Drilling advances

As geothermal gains traction as a clean power source, it likewise speaks to the evolving impact of drilling engineers amid the incipient energy transition. 

While a few currents produced from maturing enhanced geothermal systems (EGS) are starting to course through electrical grids, an economic imbalance is blocking earth-generated heat from taking a significant slice of the U.S. energy mix. "As you know, EGS has been around for 40 years, but there are no commercial power plants and that's because it’s not cost-effective," Cindy Taff, CEO of Sage Geosystems, said as part of a panel discussion at the IADC Drilling Engineering Committee's (DEC) technical forum on Nov. 1. That forum explored drilling's role in geothermal development. "I think as an industry, we need to focus on driving the costs down and improving efficiency,” added Taff. 

While EPA Class II injection wells for oil and gas production will continue to take a predominant percentage of new drills for the foreseeable future, the IADC says projections have between 1,000 and 3,000 new geothermal wells being drilled every year over the next decade. Add to that, the expected increase in EPA Class VI wells used for the permanent geologic sequestration of carbon dioxide (CO2 ), and it becomes clear that the traditional functions of contemporary drilling engineers and well designers are markedly different from their peers of yesteryear. Much of the work today is centered on trying to replicate the advancements made in drilling harsh-environment and unconventional oil and gas wells safely and within budget. 

 In many ways, modern EGS wells resemble their hydrocarbon brethren with highly deviated multi-lateral holes, but there are peculiarities, not the least of which is dealing with constant heat cycling. Combined with efficiently delivering a widely divergent production stream, drilling in these subterranean environments requires a new look at both technologies and practices.  

Forging ahead. Accelerating the refinement of ESG tools and practices to make the renewable technology commercially viable has been the driving force behind the U.S. Department of Energy's National Energy Technology Laboratory (NETL)-funded Frontier Observatory for Research in Geothermal Energy (FORGE) field laboratory in Milford, Utah. The most recent application in the nearly 10-year-old project has researchers evaluating cores and other data from the 16B production well drilled to total depth of 10, 947 ft (8,357 ft, vertical depth), some 300 ft parallel to above the original injection well.  

"The well was drilled with three frac stages, and the plan was to intersect the fractures put in by the 16 (injection) well," Dr. Sam Noynaert, Texas A&M University petroleum engineering professor, told the forum. "It's very similar to the HFTS (hydraulic fracture test sites) projects many of you may have been involved in, out in West Texas, where you drill a well, frac it and then come back in and try to cut those fractures with cores. At some point, we're going to complete the well and have a series of frac stages put in there."  

Operating under a DOE grant, Texas A&M's objectives are to "refine drilling methods and create a cost-saving business model for future geothermal energy companies," according to a FORGE-related website.  

FORGE features subsurface conditions that are not for the faint of heart, including the presence of granite from around 4,000 to 8,000 ft, packing unconfined compressive strengths (USC) of 30 to more than 40 ksi. Nevertheless, Noynaert said researchers have managed to reduce drilling time by 85% since the project kicked off in 2015. "Overall, the goal is to decrease surface area exponentially to allow for improved heat exchange, and that's kind of the whole point of ESG," he said.  

Surrounded by a developed energy infrastructure, simply defining FORGE as a field laboratory is a bit of a misnomer, Noynaert said. "The energy produced here will go into the grid."   

Leveraging O&G technologies. In Nevada, Houston-based geothermal operator Fervo Energy put 3.5 MW into the local grid this past summer from a vertical ESG development well and is wrapping up a horizontal four-well pad that will deliver a combined 400 MW from 8 3/4-in. laterals. "Our ESG uses injector and producer wells, where we establish a fracture network and inject water to stimulate the reservoir to about 400oF," said Drilling Engineering Manager Elliot Howard.  

Howard said Fervo brings oil and gas technologies, such as PDC bits, high-temperature water-based drilling fluids and high-torque top drives, which have been perfected over the last 10 to 20 years, to next-generation geothermal wells. "A lot of our challenges are no different. Physics is still physics. The rocks are hard and abrasive, so you have to figure out how to have functional and stable drilling, improve your lubricity and reduce shocks and vibrations. Also, how do you manage temperature while staging in? Downhole temperature can be in the 200 to 250oF range while circulating, but when you're tripping in, how do you manage the temperature (spikes) during that process? Those are some of the things we see as challenges, but we're finding solutions to those," he said.  

Sage's Taff, likewise, says existing oil and gas tools are fine and dandy for the Houston operator's ESG projects, illustrated by a 19,000-ft, TD, straight hole test well in Starr County, Texas. "The oil and gas industry has been drilling at these depths and temperatures for a long time. So, our strategy is to use existing off-the-shelf oil and gas drilling technology. We're trying to figure out the geomechanics and thermodynamics to make geothermal more cost-effective," she said. 

Mike Hodder, V.P. of well engineering and operations for Calgary-based geothermal developer Eavor Technologies, agrees, saying, "We use a lot of the same oil and gas drilling technologies, but are working on how to manage the temperature aspects and drill cheaper."      

NETL's FORGE Manager Scott Beautz said the long-term effects of thermal cycling on wellbore integrity remains an open question. "There are concerns about cement and these constant heating and cooling cycles and the effect on wellbore shrinkage and expansion that could lead to microannulus or cracks in your isolation." 

While conceding "we're just beginning in this venture," Ashok Santra, a Saudi Aramco Americas geoscientist and cement specialist, said work is ongoing to develop concentrations to head off heat degradation, with the aim of ensuring the long-term lives of geothermal wells.  

About the Authors

Jim Redden

Contributing Editor

Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.