Carbon capture and sequestration (CCS) offers operators a real economic opportunity through the 45Q tax credit—up to $85/ton for geologic sequestration and up to $60/ton for CO2 used in enhanced oil recovery (EOR). Most operators aren't using it. The bottleneck isn't geology or regulation. It's coordination.
Jim Clark of JWC3 Resources LLC has 44 years of petroleum engineering experience across Gulf of Mexico deepwater, West Texas CO2 floods, California oil fields, and East Africa gas discoveries. He holds dual petroleum engineering degrees from Texas A&M, an MBA, and an MS in analytics. In a recent interview, Clark broke down the economics of carbon capture, the regulatory divide between Class II and Class VI permits, and why the 45Q credit is an opportunity operators keep walking past.
What Does a Reservoir Engineer Actually Do?
A reservoir engineer is a subsurface detective, working with limited data scattered over miles and making sense of a lot of unknowns.
Clark makes this concrete with a single image: hold up a pen. That's the scale of a core sample. A few inches of rock may be the only physical data available across a reservoir stretching miles in every direction. From that sample, engineers infer the size, connectivity, fluid movement, and economic value of the entire formation.
The rest is integration: pressure data, well logs, seismic reflectors, production trends—all cross-checked across disciplines. It's applied physics under financial pressure. Mistakes cost millions.
This forensic approach shapes Clark's work in CCS reservoir analytics. Carbon sequestration, in his view, is fundamentally a subsurface problem. Treating it primarily as a policy question misses the point entirely.
How Much Does Carbon Capture and Storage Cost?
Total CCS costs run approximately $100 per ton of CO2. Capture and compression account for 70—80% of that figure.
Public data backs this up. Reports from the Congressional Budget Office and the National Petroleum Council show that CO2 capture constitutes roughly three-quarters of total CCS costs. Getting CO2 from a gas stream or smokestack to supercritical form is where the money goes. Drilling injection wells is, by comparison, a small expense.
Direct Air Capture (DAC) makes the economics harder still. The International Energy Agency estimates DAC costs between $135 and $345 per ton—well above the 45Q credit values for point-source capture. Some analyses project costs remaining elevated for DAC through the next decade. This is why current projects focus on high-concentration CO2 sources: natural gas processing, ethanol, and ammonia plants, where capture is economically viable.
Illinois and Indiana illustrate this clearly. Both states host ethanol and ammonia facilities emitting CO2 at 85—95% concentration. Operators strip impurities, pressurize the CO2, and inject it into storage reservoirs. The capture economics work because the concentration does the heavy lifting.
California Resources Corporation (CRC) is running this playbook at Elk Hills. CRC is developing a project to capture CO2 from their 550-megawatt power plant and inject it into depleted reservoirs, targeting 1.5 million metric tons annually. Clark sees this as exactly the type of project the 45Q credit was designed to enable.
What Is the Difference Between Class II and Class VI Injection Permits for CCS?
Class VI permits are required for geologic sequestration under the 45Q tax credit's highest tier ($85/ton). Class II permits govern CO2-EOR, qualify for up to $60/ton under 45Q, and are significantly faster to obtain.
Class VI permits involve multiple reviews, information requests, draft permits, public comment periods, and final EPA approval. According to the CBO, obtaining a Class VI permit is a multiyear process, and very few applications result in actual well construction.
Class II permits are a different story. They're already widely used for CO2-enhanced oil recovery and are familiar to Texas operators. Less regulatory red tape. A faster path to injection.
"The permitting for Class II is much simpler," Clark says. "It's a faster way to get CO2 in the ground."
Pore space ownership adds another layer of complexity. Louisiana has resolved many legal questions around subsurface injection rights—and as of September 2025, issued its first state-level Class VI permit to Hackberry Carbon Sequestration following a nearly four-year application process. Texas received Class VI primacy in November 2025 (effective December 15, 2025), though its regulatory framework is still taking shape, and legal challenges common to other primacy states remain possible.
Is There an Untapped CCS Opportunity in Existing Water Floods?
Yes. Clark argues it's one of the most overlooked pathways in CCS right now.
Twenty-five years ago, Clark ran CO2 floods in West Texas at lower pressures—around 1,500 psi—where CO2 behaves as a gas, rather than the 3,000—5,000 psi required for supercritical injection. The physics is well understood. The costs are lower: less compression, shorter pipelines.
His thesis is direct: convert old water flood units to CO2 injection. Capture CO2 from a nearby industrial source, build a short pipeline, inject at low pressure, and collect both the $60/ton 45Q EOR credit and incremental oil recovery revenue.
This works especially well where gas-fired power plants sit near aging water floods. Whenever Clark pitches the idea, he hears the same response: "It's too hard."
His reply: "It's not hard. It just requires coordination between disciplines."
What Are the Subsurface Risks in CCS That Operators Can't Ignore?
The biggest underappreciated risk is legacy wellbore integrity in heavily drilled formations.
A migrating CO2 plume can encounter wells drilled decades before CO2 exposure was a design consideration. Casing corrodes. Cement degrades. CO2 mixed with water forms carbonic acid—chemically aggressive to infrastructure and a contamination risk to underground drinking water. Regulators take this seriously. So should operators.
Offshore storage limits this risk. Fewer legacy wells per square mile means less exposure. But offshore adds cost and complexity—pipelines capable of handling supercritical CO2, prevention of water contamination, longer supply chains.
For Clark, these aren't reasons to walk away. They're problems that require subsurface expertise. "This work needs to be led by people who understand the geology, not just policy."
How Is AI Being Used in CCS and Subsurface Analytics?
AI accelerates workflows and improves judgment. It doesn't replace domain knowledge—and trusting it without that knowledge is a serious mistake.
Clark built this out directly. In one East Africa gas project, he developed a machine learning model to predict 20-year production values from well logs. The model was built from 1,000 reservoir simulations. Accuracy rate: 98%. Results delivered to decision-makers within an hour.
The model didn't make decisions. It gave the right information to the right people at the right time.
Clark's warning is plain: "You need enough domain knowledge to know if the answer makes sense." AI speeds up the work. It doesn't validate it. Engineers who treat AI outputs as conclusions rather than inputs will make expensive mistakes.
Why Communication Skills Matter as Much as Technical Skills in Reservoir Engineering
"Your ability to communicate is as important as your technical skills."
Reservoir engineers sit at the intersection of geology, economics, regulatory policy, and operations. Whether explaining pore space rights to a land team or presenting injection risks to a board, communication determines whether good technical work moves forward—or doesn't.
This is the part of the job that doesn't appear in the job description but decides outcomes. Clark is direct about it: the best technical analysis, poorly communicated, doesn't move a project. It gets shelved.
The 45Q Opportunity Is Here—For Now
The 45Q tax credit is an immediate, operational opportunity: up to $85/ton for geologic sequestration and up to $60/ton for EOR under Class II permits, with both figures adjusted for inflation after 2026. As of mid-2025, the 45Q framework had already supported more than 270 announced and operational projects, with 130 in advanced development, according to the Carbon Capture Coalition. Projects that begin construction before January 1, 2033 can claim the credit for up to 12 years after being placed in service.
Existing Class II EOR infrastructure means operators don't need to wait for Class VI permits to start.
CRC's Elk Hills project shows what execution looks like. But the bottleneck isn't geology. It isn't regulation. It's the willingness to coordinate across disciplines.
"The 45Q credit is here now," Clark says. "It may not be in 20 years. The opportunity is real—it just takes collaboration to seize it."
Frequently Asked Questions
**Q: What is the 45Q tax credit, and who can claim it?**The 45Q tax credit is a U.S. federal performance-based incentive for carbon capture projects. It provides up to $85/ton for dedicated geologic sequestration and up to $60/ton for CO2 used in enhanced oil recovery. The owner of the capture equipment is eligible to claim it and may elect to transfer the credit to another taxpaying entity. Eligible projects that begin construction before January 1, 2033 can claim the credit for up to 12 years after being placed in service.
**Q: Can operators access the 45Q credit without a Class VI permit?**Yes. CO2 used in enhanced oil recovery (EOR) under a Class II injection permit qualifies for the 45Q EOR credit—up to $60/ton. Class II permits are widely used, faster to obtain, and familiar to operators already active in water flooding or CO2 injection. Class VI permits are required only for dedicated geologic sequestration projects seeking the higher $85/ton credit tier.
**Q: What role does AI play in CCS project evaluation and reservoir analytics?**AI tools can significantly accelerate subsurface analysis—reducing the time required to model reservoir behavior from weeks to hours. However, AI outputs require validation by engineers with strong domain knowledge. As Clark's East Africa example demonstrates, a machine learning model built on 1,000 reservoir simulations can achieve 98% predictive accuracy, but only when the inputs are correct and the outputs are interpreted by someone who understands the underlying geology.
Jim Clark is a petroleum and reservoir analytics engineer at JWC3 Resources LLC. Listen to his full interview on the Local Energy Podcast.
