The breakdown of shale and the created fracture complexity are greatly dependent on the flow behaviors of fracturing fluids just before fracture initiation. Because of the unique characteristics of shale formations—including low permeability, existence of microfractures, and sensitivity to contacting fluids—it is difficult to evaluate fluid flow with traditional laboratory methods. Nuclear Magnetic Resonance (NMR) technology has been explored to study the propagation of fracturing fluids inside shale cores 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), and injection pressure were evaluated.
Based on experimental results, the leakoff rate inside the shale formation during the hydraulic fracturing treatment can be calculated using NMR technology. NMR confirmed that slickwater and a higher-viscosity fracturing fluid propagated into the larger pores and existing microfractures. Increasing the viscosity from 1 to 200 cP reduced the leakoff rate by 6.5 times. This reduction can significantly affect the shape of the fracture and the corresponding breakdown pressure. Leakoff rate increased 2.65 times by doubling the injection pressure because increasing the injection pressure also increases the communication among the pores, and may ‘balloon’ the large pores, or increase the microfracture density. Reactive fluids, such as HCl acid, show an infinite value of leakoff as they were found to break through the shale core, even in shale having low HCl solubility (less than 2 wt%).