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Putting geothermal projects on the fast track

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Energy Global,

Ted Moon, Tony Pink, and Alexis Garcia, NOV, makes the case for how resource management solutions developed for oil and gas can accelerate the commercialisation of geothermal projects.

Geothermal energy is both the largest potential source of renewable energy on earth and the one that is used the least.

The earliest applications – hot springs for local heating and bathing in ancient Rome, and the use of geothermal power plants for generating a few hundred kilowatt-hours of electricity in the early 1900s – only scratched the surface of geothermal’s potential as a reliable, carbon-free, always-on energy source. Even today, conventional geothermal power production capacity totals roughly 16 GW worldwide, which is just 0.5% of electricity generation capacity from renewables.1

But now a combination of factors (technology advancements, societal demand for sustainable energy, and bi-partisan governmental support for renewable energy projects that promise long-term job growth) are aligned to take geothermal energy from a minority player to a mainstream provider of safe, reliable, and widely-available heat and baseload electrical power.

There is growing enthusiasm for enhanced geothermal systems (EGS), which inject water into dry geological formations at temperatures from 150°C – 300°C (302°F – 572°F) and bring the superheated water back to the surface for district heating and power generation. Groups like the Clean Air Task Force (CATF) see EGS production and superhot rock projects, which are a deeper and hotter extension of EGS (Figure 1), as viable means of expanding geothermal’s global reach by eliminating the need to tap into natural steam in shallow, lower-temperature reservoirs.2 These steam reservoirs are only located in select spots around the world, many of which have a long history of cultural significance to the region.

But despite EGS’ promise, the pace of commercialising EGS projects remains painfully slow. CATF points to a lack of engineering investments and limited engagement with an industry that has the people, technical know-how, and practical experience required to bring commercial scale EGS projects online in less time and at lower costs – namely, oil and gas.

CATF sees technology companies, such as NOV, as taking a critical role in applying proven oil and gas drilling, completion, and production solutions to advance EGS. NOV is uniquely positioned to take its 160 years of technology innovations developed for oil and gas and make the right engineering iterations to deliver for geothermal. And, just as importantly, the company has the necessary resource management and process implementation services to shorten the time to get commercial EGS projects up and running.

NOV is actively working to resolve several challenges to shorten EGS’ commercialisation timeline and ensure reliable, long-term resource management for decades of steady geothermal generation.

Optimising drilling systems for higher rate of penetration and fewer trips

The high cost of drilling, which currently represents more than half the cost of developing a geothermal project, is a major factor in the slow pace of commercialisation. It is also slowing the progress of the U.S. Department of Energy’s (DOE) Enhanced Geothermal Shot, an initiative to cut EGS costs by 90% to US$45/MWh by 2035.3 EGS drilling is so expensive due to the extreme environments and depths where the source rock is found. EGS reservoirs are drilled through granite formations 10 – 20 times harder than sidewalk cement and reach temperatures of 250°C (482°F) or higher. These conditions can quickly damage or destroy drill bits – adding time and additional trips to the surface to make repairs or replacements.

NOV’s ReedHycalog business unit developed the PhoenixTM series of high-performance polycrystalline diamond compact (PDC) drill bits to withstand these conditions and drill farther and faster in hard rock. Drawing on extensive product development expertise and rapid prototyping capabilities at NOV’s Engineering, Research, and Development Test Centers in Texas, Phoenix drill bit specialists design, build, and test specific drill bits that last longer, increase rate of penetration (ROP), and lower overall drilling costs for a given geothermal application.

Case study: USA

ReedHycalog tested its drill bit selection process in a well at the DOE’s Frontier Observatory for Research in Geothermal Energy (FORGE) project in Utah. Initial discussions with the DOE on the nature of the geothermal drilling environment and anticipated challenges informed the optimal drill bit design for the well. Advanced cutter testing and failure analysis from previous wells helped identify the most suitable cutter shape, diamond grade, bit body, and chamfer type for the specific rock composition and drive type. The resulting systematic improvements helped mitigate similar bit failure risks for more reliable drilling of longer intervals.

Based on this upfront drill bit analysis and design work, ReedHycalog built a 9.5 in. Phoenix TKC83 drill bit for the FORGE well test (Figure 2). This test well would mirror a previously drilled well with a 300 ft TVD offset, a 5°/100-ft curve, and a 65° tangent to reach a target zone with a bottomhole temperature ranging from 220°C – 230°C (428°F – 446°F).4

Drilling followed a Limiter Redesign Workflow developed by researchers at Texas A&M University to identify and address factors that limit the efficiency of the well construction process.5 ReedHycalog stayed engaged during this workflow by analysing digital data and dulls daily and redesigning bits to redistribute cutter wear, increase aggressiveness, and make iterative changes to cutter grade and shape.

This process improved bit longevity and ROP while reducing drilling time and costs. While the previous well logged a total on-bottom time for the drill bit of 312.3 hours, the optimised Phoenix bit reduced the on-bottom time by 63% to just 115.6 hours. In addition, the new bit drilled through 500 ft (152 m) of granite with an average ROP of 109 ft/h (33 m/h) without the need for replacement or repairs, proving that this optimised design workflow increases bit longevity and ROP to reach the target zone in less time.

Case study: New Zealand

This same drill bit optimisation process helped reduce geothermal well construction costs in New Zealand. The country’s volcanic and interbedded formations create drilling challenges for conventional roller cone bits that lower ROP and shorten bearing life, resulting in costly bit refurbishments.

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For more news and technical articles from the global renewable industry, read the latest issue of Energy Global magazine.

Energy Global's Winter 2023 issue

The Winter 2023 issue of Energy Global hosts an array of technical articles weather analysis, geothermal solutions, energy storage technology, and more. This issue also features a regional report looking at the future of renewables in North America, and a report from Théodore Reed-Martin, Editorial Assistant, Energy Global, on how Iceland utilises its unique geology for renewable energy.

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