Abstract
The formation mechanism and propagation behaviors of a three-dimensional hydraulic fracture network in fractured shale reservoirs remain unclear, especially when the scale of hydraulic fractures is much larger than that of natural fractures. In this study, taking the well XH in the Longmaxi shale reservoir in the Sichuan Basin, China as an example, we develop a fully three-dimensional numerical model for hydraulic fracturing coupled with microseismicity based on the discrete lattice method. We introduce a randomly generated discrete fracture network into the proposed model and explore the formation mechanism of the hydraulic fracture network under the condition that the hydraulic fractures are much larger than natural fractures in scale. Moreover, microseismic events are inversely synthesized in the numerical model, which allows the evolution of the fracture network to be monitored and evaluated quantitatively. In addition, we analyze the effects of injection rate, horizontal stress difference, and fluid viscosity on fracture propagation. Our results show that when the scale of hydraulic fractures is much larger than that of natural fractures, the fracture morphology of “main hydraulic fractures + complex secondary fractures” is mainly formed. We find that a high injection rate can not only create a complex fracture network, but also improve the uniform propagation of multi-cluster fractures and enhance far-field stimulation efficiency. Optimizing the horizontal wellbore intervals with low horizontal stress differences as the sweet spots of hydraulic fracturing is also beneficial to improve the stimulation efficiency. For zones with a large number of natural fractures, it is recommended to use an injection schedule with high viscosity fluid early and low viscosity fluid late to allow the hydraulic fractures to propagate to the far-field to maximize the stimulation effect.
Highlights
We introduce a discrete fracture network characterized by randomly distributed natural fractures and explore the formation mechanism of the fracture network with the scale of the hydraulic fracture being much larger than that of a natural fracture
The second type are mimicroseismic events still appear in the near-wellbore area, indicating that a large amount croseismic events that occur at the propagation front of hydraulic fractures, represented of fracturing fluid is consumed by fluid filtration or reactivation of natural fractures in the near-wellbore area
(2) The spatial growth and evolution of the fracture network can be reflected by the evolution of microseismic events during the numerical simulation
Summary
Tan et al (2017) conducted true-triaxial fracturing experiments on specimens recovered from layered shale outcrops, found complex fracture morphology from specimens with developed bedding planes, and obtained the favorable conditions for creating a complex fracture network [32] These studies have improved the understanding of complex fracture propagation in fractured unconventional reservoirs under the influence of various geological and engineering factors and have provided theoretical support for the design and optimization of fracturing operation parameters in the field. It is generally assumed that the scale of natural fractures, especially in the fracture height, is equivalent to the scale of hydraulic fractures in the existing research These are the possible reasons that the propagation of the fracture network obtained from numerical simulations differs from the actual situation, which is not beneficial to fracture optimization in unconventional reservoirs. We systematically examine the effects of injection rate, horizontal stress difference, and fluid viscosity on the propagation behavior of the fracture network
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