页岩储层体积压裂复杂裂缝支撑剂的运移与展布规律

为了研究页岩储层体积压裂复杂裂缝支撑剂的运移与展布规律,构建了大尺度复杂裂缝支撑剂运移与展布评价实验系统,测试了次裂缝角度、注入排量、加砂浓度、支撑剂粒径、压裂液黏度等对支撑剂运移与展布的影响,研究了主/次裂缝中支撑剂的运移与展布规律。结果表明:(1)裂缝中流体流态随裂缝支撑高度增加逐步由层流向紊流转变;(2)支撑剂在裂缝中的运移方式主要包括悬浮运移和滑移运动;(3)分支前主裂缝的支撑剂展布形态与次裂缝角度、注入排量、加砂浓度和支撑剂粒径等参数相关,其中注入排量为最主要的影响因素;(4)分支后主裂缝的支撑剂质量比与次裂缝角度、注入排量、液体黏度、加砂浓度和支撑剂粒径呈正比,同次裂缝与主裂缝的流量比呈反比;(5)分支后次裂缝的支撑剂质量比与注入排量、次裂缝与主裂缝的流量比、压裂液黏度呈正比,与次裂缝角度、加砂浓度和支撑剂粒径呈反比;(6)分支后主裂缝的砂堤前缘角度同加砂浓度、支撑剂粒径、次裂缝与主裂缝的流量比呈正比,与次裂缝角度、注入排量和压裂液黏度呈反比;(7)次裂缝的砂堤前缘角度同次裂缝角度、加砂浓度与支撑剂粒径呈正比,和注入排量、压裂液黏度、次裂缝与主裂缝的流量比呈反比。结论认为,该研究成果可以为页岩储层体积压裂支撑剂的优选和压裂方案设计提供理论支撑。

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

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.