Understanding how fracture networks develop in shale formations is important when exploiting unconventional hydrocarbon reservoirs and analyzing the integrity of the seals of conventional and carbon capture and storage reservoirs. Despite this importance, experimentally derived fracture data for shale remains sparse. Here we characterize shale from Nash Point in South Wales, United Kingdom, in terms of ultrasonic wave velocities, tensile strength, and fracture toughness (K_Ic). We measure these properties in multiple orientations, including angles oblique to the three principal fracture orientations—Short‐transverse, Arrester, and Divider. We find that the Nash Point shale is mechanically highly anisotropic, with tensile strength and K_Ic values lowest in the Short‐transverse orientation and highest in the Arrester and Divider orientations. Fractures that propagate in a direction oblique or normal to bedding commonly deflect toward the weaker Short‐transverse orientation. Such deflected fractures can no longer be considered to propagate in pure mode‐I. We therefore present a method to correct measured K_Ic values to account for deflection by calculating mode‐I and mode‐II deflection stress intensities (K_Id and K_IId, respectively). Because of the mixed‐mode nature of deflected fractures, we adopt a fracture (G_c) energy‐based approach that allows analysis of critical fracture propagation conditions for both deflected and undeflected fractures in all orientations. We find that G_c increases as the angle from the Short‐transverse plane increases. We conclude that a modified elliptical function, previously applied to tensile strength and K_Ic, can be used to estimate values of G_c at angles between the Short‐transverse and Arrester orientations.

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 (K_Ic) 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, P_inj) increases from 6.1 MPa at 2.2‐MPa confining pressure (P_c), 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 P_c = 4.5 MPa) and 58 MPa (P_c = 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 K_Ic from 0.36 to 4.05 MPa·m^1/2 as differential fluid pressure (P_inj − P_c) 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.

Carbonate reservoirs accommodate a significant proportion of global hydrocarbon reserves. However they are often tight and permeability is therefore usually dependent on either flow through existing fractures or through those produced by hydraulic stimulation. Hence, understanding how fracture networks develop in carbonate reservoir rocks is key to efficient and effective production. However, despite their prevalence as reservoir rocks, there is a paucity of data on key fracture properties of carbonate rocks, particularly in more than one orientation. Here, therefore we report measurements of both the tensile strength and fracture toughness of Nash Point limestone in the three principal fracture orientations to determine what effect any mechanical anisotropy might have on fracture propagation. We find Nash Point limestone to be essentially isotropic in terms of both its microstructure and its fracture properties. When comparing the fracture toughness of Nash Point limestone with that of others limestones, we find that fracture toughness decreases with increasing porosity, although this dependency is not as strong as found in other porous rocks. Finally, as many so-called carbonate reservoirs actually comprise layered sequences, we extend our analysis to consider the layered sequence of limestones and shales at Nash Point. We find that the fracture toughness of Nash Point limestone is higher than Nash Point shale but that the fracture energy is lower. We therefore discuss how the implications of fracturing through multi-layered sequences could be explored in future work.