Using CO2 to Produce Geothermal Energy

SAN FRANCISCO - Researchers are developing a new kind of geothermal power plant that will lock away unwanted carbon dioxide (CO2) underground and use it as a tool to boost electric power generation by at least 10 times compared to conventional geothermal power.

The technology for this design already exists in different industries, and the researchers, led by Tom Buscheck, earth scientist from Lawrence Livermore National Laboratory, are hopeful that their new approach to the technology will expand the use of geothermal energy in the U.S. far beyond the small handful of states that can take advantage of it now. Heat Mining Company, LLC, a startup spun off from the University of Minnesota, expects to have an operational project based on an earlier form of this new approach in 2016.

At the American Geophysical Union meeting on Friday, Dec. 13, Buscheck and his colleagues fromThe Ohio State University, the University of Minnesota and Lawrence Livermore, will debut an expanded version of the design and explain the role that this new approach to geothermal energy production and grid-scale energy storage can have in addressing climate change.

The new power plant design resembles a cross between a geothermal plant and the Large Hadron Collider: it features a network of subsurface concentric rings of horizontal wells inside which CO2, nitrogen and water circulate to draw heat from deep below ground up to the surface, where it can be used to turn turbines and generate electricity.

"This well arrangement encircles the injected fluids with a subsurface hydraulic dam, functioning much like a hydroelectric dam. The intent is to recover the maximum energy benefit from fluid injection operations, a major improvement over conventional geothermal power systems," Buscheck noted.

The design contrasts with conventional geothermal plants in a number of important ways, explained study co-principal investigator Jeffrey Bielicki, assistant professor of energy policy in the Department of Civil, Environmental and Geodetic Engineering at The Ohio State University.

"Typical geothermal power plants tap into hot water that is deep underground,pull the heat off the hot water, use that heat to generate electricity and then return the cooler water back to the deep subsurface. Here the water is partly replaced with CO2 and/or another fluid," he said.

"Tt that there are benefits to using CO2, because it mines heat from the subsurface more efficiently than water," he continued."This combined approach (originally developed by Martin Saar at the University of Minnesota) can be at least twice as efficient as conventional geothermal approaches, and expand the reach of geothermal energy in the United States to include most states west of the Mississippi River."

The research team used computer simulations to design the system. In the simulations, a system of four concentric rings of horizontal wells about three miles below ground, with the outer ring being a little more than 10 miles in diameter, produced as much as a half a gigawatt of electrical power - an amount comparable to a medium-sized coal-fired power plant, and more than 10 times bigger than the 38 megawatts produced by the average geothermal plant in the U.S.

The simulations also revealed that a plant of this design might sequester as much as 15 million tons of CO2 per year, which is roughly equivalent to the amount produced by three medium-sized coal-fired power plants in that time.

"One of our key objectives when we began developing the CO2 plume geothermal technology was to find a way to help make CO2 storage cost effective while expanding the use of geothermal energy," said Jimmy Randolph, postdoctoral researcher in the Department of Earth Sciences at the University of Minnesota.

During the past year,  Buscheck added another gas - nitrogen - to the mix, resulting in a design that he and his colleagues believe will enable highly efficient energy storage at an unprecedented magnitude (at least hundreds of gigawatt hours) and unprecedented duration (days to months), provide operational flexibility, and lower the cost of renewable power generation.

"Nitrogen has several advantages," Buscheck explained. "It can be separated from air at lower cost than captured CO2, it's plentiful, it's not corrosive and will not react with the geologic formation in which it is being injected. And because nitrogen is readily available, it can be injected selectively. Thus, much of the energy required to drive the hot fluids out of the deep subsurface to surface power plants can be shifted in time to coincide with minimum power demand or when there is a surplus of renewable power on the electricity grid.

The distribution of stored nitrogen in the underground geothermal reservoir system is shown after 10 years of energy storage and production operations.

"Because we are storing energy in the form of pressurized fluids, we can further improve on this concept by selectively producing hot fluids when power demand is high, as well as reduce or stop that production when power demand is low. What makes this concept transformational is that we can deliver renewable energy to customers when it is needed, rather than when the wind happens to be blowing, or when spring thaw causes the greatest runoff."

The technology could possibly be used to expand the use of geothermal energy around the country. Right now, most geothermal power plants are in California and Nevada, where an especially strong geothermal gradient heats water underground. But the new design is so much more efficient at extracting heat that even smaller-scale "hotspots" throughout the western U.S. could generate power. (The eastern U.S. is mostly devoid of even small hotspots, so geothermal power would still be limited to a few particularly active areas such as West Virginia, Bielicki said.)

Another caveat: the geothermal plant would probably have to be connected to a large CO2 source, such as a coal-fired power plant, which was scrubbing the CO2 from its own emissions. That connection would likely be made by pipeline. Buscheck added, however, that a pilot plant based on this design could initially be powered solely by nitrogen injection, in order to prove the economic viability of using CO2. The study also showed that this design can work effectively with or without CO2, broadening where this approach could be deployed. The research team is currently working on more detailed computer model simulations and economic analyses for specific geologic settings in the U.S.

Co-authors on the presentation included Mingjie Chen, Yue Hao, Yunwei Sun, all of Lawrence Livermore. Work at the University of Minnesota and The Ohio State University is funded by the National Science Foundation, while work at Lawrence Livermore National Laboratory is funded by the U.S. Department of Energy's Office of Energy Efficiency and Renewable Energy. 

Source: Lawrence Livermore National Laboratory

Texas CCUS Project Officially Up and Running

WASHINGTON — The Energy Department’s Acting Assistant Secretary for Fossil Energy Christopher Smith attended last week's dedication ceremony at the Air Products and Chemicals hydrogen production facilities in Port Arthur, Texas. Supported by a $284 million Energy Department investment, the company has successfully begun capturing carbon dioxide from industrial operations and is now using that carbon for enhanced oil recovery (EOR) and securely storing it underground. This first-of-a-kind, breakthrough project advances carbon capture, utilization and storage technologies and demonstrates the potential to safely secure carbon dioxide pollution underground while providing an economic benefit and increasing our energy security.

At full-scale operation, more than 90 percent of the carbon dioxide from the product stream of two methane steam reformers — or approximately one million metric tons of carbon dioxide per year — will be delivered for sequestration and EOR, which will lead to an estimated annual increase in oil production of 1.6 to 3.1 million barrels from the West Hastings oil field located about 20 miles south of Houston, Texas.

“The Energy Department is investing in cutting-edge technologies that will help us safely and more sustainably develop all of America’s rich energy resources,” said Acting Assistant Secretary for Fossil Energy Christopher Smith. “This groundbreaking project demonstrates the potential to produce economic benefits and increase our energy security while greatly reducing the environmental impacts of our fossil energy use.”

The two retrofitted Air Products and Chemicals plants produce commercial bulk hydrogen primarily for use at the nearby Valero refinery. The approximately $431 million project, supported by $284 million from the Energy Department, included retrofitting the plants with an innovative system that separates carbon dioxide from the steam reformer product gas during hydrogen production, followed by compression and drying processes. The Energy Department investment also helped construct a 13.1-mile-long feeder that connects the two plants to an existing 325-mile, 24-inch carbon dioxide pipeline, Denbury’s Green Pipeline, that begins in Louisiana and ends at the West Hastings field. Careful carbon dioxide monitoring, verification, and accounting activities to ensure the injected carbon dioxide remains in the underground geologic formation will take place throughout the lifetime of the project.

The first plant has been capturing carbon dioxide since December 2012, while the second plant completed construction in February and began carbon capture operations in March.  Both units are now operating at full capacity.  Over 222,000 tons of carbon dioxide have been captured and provided for storage as of early May.

The Port Arthur project is part of the Energy Department’s broader efforts to leverage cutting-edge research to show that not only can Carbon Capture and Storage (CCS) technology help industry make fossil energy use cleaner, safer and more sustainable, it also shows promise as a method to extract more, hard-to-access and presently untapped fossil energy resources. By putting the captured carbon dioxide to use, Carbon Capture, Utilization and Storage (CCUS) provides an additional business and market case for companies to pursue the environmental benefits of CCS.

To learn more about CCUS, watch the short video HERE

Source: NETL

NETL Releases Data on Methane Hydrate Test

Washington, D.C. —Data from an innovative test conducted last year that used carbon dioxide (CO₂) and nitrogen (N₂) injection to release natural gas from methane hydrates at a well on the Alaska North Slope is now available to researchers and the public on the National Energy Technology Laboratory (NETL) website.

Methane hydrate - essentially molecules of natural gas trapped in ice crystals - represents a potentially enormous energy resource, possibly exceeding the combined energy content of all other fossil fuels. Hydrate resources in arctic sandstone reservoirs contain an in-place gas volume estimated to be in the 100’s of trillions of cubic feet (TCF), while hydrate in marine sands is estimated to contain 1,000’s to 10,000’s of TCF, and hydrate dispersed through marine mud is estimated to contain 100,000’s of TCF. In addition to the immense resource, CO₂ injection into methane hydrate deposits is a technology that can potentially both release an energy resource while permanently storing carbon dioxide, a major greenhouse gas.

The U.S. Department of Energy (DOE), in partnership with other nations and industry, has played a leading role in developing technologies to evaluate how to safely recover these methane hydrate energy resources in order to provide new supplies of clean-burning natural gas.  These resources occur in a variety of forms in sediments within and below thick permafrost in Arctic regions, and in the subsurface of continental waters with a depth of 1,500 feet or greater.  The U.S. Geological Survey (USGS) has estimated a potentially recoverable resource of 85 trillion cubic feet of gas in favorable hydrate accumulations on the Alaska North Slope alone. 

NETL, the research laboratory of DOE’s Office of Fossil Energy (FE), participated in gas hydrate field production trials in early 2012 in partnership with ConocoPhillips and the Japan Oil, Gas and Metals National Corp. (JOGMEC). This test well (known as Iġnik Sikumi, Inupiat for “Fire in the Ice”) represented the first test of a CO₂ exchange technology that was developed by ConocoPhillips and the University of Bergen, Norway.  In the test, a small volume of CO₂ and nitrogen was injected into the well and then the well was produced back to demonstrate that this mixture of injected gases could promote production of natural gas.

The large volumes of raw data from the test are currently under evaluation.  The data now available from the test program include the rates and composition of gases both injected and produced, and information on changes in the reservoir pressure and temperature during the test. ConocoPhillips has further augmented the raw data through extensive quality control checks and integration of the various measurements to a standard time framework.  The data are now fully available to all researchers and the public for analysis and evaluation. 

Both the U.S. and Japan have committed to utilizing Arctic gas hydrate research opportunities as an important step in assessing the potential for gas hydrate production in deepwater marine settings, the location of the vast majority of global resources.  DOE and JOGMEC have also collaborated on the development of specialized core sampling devices through the Gulf of Mexico Gas Hydrates Joint Industry Project (an industry consortium managed by Chevron) conducting research on deepwater gas hydrate characterization technology.

In addition to the U.S./Japan collaboration, FE scientists have worked actively with researchers in Korea, India, China, Canada and other nations, as well as with USGS, the Bureau of Ocean Energy Management (BOEM), and other federal agencies, to advance methane hydrate technology.  The Methane Hydrate Research and Development Act of 2000 established DOE (through the efforts of FE and NETL) as the lead U.S. agency for methane hydrate research and development.

Source: NETL

SaskPower CCUS Project Update

According to a Reuters report yesterday, the carbon capture facility being constructed by Saskatchewan's SaskPower at the Boundary Dam power station will be ready to launch by April 2014.  SaskPower is doing a $1.24 billion retrofit of the 45-year-old plant to capture one million tonnes a year of carbon dioxide as well as sulphur dioxide. When completed, Boundary Dam will be the world's first coal-fired power plant with a commercial scale carbon capture component. SaskPower officials believe the addition of carbon capture will reduce the total power output of the plant by approximately 25 percent, according to Reuters. Officials also stated that the cost of retrofitting the plant, which will reduce CO2 emissions by approximately 90 percent, were approximately the same as constructing a comparable plant powered by natural gas. SaskPower announced last month that it has agreed to sell the captured CO2 to Canadian oil company Cenovus Energy for use in enhaced oil recovery. Read more

CCUS/EOR Project Begins in Texas

Washington, D.C. — A breakthrough carbon capture, utilization, and storage (CCUS) project in Texas has begun capturing carbon dioxide (CO2) and piping it to an oilfield for use in enhanced oil recovery (EOR). 

The project at Air Products and Chemicals hydrogen production facility in Port Arthur, Texas, is significant for demonstrating both the effectiveness and commercial viability of CCUS technology as an option in helping mitigate atmospheric CO2 emissions. Funded in part through the American Recovery and Reinvestment Act (ARRA), the project is managed by the U.S. Department of Energy (DOE) Office of Fossil Energy’s National Energy Technology Laboratory. DOE is collaborating with industry in cost-sharing arrangements to demonstrate these next-generation technologies.  

This event marks a milestone in DOE’s Industrial Carbon Capture and Storage (ICCS) program: progressing beyond research and development to a demonstration scale that can be readily replicated and deployed into commercial practice within the industry. Goals of the ICCS program are to mitigate climate change through CCUS; create jobs; and position the United States as a world leader in carbon capture technologies.  

In the Air Products project, CO2 that would ordinarily be released to the atmosphere is separated from the gas stream of one of the company’s steam methane reformers using a gas-separation technology called "vacuum swing adsorption." After compression and drying, the CO2 purity is greater than 97 percent, concentrated from an initial 10–20 percent. The CO2 is then transported through Denbury Green Pipeline – Texas, LLC’s pipeline for injection into the Denbury Onshore operated West Hastings Unit, an EOR project in Texas.

When an oil well begins "playing out," not enough oil is pumped to make it worthwhile to continue using the well, and the well is closed or "shut in," even though much of the original oil in the field remains in the formation. Several methods of enhanced oil recovery have been developed to recover this remaining oil, including pumping CO2 down to the oil reservoir. In the Port Arthur project, a monitoring, verification, and accounting program will ensure that the injected CO2 remains underground, safely and permanently trapped in the same geologic formation that confined the oil brought to the surface in the demonstration. 

In 2009, during the first phase of DOE’s ICCS program, 12 projects were chosen to receive ARRA funding to expedite or carry out large-scale CCUS from industrial sources. After 7 months, a competitive evaluation was undertaken, and in 2010, Air Products was selected as one of three companies to enter Phase 2 and continue receiving funding for a commercial demonstration project.  

Specific advantages of the Air Products demonstration project include:

• Capturing approximately 1 million metric tons of CO2 per year that would otherwise be released into the atmosphere; and 

• Recovering 1.6-3.1 million additional barrels of domestic oil annually. 

When other companies join with Air Products and begin CO2 capture and utilization, these numbers will increase. Air Products plans to begin CO2 capture at a second steam methane reformer within its Port Arthur facility in the next several months. 

Source: NETL

Cenovus to Buy SaskPower's CO2 for EOR

SaskPower, Saskatchewan's electric utility, announced last week that it has reached an agreement with Cenovus Energy for the purchase of carbon dioxide (CO2) from SaskPower’s carbon capture and storage facility now under construction at Boundary Dam Power Station, near Estevan, Saskatchewan.

Cenovus will purchase the full volume, approximately one million tonnes per year, of the CO2 captured at SaskPower’s facility and use it for enhanced oil recovery at a project operated by Cenovus on behalf of its partners near Weyburn, Saskatchewan. SaskPower’s facility is the world’s first and largest coal-fired integrated carbon capture and storage project.

The long-term contract with Cenovus was signed at the completion of an extensive sales process. Cenovus expects to be ready to accept the CO2 when SaskPower’s integrated carbon capture and storage facility goes into commercial operation on or about April 1, 2014.

Source: SaskPower

Can CO2 Increase Bakken Well Production?

Researchers from the University of North Dakota's Energy and Environmental Research Center have announced a project to determine if injecting carbon dioxide into the Bakken formation could increase the productivity of depleted wells. The scientists estimate that pumping one percent of additional oil from the Bakken and Three Forks formations would yield an additional 1.7 billion barrels. The process, called enhanced oil recovery, has been used successfully with conventional reservoirs in other parts of the U.S. and  in Canada, but has not been tried with unconventional reservoirs such as the shale formations in the Williston Basin. Read more

NREL Produces Ethylene via Photosynthesis

Scientists at the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) have demonstrated a better way to use photosynthesis to produce ethylene, a breakthrough that could change the way materials, chemicals, and transportation fuels are made, and help clean the air.

NREL scientists introduced a gene into a cyanobacterium and demonstrated that the organism remained stable through at least four generations, producing ethylene gas that could be easily captured. Research results were published in the journal Energy & Environmental Science.

The organism – Synechocystis sp. PCC 6803 – produced ethylene at a high rate and is still being improved. The laboratory demonstrated rate of 170 milligrams of ethylene per liter per day is greater than the rates reported for the photosynthetic production by microorganisms of ethanol, butanol or other algae biofuels.

The process does not release carbon dioxide into the atmosphere. Conversely, the process recycles carbon dioxide, a greenhouse gas, since the organism utilizes the gas as part of its metabolic cycle.

Ethylene is the most widely produced petrochemical feedstock in the world. But currently it is produced only from fossil fuels, and its production is the industry’s largest emitter of carbon dioxide. Steam cracking of long-chain hydrocarbons from petroleum produces 1.5 to 3 tons of carbon dioxide for every ton of ethylene produced.

The NREL process, by contrast, produces ethylene by using carbon dioxide, which is food for the bacteria. That could mean a savings of six tons of carbon dioxide emissions for every ton of ethylene produced -- the three tons that would be emitted by tapping fossil fuels and another three tons absorbed by the bacteria.

NREL principal investigator, Jianping Yu, says it’s the difference between using old photons and new photons. Ethylene from old photons is the ethylene produced from fossil fuels, derived from photosynthetic organisms that captured the sun’s energy millions of years ago. The NREL process uses new photons that are currently hitting plants, algae and bacteria capable of producing fuels directly.

Ten years ago, a group of Japanese scientists led by Takahira Ogawa at Sojo University was the first to try to produce ethylene via photosynthetic conversion in the cyanobacterium Synechococcus 7942. But by the fourth generation, the bacteria were defunct, producing no ethylene at all, Yu said.

NREL turned to a different cyanobacterium, Synechocystis 6803, which scientists had been researching for a long time, knowing how to change its DNA sequences. They manipulated the sequence to design an ethylene-producing gene to be more stable and more active than the original version.

This process resulted in an organism that uses carbon dioxide and water to produce ethylene, but doesn’t lose its ability to produce ethylene over time. The product ethylene is non-toxic to the producing microorganisms and is not a food source for other organisms that could potentially contaminate an industrial process.

“Our peak productivity is higher than a number of other technologies, including ethanol, butanol, and isoprene,” Yu said. “We overcame problems encountered by past researchers. Our process doesn’t produce toxins such as cyanide and it is more stable than past efforts. And it isn’t going to be a food buffet for other organisms.”

After the culture reaches maximum growth, it’s possible that it could keep producing for months at a time, said Rich Bolin, who is a member of NREL’s partnerships group. The ethylene gas it produces naturally leaves the organism, spurring the organism to keep producing more.

The ethylene would be produced in an enclosed photobioreactor containing seawater enriched with nitrogen and phosphorous. The ethylene gas would rise and be captured from the reactor’s head space. It could then undergo further processing, including a catalytic polymer process to produce fuels and chemicals. The continuous production system improves the energy conversion efficiency and reduces the operational cost.

NREL is initiating discussions with potential industry partners to help move the process to commercial scale. Interested companies include those in the business of producing ethylene or - transportation fuels, as well as firms that build photobioreactors.

“Separations in biotechnology are complicated and costly,” said Jim Brainard, director of NREL’s Biosciences Center. “The nice thing about this system is that it is a gas that just separates from the culture media and rises to the head space. That’s a huge advantage over having to destroy the valuable culture that is taking carbon dioxide and light and water to make your product. It’s much easier than a liquid-liquid separation like in ethanol.”

NREL is the U.S. Department of Energy's primary national laboratory for renewable energy and energy efficiency research and development. NREL is operated for DOE by the Alliance for Sustainable Energy, LLC.

Source: NREL