Ethanol Plant CCS: Sequestration Sensors

Source: By Katie Schroeder, Ethanol Producer Magazine • Posted: Monday, October 17, 2022

With CCS expanding rapidly, there is an accompanying need for technology to monitor the CO2 underground. A North Dakota ethanol producer, environmental researcher and a geophysicist explain how it’s done.

With CCS expanding rapidly, there is an accompanying need for technology to monitor the CO2 underground. A North Dakota ethanol producer, environmental researcher and a geophysicist explain how it’s done.

As the number of new and proposed carbon capture and sequestration (CCS) projects in the United States surges—with about 75 ethanol plants alone now pursuing it—new services and technologies are being introduced to producers in the space. With test wells and injection sites being built, and several projects in the permitting phase, under construction or already functioning, there is an immediate need for well-site monitoring technology that observes the CO2 to make sure it stays where it is sequestered.

The state of California, a major market for ethanol producers, as well as individual states and the U.S. Environmental Protection Agency, have rules in place requiring entities sequestering CO2 to verify that it is staying underground. Red Trail Energy LLC in Richardton, North Dakota, started injecting CO2 on June 16. Explaining the technology Red Trail uses and the regulations surrounding CO2 injection, Kent Glasser, plant manager, and Dave Burns, an environmental manager with the state who worked on the project, tell Ethanol Producer Magazine the company has been injecting roughly 450 tons of CO2 every day since mid-July.

The passage of the Inflation Reduction Act has made CCS look more attractive from an economic standpoint, boosting 45Q tax credits from $50 per ton to $85 per ton. The legislation also gives producers an option to directly sell their tax credits to interested parties on a one-time basis (a buyer cannot resell credits).

But even prior to the passage of the IRA, Red Trail already saw value in CCS due to the 45Q tax credit and opportunities in low carbon intensity ethanol in California, Glasser says. Red Trail also recognized its unique opportunity given that the plant is located on top of the Broom Creek formation. “The Broom Creek Formation is kind of like a honey hole for carbon sequestration,” Burns adds.

John Hamling, assistant vice president of strategic partnerships with the Energy and Environmental Research Center, has been involved with the Red Trail project for the past five years. EERC is also the leader of the Plains CO2 Reduction Partnership, which focuses on “advancing commercial CCS throughout a 10-state, four Canadian province region.” EERC has played a major role in assisting Red Trail in navigating the process leading up to injection. “We worked with Red Trail Energy as the first CCS project that’s permitted and operational under a state primacy program,” Hamling says. He explains that since Red Trail was the first CCS project to be built and permitted under North Dakota’s state primacy—meaning that the state issues permits for Class VI wells and not the EPA—EERC worked closely with them on site development, including many aspects of permitting and incentive program compliance, while offering insight on the operation from a geological perspective. 

In 2021, the U.S. Department of Energy released a funding opportunity announcement looking for a company that would develop a turnkey service business that utilizes passive seismic to monitor CO2 sequestration. MicroSeismic was awarded the grant in February 2022. Peter Duncan, geophysicist and CEO of MicroSeismic, explains why monitoring technology is important and the specifications the DOE requires.

Before Injection
Long before injection begins, there are several preliminary steps that need to be taken, including site screening, site characterization and permit development alongside ensuring compliance with incentive programs such as 45Q tax credits and the California Air Resources Board’s LCFS markets, according to Hamling.

Site screening involves determining if the geology near the plant is conducive to CO2 storage. Hamling explains that Red Trail’s site used pre-existing work from the PCOR Partnership and state geologic studies done for oil and gas developments. He recommends that parties interested in sequestration utilize this type of data from public resources. The geology must have a rock formation which has space between the grains for containing CO2, that also being deep enough to keep it in a dense phase so that it behaves like a liquid allowing for more storage. There also needs to be “adequate confinement zones” above and below the permeable formation to contain the CO2, and they check for any potential leakage pathways that would allow the CO2 to get out. Site characterization requires collecting site specific data, Hamling says. Producers will drill appraisal wells, do well testing, collect measurements of the subsurface and more. All of the information gathered is necessary for permitting and ensuring compliance with incentive programs.

“It’s a multi-stage process, generally—the geological storage component takes several years to step through each stage of the process,” Hamling says. “And because Red Trail Energy was located in an area where we had already done preliminary work, we were able to work with them to get the first CO2 storage project permitted under state primacy.

Ethanol producers have an advantage when it comes to carbon capture because the CO2 is 99 percent pure coming off fermentation, Glasser explains. However, the CO2 needs processing prior to injection to further purify, cool and condense it into liquid form so it can be pumped into the ground. The two key steps to liquifying CO2 are compressing it to a high pressure and making it very cold. “It just depends on the balance and combination of how much pressure, how cold it needs to be,” Glasser says.

The CO2 is transferred from the CO2 scrubber off the fermentation tank, then goes through subcooling prior to compression, so that it doesn’t heat up too much. After compression, it goes through dehydration to get rid of any moisture. Then, the CO2 is cooled to the point where it changes state from a gas to a liquid. Once the CO2 is liquified, it is distilled to remove any lingering impurities and goes through a carbon filtration system. Afterwards, it is transferred and injected via high pressure pumps into a well that, in Red Trail’s case, is nearly 6,500 feet deep.

Regulatory Requirements
There are three goals the DOE requires technologies to meet, Duncan explains. The first is detecting and evaluating whether there is a possibility of CO2 injection creating any kind of seismic event or earthquake. Secondly, the technology must be able to make sure that the CO2 does not crack the cap rock keeping the CO2 underground. Duncan explains that though the CO2 is not being inserted in the ground under high pressure, the fluid will seep into preexisting fractures in the rock and reduce the friction holding the rocks together, which may cause the cracks to shift. Finally, the technology must provide verification of the CO2 “plume” spreading throughout the reservoir as it is injected.

Essentially, he explains, they are trying to solve three problems. “The problem of is there induced seismicity? Or is there potential for induced seismicity? Is the CO2 staying in place in the reservoir? And, where in the reservoir is it going? Well, how do we know when the reservoir is full? Those three areas people are investing a lot of technical trials into,” Duncan says.

Producer Perspective
During CO2 injection, there are several different monitoring plans Red Trail needed to create, Burns says. The plant created a monitoring plan for the state, assisted by the EERC, as well as a MRV for the EPA at the federal level. In early September, Red Trail had another monitoring plan under submission in California to access the state’s low carbon fuels program.

Burns explains that Red Trail has a partnership with Japanese company RITE, which uses a surface orbital vibrator technology to model the CO2 plume and watch for any induced seismicity. “If the CO2 plume moves out there, they’ll see a change in the vibration, and they’ll model that to see where the plume is going to be,” he says. The EERC also monitors the well using nodes on the surface.

They also had to do multiple tests to acquire a baseline of the soil isotopes and the Fox Hills Aquifer, the deepest freshwater aquifer in the area, to make sure there aren’t any changes happening due to injection. “We have a third party come and take those [soil gas] samples … [and] we had to take an isotope test of the CO2 coming off our plant, so if there’s a lot of that CO2 in the ground then they’ll be able to trace it back to our source through isotope monitoring,” he explains.

There is no singular technology that checks all the boxes for monitoring, Hamling says. In today’s current regulatory landscape, a monitoring strategy is necessary. “But the purpose of monitoring is two-fold,” he says. “You need monitoring data to inform how you operate the site; you also need monitoring data to demonstrate to regulators and incentive programs that the CO2 you’re injecting is staying stored permanently and that it’s staying within the permitted area.”

Monitoring with Passive Seismic
Passive seismic technology listens to the earth and the sounds it makes, then uses those readings to learn and map what is going on beneath the surface. MicroSeismic developed its technology in working with the oil and gas industries, and when those industries took a hit in 2019-’20, moved toward utilizing its technology to detect sinkholes before they cause damage.

“The monitoring, measurement and verification plan that people are putting in place are really directed, as I said before, at these three issues: number one, the seismicity; number two, the integrity of the cap rock that is keeping CO2 below ground; and three, where that plume is going in the ground to make sure it’s not leaking out around the edges of the reservoir and getting up to the surface,” Duncan says.

At the beginning of a project, MicroSeismic assists in evaluating the sequestration site by cementing six to twelve geophones less than 300 feet underground to check for signs of active faults. “The way you do that is to listen, because those fractures are causing little mini earthquakes. Now, I’m talking about seismic events that are kind of equivalent to the pop sound that happens when you take a can of Coke and drop it from your waist onto a cement floor,” Duncan says. These geophone stations wirelessly transmit data back to MicroSeismic where they are monitored 24/7.

They will listen for six months, and if they detect any active faults in the area, the injection point will be relocated. Once injection does start, MicroSeismic would increase the number of geophones to between 50 and 100, with about three to five stations per mile. They are able to use the “pops and pings” they hear to understand what is going on underground. As injection starts, they will use the data gathered to set up a sort of “traffic light system,” he explains. This warning system feeds back to the operator to give them an alert if problems arise.

“If all we’re hearing are little, tiny pops and pings that are kind of random around then it’s green light. If the size of those pops and snaps increases, or they start to be concentrated in a particular area that seems related to the injection, then we might go to a yellow alert level, and at yellow alert level we probably recommend some other kinds of geophysical investigations,” Duncan says.

“And if we were to see large events that are suggesting there’s going to be a seismic event that could be felt at the surface or that the cap rock is being broken or that the fluids are leaking, which then would be indicated by a flurry of events of increasing size, concentrated in a given area, then we might go to a red alert level at which point they would probably slow down or stop injection for a period of time until they could figure out what’s going on.”

For any ethanol producers who are considering carbon capture and storage onsite, Hamling encourages them to keep in mind that getting approved to build a storage facility is a multi-year process. He also suggests that they reach out to those who have worked in that space, as well as checking into regional CO2 partnerships, like the PCOR Partnership to understand the storage potential near their plant. “These projects take time to develop and permit,” Hamling says. “Each project has site specific considerations, so being able to characterize and understand, you know, the specific site relative to the project is important for moving projects forward.”