There have been significant changes in certain EPA programs under the new administration. Some have been emphasized, and others have changed their direction. Class VI projects are regulated under the Safe Drinking Water Act, and states are attempting to ensure that, to the extent possible, they are using local resources to address local challenges, as carbon sequestration in Texas differs from that in California or West Virginia.
This is why the federal government says it encourages states to take primacy. It is believed that this will remove regulatory barriers to permitting these projects, streamline the process, and expedite it, resulting in a better outcome for permittees because local decision-makers may better understand and can address any issues.
The EPA has granted primacy for Class VI underground injection control (UIC) wells to four states: Wyoming (2018), North Dakota (2020), Louisiana (2024), and West Virginia (2025). Arizona and Texas are pending approval – expected in 2025. Here, we cover several states with primacy, moving toward primacy, or with local influences to illustrate what makes each state particularly attractive or challenging for carbon sequestration project developers. We’ll also provide some key recommendations for mitigating challenges with navigating a carbon sequestration project within each state.
Texas is interesting – the EPA retains primacy as it transitions to the state.
When you submit a Class VI project to Texas, you’re submitting it to both EPA Region 6 and, by Texas state law, to the Texas Railroad Commission. You also need a no-harm determination letter from the Texas Commission on Environmental Quality. Each agency has jurisdiction in different ways.
Some of our clients in Texas are receiving three sets of questions or requests for clarification on these permits from three different agencies. With the transition to the state, this process is expected to be simplified relatively quickly after the memorandum of understanding completes the public comment period.
For those in the Lone Star State, it is advisable to consider approaches to solving technical issues, as Texas law requires. For example:
Louisiana got its primacy a year ago, but using public lands is an issue.
Louisiana is a state with a significant petrochemical industry and numerous potential permits. Notably, part of Louisiana’s process for Class VI wells involves leasing public lands, specifically the pore space beneath public lands. Pore space is the empty space within rocks, soils, and sediments, essentially the gaps between particles or within fractures. Pore space serves as storage for injected carbon dioxide. It is one of many factors examined in geological formations and processes like carbon capture and storage.
Public lands, such as state wildlife refuges, have been considered for carbon sequestration. The state leases pore space beneath these lands for 99-year periods or some long-term lease for developing a project. The underlying issue we see in Louisiana’s approach is that they’ve chosen to lease public land as a framework for many of their project developers and as a means to raise money and pay for carbon sequestration. There’s a tussle between different stakeholders who view things differently.
If you’ve worked on any number of these projects, education is paramount to the permitting process; the public needs to feel confident in the protection of the environment and their drinking water resources. As our projects in Louisiana progress, we continually talk about the safety of deep geologic storage on drinking water resources, monitor potential reevaluations, and stay ahead of opportunities to educate and inform the public. SCS employs conservative design philosophies and utilizes the most up-to-date scientific information on materials to prevent unexpected problems in wells. Robust testing and monitoring programs ensure that operations remain functional and safe. It may be that the state will have to choose a different way to implement Class VI reviews.
Illinois does not have primacy, but it passed a bill and a moratorium this year.
The bill SB1723 doesn’t replace the EPA Region 5 rule for carbon sequestration but adds bans or exemptions based on local geology requirements. The map shown here is of the subsurface Mahomet Aquifer, ranging from 300 to 500 feet deep. The bill prohibits penetrating this aquifer for geologic sequestration (typically 5,000 to 6,000 feet deep) to protect the aquifer if there is a leak. Redundant controls help to mitigate any compromise of integrity and escape of CO2.
Champaign County has also put a county-wide moratorium on wells for a year using Zoning Case 157-AT-24. When evaluating project feasibility in Illinois, there are federal-level regulations, plus state, county, and, in some cases, city regulations. These are very specific regulations about whether or not wells are acceptable on certain types of land. Understanding the federal-level landscape and the local stakeholders is vital for Underground Injection Control (UIC) consideration.
Arizona’s primacy was recently announced.
Primacy is a big step for Arizona with its deep sedimentary rocks. One interesting thing about Arizona is the proposed fee structure, which may make it an attractive area for injection wells. The Arizona Department of Environmental Quality administers the UIC program. It plans for its fee-for-service model to cover operating expenses of carbon sequestration projects.
Arizona’s power generation includes coal-fired power plants and management of post-combustion waste streams alongside sources like natural gas and nuclear power, which make carbon sequestration in Arizona an attractive option.
West Virginia is considered a sustainable option.
West Virginia is nestled in the Appalachian Mountains and contains strata that make the state particularly attractive and cost-effective for developing UIC projects. The geologic media combination of porous sedimentary rock formations, impermeable shale layers, and primacy streamlines project permitting while maintaining the highest levels of safety.
Case Studies and Carbon Sequestration Challenges
As we mentioned previously, education is paramount to successful projects. To be transparent and educate all stakeholders, which include the public and all agencies, science, data, and a long-term approach must back any carbon sequestration-designed solution. Developers must be able to support a client’s project to fruition and beyond monitoring and control to foresee challenges and maintain safety throughout the carbon sequestration lifecycle.
In the Midwest, the EPA issued draft permits for a Class VI project supporting a cement kiln operation. The project site is located a little bit away from the source of the actual carbon dioxide produced; thus, a short stretch of pipeline is involved.
Some of their nearby stakeholders raised this appeal for the permit in the public comment period, and they had several different claims, including the post-injection site care period, the time frame after which the injection of carbon dioxide ceases.
Facility operators are required to monitor during the post-injection period and site closure. The standard default period is 50 years. A 10-year post-injection monitoring period was proposed for this site as adequate. The EPA responded by requesting a more detailed analysis to back the request, remanding it back to Region 5 for further evaluation.
In our experience, there are many technical reasons why a shorter than the standard default period is extremely hard to demonstrate that it is safe. Issues with plume, stability, movement, and geologic stability are just the beginning. Of all the things to ask for during permitting, a short post-injection period does not seem to be fruitful, and for truly sustainable projects, it doesn’t save much in the long term. Monitoring is one of the least expensive and valuable safety precautions of carbon sequestration.
In the West, Environmental Quality Acts
Kern County hosts a carbon sequestration project in California, which is interesting because of the California Environmental Quality Act (CEQA) and proposed climate laws within SB-253 and SB-261. Plaintiffs contend that the project did not fully analyze their potential carbon dioxide sources, claiming that the carbon capture and sequestration through California Resources Corporation’s (CRC) project will attract carbon dioxide-producing operations to the site that would not otherwise have come to the county. It’s now a land use matter.
The project illustrates the need for clients to look at the ties between their sources of carbon dioxide (producers) and their geographical location, along with the geologic storage capability. This is project siting, a standard part of a feasibility analysis conducted before a carbon sequestration project is developed. Sustainable projects are a combination of safety, environmental protection, and economic feasibility in the long term.
When evaluating a potential project, we inquire whether there are sustainable sources of carbon dioxide that a developer can effectively compete for. Unless the sources of carbon dioxide and storage capabilities are considered in the feasibility stage, the proposed project may be considered speculative. In short, early consideration of these factors reduces the perception that carbon sequestration is only a business venture and devalues the fact that it reduces atmospheric carbon dioxide concentrations, significantly mitigating climate change.
Pipelines and their relationship to permitting carbon dioxide capture.
South Dakota is the latest in a history of pipelines and their relationship to carbon dioxide projects. The state enacted a ban on eminent domain for carbon dioxide pipelines.
Ethanol production, which generates almost pure carbon dioxide, has been a potential source of capture and sequestration. It’s easy to obtain, concentrated, and pure as a source for capture. The challenge is balancing the amount generated in an individual plant versus the amount of economically reasonable geologic storage.
It seems very basic, but they’re sometimes not in balance. For example, the output of 15 to 20 ethanol plants and a strategy to chain them together by pipelines was proposed to minimize transportation costs. Pipeline transport of carbon dioxide is inexpensive, so it seemed to make sense that a pipeline network could dispose of it all at one site.
The pipeline network has caused many problems for the industry regarding public opposition to pipelines, largely because the pipelines would run through farmland. Then, it brings in all sorts of additional permitting and safety issues as well.
It’s not simply an issue in South Dakota but nationwide. Under the Safe CCS Act, Illinois enacted a two-year moratorium on pipeline development until further evaluation of pipeline safety. Although an extension, the same challenges cause clients to look at alternatives.
Unique to each project, a developer might recommend right-sizing the facility or creating a smaller group of facilities rather than one networked superhub. It avoids landholder objections and pipeline issues while sizing the storage capacity to sources. It may seem more expensive in the short term, but in the long term, it may not.
Another thing we’ve been looking at that seems less objectionable is rail transport instead of pipeline transport. The bottom line is that your developer should be able to propose and analyze alternatives with you to ease the permitting process.
There are different arguments to make on one side or the other. Still, looking for alternatives to connecting a large regional pipeline across the Midwest is advisable because eminent domain issues drive firms to reevaluate spending time and resources when developing a project that relies on a large or multi-state pipeline.
About the Author: Charles Hostetler, Ph.D., is a project manager and subject matter expert in geochemistry, hydrogeology, risk assessment, environmental regulations and permitting, and natural resources assessment. He provides clarity for prospective project owners interested in developing carbon sequestration solutions, low-carbon intensity products, and environmental due diligence for the energy sector. His core competencies include project management, groundwater modeling, multimedia environmental monitoring, and wetland permitting, construction, and monitoring.
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