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Volume 115
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Transport mechanism of proppants in complex fracture networks based on multiphase particle-in-cell method
Qiang Wang a 1, Yufeng Wang a 1 *, Jinzhou Zhao a, Hai Liu b, Hao Gao c d, Yuchao Zhou a, Yongquan Hu a
a State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, China
b No. 11 Oil Production Plant, Changqing Oilfield Company, Qinyang, China
c Oil and Gas Technology Research Institute, PetroChina Changqing Oilfield Company, Xi'an, China
d National Engineering Laboratory for Exploration and Development of Low Permeability Oil & Gas Fields, Xi'an, China
10.1016/j.partic.2026.05.021
Volume 115, August 2026, Pages 277-291
Received 2 March 2026, Revised 19 May 2026, Accepted 29 May 2026, Available online 6 June 2026, Version of Record 12 June 2026.
E-mail: 202515000006@stu.swpu.edu.cn
Highlights

• MP-PIC model couples realistic shale geometries for complex fracture networks.

• Early-stage vortexes and high injection rates aggravate placement heterogeneity.

• Dual proppant transport mechanisms emerge across Main and Secondary fractures.

• Proppant volume decays distally; large intersection angles hinder migration.

• Reducing proppant density/size and elevating viscosity enhance sweep efficiency.


Abstract

To improve understanding of proppant transport mechanisms in complex fracture networks, a field-scale model based on the Multiphase Particle-in-Cell (MP-PIC) method was developed using fracture geometries derived from real shale outcrops and validated against experimental data. Results indicate that: (1) intense vortex formation during early-to-mid injection stages or at high flow rates exacerbates the longitudinal heterogeneity of proppant distribution. (2) In the near-wellbore zone, the synergistic effects of fracture width variations, high flow velocities, and natural weak planes drive proppants to migrate preferentially along paths aligned with the maximum and minimum principal stress directions, forming a dual-channel transport pattern. (3) The volume of proppant entering secondary fractures decreases with distance from the injection point, and the proppant dune height within dominant channels exhibits stepwise attenuation. Larger intersection angles between secondary and main fractures hinder proppant migration. (4) Smaller proppant size and lower density improve the planar sweep and distribution uniformity coefficients, while increased fracturing fluid viscosity extends the proppant sweep range and further improves uniformity; high injection rates promote long-distance proppant transport and broader coverage but may reduce uniformity, leading to sparse proppant distribution and necking at fracture mouths. These findings provide quantitative guidance for optimizing hydraulic fracturing designs.

Graphical abstract
Keywords
Multiphase particle-in-cell method; Liquid-solid two-phase flow; Eulerian-Lagrangian method; Complex fracture network; Proppant transport
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