Investigation on Flowback Behavior of Imbibition Fracturing Fluid in Gas-Shale Multiscale Pore Structure

To investigate the influence of flowback time and flowback difference on flowback behavior of shale fracturing fluid, we carried out the permeability test experiment of Longmaxi Formation shale under different flowback pressure gradients and analyzed the retention characteristics of water phase in shale pores and fractures after flowback by nuclear magnetic resonance (NMR) instrument. The results indicate that after flowback under the pressure gradient ranges of 0.06 similar to 0.18 MPa /cm, the content of retained water phase in shale samples ranges from 9.68% to 16.97% and the retention of fracturing fluid in shale does not decrease with the increase of flowback pressure difference. Additionally, increasing the flowback pressure difference will reduce the shale permeability damage rate, but the permeability damage rate is still above 80%. After the flowback, the water phase mainly stays in the pore space with D < 100 nm, especially in the pore space with 2 similar to 10 nm and 10 similar to 50 nm. It is extremely difficult for the water phase in the pores with D < 100 nm to flow back out. The experimental results show that the critical flowback pressure gradient for particle migration of rock powder in shale fracture surface is 0.09 MPa /cm. The research results have important guiding significance for shale gas well flowback.

Automated summary

This study investigated the influence of flowback time and flowback difference on the flowback behavior of shale fracturing fluid. Through permeability tests and analysis of water phase retention in shale samples, it was found that the retention of fracturing fluid in shale does not decrease with increasing flowback pressure difference. Increasing the flowback pressure difference can reduce the shale permeability damage rate, but the damage rate is still above 80%. The water phase mainly stays in the pore space with a diameter less than 100 nm.