proppant pillar.

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A proppant mechanical model in postfrac flowback treatment

Cited by 20 publications

References 4 publications

A Multiwalled Carbon Nanotube-Based Polyurethane Nanocomposite-Coated Sand/Proppant for Improved Mechanical Strength and Flowback Control in Hydraulic Fracturing Applications

A Multiwalled Carbon Nanotube-Based Polyurethane Nanocomposite-Coated Sand/Proppant for Improved Mechanical Strength and Flowback Control in Hydraulic Fracturing Applications

Impact of Aqueous Phase Trapping on Mass Transfer in Shales with Multiscale Channels

DEM-CFD Modeling of Proppant Pillar Deformation and Stability during the Fracturing Fluid Flowback

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