Hydraulic Aperture Reduction of Shale Fractures Due to Mechanical Stressing, with Characterization of Physical Fracture Evolution Using Comuted Tomography

Flow in fractured shale is a topic of interest for both production from non-traditional fractured shale reservoirs and for estimating the leakage potential of sealing formations above geologic carbon dioxide repositories. The hydraulic aperture of a fracture quantifies how much fluid can be transported through a fracture, similarly to how permeability describes fluid flow through porous media. The advantage of defining the fracture hydraulic aperture as opposed to permeability, is that this property can be easily scaled up to fracture reservoir simulators. Many parameters affect the hydraulic aperture, however, including the fracture roughness, the physical aperture distribution, and the tortuosity of flow paths within the fracture.

The computed tomography (CT) and flow facility at NETL has conducted an analysis of the changes in both physical and hydraulic aperture as fractures were subjected to varying external confining stresses. Changes in fracture geometry were tracked through the use of non-destructive CT imaging, allowing the determination of the physical aperture distribution, while hydraulic fracture apertures were derived from experimental fracture flow measurements. In order to evaluate the effects of fracture roughness and geometry, two fractures with different degrees of roughness were used. Tests were conducted with locally sourced shale.

Experimental results show that the volume change in the fracture is a non-linear function of the confining pressure, and both physical and hydraulic apertures decrease rapidly as the fracture is first compressed.