Evaluation of Proppant Placement Efficiency in Linearly Tapering Fractures

With growing reliance on hydraulic fracturing to develop tight oil and gas reservoirs characterized by low porosity and permeability, optimizing proppant transport and placement has become critical to sustaining fracture conductivity and production. However, how fracture geometry influences proppant distribution under varying field conditions remains insufficiently understood. This study employed computational fluid dynamics to investigate proppant transport and placement in hydraulic fractures of which the aperture tapers linearly along their length. Four taper rate models (δ = 0, 1/1500, 1/750, and 1/500) were analyzed under a range of operational parameters: injection velocities (1.38–3.24 m/s), sand concentrations (2–8%), proppant particle sizes (0.21–0.85 mm), and proppant densities (1760–3200 kg/m³). Equilibrium proppant pack height was adopted as the key metric for pack morphology. The results show that increasing injection rate and taper rate both serve to lower pack heights and enhance downstream transport, while a higher sand concentration, larger particle size, and greater density tend to raise pack heights and promote more stable pack geometries. In tapering fractures, higher δ values amplify flow acceleration and turbulence, yielding flatter, “table-top” proppant distributions and extended placement lengths. Fine, low-density proppants more readily penetrate to the fracture tip, whereas coarse or dense particles form taller inlet packs but can still be carried farther under high taper conditions. These findings offer quantitative guidance for optimizing fracture geometry, injection parameters, and proppant design to improve conductivity and reduce sand-plugging risk in tight formations. These insights address the challenge of achieving effective proppant placement in complex fractures and provide quantitative guidance for tailoring fracture geometry, injection parameters, and proppant properties to improve conductivity and mitigate sand plugging risks in tight formations.