Involving the fluid-particle hydrodynamic process and hydraulically created fracture network, fracturing-fluid flowback in hydraulically fractured shale wells is a complex transport behavior. However, there is limited research on investigating the influence of proppant transport on the fracturing-fluid flowback behavior and flowback data analysis. In this paper, a flowback model is developed to simulate the flowback behaviors of the carrying fluid and proppant from the recompacted fracture system in shale wells. The development of fluid pressure and proppant concentration profiles of the fractured shale well are presented. The fluid and proppant fluxes among the hydraulic primary fracture and the induced fracture are also calculated. The influences of proppant consideration or not, proppant density, proppant size, fracturing-fluid viscosity, and fracturing-fluid density on the flowback behavior are investigated. The simulation results are useful for fracturing-fluid optimization in the design phase. Finally, two field cases from the Longmaxi Formation, Southern Sichuan Basin, China are used for matching the actual flowback data with the model results. The results prove that the proppant transport has influence on the flowback behavior to some degree and should be considered in the flowback model for a rather elaborate flowback analysis and post-treatment fracture evaluation.

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Summary Natural fractures have significant influence on flow fields, thus affecting wormhole pattern in acidizing. This paper summarizes our research on wormholing behavior in naturally fractured carbonates. First, statistical natural-fracture models are established using the Monte Carlo method. Second, a two-scale continuum wormhole model is established to simulate wormhole propagation with natural fractures. Finally, extensive numerical simulation is conducted to investigate wormhole behavior and the effect of the natural-fracture parameters on wormhole pattern. In addition, possible wormhole-penetration distance is discussed. This study provides a theoretical basis for matrix-acidizing designs in naturally fractured carbonates.

A novel model is established to predict the temperature field in the horizontal wellbore during CO2 fracturing. The pressure work and viscous dissipation are considered, and the transient energy, mass and momentum equations as well as the CO2 physical properties are solved fully coupled. The model passes the convergence test and is verified through a comparison using the COMSOL software. Then, a sensitivity analysis is performed to study the effects of the treating parameters. Results illustrate that the relationship between the injection rate and the stable bottom-hole temperature (hereinafter referred to as BHT) is non-monotonic, which is different from the hydraulic fracturing. The existence of the horizontal section will increase the BHT at 2 m3/min condition but reduce the BHT at 10 m3/min condition. The problem of high wellbore friction can be alleviated through tube size enhancement, and the ultimate injection rate allowed increased from 2.7 m3/min to 29.6 m3/min when the tube diameter increased from 50.3 mm to 100.3 mm. Additionally, the open-hole completion method of the horizontal section can increase the BHT to 2.7 °C but reduce the near formation temperature to 24.5 °C compared with the casing completion method.