According to The Global CCS Institute, the number of active carbon capture projects is dramatically increasing across a number of heavy industrial sectors.
Reading behind the data, we see that the total number of projects in development from 2021 to 2023 has remained relatively steady, though capacity has increased due to much larger projects being developed in North America, Southeast Asia and the U.K.
In the U.S., recent federal incentives are priming the pump for carbon capture across many industrial sectors. Both the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) are injecting billions of dollars into the capture marketplace. The IIJA will jump-start investment through various matching grant programs administered by the Department of Energy (DOE), while the IRA provides a pathway to monetize carbon capture investments through increased 45Q tax credits.
As the Treasury Department finishes guidance on exactly how the IRA tax credits will work, it is becoming clear that the tax code will become an economic engine that drives many billions in investment dollars out into the market for carbon capture projects over the coming decades.
New greenhouse gas standards and guidelines issued by the EPA in May 2023 are likely to make some form of carbon capture a reality for some fossil-fuel generation plants. Unless the standards are significantly modified, they will affect development of combined-cycle plants and certain existing coal- and gas-fired plants. The new standards are subject to a public comment period and are unlikely to be finalized before 2024 at the earliest.
No matter how the final rules shake out, a better understanding of the entire process chain of carbon capture utilization and storage (CCUS) and carbon capture and sequestration (CCS) projects will be helpful.
There are unique technology options that are available when designing a capture plan for power facilities. A number of newer, developmental technologies are entering the market alongside older, proven technologies.
For post-combustion carbon capture from flue gas, the amine absorption process has the longest track record in the market. It’s been demonstrated at commercial scale and can deliver approximately 95% CO2 capture (and sometimes higher). The main drawback is that amine capture in an energy-intensive process using both thermal and electric energy that diverts significant megawatts of auxiliary power from the plant, reducing total capacity available for dispatch to the grid.
Cryogenic processes for post-combustion capture also are attracting some interest. This pathway involves cooling flue gas to approximately -120 to -130 degrees F, which reduces volume by 98% and results in phase-change of gaseous CO2 for removal from the flue gas. As a process similar to liquefying natural gas, it too requires significant megawatts of auxiliary electrical energy.
Another capture process involving sorbent adsorption technology is also used in power plant applications. This technology pathway is also used in direct-air capture systems. This process captures the CO2 and binds it within the sorbent media until it is released via heating and then stored for transport or sequestration.
Membrane systems are another technology pathway. In this process, the CO2 binds to the membrane and is released into a storage unit when saturated. The process requires high pressure and works best under conditions with high concentrations of CO2. The auxiliary power requirements are not as high for membrane systems, though capture rates are somewhat lower, ranging between 60% and 80%.
The evaluation of any capture technology will depend on the type of plant it will serve and will have potential high auxiliary loads to consider. However, with the new tax credits and other incentives, high energy cost burdens may be offset.
Connecting the Dots
Project elements must go beyond capture to incorporate separation, dehydration, compression, transport, geological sequestration or beneficial use.
For projects where a CO2 injection field is not in close proximity to the plant, a pipeline component will be necessary. As we have seen in many states, permitting for new pipelines can be particularly onerous with objections over siting a commonplace obstacle. Eminent domain rights for pipeline corridors are uncertain at best, so carbon pipelines are a risk consideration for successful carbon capture projects.
The sequestration component can also be complex. Both utilization of CO2 for enhanced oil recovery and dedicated geological sequestration wells are incentivized by the IRA. The geology of a given region will dictate whether a Class VI well for geological sequestration is feasible. In an injection well, the CO2 can transition to geospatial voids deep underground. In some geologic formations, the CO2 gas may react with surrounding mineral deposits and turn into a solid that will be perpetually locked in place. A detailed geotechnical investigation will be necessary as part of the permitting process, as this is a highly location- and geology-specific determination.
Jurisdictional considerations will also be a factor in Class VI injection well permitting. Currently, North Dakota and Wyoming have obtained state primacy to approve wells instead of the federal EPA, with Louisiana anticipating primacy by end of the year. The EPA maintains jurisdictional authority within the remaining states, although Arizona, Illinois, New Mexico, Texas, West Virginia and others are similarly seeking primacy.
For states that defer to the EPA for Class VI well approval, the targeted permitting time by EPA staff is around two years; however, some locations may see much longer durations. This rigorous process will follow the established steps of feasibility and geotechnical studies, desktop simulations, public hearings and more. Unless expedited approvals become the new norm, it is likely that well permitting will become a limiting factor in determining how fast a carbon capture project can come online.
Start Planning Now
Regardless of the final form of this rule, we should expect some form of carbon capture to be possible in the future for large, frequently operated, combined-cycle natural gas plants. The financial incentives available under both the IIJA and IRA appear to hold potential to soften the blow and jump-start investment. The Section 45Q credits under the IRA give developers 10 years to begin construction of carbon capture projects (with commencement of construction required prior to Jan. 1, 2033) and will serve to generate lucrative tax benefits for 12 years of operation following that.
Though these units will often reach or exceed $1 billion of capital investment, there are many opportunities to value-engineer the design to optimize a number of processes. For example, opportunities exist for more efficient exhaust gas recirculation to allow higher volumes of CO2 to be sent to capture units. This increases the CO2 concentration in exhaust gas and allows for more efficient and cost-effective removal of the CO2.
Other design advances can improve constructability, making capture units easier to clone with standardized fabrication and on-site construction. With the enormous investment tied up in these vessels, even incremental efficiencies can pay off with big returns.
Utilizing hydrogen in future fuel blends also could be a consideration to drive further efficiencies. Tax credits for clean hydrogen production — either from methane reformation with carbon capture or electrolysis utilizing renewable energy — are available under the IRA’s Section 45V. This can lead to a complicated evaluation, however, as the IRS tax code does not allow for double-dipping to simultaneously take advantage of both a carbon capture credit and a hydrogen production credit.
The bottom line is we’re about to enter an interesting new era that will call for careful evaluation and due diligence to reap the rewards of new carbon capture investments in power facilities.
Streamlining the permitting process for carbon capture utilization and sequestration projects will be essential as decarbonization momentum builds.