Despite the impact that hydraulic fracturing has had on the energy sector, the physical mechanisms that control its efficiency and environmental impacts remain poorly understood in part because the length scales involved range from nanometres to kilometres. We characterize flow and transport in shale formations across and between these scales using integrated computational, theoretical and experimental efforts/methods. At the field scale, we use discrete fracture network modelling to simulate production of a hydraulically fractured well from a fracture network that is based on the site characterization of a shale gas reservoir. At the core scale, we use triaxial fracture experiments and a finite-discrete element model to study dynamic fracture/crack propagation in low permeability shale. We use lattice Boltzmann pore-scale simulations and microfluidic experiments in both synthetic and shale rock micromodels to study pore-scale flow and transport phenomena, including multi-phase flow and fluids mixing. A mechanistic description and integration of these multiple scales is required for accurate predictions of production and the eventual optimization of hydrocarbon extraction from unconventional reservoirs. Finally, we discuss the potential of CO2 as an alternative working fluid, both in fracturing and re-stimulating activities, beyond its environmental advantages.This article is part of the themed issue 'Energy and the subsurface'.

No abstract

The challenge of characterizing subsurface fluid flow has motivated extensive laboratory studies, yet fluid flow through rock specimens in which fractures are created and maintained at high‐stress conditions remains underinvestigated at this time. The studies of this type that do exist do not include in situ fracture geometry measurements acquired at stressed conditions, which would be beneficial for interpreting the flow behavior. Therefore, this study investigates the apparent permeability induced by direct‐shear fracture stimulation through Utica shale (a shale gas resource and potential caprock material) at high triaxial stress confinement and for the first time relates these values to simultaneously acquired in situ X‐ray radiography and microtomography images. Change in fracture geometry and apparent permeability was also investigated at additional reduced stress states. Finite element and combined finite‐discrete element modeling were used to evaluate the in situ observed fracturing process. Results from this study indicate that the increase in apparent permeability through fractures created at high‐stress (22.2 MPa) was minimal relative to the intact rock (less than 1 order of magnitude increase), while fractures created at low stress (3.4 MPa) were significantly more permeable (2 to 4 orders of magnitude increase). This study demonstrates the benefit of in situ X‐ray observation coupled with apparent permeability measurement to analyze fracture creation in the subsurface. Our results show that the permeability induced by fractures through shale at high stress can be minor and therefore favorable in application to CO2 sequestration caprock integrity but unfavorable for hydrocarbon recovery from unconventional reservoirs.

A laboratory experiment was performed to see if passively recorded electric signals can be inverted to retrieve the position of fluid leakages along a well during an attempt to hydraulically fracture a porous block in the laboratory. The cubic block was instrumented with 32 nonpolarizing sintered Ag/AgCl electrodes. During the test, several events were detected corresponding to fluid leakoff along the seal of the well. Each event showed a quick burst in the electric field followed by an exponentialtype relaxation of the potential distribution over time. The occurrence of these "electric" events was always correlated with a burst in the acoustic emissions and a change in the fluid pressure. These self-potential data were inverted in two steps: (1) using a deterministic least-square algorithm with focusing to retrieve the position of the source current density in the block for a given snapshot in the electric potential distribution and (2) using a genetic algorithm to refine the position of the source current density on a denser grid. The results of the inversion were found to be in excellent agreement with the position of the well where the hydraulic test was performed and with the localization of the acoustic emissions in the vicinity of this well. This experiment indicates that passively recorded electric signals can be used to monitor fluid flow along the well during leakages, and perhaps monitor fluid flow for numerous applications involving hydromechanical disturbances.

The final version of the above article was posted prematurely on 16 July 2021, owing to a technical error. The final, corrected version of record will be made fully available at a later date.