Migration and distribution of complex fracture proppant in shale reservoir volume fracturing

Abstract

In this paper, a large-scale experimental system was established to identify the migration and distribution laws of complex fracture proppant in shale reservoir volume fracturing. With this system, the effects of secondary fracture angle, fluid displacement, proppant concentration and size, fracturing fluid viscosity and other factors on the migration and distribution of proppant were tested, and the migration and distribution of proppant in primary/secondary fractures were analyzed. The following results were obtained. First, the fluid flow pattern in fractures transforms gradually from laminar flow into turbulent flow with the increase of fracture supporting height. Second, the migration modes of proppant in fractures mainly include suspended migration and gliding migration. Third, the distribution form of proppant in primary fractures before branching is related to secondary fracture angle, fluid displacement and proppant concentration and size, among which the fluid displacement is the most important factor. Fourth, the mass ratio of proppant in primary fractures after branching is proportional to the secondary fracture angle, fluid displacement, fracturing fluid viscosity and proppant concentration and size, and is inversely proportional to the flow ratio between secondary fractures and primary fractures. Fifth, the mass ratio of proppant in secondary fractures after branching is proportional to fluid displacement, fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures, and is inversely proportional to secondary fracture angle and proppant concentration and size. Sixth, the angle at the leading edge of proppant bank in the primary fractures after branching is proportional to the proppant concentration and size and the flow ratio between secondary fractures and primary fractures, but is inversely proportional to secondary fracture angle, fluid displacement and fracturing fluid viscosity. Seventh, the angle at the leading edge of proppant bank in the secondary fractures after branching is proportional to the secondary fracture angle and the proppant concentration and size, but is inversely proportional to the fluid displacement, fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures. In conclusion, the research results can provide a theoretical support for proppant optimization and program design of shale reservoir volume fracturing.