Conference aims to spur development of geothermal production in oil and gas fields

SMU’s renowned Geothermal Lab will host its sixth Geothermal Energy Utilization Conference March 12-14 on the SMU campus in Dallas. Jon Wellinghoff, chairman of the Federal Energy Regulatory Commission, will be the keynote speaker and Doug Hollett, program manager of the U.S. Department of Energy Geothermal Technologies Program, will speak at an evening reception.

The conference will advance the understanding of technology that allows the production of emission-free energy while extending the life of an oil or gas field – developing a sedimentary basin into a total energy solution. The conference (and pre-conference workshop on March 12) bring together leaders from business, engineering, finance, law, and research to explore specific topics relevant to capturing energy that is often overlooked or discarded during oil and gas production.

The same technology that can power oil and gas surface equipment from waste heat (WHP) also is capable of converting waste fluids from oil and gas wells into electrical power. Both technologies have proven applications in oil and gas fields in Mississippi and Wyoming, and WHP installations are widespread in manufacturing.Generating electricity on-site in an oil and/or gas field reduces overall project expenses, eliminates CO2 emissions, decreases dependency on the local electrical grid and may qualify for state Renewable Energy Credits (RECs).

David Blackwell, SMU’s Hamilton Professor of Physics and an internationally recognized expert in geothermal energy, said, “Collaborative research between UT Austin’s Bureau of Economic Geology and SMU’s Geothermal Laboratory has dramatically advanced the understanding of unconventional reservoir thermal capacity within Texas oil and gas fields. The quantities of heat that can be extracted from these reservoirs are more measurable than previously stated, and the estimated pricing of this renewable electricity using geothermal technology drops to below 10 cents per kilowatt-hour with the use of existing oil and gas well sites.

“The next steps are to prove the reservoir fluid flow rates and longevity,” Blackwell said. “The current Texas Legislature session includes geothermal energy related bills, as the legislators now understand that geothermal energy development will be realized in the state.”

Register for the conference and pre-conference workshop at http://smu.edu/geothermal/Oil&Gas/registration/default2013.asp.


Separate registration is available at the same site for Wellinghoff’s keynote luncheon for those unable to attend the entire conference. All conference attendees will hear a single track of presentations, with 30-minute breaks designed for networking and team building.

SMU’s Geothermal Laboratory is a national resource for the development of clean, green energy from the Earth’s heat.

Historically, geothermal development was restricted to areas with substantial tectonic activity or volcanism, such as The Geysers field in California. But sophisticated mapping of geothermal resources in recent years directed by Blackwell and Maria Richards, coordinator of SMU’s Geothermal Laboratory, makes it clear that vast geothermal resources reachable through current technology could replace the levels of energy now produced in the United States, mostly by coal-fired power plants.

Recent technological developments are feeding increased geothermal development in areas with little or no tectonic activity or volcanism:

  • Low Temperature Hydrothermal – Energy is produced from subsurface areas with naturally occurring high fluid volumes at temperatures ranging from less than boiling to 300°F (150°C).

  • Geopressure and Coproduced Fluids Geothermal – Oil and/or natural gas are produced together with electricity generated from hot geothermal fluids drawn from the same well.

  • Enhanced Geothermal Systems (EGS) – Subsurface areas with low fluid content but high temperatures are “enhanced” with injection of fluid and other reservoir engineering techniques. EGS resources are typically deeper than hydrothermal resources and represent the largest share of total geothermal resources capable of supporting larger capacity power plants.

Geoscientist cites critical need for basic research to unleash promising energy sources

“There is a critical need for scientists to address basic questions that have hindered the development of emerging energy resources, including geothermal, wind, solar and natural gas, from underground shale formations,” said Mark Zoback, a professor of geophysics at Stanford University. “In this talk we present, from a university perspective, a few examples of fundamental research needs related to improved energy and resource recovery.”

Zoback, an authority on shale gas development and hydraulic fracturing, served on the U.S. Secretary of Energy’s Committee on Shale Gas Development. His remarks will be presented in collaboration with Jeff Tester, an expert on geothermal energy from Cornell University, and Murray Hitzman, a leader in the study of “energy critical elements” from the Colorado School of Mines.

Enhanced geothermal systems

“One option for transitioning away from our current hydrocarbon-based energy system to non-carbon sources is geothermal energy – from both conventional hydrothermal resources and enhanced geothermal systems,” said Zoback, a senior fellow at the Precourt Institute for Energy at Stanford.

Unlike conventional geothermal power, which typically depends on heat from geysers and hot springs near the surface, enhanced geothermal technology has been touted as a major source of clean energy for much of the planet.

The idea is to pump water into a deep well at pressures strong enough to fracture hot granite and other high-temperature rock miles below the surface. These fractures enhance the permeability of the rock, allowing the water to circulate and become hot.

A second well delivers steam back to the surface. The steam is used to drive a turbine that produces electricity with virtually no greenhouse gas emissions. The steam eventually cools and is re-injected underground and recycled to the surface.

In 2006, Tester co-authored a major report on the subject, estimating that 2 percent of the enhanced geothermal resource available in the continental United States could deliver roughly 2,600 times more energy than the country consumes annually.

But enhanced geothermal systems have faced many roadblocks, including small earthquakes that are triggered by hydraulic fracturing. In 2005, an enhanced geothermal project in Basel, Switzerland, was halted when frightened citizens were shaken by a magnitude 3.4 earthquake. That event put a damper on other projects around the world.

Last year, Stanford graduate student Mark McClure developed a computer model to address the problem of induced seismicity.

Instead of injecting water all at once and letting the pressure build underground, McClure proposed reducing the injection rate over time so that the fracture would slip more slowly, thus lowering the seismicity. This novel technique, which received the 2011 best paper award from the journal Geophysics, has to be tested in the field.

Shale gas

Zoback also will also discuss challenges facing the emerging shale gas industry. “The shale gas revolution that has been under way in North America for the past few years has been of unprecedented scale and importance,” he said. “As these resources are beginning to be developed globally, there is a critical need for fundamental research on such questions as how shale properties affect the success of hydraulic fracturing, and new methodologies that minimize the environmental impact of shale gas development.”

Approximately 30,000 shale gas wells have already been drilled in North America, he added, yet fundamental challenges have kept the industry from maximizing its full potential. “The fact is that only 25 percent of the gas is produced, and 75 percent is left behind,” he said. “We need to do a better job of producing the gas and at the same time protecting the environment.”

Earlier this year, Zoback and McClure presented new evidence that in shale gas reservoirs with extremely low permeability, pervasive slow slip on pre-existing faults may be critical during hydraulic fracturing if it is to be effective in stimulating production.

Even more progress is required in extracting petroleum, Zoback added. “The recovery of oil is only around 5 percent, so we need to do more fundamental research on how to get more hydrocarbons out of the ground,” he said. “By doing this better we’ll actually drill fewer wells and have less environmental impact. That will benefit all of the companies and the entire nation.”

Energy critical elements

Geology plays a surprising role in the development of renewable energy resources.

“It is not widely recognized that meeting domestic and worldwide energy needs with renewables, such as wind and solar, will be materials intensive,” Zoback said. “However, elements like platinum and lithium will be needed in significant quantities, and a shortage of such ‘energy critical elements’ could significantly inhibit the adoption of these otherwise game-changing technologies.”

Historically, energy critical elements have been controlled by limited distribution channels, he said. A 2009 study co-authored by Hitzman found that China produced 71 percent of the world’s supply of germanium, an element used in many photovoltaic cells. Germanium is typically a byproduct of zinc extraction, and China is the world’s leading zinc producer.

About 30 elements are considered energy critical, including neodymium, a key component of the magnets used in wind turbines and hybrid vehicles. In 2009, China also dominated the neodymium market.

“How these elements are used and where they’re found are important issues, because the entire industrial world needs access to them,” Zoback said. “Therefore, if we are to sustainably develop renewable energy technologies, it’s imperative to better understand the geology, metallurgy and mining engineering of these critical mineral deposits.”

Unfortunately, he added, there is no consensus among federal and state agencies, the global mining industry, the public or the U.S. academic community regarding the importance of economic geology in securing a sufficient supply of energy critical elements.

Panel discussion

Immediately following the Dec. 4 AGU talk, Zoback will participate in a panel discussion at 5:35 p.m. on the challenges and opportunities for energy and resource recovery. The panel will be led by Joseph Wang of the Lawrence Berkeley National Laboratory and will include William Brinkman of the U.S. Department of Energy’s Office of Science; Marcia McNutt, director of the U.S. Geological Survey; and Jennifer Uhle of the U.S. Nuclear Regulatory Commission’s Office of Nuclear Regulatory Research.

On Wednesday, Dec. 5, at 12:05 p.m., Zoback will deliver another talk on the risk of triggering small-to-moderate size earthquakes during carbon capture and storage.

Carbon capture technology is designed to reduce greenhouse gas emissions by capturing atmospheric carbon dioxide from industrial smokestacks and sequestering the CO2 in underground reservoirs or mineral deposits.

Zoback will outline several elements of a risk-based strategy for assessing the potential for accidentally inducing earthquakes in carbon dioxide reservoirs. The talk will be held in Room 2004, Moscone Center West.

Mining for heat

Underground mining is a sweaty job, and not just because of the hard work it takes to haul ore: Mining tunnels fill with heat naturally emitted from the surrounding rock. A group of researchers from McGill University in Canada has taken a systematic look at how such heat might be put to use once mines are closed. They calculate that each kilometer of a typical deep underground mine could produce 150 kW of heat, enough to warm 5 to 10 Canadian households during off-peak times.

A number of communities in Canada and Europe already use geothermal energy from abandoned mines. Noting these successful, site-specific applications, the McGill research team strove to develop a general model that could be used by engineers to predict the geothermal energy potential of other underground mines. In a paper accepted for publication in the American Institute of Physics’ Journal of Renewable and Sustainable Energy, the researchers analyze the heat flow through mine tunnels flooded with water. In such situations, hot water from within the mine can be pumped to the surface, the heat extracted, and the cool water returned to the ground. For the system to be sustainable, heat must not be removed more quickly than it can be replenished by the surrounding rock. The team’s model can be used to analyze the thermal behavior of a mine under different heat extraction scenarios.

“Abandoned mines demand costly perpetual monitoring and remediating. Geothermal use of the mine will offset these costs and help the mining industry to become more sustainable,” says Seyed Ali Ghoreishi Madiseh, lead author on the paper. The team estimates that up to one million Canadians could benefit from mine geothermal energy, with an even greater potential benefit for more densely populated countries such as Great Britain.

Geothermal industry to get boost

Jim Faulds, geologist and research professor at the University of Nevada, Reno's Bureau of Mines and Geology, lectures his geothermal exploration class in April at the Fly Ranch Geyser north of Gerlach, Nev. -  Photo courtesy of the University of Nevada, Reno.
Jim Faulds, geologist and research professor at the University of Nevada, Reno’s Bureau of Mines and Geology, lectures his geothermal exploration class in April at the Fly Ranch Geyser north of Gerlach, Nev. – Photo courtesy of the University of Nevada, Reno.

An ambitious University of Nevada, Reno project to understand and characterize geothermal potential at nearly 500 sites throughout the Great Basin is yielding a bounty of information for the geothermal industry to use in developing resources in Nevada, according to a report to the U.S. Department of Energy.

The project, based in the University’s Bureau of Mines and Geology in the College of Science, is funded by a $1 million DOE grant from the American Recovery and Reinvestment Act of 2009. It has reached the one-year mark and is entering phase two, when five or six of the 250 identified potentially viable geothermal sites will be studied in more detail. Some of the studied sites will even have 3-D imaging to help those in the industry better understand geothermal processes and identify where to drill for the hot fluids.

The research aims to provide a catalog of favorable structural elements, such as the pattern of faulting and models for geothermal systems and site-specific targeting using innovative techniques for fault analysis. The project will enhance exploration methodologies and reduce the risk of drilling nonproductive wells.

Jim Faulds, principal investigator for the project, geologist and research professor at the University of Nevada, Reno, has a team of six researchers and several graduate students working with him on various aspects of the project.

“Of the 463 geothermal sites to study, we’ve studied and characterized more than 250 in the past year, either using existing records or on-site analyses,” Faulds said. “We’ll continue to study more of the sites so we can develop better methods and tools for geothermal exploration. Most, about two-thirds, of the geothermal resources in the Great Basin are blind – that is, there are no surface expressions, such as hot springs, to indicate what’s perhaps 1,500 feet below the surface.”

Better characterization of known geothermal systems is critical for new discoveries, targeting drilling sites and development, Faulds said. The success of modeling sites for exploration is limited without basic knowledge of which fault and fracture patterns, stress conditions, and stratigraphic intervals are most conducive to hosting geothermal reservoirs.

“The geothermal industry doesn’t have the same depth of knowledge for geothermal exploration as the mineral and oil industries,” he said. “Mineral and oil companies conducted extensive research years ago that helps them to characterize favorable settings and determine where to drill. With geothermal, it’s studies like this that will enhance understanding of what controls hot fluids in the earth’s crust and thus provide an exploration basis for industry to use in discovering and developing resources.”

Faulds and his team have defined a spectrum of favorable structural settings for geothermal systems in the Great Basin and completed a preliminary catalogue that interprets the structural setting of most its geothermal systems.

“This is the first attempt to broadly characterize and catalogue Great Basin geothermal systems in this way,” he said.

In addition, Faulds has developed and taught a geothermal exploration class, published many papers on his work and presented his work at many conferences, including the World Geothermal Congress in Bali, Indonesia and the GEONZ2010 Geoscience-Geothermal Conference in Auckland, New Zealand.

Faulds also presented information from his study at a session of the National Geothermal Academy today at the University of Nevada, Reno.

“We want to help the industry achieve acceptable levels of site-selection risk ahead of expensive drilling,” he said. “This study costs only $1 million, but it could cost a company several million dollars for drilling at a single prospect in the hopes that they hit a good hot well. Our research will provide the baseline studies that are absolutely needed if Nevada is going to become the Saudi Arabia of geothermal.”

Novel geothermal technology packs a one-two punch against climate change

Two University of Minnesota Department of Earth Sciences researchers have developed an innovative approach to tapping heat beneath the Earth’s surface. The method is expected to not only produce renewable electricity far more efficiently than conventional geothermal systems, but also help reduce atmospheric carbon dioxide (CO2) — dealing a one-two punch against climate change.

The approach, termed CO2-plume geothermal system, or CPG, was developed by Earth sciences faculty member Martin Saar and graduate student Jimmy Randolph in the university’s College of Science and Engineering. The research was published in the most recent issue of Geophysical Research Letters. The researchers have applied for a patent and plan to form a start-up company to commercialize the new technology.

Established methods for transforming Earth’s heat into electricity involve extracting hot water from rock formations several hundred feet from the Earth’s surface at the few natural hot spots around the world, then using the hot water to turn power-producing turbines. The university’s novel system was born in a flash of insight on a northern Minnesota road trip and jump-started with $600,000 in funding from the U of M Institute on the Environment’s Initiative for Renewable Energy and the Environment (IREE). The CPG system uses high-pressure CO2 instead of water as the underground heat-carrying fluid.

CPG provides a number of advantages over other geothermal systems, Randolph said. First, CO2 travels more easily than water through porous rock, so it can extract heat more readily. As a result, CPG can be used in regions where conventional geothermal electricity production would not make sense from a technical or economic standpoint.

“This is probably viable in areas you couldn’t even think about doing regular geothermal for electricity production,” Randolph said. “In areas where you could, it’s perhaps twice as efficient.”

CPG also offers the benefit of preventing CO2 from reaching the atmosphere by sequestering it deep underground, where it cannot contribute to climate change. In addition, because pure CO2 is less likely than water to dissolve the material around it, CPG reduces the risk of a geothermal system not being able to operate for long times due to “short-circuiting” or plugging the flow of fluid through the hot rocks. Moreover, the technology could be used in parallel to boost fossil fuel production by pushing natural gas or oil from partially depleted reservoirs as CO2 is injected.

Saar and Randolph first hit on the idea behind CPG in the fall of 2008 while driving to northern Minnesota together to conduct unrelated field research. The two had been conducting research on geothermal energy capture and separately on geologic CO2 sequestration.

“We connected the dots and said, ‘Wait a minute – what are the consequences if you use geothermally heated CO2?'” recalled Saar. “We had a hunch in the car that there should be lots of advantages to doing that.”

After batting the idea around a bit, the pair applied for and received a grant from the Initiative for Renewable Energy and the Environment, which disburses funds from Xcel Energy’s Renewable Development Fund to help launch potentially transformative projects in emerging fields of energy and the environment. The IREE grant paid for preliminary computer modeling and allowed Saar and Randolph to bring on board energy policy, applied economics and mechanical engineering experts from the University of Minnesota as well as modeling experts from Lawrence Berkeley National Laboratory. It also helped leverage a $1.5 million grant from the U.S. Department of Energy to explore subsurface chemical interactions involved in the process.

“The IREE grant was really critical,” Saar said. “This is the kind of project that requires a high-risk investment. I think it’s fair to say that there’s a good chance that it wouldn’t have gone anywhere without IREE support in the early days.”

Saar and Randolph have recently applied for additional DOE funding to move CPG forward to the pilot phase.

“Part of the beauty of this is that it combines a lot of ideas but the ideas are essentially technically proven, so we don’t need a lot of new technology developed,” Randolph said.

“It’s combining proven technology in a new way,” Saar said. “It’s one of those things where you know how the individual components work. The question is, how will they perform together in this new way? The simulation results suggest it’s going to be very favorable.”

Magma power for geothermal energy?

When a team of scientists drilling near an Icelandic volcano hit magma in 2009, they had to abandon their planned experiments on geothermal energy. But the mishap could point the way to an alternative source of geothermal power.

“Because we drilled into magma, this borehole could now be a really high-quality geothermal well,” said Peter Schiffmann, professor of geology at UC Davis and a member of the research team along with fellow UC Davis geology professor Robert Zierenberg and UC Davis graduate student Naomi Marks. The project was led by Wilfred Elders, a geology professor at UC Riverside.

A paper describing geological results from the well was published this month in the journal Geology.

When tested, the magma well produced dry steam at 750 degrees Fahrenheit (400 degrees Celsius). The team estimated that this steam could generate up to 25 megawatts of electricity — enough to power 25,000 to 30,000 homes.

That compares to 5 to 8 megawatts produced by a typical geothermal well, Elders said. Iceland already gets about one-third of its electricity and almost all of its home heating from geothermal sources.

The team was drilling into the Krafla caldera as part of the Iceland Deep Drilling Project, an industry-government consortium, to test whether “supercritical” water — very hot water under very high pressure — could be exploited as a source of power.

They planned to drill to 15,000 feet — more than two miles deep– but at 6,900 feet, magma (molten rock from the Earth’s core) flowed into the well, forcing them to stop.

The composition of magma from the borehole is also providing insight into how magmas form beneath Iceland, Schiffmann said.

Geologists get unique and unexpected opportunity to study magma

This is a view of the exploratory geothermal well during flow testing. -  Bjarni Palssen.
This is a view of the exploratory geothermal well during flow testing. – Bjarni Palssen.

Geologists drilling an exploratory geothermal well in 2009 in the Krafla volcano in Iceland encountered a problem they were simply unprepared for: magma (molten rock or lava underground) which flowed unexpectedly into the well at 2.1 kilometers (6,900 ft) depth, forcing the researchers to terminate the drilling.

“To the best of our knowledge, only one previous instance of magma flowing into a geothermal well while drilling has been documented,” said Wilfred Elders, a professor emeritus of geology in the Department of Earth Sciences at the University of California, Riverside, who led the research team. “We were drilling a well that was designed to search for very deep – 4.5 kilometers (15,000 feet) – geothermal resources in the volcano. While the magma flow interrupted our project, it gave us a unique opportunity to study the magma and test a very hot geothermal system as an energy source.”

Currently, a third of the electric power and 95 percent of home heating in Iceland is produced from steam and hot water that occurs naturally in volcanic rocks.

“The economics of generating electric power from such geothermal steam improves the higher its temperature and pressure,” Elders explained. “As you drill deeper into a hot zone the temperature and pressure rise, so it should be possible to reach an environment where a denser fluid with very high heat content, but also with unusually low viscosity occurs, so-called ‘supercritical water.’ Although such supercritical water is used in large coal-fired electric power plants, no one had tried to use supercritical water that should occur naturally in the deeper zones of geothermal areas.”

Elders and colleagues report in the March issue of Geology (the research paper was published online on Feb. 3) that although the Krafla volcano, like all other volcanoes in Iceland, is basaltic (a volcanic rock containing 45-50 percent silica), the magma they encountered is a rhyolite (a volcanic rock containing 65-70 percent silica).

“Our analyses show that this magma formed by partial melting of certain basalts within the Krafla volcano,” Elders said. “The occurrence of minor amounts of rhyolite in some basalt volcanoes has always been something of a puzzle. It had been inferred that some unknown process in the source area of magmas, in the mantle deep below the crust of the Earth, allows some silica-rich rhyolite melt to form in addition to the dominant silica-poor basalt magma.”

Elders explained that in geothermal systems water reacts with and alters the composition of the rocks, a process termed “hydrothermal alteration.” “Our research shows that the rhyolite formed when a mantle-derived basaltic magma encountered hydrothermally altered basalt, and partially melted and assimilated that rock,” he said.

Elders and his team studied the well within the Krafla caldera as part of the Iceland Deep Drilling Project, an industry-government consortium, to test whether geothermal fluids at supercritical pressures and temperatures could be exploited as sources of power. Elders’s research team received support of $3.5 million from the National Science Foundation and $1.5 million from the International Continental Scientific Drilling Program.

In the spring of 2009 Elders and his colleagues progressed normally with drilling the well to 2 kilometers (6,600 feet) depth. In the next 100 meters (330 feet), however, multiple acute drilling problems occurred. In June 2009, the drillers determined that at 2104 meters (6,900 feet) depth, the rate of penetration suddenly increased and the torque on the drilling assembly increased, halting its rotation. When the drill string was pulled up more than 10 meters (33 feet) and lowered again, the drill bit became stuck at 2095 meters (6,875 feet). An intrusion of magma had filled the lowest 9 meters (30 feet) of the open borehole. The team terminated the drilling and completed the hole as a production well.

“When the well was tested, high pressure dry steam flowed to the surface with a temperature of 400 Celsius or 750 Fahrenheit, coming from a depth shallower than the magma,” Elders said. “We estimated that this steam could generate 25 megawatts of electricity if passed through a suitable turbine, which is enough electricity to power 25,000 to 30,000 homes. What makes this well an attractive source of energy is that typical high-temperature geothermal wells produce only 5 to 8 megawatts of electricity from 300 Celsius or 570 Fahrenheit wet steam.”

Elders believes it should be possible to find reasonably shallow bodies of magma, elsewhere in Iceland and the world, wherever young volcanic rocks occur.

“In the future these could become attractive sources of high-grade energy,” said Elders, who got involved in the project in 2000 when a group of Icelandic engineers and scientists invited him to join them to explore concepts of developing geothermal energy.

The Iceland Deep Drilling Project has not abandoned the search for supercritical geothermal resources. The project plans to drill a second deep hole in southwest Iceland in 2013.

Geothermal mapping project reveals large, green energy source in coal country

New research produced by Southern Methodist University's Geothermal Laboratory, funded by a grant from Google.org, suggests that the temperature of the Earth beneath the state of West Virginia is significantly higher than previously estimated, and is capable of supporting commercial baseload geothermal energy production. The graphic shows subsurface West Virginia temperatures at various depths, with red points showing actual drilled temperatures. -  SMU Geothermal Laboratory
New research produced by Southern Methodist University’s Geothermal Laboratory, funded by a grant from Google.org, suggests that the temperature of the Earth beneath the state of West Virginia is significantly higher than previously estimated, and is capable of supporting commercial baseload geothermal energy production. The graphic shows subsurface West Virginia temperatures at various depths, with red points showing actual drilled temperatures. – SMU Geothermal Laboratory

New research produced by Southern Methodist University’s Geothermal Laboratory, funded by a grant from Google.org, suggests that the temperature of the Earth beneath the state of West Virginia is significantly higher than previously estimated and capable of supporting commercial baseload geothermal energy production.

Geothermal energy is the use of the Earth’s heat to produce heat and electricity. “Geothermal is an extremely reliable form of energy, and it generates power 24/7, which makes it a baseload source like coal or nuclear,” said David Blackwell, Hamilton Professor of Geophysics and Director of the SMU Geothermal Laboratory.

The SMU Geothermal Laboratory has increased its estimate of West Virginia’s geothermal generation potential to 18,890 megawatts (assuming a conservative two percent thermal recovery rate). The new estimate represents a 75 percent increase over estimates in MIT’s 2006 “The Future of Geothermal Energy” report and exceeds the state’s total current generating capacity, primarily coal based, of 16,350 megawatts.

Researchers from SMU’s Geothermal Laboratory will present a detailed report on the discovery at the 2010 Geothermal Resources Council annual meeting in Sacramento, Oct. 24-27. A summary of the report is available at http://smu.edu/smunews/geothermal/documents/west-virginia-temperatures.asp

The West Virginia discovery is the result of new detailed mapping and interpretation of temperature data derived from oil, gas, and thermal gradient wells – part of an ongoing project to update the Geothermal Map of North America that Blackwell produced with colleague Maria Richards in 2004. Temperatures below the Earth almost always increase with depth, but the rate of increase (the thermal gradient) varies due to factors such as the thermal properties of the rock formations.

“By adding 1,455 new thermal data points from oil, gas, and water wells to our geologic model of West Virginia, we’ve discovered significantly more heat than previously thought,” Blackwell said. “The existing oil and gas fields in West Virginia provide a geological guide that could help reduce uncertainties associated with geothermal exploration and also present an opportunity for co-producing geothermal electricity from hot waste fluids generated by existing oil and gas wells.”

The high temperature zones beneath West Virginia revealed by the new mapping are concentrated in the eastern portion of the state (Figure 1). Starting at depths of 4.5 km (greater than 15,000 feet), temperatures reach over 150°C (300°F), which is hot enough for commercial geothermal power production.

Traditionally, commercial geothermal energy production has depended on high temperatures in existing subsurface reservoirs to produce electricity, requiring unique geological conditions found almost exclusively in tectonically active regions of the world, such as the western United States. Newer technologies and drilling methods can be used to develop resources in wider ranges of geologic conditions. Three non-conventional geothermal resources that can be developed in areas with little or no tectonic activity or volcanism such as West Virginia are:

  • Low‐Temperature Hydrothermal – Energy is produced from areas with naturally occurring high fluid volumes at temperatures ranging from 80°C (165°F) to 150°C (300°F) using advanced binary cycle technology. Low-Temperature systems have been developed in Alaska, Oregon, and Utah.
  • Geopressure and Co-produced Fluids Geothermal – Oil and/or natural gas produced together with hot geothermal fluids drawn from the same well. Geopressure and Co-produced Fluids systems are currently operating or under development in Wyoming, North Dakota, Utah, Louisiana, Mississippi, and Texas.
  • Enhanced Geothermal Systems (EGS) – Areas with low natural rock permeability but high temperatures of more than 150°C (300°F) are “enhanced” by injecting fluid and other reservoir engineering techniques. EGS resources are typically deeper than hydrothermal and represent the largest share of total geothermal resources. EGS is being pursued globally in Germany, Australia, France, the United Kingdom, and the U.S. EGS is being tested in deep sedimentary basins similar to West Virginia’s in Germany and Australia.

“The early West Virginia research is very promising,” Blackwell said, “but we still need more information about local geological conditions to refine estimates of the magnitude, distribution, and commercial significance of their geothermal resource.”

Zachary Frone, an SMU graduate student researching the area said, “More detailed research on subsurface characteristics like depth, fluids, structure and rock properties will help determine the best methods for harnessing geothermal energy in West Virginia.” The next step in evaluating the resource will be to locate specific target sites for focused investigations to validate the information used to calculate the geothermal energy potential in this study.

The team’s work may also shed light on other similar geothermal resources. “We now know that two zones of Appalachian age structures are hot – West Virginia and a large zone covering the intersection of Texas, Arkansas, and Louisiana known as the Ouachita Mountain region,” said Blackwell. “Right now we don’t have the data to fill in the area in between,” Blackwell continued, “but it’s possible we could see similar results over an even larger area.”

Blackwell thinks the finding opens exciting possibilities for the region. “The proximity of West Virginia’s large geothermal resource to east coast population centers has the potential to enhance U.S. energy security, reduce CO2 emissions, and develop high paying clean energy jobs in West Virginia,” he said.

SMU’s Geothermal Laboratory conducted this research through funding provided by a Google.org’s initiative dedicated to using the power of information and innovation to advance breakthrough technologies in clean energy.

Study uses satellite imagery to identify active magma systems in East Africa’s Rift Valley

<IMG SRC="/Images/655508697.jpg" WIDTH="320" HEIGHT="450" BORDER="0" ALT="A team from University of Miami, University of El Paso and University of Rochester used Interferometric Synthetic Aperture Radar (InSAR) images compiled over a decade to study volcanic activity in the African Rift. A paper, published in the November issue of Geology, focuses on the section of the rift in Kenya. Surface deformation of four active volcanoes underscore possibility for human hazard, as well as the potential of geothermal resources. – J. Biggs, E.Y. Anthony,C.J. Ebinger”>
A team from University of Miami, University of El Paso and University of Rochester used Interferometric Synthetic Aperture Radar (InSAR) images compiled over a decade to study volcanic activity in the African Rift. A paper, published in the November issue of Geology, focuses on the section of the rift in Kenya. Surface deformation of four active volcanoes underscore possibility for human hazard, as well as the potential of geothermal resources. – J. Biggs, E.Y. Anthony,C.J. Ebinger

A team from the University of Miami, University of El Paso and University of Rochester have employed Interferometric Synthetic Aperture Radar (InSAR) images compiled over a decade to study volcanic activity in the African Rift. The study, published in the November issue of Geology, studies the section of the rift in Kenya.

“The Kenyan Rift volcanoes are part of a larger Great Rift Valley complex that extends all the way from Mozambique to Djibouti; their presence in East Africa attests to the presence of magma reservoirs within the Earth’s crust,” said Lead Author Dr. Juliet Biggs, Rosenstiel Postdoctoral Fellow at the University of Miami. “Our study detected signs of activity in only four of the 11 volcanoes in the area — Suswa, Menengai, Longonot and Paka — all within the borders of Kenya.”

Small surface displacements, which are not visible to the naked eye, were captured using InSAR, a sophisticated satellite-based radar technique. Using images from European Space Agency satellites ERS and Envisat, the team was able to detect the smallest ((<1 cm) of surface displacements at a very high resolution. From 1997 – 2000 they discovered that the volcanoes at Suswa and Menengai subsided 2 – 5 cm, and between 2004 and 2006 the Longonot volcano experienced uplift of ~9 cm. However, the most dramatic uplift unfolded at Paka, which had uplift of ~21 cm during a nine month period in 2006-2007. This pulse of activity was preceded by transient uplift and subsidence at a second source, associated with the magma flow through the complex underground plumbing system. Overall the events were short in duration and episodic rather than continuous, which means discrete pulses of magma were arriving at the crust, similar to a stop valve that is being turned on and off intermittently.

“The fact that these areas are so close to a major metropolitan area pose a challenge in terms of a large volcanic or seismic event” says co-author Cindy Ebinger. Suswa, Menengai and Longonot are all located in densely populated areas within 100 km of Nairoibi.

The study also provides insight as to the geothermal potential of the region. Kenya was the first African country to build geothermal energy plants to generate this renewable, environmentally friendly alternative to coal and oil. The impact of harnessing such a resource could provide an important economic engine for the region.

Geothermal energy is generated by drilling deep holes into the Earth’s crust, pumping cold water through one end so by the time it resurfaces it is steam, which is then used to fuel a turbine, which in turn drives a generator, and creates power.

“This study demonstrates the potential for using InSAR to measure active magmatic and tectonic phenomena in Africa, allowing us to watch the processes by which continents break apart” says lead author Juliet Biggs, who has just begun a 2-year project at the Univeristy of Oxford, funded by the European Space Agency, to map the pattern of volcanic activity, dike intrusion and active faulting along the whole of the East African Rift.

Making geothermal more productive

Steam rises from cooling towers as US Geothermal's Raft River geothermal power plant near Malta, Idaho. Researchers from the University of Utah's Energy and Geoscience Institute will inject cool water and pressurized water into a 'dry' geothermal well at the site during a $10.2 million study aimed at making existing power plants more productive and making geothermal power feasible nationwide. -  US Geothermal Inc.
Steam rises from cooling towers as US Geothermal’s Raft River geothermal power plant near Malta, Idaho. Researchers from the University of Utah’s Energy and Geoscience Institute will inject cool water and pressurized water into a ‘dry’ geothermal well at the site during a $10.2 million study aimed at making existing power plants more productive and making geothermal power feasible nationwide. – US Geothermal Inc.

University of Utah researchers will inject cool water and pressurized water into a “dry” geothermal well during a five-year, $10.2 million study aimed at boosting the productivity of geothermal power plants and making them feasible nationwide.

“Using these techniques to increase pathways in the rock for hot water and steam would increase availability of geothermal energy across the country,” says geologist Ray Levey, director of the Energy & Geoscience Institute (EGI), which is part of the university’s College of Engineering.

EGI geologist Joe Moore – who will head the research effort at U.S. Geothermal Inc.’s Raft River power plant in southeast Idaho – says most geothermal power in the United States now is produced west of the Rocky Mountains, where hot rocks are found closest to the surface.

“Hot rock is present across the United States, but new methods have to be developed to use the heat in these rocks to produce geothermal power,” says Moore. “We want to use oil and gas industry techniques to create pathways in the rock so that we can use the heat in the rocks to generate electricity.”

“There’s incredible potential in Utah and other states for geothermal development,” he adds. “Engineered geothermal systems [in which water is injected to enhance natural cracks in the rock] could provide a means of developing these resources much faster.”

The U.S. Department of Energy on Sept. 4 signed an agreement with the University of Utah and EGI to pay almost $7.4 million of the project’s cost.

The University of Utah is providing $1.1 million through the Office of the Vice President for Research. Another $1.7 million will be provided by discounts or cash or in-kind donations by two of EGI’s partners in the project: U.S. Geothermal, Inc. of Boise, and Apex HiPoint, LLC, of Littleton, Colo.

Moore says the university’s contribution will help fund involvement of graduate and undergraduate students from the College of Engineering and College of Mines and Earth Sciences.

Experiment at Raft River


“We’re going to take a geothermal field and improve its productivity,” Moore says. “We’re going to test the techniques on one well at Raft River. We’re testing methods to take wells that are not productive and make them productive.”

Moore says the Department of Energy did geothermal research for three decades at the site, located 11 miles from Interstate 84 in southeast Idaho halfway between Boise and Salt Lake City. Raft River is now a U.S. Geothermal power plant producing 10.5 to 11.5 megawatts of electricity – enough for roughly 10,000 homes. The power is sold to Idaho Power Co.

Some estimate the site may be capable of producing 110 megawatts of power. Researchers believe production can be increased because underground temperatures measure 275 to 300 degrees Fahrenheit at depths of 4,500 to 6,000 feet.

The Raft River plant currently has five “production” wells that produce geothermal energy and four “injection” wells where water from the production wells is returned to the underground geothermal reservoir. Water must be re-injected to maintain pressure in a geothermal power system.

One well drilled in recent years did not produce enough hot water to be used as a production well because it did not connect with enough of the underground cracks that carry the hot water.

“Geothermal wells are like oil wells – some wells produce and some don’t,” Moore says. “Drilling wells is expensive. That is why we need to develop low-cost techniques to improve their productivity.”

If the experiments run by EGI work, U.S. Geothermal eventually will operate the test well and put it into service.

Stimulating Geothermal Power by Cracking Hot Rock


To produce geothermal power, hot rock is not enough. The rock also must be permeable to the flow of water and-or steam, says John McLennan, an engineer at EGI. Many geothermal reservoirs have heat, but the rock is impermeable, which is the problem at the Raft River well known as RRG-9.

The experiment will try to make RRG-9 into an effective injection well because U.S. Geothermal must inject more water into the ground to increase the productivity of its existing production wells. Moore says all the water-injection “stimulations” will be done during 2010, with the well monitored over the rest of the five-year study period. All the water will come from production wells, not from streams.

Researchers will first let cold water flow into the hot rocks around the 6,000-foot-deep well, hoping to crack them extensively, and then pump water into the ground under high pressures to force the cracks to open wider. The goal of this “hydraulic stimulation” is to create a network of underground conduits that connect the well with underground cracks that already carry hot water.

“When the cold water reaches the hot rock it will crackle,” Moore says. “Stimulation is the process of generating new cracks.”

Apex Petroleum Engineering, Inc. of Englewood, Colo., will help design the water injection operations to create “hydraulic fractures.” Apex HiPoint’s monitoring equipment will listen to microseismic activity in the rural area to determine the extent of the cracking and thus the growth of the underground geothermal reservoir. Groundwater flow and pressures will be monitored.

Moore says three “stimulations” will occur. During the first two, relatively cool water (40 to 135 degrees Fahrenheit) will flow into the well to crack the rock at a depth of 6,000 feet. Then, a third “stimulation” will involve pumping large volumes of water into the well at high pressure to expand the cracks and keep them open to the flow of water and steam.

The lower half of the well is uncased by piping. The researchers will insert more piping so that the injected water will flow to the depths where it is needed.

McLennan says semi-sized trucks carrying large pumps will come to the well site and may pump as much as 4,200 gallons of water per minute into the ground during each “stimulation.” The total amount injected “could be on the order of 1 million gallons” for each of three “stimulations,” he adds.

The goal, says Moore, is “to create a complex fracture network over an extensive area.”

The Department of Energy wants to develop methods that can “stimulate” geothermal production in various geological environments with various rock types, Moore says. If the techniques used at Raft River prove effective, they could be used anywhere rock is hot.

“It will definitely be an advantage to Raft River if they can improve the productivity of the well, but the Department of Energy is funding this as a research program because hot rock exists everywhere,” Moore says.

The Energy & Geoscience Institute is a contract research organization. Levey says that in terms of the number of participating companies, EGI is the largest university-based research consortium working with the energy exploration and production industry.