Geothermal energy is “having a moment.” It has been part of the global energy mix for many decades, but growth has been limited by the relatively limited number of sites with optimal geologic conditions. Technologies developed in the oil and gas sector have the potential to overcome these limitations and unlock dramatically increased geothermal production in the US and worldwide. Success is far from certain, but with the enthusiasm, ingenuity, and capital flowing toward these technologies, there is a realistic shot at breakthrough success.
Geothermal energy comes in a variety of flavors, from shallow heat-pump systems used for residential heating and cooling to deep, hot wells drilled for electricity production. While opportunities exist across this spectrum, this column is specifically concerned with the drilling of deep, high-temperature wells for electricity production.
Flow rate is a major challenge for geothermal. The energy content of one barrel of hot water is much lower than the energy content of one barrel of oil. Thus, to achieve profitability, geothermal wells must produce the equivalent of tens of thousands of barrels of water or steam per day. Across much of the western US, temperatures are hot enough for geothermal electricity production within reasonable drilling depth. However, in the absence of special geologic conditions from a hydrothermal system, wells usually cannot produce sufficient rate.
Dating back to the 1970s, hydraulic stimulation has been tested as a way of increasing flow rate per well. Designs utilize injection and producer wells, with fluid heating up as it circulates between the wells. If engineers could use stimulation to consistently achieve high flow rates, a vast resource would be unlocked. The US Department of Energy’s (DOE) 2019 GeoVision report estimates that more than 60 GWe could be produced in the US by 2050.
To date, success with hydraulic stimulation has been limited. Conventionally, geothermal wells have been drilled vertically and then stimulated by injecting only water (no proppant) into a single openhole section (without using multiple stages). Engineers have hoped that the injected water would shear-stimulate a dense network of natural fractures, with a large amount of surface area and fracture conductivity. These designs can yield modest success because geothermal wells are usually drilled in high-strength rock in the crystalline basement, and so fractures have considerable self-propping capability. However, rather than creating a dense network, flow tends to localize into a small number of dominant flowing pathways. Without a large number of flowing pathways, the reservoirs lack the ability to sustain high rate and are subject to thermal short circuiting that prematurely reduces the production temperature.
Fortunately, similar problems have been encountered and solved by the shale industry. The shale revolution was unlocked by the application of multistage hydraulic fracturing along horizontal wellbores. Mechanical isolation allows sequential injection into sections of the well. Within each stage, perforation pressure drop is used to force fluid to flow into multiple pathways along the well. Perforation clusters are spaced tightly—typically from 10 to 50 ft. Recent core-through studies confirm that stimulation is creating hundreds or thousands of conductive fractures along each fractured lateral.
