A potentially different picture
An even higher degree of overlap occurred when the two mapped large stationary sources of CO2 in the United States, such as coal plants, and considered available storage spots for CO2 within 20 miles of those emitters. In that case, the researchers concluded that shale and tight gas production could affect 85 percent of potential storage spots for stored CO2.
One reason the overlap between shale gas and sequestration regions is so great, they said, is that shale formations typically have very low permeability in the first place. That gives them an obvious dual purpose -- ideal for gas extraction, but also for protecting underground storage spots for CO2.
But Bruce Hill, a geologist at the Clean Air Task Force, said the study offered a simplistic, two-dimensional view of the landscape underground.
Similarly, Susan Hovorka, a sequestration expert and senior research scientist at the University of Texas, Austin, said sedimentary rock is very thick. There typically would be layers and layers of rock offering protection against leakage from a CO2 storage spot 800 meters beneath the ground, she said.
That means that if a rock seal in one spot were broken by hydraulic fracturing, or "fracking," it wouldn't usually create an issue at all, she said. Other layers of impermeable rock underneath the fractured area would block migration of the gas, she said.
"We need to pay attention to this, but I don't think you can conclude that 85 percent of the resource for underground storage of CO2 is crossed out," said Hill.
If additional three-dimensional imaging of the subsurface were done, it would show the overlap number could be much smaller, because of the other protective layers, said Hill.
Additionally, the potential area for underground storage of CO2 in saline aquifers is vast, he said. The database from the federal government reports that the overall storage capacity for injected CO2 could be as high as 20,000 gigatons of carbon dioxide. In comparison, annual CO2 emissions from fossil fuel combustion are a tiny fraction of that, or about 5.7 gigatons.
Future room to maneuver
The size of the resource indicates there will still be plenty of room for CO2 injections in the future, despite the overlap, said Hill. Currently, federal law requires carbon sequestration operators to undergo a vigorous permitting process under the Safe Drinking Water Act.
The Class VI injection well program for carbon sequestration under federal law, for example, requires CCS developers to do thorough seismic measurements of the subsurface and ensure a stable overhead rock before obtaining a permit to shoot CO2 underground. It also requires continual monitoring of underground plumes of gas.
The scenario raised by the study would be mainly relevant in one scenario, where gas producers wanted to come into an area after CO2 injections, several analysts said.
An already-fractured caprock is not going to win approval for CO2 injection in the first place, said Robert Van Voorhees, a counsel at the law firm Bryan Cave.
If gas producers did become interested in the same formation holding CO2, there would be an extensive record of the injections of the greenhouse gas from the Class VI program, making it known where to avoid, said Van Voorhees. Additionally, gas producers do not want to fracture a whole formation because it would impede gas production, he said.
"The two can co-exist if the geology works," he said about CCS and shale gas production.
Because CCS is still in a very early state, gas production is likely to come first in most cases as well, he said. That reduces the likelihood of the "CO2 first" scenario, he said.
Additionally, Hill said, much of the potential for carbon capture and sequestration involves a process not considered by the study -- enhanced oil recovery. In enhanced oil recovery, captured carbon dioxide is piped to an oil field, where the gas is injected under pressure into the reservoir to push out more crude.