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. 2023 Mar 21;15(6):1560.
doi: 10.3390/polym15061560.

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

Guodong Zou  1 , Bin Pan  1 , Weiyao Zhu  1 , Yuwei Liu  1 , Shou Ma  2 , Mingming Liu  2
Affiliations

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

Guodong Zou et al. Polymers (Basel). .

Abstract

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.

Keywords: fracturing fluid flowback; hydraulic fracture; microscopic model; polyacrylamide; shale gas.

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Conflict of interest statement

The authors declare no conflict of interest.

Figures

Figure 1
Figure 1
The molecular structure characteristics of polyacrylamide polymer.
Figure 2
Figure 2
The structural characteristics of AMPS-AM.
Figure 3
Figure 3
The contact angles of fracturing fluid-nitrogen and glass surface: (a) 0.1 wt% fracturing fluid; (b) 0.8 wt% fracturing fluid; (c) 1.2 wt% fracturing fluid.
Figure 4
Figure 4
Schematic diagram of the microscopic model.
Figure 5
Figure 5
Schematic diagram of experiment.
Figure 6
Figure 6
The fracturing fluid (0.1 wt%) flowback process images and binary images (a) 0.1 MPa gas drive, (b) 0.2 MPa gas drive, (c) 0.3 MPa gas drive.
Figure 6
Figure 6
The fracturing fluid (0.1 wt%) flowback process images and binary images (a) 0.1 MPa gas drive, (b) 0.2 MPa gas drive, (c) 0.3 MPa gas drive.
Figure 7
Figure 7
Relationship between time and flowback efficiency of fracturing fluid (0.1 wt%).
Figure 8
Figure 8
The fracturing fluid (0.8 wt%) flowback process images and binary images (a) 0.1 MPa gas drive, (b) 0.2 MPa gas drive, (c) 0.3 MPa gas drive.
Figure 8
Figure 8
The fracturing fluid (0.8 wt%) flowback process images and binary images (a) 0.1 MPa gas drive, (b) 0.2 MPa gas drive, (c) 0.3 MPa gas drive.
Figure 9
Figure 9
Relationship between time and flowback efficiency of fracturing fluid (0.8 wt%).
Figure 10
Figure 10
The fracturing fluid (1.2 wt%) flowback process images and binary images (a) 0.3 MPa gas drive, (b) 0.4 MPa gas drive, (c) 0.5 MPa gas drive.
Figure 10
Figure 10
The fracturing fluid (1.2 wt%) flowback process images and binary images (a) 0.3 MPa gas drive, (b) 0.4 MPa gas drive, (c) 0.5 MPa gas drive.
Figure 11
Figure 11
Relationship between time and flowback efficiency of fracturing fluid (1.2 wt%).
Figure 12
Figure 12
Four kinds of fracturing fluid retention in the microscopic model, fracturing fluid is in the light area, nitrogen is in the dark area and the residual fracturing fluid is marked by the yellow dashed box. (a) the viscous retention, (b) the Jamin effect, (c) the gas blockage effect, (d) the dead end of the pore.
Figure 13
Figure 13
Binary images of the residual fracturing fluid (1.2 wt%) after flowback (a) 0.3 MPa gas drive, (b) 0.4 MPa gas drive, (c) 0.5 MPa gas drive.
Figure 14
Figure 14
cryo-SEM images of fracturing fluid (a) 0.1 wt%, (b) 0.8 wt%, (c) 1.2 wt%.
Figure 15
Figure 15
Binary images of the residual fracturing fluid after 0.3 MPa gas drive (a) 0.1 wt%, (b) 0.8 wt%, (c) 1.2 wt%.
Figure 16
Figure 16
The ultimate flowback efficiencies for nine experimental groups.
Figure 17
Figure 17
Relationship between the ultimate flowback efficiency of fracturing fluid and capillary number.
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