Abstract
Post-fracturing well shut-in is traditionally due to the elastic closure of hydraulic fractures and proppant compaction. However, for shale gas wells, the extension of shut-in time may improve the post-fracturing gas production due to formation energy supplements by fracturing-fluid imbibition. This paper presents a methodology using numerical simulation to simulate the hydrodynamic equilibrium phenomenon of a hydraulically fractured shale gas reservoir, including matrix imbibition and fracture network crossflow, and further optimize the post-fracturing shut-in time. A mathematical model, which can describe the fracturing-fluid hydrodynamic transport during the shut-in process, and consider the distinguishing imbibition characteristics of a hydraulically fractured shale reservoir, i.e., hydraulic pressure, capillarity and chemical osmosis, is developed. The key concept, i.e., hydrodynamic equilibrium time, for optimizing the post-fracturing shut-in schedule, is proposed. The fracturing-fluid crossflow and imbibition profiles are simulated, which indicate the water discharging and sucking equilibrium process in the coupled fracture–matrix system. Based on the simulation, the hydrodynamic equilibrium time is calculated. The influences of hydraulic pressure difference, capillarity and chemical osmosis on imbibition volume, and hydrodynamic equilibrium time are also investigated. Finally, the optimal shut-in time is determined if the gas production rate is pursued and the fracturing-fluid loss is allowable. The proposed simulation method for determining the optimal shut-in time is meaningful to the post-fracturing shut-in schedule.
Highlights
Shale gas reservoir development mostly uses multi-stage fracturing technology in large-scale horizontal wells, but field data indicate that only 15%–30% of the fracturing water is recovered after the flowback [1], which is very low compared with conventional reservoirs
The simulation results are used to establish a relationship between the reservoir hydrodynamic equilibrium and well shut-in time, and, further, to determine the optimal shut-in time for a hydraulically fractured shale gas well
The imbibition needs extra time to achieve equilibrium, because the physicochemical phenomena are relatively slow compared with the natural convection, and the driving forces, such as the capillary pressure and osmotic pressure, are relatively small compared with the hydraulic pressure
Summary
Shale gas reservoir development mostly uses multi-stage fracturing technology in large-scale horizontal wells, but field data indicate that only 15%–30% of the fracturing water is recovered after the flowback [1], which is very low compared with conventional reservoirs. There is a view in academia that the shut-in process will cause further imbibition of fracturing fluid from hydraulic fractures to form water-phase traps, resulting in reservoir damage [3]. Leung [5] used the commercial simulator Computer Modeling Group (CMG) to simulate the backflow and retention of fracturing fluid after large-scale hydraulic fracturing Their simulation study shows that, during shut-in, the water in the fracture will permeate into the matrix, and with the increase of shut-in time, the infiltration range will increase, which will promote oil entering the fracture and increase the initial production. Wang et al [7] established a numerical model to investigate the chemical osmosis phenomena on fracturing-fluid leakoff during shut-in periods Their simulation results indicate that chemical osmosis can lead to an extra leakoff volume of 7%. The simulation results are used to establish a relationship between the reservoir hydrodynamic equilibrium and well shut-in time, and, further, to determine the optimal shut-in time for a hydraulically fractured shale gas well
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