All of the carbon dioxide siphoned from power plant flue gas has to go somewhere — not back into the sky as greenhouse gas. That somewhere is typically underground.
CO2 can be used for enhanced oil recovery — to stimulate the flow of untapped oil in fields exhausted by conventional methods.
It can also just be pumped deep underground through injection wells — a process called carbon sequestration or carbon storage.
There are risks associated with storage — particularly leakage and induced seismic events. Lab tests can help predict short-term effects, said Madhava Syamlal, Computational Science & Engineering focus area leader for the National Energy Technology Laboratory’s (NETL) Carbon Capture Simulation Initiative (CCSI).
But what about a century or 10 centuries down the road? “We need to have a good handle on what is the risk of CO2 leaking, what is the risk of seismicity,” Syamlal said.
That’s the role of CCSI sister project NRAP: The National Risk Assessment Partnership. The partners are NETL and other national labs, a group of universities and a group of stakeholders, including insurance companies and federal agencies.
“This is a real challenge, because unlike a power plant or an engineered facility, the subsurface is a natural system,” said Grant Bromhal, NRAP Fluid-Rock Geophysics Team leader.
Like CCSI, NRAP uses computational tools to model, predict and quantify the risks of CO2 storage. NRAP looks at the natural storage fields — the geology, sedimentation, ground water. And it looks at the technology: Well bores, well casings, cement.
The idea is to fine-tune the whole process to ensure confidence, Bromhal said.
“We’re reducing the risk of your putting it underground,” he said. “We want to take that risk down to where people say, ‘Yeah, you can put it in my backyard. I don’t care because I know it’s safe.’ ”
It begins on the small scale. They pull cores from well bores, test the bores for characteristics of the rock strata and extrapolate to entire subsurface system. They determine how CO2 will interact with water, rocks, cement, steel.
It’s not just guesswork. “We know through decades of experience with oil and gas how the subsurface behaves,” Bromhal said.
A simulation of 40 to 50 years of the life of an injection well can take hours or days, he said. But that’s not enough.
They’ve boiled down the simulation process into “rapid performance models” that can predict in seconds the effects on a storage reservoir, and with more time, the well bores, groundwater, air.
The NRAP team generates rapid performance models to predict and quantify uncertainties not just 50 years out, but 1,000 years out, Bromhal said.
Induced seismicity hasn’t been a factor so far in CO2 storage, he said, but they’re studying it because of quakes induced by fracking wastewater injection. And they hope that knowledge they gather can be applied to fracking injection, too.
And they don’t stop at computer models. They do real-world testing too. Kanwal Mahajan, Storage Division director, said NRAP is in its third phase — demonstration — which runs to 2018. For three years, at sites across the nation, they are monitoring what the CO2 does underground.
This article was written by David Beard from The Dominion Post, Morgantown, W.Va. and was legally licensed through the NewsCred publisher network.