To investigate how the characteristics of interbeds affect hydraulic fracture propagation in the continental shale formation, a series of 300 mm × 300 mm × 300 mm concrete blocks with varying interbeds, based on outcrop observation and core measurement of Chang 7-2 shale formation, were prepared to conduct the hydraulic fracturing experiments. The results reveal that the breakdown pressure increases with the rise of thickness and strength of interbeds under the same in-situ field stress and injection rate. In addition, for the model blocks with thick and high strength interbeds, the hydraulic fracture has difficulty crossing the interbeds and is prone to divert along the bedding faces, and the fracturing effectiveness is not good. However, for the model blocks with thin and low strength interbeds, more long branches are generated along the main fracture, which is beneficial to the formation of the fracture network. What is more, combining the macroscopic descriptions with microscopic observations, the blocks with thinner and lower strength interbeds tend to generate more micro-fractures, and the width of the fractures is relatively larger on the main fracture planes. Based on the experiments, it is indicated that the propagation of hydraulic fractures is strongly influenced by the characteristics of interbeds, and the results are instructive to the understanding and evaluation of the fracability in the continental shale formation.

The formation of dense spacing fracture network is crucial to the hydraulic fracturing treatment of unconventional reservoir. However, one difficulty for fracturing treatment is the lack of clear understanding on the nature of fracture complexity created during the treatment. In this paper, fracture propagation is numerically investigated to find the conditions needed for the stable propagation of complex fracture network. Firstly, starting from a parallel fracture system, the stability of fracture propagation is analyzed and a dimensionless number M is obtained. Then, by developing a hydraulic fracturing simulation model based on displacement discontinuity method, the propagation of parallel fractures is simulated and a clear relation between M and the stability of parallel fractures is obtained. Finally, the investigation on parallel fractures is extended to complex fracture networks. The propagation of complex fracture networks is simulated and the results show that the effects of M on complex fracture networks is the same to that of parallel fractures. The clear relation between M and fracture propagation stability is important for the optimization of hydraulic fracturing operation.

Numerical simulation is very useful for understanding the hydraulic fracturing mechanism. In this paper, we simulate the hydraulic fracturing using the distinct element approach, to investigate the effect of some critical parameters on hydraulic fracturing characteristics. The breakdown pressure obtained by the distinct element approach is consistent with the analytical solution. This indicates that the distinct element approach is feasible on modeling the hydraulic fracturing. We independently examine the influence of in-situ stress ratio, injection rate and fluid viscosity on hydraulic fracturing. We further emphasize the relationship between these three factors and their contributions to the hydraulic fracturing. With the increase of stress ratio, the fracture aperture increases almost linearly; with the increase of injection rate and fluid viscosity, the fracture aperture and breakdown pressure increase obviously. A low value of product of injection rate and fluid viscosity (i.e., Qμ) will lead to narrow fracture aperture, low breakdown pressure, and complex or dispersional hydraulic fractures. A high value of Qμ would lead wide fracture aperture, high breakdown pressure, and simple hydraulic fractures (e.g., straight or wing shape). With low viscosity fluid, the hydraulic fracture geometry is not sensitive to stress ratio, and thus becomes a complex fracture network.

Multiple-factor analysis and optimization play a critical role in the the ability to maximizethe stimulated reservoir volume (SRV) and the success of economic shale gas production. In this paper, taking the typical continental naturally fractured silty laminae shale in China as anexample, response surface methodology (RSM) was employed to optimize multiple hydraulic fracturing parameters to maximize the stimulated area in combination with numerical modeling based on the coupled flow-stress-damage (FSD) approach. This paper demonstrates hydraulic fracturing effectiveness by defining two indicesnamelythe stimulated reservoir area (SRA) and stimulated silty laminae area (SLA). Seven uncertain parameters, such as laminae thickness, spacing, dip angle, cohesion, internal friction angle (IFA), in situ stress difference (SD), and an operational parameter-injection rate (IR) with a reasonable range based on silty Laminae Shale, Southeastern Ordos Basin, are used to fit a response of SRA and SLA as the objective function, and finally identity the optimum design under the parameters based on simultaneously maximizingSRA and SLA. In addition, asensitivity analysis of the influential factors is conducted for SRA and SLA. The aim of the study is to improve the artificial ability to control the fracturing network by means of multi-parameteroptimization. This work promises to provide insights into the effective exploitation of unconventional shale gas reservoirs via optimization of the fracturing design for continental shale, Southeastern Ordos Basin, China.

In this study, variable injection-rate technology was numerically investigated in a pre-existing discrete fracture network (DFN) formation, the Tarim Basin in China. A flow-stress-damage (FSD) coupling model has been used in an initial attempt towards how reservoir response to variable injection-rates at different hydraulic fracturing stages. The established numerical model simultaneously considered the macroscopic and microscopic heterogeneity characteristics. Eight numerical cases were studied. Four cases were used to study the variable injection-rate technology, and the other four cases were applied for a constant injection-rate in order to compare with the variable injection-rate technology. The simulation results show that the variable injection-rate technology is a potentially good method to a form complex fracturing networks. The hydraulic fracturing effectiveness when increasing the injection-rate at each stage is the best, also, the total injected fluid is at a minimum. At the initial stage, many under-fracturing points appear around the wellbore with a relatively low injection-rate; the sudden increase of injection rate drives the dynamic propagation of hydraulic fractures along many branching fracturing points. However, the case with decreasing injection rate is the worst. By comparing with constant injection-rate cases, the hydraulic fracturing effectiveness with variable flow rate technology is generally better than those with constant injection-rate technology. This work strongly links the production technology and hydraulic fracturing effectiveness evaluation and aids in the understanding and optimization of hydraulic fracturing simulations in naturally fractured reservoirs.