Geothermal energy provides clean, steady and renewable electricity and heat, but the use of geothermal energy has conventionally been constrained to locations with adequate subsurface heat and fluid flow. Enhanced geothermal systems (EGS) enable geothermal energy usage in unconventional areas by enhancing the subsurface permeability and increasing fluid flow, which is then extracted as a carrier of the thermal energy. In this Review, we discuss the development of EGS and its role in providing energy. Some EGS are operating commercially in Europe and provide heat and/or electricity, but technical issues and concerns over induced seismicity have historically hindered the broader expansion of EGS. Adaptation of advanced drilling techniques (including the use of polycrystalline diamond compact bits, multiwell drilling pads, horizontal drilling and multistage stimulation) is enabling an increase in scale and decrease in cost of EGS projects. As a result, in the USA, enhanced geothermal is expected to achieve plant capital costs (US$4,500 kW⁻¹) and a levelized cost of electricity (US$80 MWh⁻¹) that are competitive with market electricity prices by 2027. With further development of EGS to manage induced seismicity risk and increase system flexibility, EGS could provide stable baseload and potentially dispatchable electricity in clean energy systems.

Despite the wide application of hydraulic fracturing in enhanced geothermal system (EGS) development and unconventional hydrocarbon production, our understanding of the many factors affecting the propagation of hydraulic fractures has relied on circumstantial evidence. This is partly due to the scarcity of direct observations in the subsurface. The EGS Collab project attempts to address this issue in the context of EGS research by performing intermediate-scale (∼10 m) hydraulic stimulation experiments in a thoroughly characterized and heavily instrumented underground testbed. This paper analyzes the data collected from the first suite of hydraulic fracturing tests in this testbed, consisting of seven stimulation episodes. High-quality microseismic data delineate five planar features very clearly. Combining fracture-wellbore intersection observations from distributed temperature sensing (DTS) and visual observations from an open-hole well, as well as prior in situ stress measurements, we conclude with high certainty that the four larger planes were hydraulic fractures. The growth of the hydraulic fractures was temporarily halted by a prominent, open natural fracture in the testbed but they eventually crossed and slightly reoriented under continued stimulation. Mineral-filled (i.e. healed) natural fractures, though prevalent in the testbed, did not have perceivable effects on hydraulic fracture propagation. The high quality, mutually corroborating datasets allowed conclusions to be drawn with high confidence and attests to the advantage of intermediate-scale experiments in subsurface research.

Understanding flow mechanisms in fractured media is essential for geoscientific research and geological development industries. This study used 3‐D printed fracture networks in order to control the properties of fracture distributions inside the sample. The accuracy and appropriateness of creating samples by the 3‐D printer was investigated by using a X‐ray CT scanner. The CT scan images suggest that the 3‐D printer is able to reproduce complex three‐dimensional spatial distributions of fracture networks. Use of hexane after printing was found to be an effective way to remove wax for the posttreatment. Local permeability was obtained by the cubic law and used to calculate the global mean. The experimental value of the permeability was between the arithmetic and geometric means of the numerical results, which is consistent with conventional studies. This methodology based on 3‐D printed fracture networks can help validate existing flow modeling and numerical methods.