Drilling advances

The headline of a June 27 editorial in The Wall Street Journal came straight from the playbook of the Republicans’ unsuccessful 2008 U.S. presidential campaign: “Drill, Baby, Drill is the Future.” However, in a twist to that rally cry for increased oil and gas drilling, the commentary bowed to a world demanding less carbon-spewing energy sources, and called for exploitation of another subsurface, but comparably greener, pocket of energy, namely geothermal.

The idea of drilling deep into the earth’s mantle and injecting water into extremely hot formations to produce electric-generating steam is certainly not a contemporary creation. While a number of geothermal installations have long been in production elsewhere, North America has a way to go before it catches up with the rest of the world, and geothermal becomes a viable component of the continent’s energy mix. Only around 20 commercial geothermal wells are drilled per year in North America, seemingly providing little incentive to advance the metallurgy and associated drilling technologies to corral in-situ temperatures that can routinely exceed 600°F (320°C) and destroy often-fractured rock with compressive strengths of 50,000 psi. Any constructed well also must possess the integrity to deliver steam for up to 30 years.

As the editorial suggests, the current societal and political temperature could well give new life to the geothermal sector. Taking note, the IADC’s Drilling Engineering Committee (DEC) convened industry, academic and government representatives on June 30 to examine the extreme drilling challenges confronting geothermal operators. The drilling difficulties dovetail with demanding economic constraints, which DEC chairman and retired Marathon Oil technical consultant Dennis Moore put in clear perspective. “Hot water is just not as valuable as petroleum, therefore, you have to go for bigger volumes. As drilling engineers, that gives us more difficulty in making a big hole, deep and into a hot, hard-rock formation,” he said at the onset of the virtual technology forum.

Challenges aplenty. While today’s Enhanced Geothermal Systems (EGS) have adapted many oil and gas drilling advancements, including directional well trajectories, closed-loop systems and hydraulic fracing, the comparative cost/ft is totally out of whack. Much of that disparity can be traced to the few geothermal wells being drilled. Unlike the extensive databases that usually accompany hydrocarbon wells, their higher-risk geothermal counterparts are typically drilled blind, which especially puts contractors at a decided disadvantage. “When we start to drill, we don’t have the analysis or database like we have with oil and gas wells,” says Hani Ibrahim, who heads up Helmerich & Payne’s Well Construction Management Solutions.

In a nod to high-profile oil and gas drilling programs, Ibrahim recommends all parties be assembled for a drill-well-on-paper (DWOP) exercise, well ahead of the spud date, allowing ample time for any mitigations to be implemented and the delivery of often non-standard tools. “With proper planning and procedures, I think we can pretty much drill anything right now,” adds Ozgur Balamir, drilling manager for California-based GeothermEX, which claims to have participated in 60% of the geothermal wells drilled in some 56 countries.

Given the takeaway restrictions of steam, most geothermal wells must be drilled close to power plants and other end-users, much like a residential heat pump. This requirement poses a challenge, as geothermal wells normally are drilled in select areas with very high temperature gradients, closer to surface. Being forced to drill wells anywhere to connect directly to the consumer, drillers may be forced to land wells between 4 and 6 mi (7-10 km) deep, to tap the thermal zone, says Eric van Oort, a University of Texas at Austin professor of petroleum engineering.

Citing International Energy Agency (IEA) data, Dr. Van Oort said to be profitable and compete with other renewable energy sources, geothermal has to come in at no less than $100/megawatt hour. “When you look at the typical rate of penetration (ROP) of geothermal wells, we’re at around $700/megawatt hr,” he said. “We need to drill these hard rocks at around 164 ft/hr (50 m/hr) and also generate more reservoir exposure and depth through multi-laterals in the high-temperature zone and by using a more efficient heat cycle, among other things.”

FORGEing ahead. The high well construction costs are being targeted by the U.S. Department of Energy (DOE)-funded Frontier Observatory for Research in Geothermal Energy (FORGE) project in Utah, dedicated to advancing EGS technologies and techniques. To that end, the Petroleum Engineering Department of Texas A&M University is working under a DOE contract to transfer its physics-based drilling model from oil and gas to geothermal wells.

One of the onsite researchers, Associate Professor of Engineering Practice Sam Noynaert, said while continuous improvement is hard to measure, promising cost-reducing signs are emerging, like the successful running of a five-bladed PDC bit in a long section of granite. “Using PDC bits to drill long sections of granite is unique,” he said. “We’re now looking at a well, where (a PDC bit) run of over 1,000 ft is expected.”

Owing to the paucity of geothermal wells drilled, it is critical that each new well be treated like a data treasure chest, says DOE Geothermal Project Monitor/Engineer George Stutz. “Every well that you drill is a very important data point, so we need to extract as much information from every well that we can,” he said. “It’s hard to drill the perfect well, if you don’t know what it is, so every well you drill becomes very, very important.” 

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.