The breakdown of shale and the created fracture complexity are greatly dependent on the flow behaviors of fracture fluids just before fracture initiation. Because of the unique characteristics of shale formations—including low permeability, existence of micro-fractures, and sensitivity to contacting fluids—it is difficult to evaluate fluid flow with traditional laboratory methods. NMR technology has been explored to study the propagation of fracture fluid inside shale core before fracture initiation. All fluids were injected at pressures less than fracture pressure. Cores from three different shale formations (Eagle Ford, Marcellus and Mancos) were evaluated with the new methods. Variations such as fluid types (slickwater, acid and oil), injection pressure were evaluated.
Based on experimental results, the volume of fracture fluid that propagated inside shale cores has a strong relationship with fluid viscosity, where increasing fluid viscosity reduced this volume. NMR confirmed that slickwater or a higher-viscosity fracture fluid did not propagate inside the small shale pores (less than 0.01 μm as an average estimation) but did propagate inside larger pores and inside the existing microfractures. High-viscosity fracturing fluid was only able to fill the larger shale pores, while slickwater fracture fluid filled the large pores and connected them to increase the microfracture density. This allows the slickwater fluid to break the shale formation with lower pressure and produce more complex fractures than high viscosity fluids. Reactive fluids, such as HCl acid solution, were also studied and found to leak into the shale core by increasing the contact time, even for shale with low HCl solubility (less than 2 wt%).
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