It’s a safe bet that carbon sequestration has a big future, but a wild gamble to guess how that future will play out.
Government regulation, the economics of capture-and-injection, legal restrictions, geological considerations and even the price of crude oil will help determine how – and how fast – new CO2 projects develop.
Two oral presentation sessions will address carbon sequestration issues at the 2008 AAPG-SPE Eastern Section’s annual meeting, set Oct. 11-15 in Pittsburgh.
Both sessions cover relevant geological and technical topics, including a look at CO2 sequestration possibilities in the Michigan, Illinois and Appalachian basins.
AAPG members Larry Wickstrom, Ohio’s state geologist and division chief of the Ohio Geological Survey in Columbus, and Kristin Carter, senior geological scientist at the Pennsylvania Geological Survey in Pittsburgh, will serve as co-chairs for the sessions.
Wickstrom noted that the U.S. Department of Energy sponsors a network of seven Regional Carbon Sequestration Partnerships to help determine the technology, infrastructure and regulations needed for large-scale CO2 projects.
“In the Eastern Section we’ve got two of the DOE regional partnerships – one is the Midwest Regional Carbon Sequestration Partnership that’s led by Battelle,” as well as the Midwest Geological Sequestration Consortium (MGSC), Wickstrom said.
Another DOE partnership, the Southeast Regional Carbon Sequestration Partnership, includes some of the southern states in the AAPG Eastern Section area.
Economics will play a huge part in the future development of carbon sequestration. Because of that, Wickstrom said CO2 injection for enhanced oil recovery (EOR) makes the most sense as a starting point.
“I’ve been looking at geologic CO2 sequestration-related topics for 10 years,” he said. “Just about everybody who works in that field agrees that EOR is vital in getting CO2 sequestration off the ground.
“With oil prices as they are now, it’s very doable,” he added.
The costs of building infrastructure simply to begin carbon dioxide capture and injection is a major hurdle for CO2 projects.
“It will be very expensive on the front end to develop the compression needs and the pipelines,” Wickstrom said. “You’re talking hundreds of millions of dollars just to develop one region.”
Another challenge for EOR projects has been finding sources for reasonably pure, injectable CO2.
Operators in West Texas enjoy an at-hand source of natural carbon dioxide but are still “starving for CO2 – they can’t get enough of it to do all the EOR projects they’ve wanted to do,” Wickstrom noted.
“Here in the East we’ve never had a CO2 source available to us, but right now the ethanol plants that have been built and are being built are a good source of CO2,” he said. “That’s a pretty easy source to capture.”
Taking CO2 produced by Integrated Gasification Combined Cycle power plants is another possibility, Wickstrom said. Combined-cycle plants use coal to produce syngas, typically for powering gas turbines, and are considered more efficient than coal-fired plants because they can capture and use waste heat.
With a high-purity CO2 source on one end and the economic boost of EOR on the other, oilfield injection for carbon sequestration appears to make economic sense.
“What I’m hoping to see is that the oil and gas operators and the large CO2 point-source generators can form some nice partnerships to share the cost of all of this,” Wickstrom said.
Long Time Coming
But even then, large-scale projects will take many years to develop.
Wickstrom described a hypothetical EOR project in which a large oil field may eventually take most of the projected two million metric tons per year of CO2 available from a large plant some tens of miles away.
The project requires pipelines, compression equipment and injection equipment. Some existing wells would become injectors and other new injector wells would be drilled.
“It may take 10 to 15 years to ramp that field up to where it could take the entire two million tons per year,” Wickstrom noted. “But once you start to develop that pipeline infrastructure, you can leapfrog to other oil fields and start connecting to other CO2 point sources.
Unlike sequestration of CO2 from power plants, EOR injection projects don’t necessarily require a great deal of government involvement or support, he said.
“I think a lot of this could pay for itself – the price of oil right now is going to pay for a lot of it,” Wickstom explained.
“What’s needed are simply some federal government-guarantees for the developers of these very capital-intensive projects, such as new IGCC power plants and proposed coal-to-liquid plants,” he added.
In regard to capturing CO2 from power plants, “there’s a lot of research going into that but it’s very expensive,” he said. “There’s a big challenge in getting that CO2 out of the flue gas.”
That’s why government regulation and coming carbon-capture requirements will drive the development of CO2-injection projects for power plant emissions, according to AAPG member Hannes Leetaru, petroleum geologist for the carbon sequestration team at the Illinois State Geological Survey in Champaign, Ill.
“For power plants you have to have requirements because you probably increase your utility rates by 20 percent or more if you capture CO2,” he said. “You don’t want to do it if your competitors aren’t going to do it.”
Leetaru and many others working in the carbon sequestration area expect the U.S. Congress to write new cap-and-trade emissions trading laws.
In a cap-and-trade system, regulators define an established cap or total limit on emissions. Companies then trade credits to determine how much pollution each source can emit. Total emissions have to remain below the cap.
Emissions trading has many variations, however, and no one can predict how Congress will handle the issue or how the result will influence carbon sequestration.
Under the DOE’s MGSC partnership, the Illinois survey is conducting field testing and drilling for carbon-sequestration demonstration projects.
“Most of our efforts right now are going into drilling a CO2 sequestration well in Decatur (Illinois),” Leetaru said.
“There’s an Archer Daniels Midland (ADM) Co. ethanol plant there. We’re going to capture the CO2 from that plant – it’s really almost pure CO2 – and pump it into the subsurface,” he added.
This type of activity is so new that the Illinois Environmental Protection Agency had to develop new rules and procedures for issuing a CO2 underground injection control permit, Leetaru noted.
And in July, the U.S. Environmental Protection Agency proposed its first technical criteria for CO2 injection-well construction, operation and monitoring.
The EPA’s proposed rule would add a sixth category to its injection-well control program, this one specifically for geologic storage of CO2 800 meters or more underground.
The recent regulatory activity points up how near to its infancy CO2 injection for carbon storage really is.
According to the DOE, only about 35 million tons of CO2 are currently stored in the United States, mainly for EOR. By contrast, a state like Ohio emits an estimated 275 million metric tons of CO2 into the atmosphere annually.
For long-term sequestration of CO2, geologists will have to identify reservoirs with the right characteristics for storage.
“In a way, it’s very similar to looking for an oil and gas reservoir – you look for porosity and permeability. The key factor you look for is whether there’s a seal on top,” Leetaru said.
For injection of CO2 from the ADM ethanol plant in Decatur, the MGSC test well targets the Mt. Simon Sandstone, a major regional saline-reservoir formation that extends across several states.
“In Illinois we know we have a seal on top of the Mt. Simon because they’ve been injecting natural gas into the formation in the northern part of the state for gas storage for a long time,” Leetaru said.
Current plans call for the compressed CO2 to be injected to a depth of more than 6,500 feet. The CO2 is compressed but not cooled to liquefy, and in fact may have to be heated, Leetaru noted.
“If you have really cold CO2 going down there it would probably crack the rocks,” he said.
The entire project should conclude in 2012 and will cost an estimated $84.3 million, with the DOE providing $66.7 million and the rest coming from ADM and other sources.
In this case, also, the injection program will be limited to a trial basis and will take only part of the available CO2 output.
“We plan to inject about 1,000 metric tons a day into the formation. That’s a fairly low rate,” Leetaru said.
Geologists may be pressed to identify and analyze saline reservoirs of sufficient, reliable capacity if and when large-scale sequestration projects develop across the United States.
“Trying to understand the geology is a challenge because there haven’t been a lot of wells drilled into the saline formations,” Leetaru said.
Even in EOR projects for currently producing fields, reservoir nature has to be analyzed for response to CO2 injection, Wickstrom observed.
“The reservoir testing is key. We’ve got some reservoirs that are sure, or almost sure, because they’re similar to the West Texas fields that have already been flooded,” he said.
The only predictable part of the future of CO2 sequestration may be that it will take many more trial projects, many more dollars and many more years to develop.
“There are only a handful of sequestration projects going on right now. You want to have a big representation of test sites,” Leetaru noted, “so you can say, ‘It works here. And it works there.’”