Exploring the Limitations of Fracture Caging in NextGen Enhanced Geothermal Systems

ABSTRACT Fracture caging limits hydraulic fracture growth and the activation of faults during high-rate high-pressure fluid injection using pre-drilled boundary wells around the injection well. If successful, this approach could offer a means to limit injection induced seismic magnitudes by preventing the activation of large faults outside of the cage. This concept has many possible applications, but the most relevant should be geothermal energy where caging could enable safe and economic energy production. In this study we explore the validity of caging using experiments and models to identify the well design, flow rate, economic, and engineering limits for deploying caging successfully in the field. Our work shows that the two primary mechanisms for failure of a cage can be attributed to poor well-fracture connectivity due to poor well placement in uncertain stress fields or due to undersized production wells. Ultimately, we find that (1) fracture caging combined with (2) limited entry injection wells, (3) high-temperature directional drilling, and (4) sustained high-pressure high-rate injection could unlock vast reserves of geothermal energy, all without requiring major new technological advancements. INTRODUCTION The concept of fracture caging was initially focused on containing the growth of hydraulic fractures by placing boundary wells around an injection well prior to high-pressure high-rate hydraulic stimulation (Frash et al., 2018). In addition, it appears to be possible that fracture caging could offer control over injection induced seismic magnitudes by preventing the activation of faults outside of the cage (Frash et al., 2020). Such a capability would greatly benefit geothermal energy applications by safely enabling fluid injection at the high rates that are required for economic energy production (Frash, 2022b; Frash et al., 2023). Simply put, it is possible that fracture caging could eliminate the need for conventional pressure and flow rate limits, but to do so, its reliability must be proven. Unlike the conventional pressure management approach, caged injection assumes that the critical pore pressure for shear slip and that the hydraulic fracturing breakdown pressure will be reached during stimulation, periodically after stimulation, or perhaps even continuously during the operation of an Enhanced Geothermal System (EGS) in Hot Dry Rock (HDR). Similar to what routinely occurs during typical oil and gas hydraulic fracturing operations, this fluid injection will trigger low energy microseismic events (Ellsworth, 2013). However, with caging, a set of pre-drilled boundary wells are emplaced to intercept this high-pressure fluid before it can leak out into the wider environment and risk triggering damaging earthquakes. Furthermore, we anticipate that the microsiesmicity that does occur will be limited to the volume of rock that is defined by the geometry of the boundary-well cage. If designed and implemented correctly, we expect that the signature of fracture caging should be steadily increasing microseismic event frequency and magnitude until the events abruptly cease and the site lays quiet, despite continuing high-rate and high-pressure fluid injection. Comparable phenomenon has been observed both in the laboratory (Frash et al., 2020) and the field (GERD, 1991) for fracture-dominated rock that contained both injection and production wells. However, evidence does not yet exist to prove that caging can be reliably achieved, nor has an analysis been completed to show that the upfront cost of drilling both an injection well and a set of production wells is justifiable with respect to uncertainty and future power production. Lacking a suitable alternative, we have been developing a stochastic EGS design tool, GeoDT, to evaluate the physics, statistics, and economics of caging as a potential enabling key to NextGen EGS development. In addition, we have been completing lab experiments to demonstrate fracture caging and its limits.