Comments: Why Scaling CO₂-EOR Remains Difficult

In August, Occidental Petroleum told investors that Stratos, its long-awaited direct air capture (DAC) project, could be fully constructed by year-end, with full commercial operations expected in 2027.

The Permian Basin facility, expected to be the world's largest DAC plant with a nameplate capacity of 500,000 metric tons of CO₂ per year, was initially targeted to begin operating in 2024. The startup date was later pushed to mid-2025, which ended up slipping once again. The company attributed the most recent setback to an unspecified component that required significant repairs but was said to be unrelated to the core DAC technology involved.

The lengthy delay reflects not only the challenge of scaling emerging technologies such as DAC, but also serves as a general reminder of the often long and difficult process of integrating carbon capture, storage and utilization (CCUS) projects with oilfield operations.

A point source for the emissions usually needs to be relatively close to the oil field to keep midstream costs manageable. Then there’s the cost of capturing technology, which can be expensive to install and maintain. In a low-price environment, justifying these added expenses can be too high a bar for management.

Stratos is estimated to have cost Occidental and its partners $1.3 billion, which the company is hoping to make back by selling carbon credits to other industrial firms. It also wants to make money with the CO₂ by supporting its enhanced oil recovery (EOR) business in the Permian. The company has for decades used naturally sourced (i.e., geologic) CO₂ for EOR in conventional rocks, but has recently committed to commercial-scale shale CO₂-EOR.

Occidental has outlined plans for three shale CO₂-EOR projects, two in Texas and one in New Mexico, with additional developments hoped to come in the future. Early pilot results saw production gains of 40 to 50% above baseline levels, which represent a big enough carrot for the company to go after with new CO₂ infrastructure.

ExxonMobil is also looking to step up its CO₂-EOR business following its 2023 acquisition of Denbury, which operated 1,300 miles of CO₂ pipelines across the US.

The US supermajor has recently proposed a 900-mile "carbon superhighway" designed to transport captured shale CO₂ from industrial facilities across Texas, Louisiana, and Mississippi to other locations for EOR, permanent storage, and commercial beverage manufacturing. ExxonMobil has said CO₂ volumes and quality will be monitored as they enter and move through the system, likening the process to vehicles passing through toll booths.

The US pioneered CO₂-EOR in the 1970s and remains a global leader in the practice. There are more than 140 such projects spread across the country. This is according to a slightly dated report in 2021 from the Enhanced Oil Recovery Institute, which said then that CO₂-EOR projects accounted for 273,000 B/D of combined output.

But there are also projects outside of the US that are worth noting.

In Canada, the best-known and successful may be the Weyburn-Midale Field in Saskatchewan. Pilot CO₂ injections started in the 1980s and by 2000 full-scale injections began.

As summarized in a recent paper (SPE 233164), more than 121 million metric tons of CO₂ have been placed into the reservoir, sourced from a coal gasification facility across the international border in North Dakota.

But not all the CO₂ stays in the ground in some of these projects. Researchers responsible for the paper highlighted that, in the Weyburn-Midale Field, about 65 million metric tons, or just over half, of the CO₂ has remained sequestered, while the rest was produced back with the oil.

In 2025, Brazil’s Petrobras said it had injected almost 68 million metric tons of CO₂ since 2008, and it expected that figure to rise to a total of 80 million metric tons by the end of that year.

In 2024 alone, the company injected 14.2 million metric tons into the pre-salt rocks of the Santos Basin, which it said represented the largest CO₂-EOR project of its kind in the world and represented more than a quarter of all CCUS efforts globally.

The data suggest Petrobras has rapidly scaled up injection activity, with 2024 and 2025 injection volumes running several times above the project's long-term historical average.

The strategy used by Petrobras involves 22 floating production, storage, and offloading (FPSO) units that are equipped with CO₂ capture and injection technologies.

One of the newest technologies in this area is a subsea high-pressure separation and reinjection system called HISEP. Developed by Petrobras and built by Technip, HISEP was the cornerstone of a $1.5-billion pilot program in 2024 in the Mero field. The goal was to lower the cost of processing CO₂ on the topsides of an FPSO.

The technology is now hoped to be applied across other developments, potentially extending production from Brazil's pre-salt fields and especially those reservoirs with a high CO₂ content.

Other countries including China, Turkey, Hungary, the UAE, and Saudi Arabia have also established CO₂-EOR projects of varying scale. Several more are either piloting or are in the early stages of launching their first CO₂-EOR developments.

One to watch is in Oman. A pilot project that has led to a full-field development was recently presented at the SPE Improved Oil Recovery Conference this year in SPE 231525.

The paper outlines Oman’s first full-field CO²-EOR project that will involve capturing up to 250,000 metric tons of CO₂ per year which will be transported just over 57 miles to well locations.

The project, owned and operated by Petroleum Development Oman (PDO), includes the drilling of 94 new horizontal wells for production along with 42 new dual and single lateral wells for gas injection. PDO expects to have CO₂ injections running by 2031 and thanks in part to CO₂ recycling aims to produce the field for 25 or more years.

Notably, the field could not be economically produced without this approach. PDO reports that the low permeability of the rock resulted in a primary recovery factor of only 2%. With the CO₂ injections, PDO believes it can recover as much as 30% while also hoping to leave all the injected CO₂ in the ground.

Various analyses have shown that there is a great deal of potential to expand CO₂-EOR across many of the world’s reservoirs, at least from a technical perspective.

But as is pointed out by the author of SPE 233164, companies must first have a very detailed and clear vision to accomplish such a project. And as mentioned, capturing technology is expensive and complex, as is moving the gas around.

ExxonMobil’s plan hinges on an existing network of several hundreds of miles of CO₂ pipelines it bought from what was a pure play CO₂-EOR operator. In other words, it did not sprout overnight.

Also, almost no countries offer the kind of government incentives or generous tax breaks that the US and Canada do for this type of operation.

Then there is the critical factor of human capital. Experience and technical expertise are widely viewed as essential to the success of CO₂ management programs and to controlling project costs.

That expertise may be more readily available than two other essential ingredients. The first is corporate commitment. The second, closely related, is access to capital, or at least capital that can compete with other investment opportunities for funding.

Occidental provides a useful example. In 2023, the company outlined a vision of building 100 DAC plants globally by 2035. Today, with its first commercial-scale facility facing the sometimes-harsh realities of startup and scale-up, that goal appears unrealistic. The company has likewise stepped back from publicly mentioning its original target.

For Further Reading

SPE 231525 The Field Development Plan for Sultanate of Oman’s First Full-Field CO₂ Enhanced Oil Recovery Project by R. Valdez, J. Gavnholt, and A. Dhahli, et al.

SPE 233164 Thirty Years of CO₂ Storage: Lessons Learned, Field Realities, and the Central Role of CO₂-EOR by Tayfun Babadagli.