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 200oF-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. WO
JIMREDDEN@SBCGLOBAL.NET / JIM REDDEN, a Houston-based consultant and a journalism graduate of Marshall University, has more than 45 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.