From Fluid Flow to Coupled Processes in Fractured Rock: Recent Advances and New Frontiers

Abstract

Quantitative predictions of natural and induced phenomena in fractured rock is one of the great challenges in the Earth and Energy Sciences with far‐reaching economic and environmental impacts. Fractures occupy a very small volume of a subsurface formation but often dominate fluid flow, solute transport and mechanical deformation behavior. They play a central role in CO2 sequestration, nuclear waste disposal, hydrogen storage, geothermal energy production, nuclear nonproliferation, and hydrocarbon extraction. These applications require predictions of fracture‐dependent quantities of interest such as CO2 leakage rate, hydrocarbon production, radionuclide plume migration, and seismicity; to be useful, these predictions must account for uncertainty inherent in subsurface systems. Here, we review recent advances in fractured rock research covering field‐ and laboratory‐scale experimentation, numerical simulations, and uncertainty quantification. We discuss how these have greatly improved the fundamental understanding of fractures and one's ability to predict flow and transport in fractured systems. Dedicated field sites provide quantitative measurements of fracture flow that can be used to identify dominant coupled processes and to validate models. Laboratory‐scale experiments fill critical knowledge gaps by providing direct observations and measurements of fracture geometry and flow under controlled conditions that cannot be obtained in the field. Physics‐based simulation of flow and transport provide a bridge in understanding between controlled simple laboratory experiments and the massively complex field‐scale fracture systems. Finally, we review the use of machine learning‐based emulators to rapidly investigate different fracture property scenarios and accelerate physics‐based models by orders of magnitude to enable uncertainty quantification and near real‐time analysis.

A Geo‐Structurally Based Correction Factor for Apparent Dissolution Rates in Fractured Media

“…Our model setup was designed to isolate the effect of network structure on geochemical behavior. Recent studies of single phase steady flow through fracture networks indicate that as the geological heterogeneity increases, for example, distribution of fracture lengths; network density; fracture intensity; or pre-existing internal aperture variability, flow channelization becomes more pronounced (Doolaeghe et al, 2020;Hyman, 2020;Hyman et al, 2021;Hyman & Jiménez-Martínez, 2018;Kang et al, 2020;Maillot et al, 2016;Tsang & Neretnieks, 1998;Viswanathan et al, 2022) Thus, in turn, one would expect a clearer distinction of primary and secondary networks, which is the foundation of the proposed correction factor. Nonetheless, how interactions within the hierarchy of length scales in fracture networks influences the apparent dissolution rate and applicability of the correction factor warrants detailed investigation.…”

Three‐Dimensional Thermoporoelastic Modeling of Hydrofracturing and Fluid Circulation in Hot Dry Rock

“…To monitor the coupled THMC processes associated with hydraulic stimulations and fluid circulations, all of the subhorizontal wells with a nominal length of 60 m (see Figure 4) were intensively instrumented with various monitoring sensors (Schoenball et al, 2019;Viswanathan et al, 2022), including geophones, hydrophones, accelerometers, thermistors, a 3D electrical resistivity tomography (ERT) array, seismic sources for continuous active source seismic monitoring (CASSM), and distributed temperature sensing (DTS), distributed strain sensing (DSS), and DAS. Two SIMFIP (step-rate injection method for fracture in-situ properties, Guglielmi et al ( 2014)) displacement sensors were additionally instrumented in E1-I and E1-P to measure the 3D displacements of the openhole interval of the wells (Guglielmi et al, 2021).…”

“…Although EGS technology is promising for harnessing geothermal energy, there still exist a variety of scientific and technological challenges in identifying natural fractures, unveiling hydraulic stimulation mechanisms, simulating the processes of hydraulic stimulation and fluid circulation, and so on. Identification of natural/hydraulic fractures usually relies on monitoring techniques, such as televiewer logs, to directly observe pre‐existing fractures cross‐cut the wellbores (Schwering et al., 2020), distributed acoustic sensing (DAS) for detection of propagating fractures and the final fracture trajectory (Becker et al., 2020; Jin & Roy, 2017; Viswanathan et al., 2022), microseismic mapping techniques to characterize hydraulic fractures (Chakravarty & Misra, 2022; Fu et al., 2021; Schoenball et al., 2020), continuous monitoring of borehole displacements to delineate hydraulic fractures' growth (Guglielmi et al., 2021), novel tracer tests using microbial community composition to identify natural fractures and well connectivity (Zhang et al., 2020, 2022), and so on. In general, any single monitoring method can hardly eliminate uncertainties, rooted in large‐scale fractured rock mass, to precisely capture every detail of the fracture.…”

Finite‐Size Scaling for the Permeability of Discrete Fracture Networks

“…Such a feature plays different roles in geo‐engineering applications. For instance, fracture networks can boost oil/gas extractions in hydraulic fracturing operations (Cheng & Bunger, 2019; Egert et al., 2021; Li & Zhang, 2021; Sanderson & Nixon, 2015); but radionuclides migrate easily within fractures, which brings the performance of deep nuclear waste storage into question (Orellana et al., 2019; Tsang et al., 2015; Viswanathan et al., 2022). Therefore, the evaluation of permeability for fracture networks is pivotal for geo‐engineering.…”