Can EOR Wells Be Converted for CCUS?

Most carbon capture and CO2 injection in the United States to date has involved enhanced oil recovery. But what if some of those EOR injection projects could be converted to dedicated, long-term carbon storage projects?

Wait a minute.

What if … a lot of those wells could turn into injectors for CO2 sequestration?

The U.S. Environmental Protection Agency designates six classes of injection wells in its Underground Injection Control program. EPA Class II wells are used exclusively for injecting fluids associated with oil and gas production. Class VI wells inject CO2 into underground formations for long-term storage or geologic sequestration.

Lately, industry has seen a new interest in the possibility of converting Class II injection wells – now being used for enhanced recovery – into Class VI wells for long-term carbon storage as EOR projects play out.

How many wells, possibly?

“We can say thousands of Class II wells are located in areas where CO2 sequestration is feasible,” said Victor Cimino, subsurface solutions geologist with Burns & McDonnell in Kansas City, Mo. The company designs and builds critical infrastructure, for industries including oil, gas and chemicals.

The Class II to Class IV Process

Cimino is an author for the presentation “Class II to Class VI Program Conversion: Preparation of Continued Sequestration in Existing EOR Fields” at the CCUS 2025 conference in Houston. Co-sponsored by AAPG with the Society of Petroleum Engineers and the Society of Exploration Geophysicists, the event will be held March 3-5 at the George R. Brown Convention Center.

He said the presentation intends to “give a 30,000-foot snapshot of the landscape,” an overview of the Class II to Class VI process. Basically, “it would be the same process as permitting a Class VI project, because you’re still needing to get that permit,” Cimino noted.

Operators of Class II CO2 injection wells are able to utilize years of data from oil field production and EOR operations for their Class VI applications. As another upside, the producing field itself provides proof of geological trap-and-seal.

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CCS facilities capture carbon dioxide emissions from industrial processes and power plants, then store it underground.

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Most carbon capture and CO2 injection in the United States to date has involved enhanced oil recovery. But what if some of those EOR injection projects could be converted to dedicated, long-term carbon storage projects?

Wait a minute.

What if … a lot of those wells could turn into injectors for CO2 sequestration?

The U.S. Environmental Protection Agency designates six classes of injection wells in its Underground Injection Control program. EPA Class II wells are used exclusively for injecting fluids associated with oil and gas production. Class VI wells inject CO2 into underground formations for long-term storage or geologic sequestration.

Lately, industry has seen a new interest in the possibility of converting Class II injection wells – now being used for enhanced recovery – into Class VI wells for long-term carbon storage as EOR projects play out.

How many wells, possibly?

“We can say thousands of Class II wells are located in areas where CO2 sequestration is feasible,” said Victor Cimino, subsurface solutions geologist with Burns & McDonnell in Kansas City, Mo. The company designs and builds critical infrastructure, for industries including oil, gas and chemicals.

The Class II to Class IV Process

Cimino is an author for the presentation “Class II to Class VI Program Conversion: Preparation of Continued Sequestration in Existing EOR Fields” at the CCUS 2025 conference in Houston. Co-sponsored by AAPG with the Society of Petroleum Engineers and the Society of Exploration Geophysicists, the event will be held March 3-5 at the George R. Brown Convention Center.

He said the presentation intends to “give a 30,000-foot snapshot of the landscape,” an overview of the Class II to Class VI process. Basically, “it would be the same process as permitting a Class VI project, because you’re still needing to get that permit,” Cimino noted.

Operators of Class II CO2 injection wells are able to utilize years of data from oil field production and EOR operations for their Class VI applications. As another upside, the producing field itself provides proof of geological trap-and-seal.

That’s the good news.

The downside is, hundreds of holes would have been drilled through it for production, so those producing wells need to be remediated and plugged.

“An evaluation has to be done of what pore space is still available for CO2 sequestration within these operating EOR fields. There also has to be an evaluation of infrastructure,” Cimino noted.

He said other considerations include the availability of CO2 supply, pipelines – especially CO2 pipelines, capturing equipment in place or planned, well infrastructure and injection capabilities.

“Well materials are being retrofitted for Class VI injection. In a lot of instances we’re seeing, the casing is being swapped out for CO2-resistant casing. Also, is your casing large enough? What is the casing diameter in terms of maximum flow and possible pressure?” Cimino said.

“That’s another consideration: Is there enough CO2 being produced in this area to transport for injection?,” he observed.

“That’s a long pole on the tent of this, having the CO2 supply,” he said.

In some cases, EOR project operators are purchasing CO2 for injection. Changing to a different model of CO2 for sequestration represents a shift in thinking, economics, operations and overview, Cimino noted.

“I’d imagine if you are in an area where emitters are used to getting paid for CO2 for injectors, it may be less likely” to see a full Class VI conversion, he said.

Risks and Obstacles

Moving to Class VI operations from EOR involves challenges and risks, in part because permanent CO2 sequestration is substantially different from injection for production, with additional requirements. Storage injection also carries geomechanical risks from pore-pressure buildup.

“One of the considerations would be addressing the multitude of well penetrations through the confining formation,” Cimino noted.

“In addition, another consideration is that you now need to be monitoring for more than CO2,” he said.

In addition to CO2 leakage, project operators would have to monitor for anything that could come out of an oilfield, including brine, heavy metals and contaminants that might enter an underground aquifer.

“The most direct risk is release of CO2 into the USDW (underground source of drinking water),” Cimino said.

“You can never inject over 90 percent of your geological stress envelope,” he added.

How It’s Playing Out So Far

Another presentation in the same March 4 session on CCUS permitting and risk and will discuss “Transitioning CO2-EOR Field to Dedicated CO2 Storage: Risk Considerations and Quantifications,” in a deeper look at sequestration project risks.

The authors, from the U.S Department of Energy’s National Energy Technology Laboratory, will present “simulation scenarios (that) consider depletion status, injection schemes, model domain impacts, Area of Review, and monitoring for risk consideration and its quantification to estimate distributions of fluids phases and pressures for CO2 storage.”

Applying for a Class VI permit and developing the required information and submissions is “an involved process. You’re having to evaluate a lot of geological properties,” Cimino observed. The EPA has a target of reviewing complete Class VI applications and issuing final permit decisions within about 24 months, but the process often runs longer.

“A large chunk of that time goes to technical review,” Cimino said.

For background, as of early January the EPA had issued final decisions on permitting a total of eight Class VI CO2 injectors, according to the agency’s Class VI Permit Tracker, with 57 projects and 167 well applications under review.

Wells with final permit approval are in Indiana, Illinois and California. The EPA also has issued draft permits, or preliminary approval, for several other wells. Those permits subsequently go through a public-hearing processing before a final decision.

Three states gained primary enforcement responsibility, known as “primacy,” for Class VI permits before 2025: North Dakota, Wyoming and Louisiana. Primacy was approved for a fourth state, West Virginia, in mid-January, and many other states have primacy applications pending.

At the end of last year, the EPA issued four Class VI well permits to Carbon TerraVault JV in California. Those permits authorize CTV to operate four CO2 injection wells in the Elk Hills Oil Field, about 20 miles west of Bakersfield.

The wells will extend more than a mile below surface level, into the Monterey Formation, the agency reported. CTV plans to inject about 1.5 million metric tons (tonnes) of carbon dioxide per year for 26 years, totaling almost 38 million tonnes of CO2 removed and stored, according to the EPA.

Before authorizing the start of injection, the EPA has required CTV to properly plug 200 wells where carbon dioxide is expected to migrate during the project.

Government Incentives

In the United States, the economics of carbon-injection projects are primarily driven by the IRS 45Q tax credit, commonly valued by the industry at $85/tonne of CO2 captured and sequestered, or $60/tonne for CO2 captured and used in materials or chemicals production.

“When people look at the economics of these injection projects, they’re mostly looking at that 45Q credit,” Cimino said.

Currently, operators of Class II injection wells are getting money for producing and selling oil in addition to the EOR sequestration tax credits.

“This would need to be fully offset by the tax credit of Class VI injection only, which would feasibly mean you would have to be injecting greater quantities of CO2 in Class VI than you were during Class II to make the economics work,” he said.

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