The largest market for CO2 captured from industrial sources through carbon capture utilization and storage (CCUS) is enhanced oil recovery (EOR), using the CO2 to produce oil. Captured CO2 can be used for cement, algae production, and other uses, but EOR has vast potential. Moreover, it has a nearly 50-year track record in the US, where it was pioneered. Carbon dioxide injected into oil formations becomes permanently stored as part of the process.
However, in recent months, world petroleum production has been far above demand, and oil storage is running low. This is due to a combination of Russian and Saudi production increases and decline in global demand during the COVID-19 pandemic. Market experts suggest that even a temporary circumstance of such significant imbalance as exists today could have lasting consequences. Many companies are expected to shut down production, resulting in delayed construction of new wells. If oil markets remain depressed for some time, projects capturing carbon may look for other storage possibilities.
Another key option for captured CO2 is underground storage in a non-producing geologic formation – for example, a saline formation. The United States has been testing formations for suitability for large-scale storage for some two decades. There is one operating large-scale industrial capture and storage project in a saline formation in the US. There need to be many more to make material progress toward meeting GHG emission reduction goals. And without CCUS, the world will not meet emission reduction goals.
To encourage people to capture CO2 from industrial processes, regardless of whether the CO2 was used for EOR and stored, or whether it was simply stored, in 2008 Congress enacted the Section 45Q tax credit. Congress amended the tax credit in 2018, significantly increasing and enhancing it in a variety of ways. Today the tax credit is set to rise over a period of years to $35 per ton of CO2 captured from an industrial source and stored through EOR, and $50 per ton for CO2 stored in a non-producing geologic formation. Congress also authorized $50 per ton for “utilized” CO2 (such as cement or algae), subject to a life cycle analysis to assure the CO2 stays out of the atmosphere. The reason for the lower credit for CO2 used for EOR is that there is an expectation that oil producers will pay for the CO2, as they have done for many years.
In recent years there has been much focus in the policy arena on making CCUS work in an EOR context. Additional focus now should be placed on how to make non-producing storage more workable.
A main focus should be the US Environmental Protection Agency’s (EPA) Class VI Underground Injection Control (UIC) program, the program under which CO2 storage not associated with oil and gas production is regulated.
Below are some of the policy concerns that have been raised regarding the Class VI program. These and others were addressed in detail in the National Petroleum Council (NPC) report to the Secretary of Energy issued last November.
- Permitting Delays – The permits for the one currently operating Class VI facility took EPA about five years to issue. EPA needs to accelerate the permit review process. Reducing permitting delays and uncertainties will be helpful as companies work to qualify their projects for the Section 45Q tax credit by the statutory “under construction” deadline. The NPC report recommends issuing the permit to drill within six months of application, and the permit to inject within six months of EPA receiving a well completion report. One means of accelerating the process would be to grant States primacy for the Class VI program.
- State Primacy – States need to be authorized by the EPA to have primary enforcement responsibility for the Class VI program so permits can be issued in a timely manner. EPA doesn’t have the resources to issue permits across the country. States typically administer the UIC program for other well classes, particularly the Class II program under which oil and gas injection wells are regulated. Only North Dakota so far has been approved to run the Class VI program in lieu of the EPA. Other States have initiated pre-application activities. EPA has issued a proposed rule, which is open for comment until May 29, to grant Class VI primacy to Wyoming. EPA should process primacy applications expeditiously, and more States should be encouraged to apply.
- Risk-Based Structure – Stakeholders have expressed concern that the UIC program has not been implemented with sufficient consideration for risk. The program is designed to prevent endangerment of underground sources of drinking water. 40 CFR 144.12 requires the program director to prescribe additional construction, corrective action, operation, monitoring, or reporting requirements as are necessary to prevent the movement of any contaminant into a USDW. The NPC report calls for greater consideration of risk in implementation of the Class VI program.
- Monitoring Flexibility – The Class VI program requires testing and monitoring to track the CO2 plume and pressure front by direct methods in the injection zone, and indirect methods as appropriate. As the NPC study points out, monitoring strategies may evolve over time, and direct measurement in the injection zone – which could be interpreted to require an additional monitoring well – may not be the most efficient means. The requirements can serve the objective of preventing endangerment of USDWs by a more flexible definition of effective monitoring.
- Financial Responsibility – A number of financial instruments may be used to meet the program’s requirement that a project operator demonstrate financial responsibility. However, some of the requirements are unnecessarily restrictive and can result in costlier financial instruments than are necessary to protect the public from having to pay for any future remediation that may be required. Moreover, overly conservative risk assumptions drive unnecessarily high estimates of potential future remediation costs.
- Post–Injection Site Care Period – EPA set a 50-year default post-injection site care period for CO2 injected in Class VI wells. This is a longer period than many commenters on the proposed rule recommended. The 50-year period is a default, and may be shortened (or lengthened) as appropriate based on site-specific circumstances. Specifically, EPA set a lengthy period out of concern that CO2 injectate may migrate for years after injection ceases. The default should be shortened to a period more commensurate with anticipated risks.
When EPA issued the Class VI rule in 2010, it said it would employ an adaptive regulatory approach and look to revise the program in six years. A review is past due. EPA is unlikely to take up Class VI revisions in 2020, but stakeholders should lay the groundwork now for the agency to take up revisions next year.