Unconventional hydrocarbon resources found across the world are driving a renewed interest in mudrock hydraulic fracturing methods. However, given the difficulty in safely measuring the various controlling factors in a natural environment, considerable challenges remain in understanding the fracture process. To investigate, we report a new laboratory study that simulates hydraulic fracturing using a conventional triaxial apparatus. We show that fracture orientation is primarily controlled by external stress conditions and the inherent rock anisotropy and fabric are critical in governing fracture initiation, propagation, and geometry. We use anisotropic Nash Point Shale (NPS) from the early Jurassic with high elastic P wave anisotropy (56%) and mechanical tensile anisotropy (60%), and highly anisotropic (cemented) Crab Orchard Sandstone with P wave/tensile anisotropies of 12% and 14%, respectively. Initiation of tensile fracture requires 36 MPa for NPS at 1‐km simulated depth and 32 MPa for Crab Orchard Sandstone, in both cases with cross‐bedding favorable orientated. When unfavorably orientated, this increases to 58 MPa for NPS at 800‐m simulated depth, far higher as fractures must now traverse cross‐bedding. We record a swarm of acoustic emission activity, which exhibits spectral power peaks at 600 and 100 kHz suggesting primary fracture and fluid‐rock resonance, respectively. The onset of the acoustic emission data precedes the dynamic instability of the fracture by 0.02 s, which scales to ~20 s for ~100‐m size fractures. We conclude that a monitoring system could become not only a forecasting tool but also a means to control the fracking process to prevent avoidable seismic events.

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A number of key processes, both natural and anthropogenic, involve the fracture of rocks subjected to tensile stress, including vein growth and mineralization, and the extraction of hydrocarbons through hydraulic fracturing. In each case, the fundamental material property of mode‐I fracture toughness must be overcome in order for a tensile fracture to propagate. While measuring this parameter is relatively straightforward at ambient pressure, estimating fracture toughness of rocks at depth, where they experience confining pressure, is technically challenging. Here we report a new analysis that combines results from thick‐walled cylinder burst tests with quantitative acoustic emission to estimate the mode‐I fracture toughness (KIc) of Nash Point Shale at confining pressure simulating in situ conditions to approximately 1‐km depth. In the most favorable orientation, the pressure required to fracture the rock shell (injection pressure, Pinj) increases from 6.1 MPa at 2.2‐MPa confining pressure (Pc), to 34 MPa at 20‐MPa confining pressure. When fractures are forced to cross the shale bedding, the required injection pressures are 30.3 MPa (at Pc = 4.5 MPa) and 58 MPa (Pc = 20 MPa), respectively. Applying the model of Abou‐Sayed et al. (1978, https://doi.org/10.1029/JB083iB06p02851) to estimate the initial flaw size, we calculate that this pressure increase equates to an increase in KIc from 0.36 to 4.05 MPa·m1/2 as differential fluid pressure (Pinj − Pc) increases from 3.2 to 22.0 MPa. We conclude that the increasing pressure due to depth in the Earth will have a significant influence on fracture toughness, which is also a function of the inherent anisotropy.

The process of hydraulic fracture is well known in both natural (e.g. veining and mineralisation) and engineered environments (e.g. stimulating tight mudrocks and sandstones to boost their hydraulic properties). Here, we report a method and preliminary data that simulates both tensile fracture and fluid flow at elevated pressures. To achieve this we developed a sample assembly consisting of a cylindrical core drilled with an axial borehole encapsulated in a 3D printed jacket permitting fluid from the borehole to move through the freshly generated tensile fracture to a voluometer. The permeability of Nash Point Shale increases from a pre-fracture value of 10 −18 to 10 −20 m 2 (1 microDarcy, μD to 0.01 μD) to 2 × 10 −15 m 2 (2 milliDarcy, mD) immediately after fracture (at 2.1 MPa confining pressure). Permeability is strongly dependent on confining pressure, decreasing to 0.25 × 10 −15 m 2 (0.25 mD) at 19 MPa confining pressure (approximately 800 m depth), and does not recover when confinement is removed. Using concomitant measurements of the radial strain as a proxy for fracture aperture, we conclude that the effective permeability is governed solely by the width of the developed cracks, revealed by post-test X-Ray Computed Tomography to be planar, extending radially from the central conduit.

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