Carbon capture and storage (or sequestration)—known as CCS—is a process intended to capture man-made carbon dioxide (CO₂) at its source and store it to avoid its release to the atmosphere. CCS is sometimes referred to as CCUS—carbon capture, utilization, and storage. CCS could reduce the amount of CO₂ emitted to the atmosphere from power plants and other large industrial facilities. An integrated CCS system would include three main steps: (1) capturing and separating CO₂ from other gases; (2) transporting the captured and compressed CO₂ to the storage or sequestration site; and (3) injecting the CO₂ in underground geological reservoirs (the process is explained more fully below in "CCS Primer"). The utilization part of CCUS has been of increased interest to researchers and policymakers. Utilization refers to the beneficial use of CO₂—in lieu of storing it—as a means of mitigating CO₂ emissions and converting it to chemicals, cements, plastics, and other products.¹ This report uses the term CCS except in cases where utilization is specifically discussed.

The U.S. Department of Energy (DOE) has long supported research and development (R&D) on CCS, currently within its Fossil Energy and Carbon Management Research, Development, Demonstration, and Deployment program (FECM).² From FY2010 to FY2022, Congress provided a total of $9.2 billion (2022 dollars)³ in annual appropriations for FECM, of which $2.7 billion (2022 dollars) was directed to CCS-related budget line items. Additionally, Congress provided a supplemental appropriation of $3.4 billion ($4.4 billion in 2022 dollars) for CCS in the American Recovery and Reinvestment Act of 2009 (ARRA; P.L. 111-5). It provided another supplemental appropriation of $8.5 billion (nominal dollars) for CCS in the Infrastructure Investment and Jobs Act (IIJA; P.L. 117-58) for FY2022 to FY2026.⁴ Congress has expressed support for continuing federal investment in CCS research and development—including financial support for demonstration projects—through the appropriations process in recent years and in DOE research reauthorizations provided in the Energy Act of 2020 (Division Z of the Consolidated Appropriations Act, 2021; P.L. 116-260). The IIJA provided funding for several programs authorized by the Energy Act of 2020 and established other programs aimed to promote CCS in the United States, as discussed later in this report.

Congress has also enacted tax credits for facilities that capture and sequester CO₂—one strategy for incentivizing CCS project deployment. In 2022, Congress enacted as part of P.L. 117-260, commonly known as the Inflation Reduction Act of 2022 (IRA), provisions that increased the tax credit for sequestering or utilizing CO₂, referred to as the "Section 45Q" tax credit.⁵ The IRA also extended the deadline for start of construction of certain facilities seeking the tax credit. The Internal Revenue Service regulations on Section 45Q issued in early 2021 could provide a more stable investment environment for project planning.

Congressional interest in addressing climate change has also increased interest in CCS, though debate continues as to what role, if any, CCS should play in greenhouse gas emissions reductions. While some policymakers and other stakeholders support CCS as one option for mitigating CO₂ emissions, others raise concerns that CCS may encourage continued fossil fuel use and that CO₂ could leak from underground reservoirs into the air or other reservoirs, thereby negating climate benefits of CCS.⁶

This report includes a primer on the CCS (and carbon utilization) process; overviews of the DOE program for CCS R&D, U.S. Environmental Protection Agency (EPA) regulation of underground CO₂ injection used for CCS, and the Section 45Q tax credit for CO₂ sequestration; and a discussion of CCS policy issues for Congress. An evaluation of the fate of injected underground CO₂ and the permanence of CO₂ storage is beyond the scope of this report.

CCS Primer

An integrated CCS system includes three main steps: (1) capturing and separating CO₂ from other gases; (2) compressing and transporting the captured CO₂ to the sequestration site; and (3) injecting the CO₂ in subsurface geological reservoirs. The most technologically challenging and costly step in the process is the first step, carbon capture. Carbon capture equipment is capital-intensive to build and energy-intensive to operate. Power plants can supply their own energy to operate CCS equipment, but the amount of energy a power plant uses to capture and compress CO₂ is that much less electricity the plant can sell to its customers. This difference, sometimes referred to as the energy penalty or the parasitic load, has been reported to be around 20% of a power plant's capacity.⁷ Figure 1 shows the options for parts of an integrated CCS process schematically from source to storage.

Figure 1. Options for an Integrated CCS Process: Capture, Injection, and Utilization

Source: U.S. Department of Energy, Office of Fossil Energy, "Carbon Utilization and Storage Atlas," Fourth Edition, 2012, p. 4. Notes: EOR is enhanced oil recovery; ECBM is enhanced coal bed methane recovery. Caprock refers to a relatively impermeable formation. Terms are explained in "CO2 Injection and Sequestration."

The transport and injection/storage steps of the CCS process are not technologically challenging per se, as compared to the capture step. Carbon dioxide pipelines are used for enhanced oil recovery (EOR) in regions of the United States today, and for decades large quantities of fluids have been injected into the deep subsurface for a variety of purposes, such as disposal of wastewater from oil and gas operations or of municipal wastewater.⁸ However, the transport and storage steps still face challenges, including economic and regulatory issues, rights-of-way, questions regarding the permanence of CO₂ sequestration in deep geological reservoirs, and ownership and liability issues for the stored CO₂, among others.

CO₂ Capture

The first step in CCS is to capture CO₂ at the source and separate it from other gases.⁹ As noted above, this is typically the most costly part of a CCS project, representing up to 75% of project costs in some cases.¹⁰ Current carbon capture costs are estimated at $43-$65 per ton CO₂ captured, though cost reductions of 50%-70% may be possible as the industry matures.¹¹

Currently, three main approaches are available to capture CO₂ from large-scale industrial facilities or power plants: (1) postcombustion capture; (2) precombustion capture; and (3) oxy-fuel combustion capture.

The following sections summarize each of these approaches. A detailed description and assessment of the carbon capture technologies is provided in CRS Report R41325, Carbon Capture: A Technology Assessment, by Peter Folger.

Postcombustion Capture

The process of postcombustion capture involves extracting CO₂ from the flue gas—the mix of gases produced that goes up the exhaust stack—following combustion of fossil fuels or biomass. Several commercially available technologies, some involving absorption using chemical solvents (such as an amine; see Figure 2), can in principle be used to capture large quantities of CO₂ from flue gases.¹² In a vessel called an absorber, the flue gas is "scrubbed" with an amine solution, typically capturing 85% to 90% of the CO₂. The CO₂-laden solvent is then pumped to a second vessel, called a regenerator, where heat is applied (in the form of steam) to release the CO₂. The resulting stream of concentrated CO₂ is then compressed and piped to a storage site, while the depleted solvent is recycled back to the absorber.

Other than the 2017-2020 Petra Nova project (discussed below in "Petra Nova: The First Large U.S. Power Plant with CCS"), no large U.S. commercial electricity-generating plant has been equipped with carbon capture equipment, though several projects are under development.

Figure 2. Diagram of Postcombustion CO2 Capture in a Coal-Fired Power Plant Using an Amine Scrubber System

Source: E. S. Rubin, "CO2 Capture and Transport," Elements, vol. 4 (2008), pp. 311-317. Notes: Other major air pollutants (nitrogen oxides-NOx, particulate matter-PM, and sulfur dioxide-SO2) are removed from the flue gas prior to CO2 capture. PC = pulverized coal. N2 = nitrogen gas.

Precombustion Capture (Gasification)

The process of precombustion capture separates CO₂ from the fuel by combining the fuel with air and/or steam to produce hydrogen for combustion and a separate CO₂ stream that could be stored. For coal-fueled power plants, this is accomplished by reacting coal with steam and oxygen at high temperature and pressure, a process called partial oxidation, or gasification (Figure 3).¹³ The result is a gaseous fuel consisting mainly of carbon monoxide and hydrogen—a mixture known as synthesis gas, or syngas—which can be burned to generate electricity. After particulate impurities are removed from the syngas, a two-stage shift reactor converts the carbon monoxide to CO₂ via a reaction with steam (H₂O). The result is a mixture of CO₂ and hydrogen. A chemical solvent, such as the widely used commercial product Selexol (which employs a glycol-based solvent), then captures the CO₂, leaving a stream of nearly pure hydrogen. This is burned in a combined cycle power plant to generate electricity—known as an integrated gasification combined-cycle plant (IGCC)—as depicted in Figure 3. Existing IGCC power plants in the United States do not capture CO₂.¹⁴

One example of IGCC technology in operation today is the Polk Power Station about 40 miles southeast of Tampa, FL.¹⁵ The 250 megawatt (MW) unit generates electricity from coal-derived syngas produced and purified onsite. The Polk Power Station does not capture CO₂.

An example of precombustion capture technology, though not for power generation, is the Great Plains Synfuels Plant in Beulah, ND. The Great Plains plant produces synthetic natural gas from lignite coal through a gasification process, and the natural gas is shipped out of the facility for sale in the natural gas market. The process also produces a stream of high-purity CO₂, which is piped northward into Canada for use in EOR at the Weyburn oil field.¹⁶

Figure 3. Diagram of Precombustion CO2 Capture from an IGCC Power Plant

Source: E. S. Rubin, "CO2 Capture and Transport," Elements, vol. 4 (2008), pp. 311-317.

Oxy-Fuel Combustion Capture

The process of oxy-fuel combustion capture uses pure oxygen instead of air for combustion and produces a flue gas that is mostly CO₂ and water, which are easily separable, after which the CO₂ can be compressed, transported, and stored (Figure 4). Oxy-fuel combustion requires an oxygen production step, which would likely involve a cryogenic process (shown as the air separation unit in Figure 4). The advantage of using pure oxygen is that it eliminates the large amount of nitrogen in the flue gas stream, thus reducing the formation of smog-forming pollutants like nitrogen oxides.

Currently oxy-fuel combustion projects are at the lab- or bench-scale, ranging up to verification testing at a pilot scale.¹⁷

Figure 4. Diagram of Oxy-Combustion CO2 Capture from a Coal-Fired Power Plant

Source: E. S. Rubin, "CO2 Capture and Transport," Elements, vol. 4 (2008), pp. 311-317.

Allam Cycle

The Allam Cycle is a novel power plant design that uses supercritical CO₂ (sCO₂) to drive an electricity-generating turbine.¹⁸ sCO₂ is CO₂ held at certain temperature and pressure conditions, giving it unique chemical and physical properties.¹⁹ In contrast, most power plants in operation today (and most proposed power plants using CCS) use steam (i.e., water) to drive a turbine. Power plants using the Allam Cycle combust fossil fuels in pure oxygen, producing CO₂ and water.²⁰ The CO₂ can be reused multiple times to generate electricity, or piped away for utilization or storage. The excess CO₂ produced by the cycle is sufficiently pure to be directly transported or used without requiring an additional capture or purification step. For power plant operations, sCO₂ may be more efficient than steam. Initial estimates indicate that power plants using the Allam Cycle could have comparable efficiencies to natural gas combined cycle power plants without CCS.²¹

The NET Power demonstration facility in La Porte, TX, is the first power plant to use the Allam Cycle. Plans for two commercial-scale Allam Cycle power plants—one in Colorado and one in Illinois—were announced in April 2021.²²

CO₂ Transport

After the CO₂ capture step, the gas is purified and compressed (typically into a supercritical state) to produce a concentrated stream for transport. Pipelines are the most common method for transporting CO₂ in the United States. Approximately 5,000 miles of pipelines transport CO₂ in the United States, predominantly to oil fields, where it is used for EOR.²³ Transporting CO₂ in pipelines is similar to transporting fuels such as natural gas and oil; it requires attention to design, monitoring for leaks, and protection against overpressure, especially in populated areas.

Costs for pipeline construction vary, depending upon length and capacity; right-of-way costs; whether the pipeline is onshore or offshore; whether the route crosses mountains, large rivers, or frozen ground; and other factors. The quantity and distance transported will mostly determine shipping costs. Shipping rates for CO₂ pipelines in the United States may be negotiated between the operator and shippers, or may be subject to rate regulation if they are considered open access pipelines with eminent domain authority. Siting of CO₂ pipelines is under the jurisdiction of the states, although the federal government regulates their safety.²⁴

Even though regional CO₂ pipeline networks currently operate in the United States for EOR, developing a more expansive network for CCS could pose regulatory and economic challenges. Some studies have suggested that development of a national CO₂ pipeline network that would address the broader issue of greenhouse gas emissions reduction using CCS may require a concerted federal policy, in some cases including federal incentives for CO₂ pipeline development.²⁵ In 2020, enacted legislation included provisions to facilitate the study and development of CO₂ pipelines that could be used for CCS.²⁶

Using marine vessels also may be feasible for transporting CO₂ over large distances or overseas. Liquefied natural gas and liquefied petroleum gases (i.e., propane and butane) are routinely shipped by marine tankers on a large scale worldwide.²⁷ Marine tankers transport CO₂ today, but at a small scale because of limited demand. Marine tanker costs for CO₂ shipping are uncertain, because no large-scale CO₂ transport system via vessel (in millions of metric tons of CO₂ per year, for example) is operating, although such an operation has been proposed in Europe.²⁸

CO₂ Injection and Sequestration

Three main types of geological formations are being considered for underground CO₂ injection and sequestration: (1) depleted oil and gas reservoirs, (2) deep saline reservoirs, and (3) unmineable coal seams. In each case, CO₂ in a supercritical state would be injected into a porous rock formation below ground that holds or previously held fluids (Figure 1). When CO₂ is injected at depths greater than about half a mile (800 meters) in a typical reservoir, the pressure keeps the injected CO₂ supercritical, making the CO₂ less likely to migrate out of the geological formation. The process also requires that the geological formation have an overlying caprock or relatively impermeable formation, such as shale, so that injected CO₂ remains trapped underground (Figure 1). Injecting CO₂ into deep geological formations uses existing technologies that have been primarily developed and used by the oil and gas industry and that potentially could be adapted for long-term storage and monitoring of CO₂.

The storage capacity for CO₂ when considering all the sedimentary basins in the world is potentially very large compared to total CO₂ emissions from stationary sources.²⁹ In the United States alone, DOE has estimated the total storage capacity to range between about 2.6 trillion and 22 trillion metric tons of CO₂ (see Table 1).³⁰ The suitability of any particular site, however, depends on many factors, including proximity to CO₂ sources and other reservoir-specific qualities such as porosity, permeability, and potential for leakage.³¹ For CCS to succeed in mitigating atmospheric emissions of CO₂, it is assumed that each reservoir type would permanently store the vast majority of injected CO₂, keeping the gas isolated from the atmosphere in perpetuity. That assumption is untested, although part of the DOE CCS R&D program has been devoted to experimenting and modeling the behavior of large quantities of injected CO₂. Theoretically—and without consideration of costs, regulatory issues, public acceptance, infrastructure needs, liability, ownership, and other issues—the United States could store its total CO₂ emissions from the electricity generating sector and other large stationary sources (at the current rate of emissions) for centuries.

Oil and Gas Reservoirs

Pumping water, gas, or chemical injectants into oil and gas reservoirs to boost production (that is, EOR) has been practiced in the oil and gas industry for several decades. CO₂ is one type of injectant that is used in EOR processes. The United States is a world leader in this technology, and oil and gas operators inject approximately 68 million tons of CO₂ underground each year to help recover oil and gas resources.³² Most of the CO₂ used for EOR in the United States comes from naturally occurring geologic formations, however, not from industrial sources. Using CO₂ from industrial emitters has appeal because the costs of capture and transport from the facility could be partially offset by revenues from oil and gas production. The majority of existing CCS facilities offset some of the costs by selling the captured CO₂ for EOR. According to some studies, EOR using CO₂ captured from an industrial source could potentially produce crude oil with a lower lifecycle greenhouse gas emissions intensity than either oil produced without EOR or oil produced through EOR using naturally occurring CO_2, depending on the process characteristics and analysis methodologies used.³³ CO₂ can be used for EOR onshore or offshore. To date, most U.S. CO₂ projects associated with EOR are onshore, with the bulk of activities in western Texas.³⁴ Carbon dioxide also can be injected into oil and gas reservoirs that are completely depleted, which would serve the purpose of long-term sequestration but without any offsetting financial benefit from oil and gas production.

Deep Saline Reservoirs

Some rocks in sedimentary basins contain saline fluids—brines or brackish water unsuitable for agriculture or drinking. As with oil and gas, deep saline reservoirs can be found onshore and offshore; they are often part of oil and gas reservoirs and share many characteristics. The oil industry routinely injects brines recovered during oil production into saline reservoirs for disposal.³⁵ As Table 1 shows, deep saline reservoirs constitute the largest potential for storing CO₂ by far. However, unlike oil and gas reservoirs, storing CO₂ in deep saline reservoirs does not have the potential to enhance the production of oil and gas or to offset costs of CCS with revenues from the produced oil and gas.

Unmineable Coal Seams

U.S. coal resources that are not mineable with current technology are those in which the coal beds are not thick enough, are too deep, or lack structural integrity adequate for mining.³⁶ Even if they cannot be mined, coal beds are commonly permeable and can trap gases, such as methane, which can be extracted (a resource known as coal-bed methane, or CBM). Methane and other gases are physically bound (adsorbed) to the coal. Studies indicate that CO₂ binds to coal even more tightly than methane binds to coal.³⁷ CO₂ injected into permeable coal seams could displace methane, which could be recovered by wells and brought to the surface, providing a source of revenue to offset the costs of CO₂ injection. Unlike EOR, injecting CO₂ and displacing, capturing, and selling CBM (a process known as enhanced coal bed methane recovery, or ECBM) to offset the costs of CCS is not part of commercial production. Currently, nearly all CBM is produced by removing water trapped in the coal seam, which reduces the pressure and enables the release of the methane gas from the coal.

Carbon Utilization

The concept of carbon utilization has gained increasingly widespread interest within Congress and in the private sector as a means for capturing CO₂ and storing it in potentially useful and commercially viable products, thereby reducing emissions to the atmosphere and offsetting the cost of CO₂ capture. EOR is currently the main use of captured CO₂, and some observers envision EOR will continue to dominate carbon utilization for some time, supporting the scale-up of capture technologies that could later rely upon other utilization pathways.³⁸ Nonetheless, research activities and congressional interest in utilization tend to focus on uses other than EOR. For example, P.L. 115-123, the Bipartisan Budget Act of 2018, which expanded the Section 45Q tax credit for carbon capture and sequestration, excludes EOR from the definition of carbon utilization. P.L. 115-123 defines carbon utilization as³⁹

• the fixation of such qualified carbon oxide through photosynthesis or chemosynthesis, such as through the growing of algae or bacteria;
• the chemical conversion of such qualified carbon oxide to a material or chemical compound in which such qualified carbon oxide is securely stored; and
• the use of such qualified carbon oxide for any other purpose for which a commercial market exists (with the exception of use as a tertiary injectant in a qualified enhanced oil or natural gas recovery project), as determined by the Secretary [of the Treasury].⁴⁰

P.L. 116-260 provides two authorizations for a DOE carbon utilization research program (to be coordinated as a single program) in the USE IT Act and Energy Act of 2020. Both focus on "novel uses" for carbon and CO₂, such as "chemicals, plastics, building materials, fuels, cement, products of coal utilization in power systems or in other applications, and other products with demonstrated market value."⁴¹

Figure 5 illustrates an array of potential utilization pathways: uptake using algae (for biomass production), conversion to fuels and chemicals, mineralization into inorganic materials, and use as a working fluid (e.g., for EOR) or other services.

Figure 5. Schematic Illustration of Current and Potential Uses of CO2

Source: U.S. DOE, National Energy Technology Laboratory (NETL), at https://www.netl.doe.gov/coal/carbon-utilization.

Commercial CCS Facilities

According to one set of data collected by the Global CCS Institute (GCCSI), 24 commercial facilities were capturing and injecting CO₂ throughout the world in 2021, 12 of which are in the United States.⁵⁰ An additional facility, the Red Trail Energy facility, came online in the United States in 2022. See Figure 6 for locations of U.S. projects capturing and injecting CO₂ for either EOR or geologic sequestration, some of which are not in operation.

Figure 6. Location of U.S. Carbon Capture and Injection Projects EOR and Geologic Sequestration

Source: CRS, using data from the Global CCS Institute, Global Status Report 2021, 2021, and the University of North Dakota Energy & Environment Research Center at undeerc.org.

These facilities reportedly have a cumulative capacity to capture an estimated 40 million metric tons of CO₂ each year.⁵¹ Additionally, according to GCCSI, one commercial facility was under construction and 15 projects were in advanced development in the United States, as of 2021.⁵²

U.S. capture and injection facilities in operation or under development occur in seven industrial sectors, according to GCCSI data: chemical production, hydrogen production, fertilizer production, natural gas processing, and power generation.⁵³ Until spring of 2022, the Archer Daniels Midland (ADM) facility in Decatur, IL (also known as the Illinois Industrial Project), was the only facility injecting CO₂ solely for geologic sequestration. The facility injects CO₂ captured from ethanol production into a saline reservoir and as of 2021 reported that 2 million metric tons of CO₂ had been injected at the site.⁵⁴ In 2022, North Dakota issued a Class VI permit for CO₂ injection by Red Trail Energy in Richardton, ND. The company plans to capture and inject 180,000 tons of CO₂ per year into an on-site formation for geologic sequestration.⁵⁵ See Figure 7 for additional information on the timeline and industrial sectors for CO₂ capture and injection facilities in the United States.

Figure 7. Operational, Planned, and Suspended Facilities in the United States Injecting CO2 for Geologic Sequestration and EOR

Source: CRS, adapted from Global CCS Institute, Global Status Report 2021, 2021; GSSCI does not define "advanced development" in this report. Red Trail Energy information from the Industrial Commission of North Dakota. Notes: Mtpa = million tons per annum (year); circle placement indicates initial year of operations or anticipated initial year of operations for projects under development, according to GCCSI (the first time frame in the figure represents 38 years, while the other time frames each represent a five-year period). Some projects under development anticipate multiple CO2 sources; in these cases, circle placement indicates the initial application being studied.

Stakeholders have paid particular attention to two power generation projects: Boundary Dam, in Saskatchewan, Canada, and Petra Nova, near Houston, TX. Both projects involved retrofitting coal-fired electricity generators with carbon capture equipment and have been noted as examples of carbon capture technology. At the same time, both projects have been criticized for high costs, relative to other low-carbon technologies for electricity generation, and for sequestering carbon via EOR.⁵⁶ In May 2020, Petra Nova's owners stopped operating the CCS equipment, citing unfavorable economics due to low crude oil prices, though reports suggest the facility may have experienced prior mechanical challenges.⁵⁷

Petra Nova: The First Large U.S. Power Plant with CCS

On January 10, 2017, the Petra Nova–W.A. Parish Generating Station became the first industrial-scale coal-fired power plant with CCS to operate in the United States. The plant began capturing 5,200 short tons (approximately 4,717 metric tons) of CO₂ per day from its 240-megawatt-equivalent slipstream using post combustion capture technology.⁵⁸ The capture technology was designed to be approximately 90% efficient (i.e., designed to capture about 90% of the CO₂ in the exhaust gas after the coal was burned to generate electricity) and was designed to capture 1.4 million metric tons of CO₂ each year.⁵⁹ The captured CO₂ was transported via an 82-mile pipeline to the West Ranch oil field, where it was injected for EOR. NRG Energy Inc., and JX Nippon Oil & Gas Exploration Corporation, the joint owners of the Petra Nova project, together with Hilcorp Energy Company (which handled the injection and EOR), anticipated increasing West Ranch oil production from 300 barrels per day before EOR to 15,000 barrels per day after EOR.⁶⁰ However, Petra Nova's operators turned off the CCS equipment in May 2020, citing low oil prices caused, in part, by the COVID-19 pandemic.⁶¹ In January 2021, the operators announced plans to indefinitely shut down the CCS equipment's power source.⁶² As of October 2022, Petra Nova remains out of service.⁶³

DOE provided Petra Nova with more than $160 million from its Clean Coal Power Initiative (CCPI) Round 3 funding, using funds appropriated under the American Recovery and Reinvestment Act of 2009 (ARRA; P.L. 111-5) together with other DOE funding for a total of more than $190 million of federal funds for the $1 billion retrofit project.⁶⁴ Petra Nova is the only CCPI Round 3 project that expended its ARRA funding and began operating.⁶⁵ The three other CCPI Round 3 demonstration projects funded using ARRA appropriations (as well as the FutureGen project—slated to receive nearly $1 billion in ARRA appropriations) all have been canceled, have been suspended, or remain in development.⁶⁶

Boundary Dam: World's First Addition of CCS to a Large Power Plant

The Boundary Dam project was the first commercial-scale power plant with CCS in the world to begin operations. Boundary Dam, a Canadian venture operated by SaskPower,⁶⁷ cost approximately $1.5 billion, according to one source, though it was originally estimated to cost $1.3 billion.⁶⁸ Of the originally estimated amount, $800 million was for building the CCS process and the remaining $500 million was for retrofitting the Boundary Dam Unit 3 coal-fired generating unit. The project also received $240 million from the Canadian federal government. Boundary Dam started operating in October 2014, after a four-year construction and retrofit of the 150-megawatt generating unit. The final project was smaller than earlier plans to build a 300-megawatt CCS plant, but that original idea may have been projected to cost as much as $3.8 billion. The larger-scale project was discontinued because of the escalating costs.⁶⁹

Boundary Dam captures, transports, and sells most of its CO₂ for EOR, shipping 90% of the captured CO₂ via a 41-mile pipeline to the Weyburn Field in Saskatchewan. CO₂ not sold for EOR is injected and stored about 2.1 miles underground in a deep saline aquifer at a nearby experimental injection site. By March 2022, the plant had captured over 4.3 million metric tons of CO₂ since full-time operations began in October 2014.⁷⁰ The project injected 370,000 metric tons of CO₂ for geologic sequestration as of 2021.⁷¹

The DOE CCS Program

DOE has funded R&D of aspects of the three main steps of an integrated CCS system since at least 1997, primarily through its Fossil Energy and Carbon Management Research, Development, Demonstration, and Deployment program (FECM).⁷² CCS-focused R&D has come to dominate the coal program area within DOE FECM since 2010. Since FY2010, Congress has provided $9.2 billion (in constant 2022 dollars) total in annual appropriations for FECM (see Table 2).⁷³

Congress has additionally provided supplemental funding for DOE's CCS activities. The American Recovery and Reinvestment Act of 2009 (ARRA; P.L. 111-5) provided an additional $3.4 billion ($4.4 billion in 2022 dollars), specifically for CCS projects.⁷⁴ The Infrastructure Investment and Jobs Act (IIJA; P.L. 117-58) provided $8.5 billion (nominal dollars) in supplemental funding for CCS for FY2022-FY2026 (see Table 3), including funding for the construction of new carbon capture facilities and commercial carbon storage facilities. Additionally, IIJA provided $3.6 billion (nominal dollars) in supplemental funding for DAC, primarily to support the establishment of four regional direct air capture hubs in the United States.⁷⁵

A 2021 evaluation by the Government Accountability Office (GAO) found several cost control risks related to DOE's past management of its CCS program, particularly DOE's implementation of ARRA.⁷⁶ These risks included a high-risk selection process, an accelerated schedule of project review, and the bypassing of internal cost controls. GAO found DOE used less risky processes in awarding CCS funding for industrial projects as compared to coal projects. Partly as a result, two out of three funded industrial CCS projects were operational in 2021, while none of the eight funded coal projects was operational. GAO noted that economic factors, such as declines in natural gas prices, affected coal projects more than industrial projects, and also contributed to withdrawal or cancellation of DOE-funded coal projects.

EPA Regulation of Underground Injection in CCS

EPA issues regulations for underground injection of CO₂ as part of its responsibilities for underground injection control (UIC) programs under the Safe Drinking Water Act (SDWA). EPA also develops guidance to support state program implementation, and in some cases, directly administers UIC programs in states.⁷⁷ The agency has established minimum requirements for state UIC programs and permitting for injection wells. These requirements include performance standards for well construction, operation and maintenance, monitoring and testing, reporting and recordkeeping, site closure, financial responsibility, and, for some types of wells, post injection site care. Most states implement the day-to-day program elements for most categories of wells, which are grouped into "classes" based on the type of fluid injected. Owners or operators of underground injection wells must follow the permitting requirements and standards established by the UIC program authority in their state.

EPA has issued regulations for six classes of underground injection wells based on type and depth of fluids injected and potential for endangerment of underground sources of drinking water (USDWs). Class II wells are used to inject fluids related to oil and gas production, including injection of CO₂ for EOR. There are more than 119,500 EOR wells in the United States, predominantly in California, Texas, Kansas, Illinois, and Oklahoma.⁷⁸ This total includes EOR wells that can be used to inject CO₂ captured from anthropogenic sources and wells using naturally derived CO₂. Class VI wells are used to inject CO₂ for geologic sequestration. Two EPA-permitted Class VI wells are currently operating for sequestration in the United States, both located at the ADM facility in Illinois.⁷⁹ In 2022, North Dakota, which has delegated authority for its UIC Class VI well program, issued two CO₂ injection permits for geologic sequestration.

To protect USDWs from injected CO₂ or movement of other fluids in an underground formation, Class II EOR wells must transition to Class VI geologic sequestration wells under certain conditions.⁸⁰ Class II well owners or operators who inject CO₂ primarily for long-term storage (rather than oil production) must obtain a Class VI permit when there is an increased risk to USDWs compared to prior Class II operations using CO₂. The Class VI Program Director (EPA or a delegated state) determines whether a Class VI permit is required based on site-specific risk factors associated with USDW endangerment. To date, no such transition has been required.

Discussion

In recent Congresses, proposed and enacted CCS-related legislation has addressed federal CCS research and development (R&D) activities and funding, CO₂ pipelines, and the carbon sequestration tax credit. Bills, or provisions thereof, addressing CCS were enacted as part of the Consolidated Appropriations Act, 2021 (P.L. 116-260). Potential implementation and oversight issues related to these provisions might be of interest in the 117^th Congress and beyond.

In the 116^th Congress, as part of the Consolidated Appropriations Act, 2021 (P.L. 116-260), Congress reauthorized the DOE CCS research program. Among other provisions, the law expanded the scope of DOE's research to noncoal applications (e.g., natural gas-fired power plants, other industrial facilities).⁹¹ The law also authorized a DOE carbon utilization research program and specific activities related to direct air capture (e.g., a DAC technology prize). IIJA built upon this expanded scope, providing supplemental appropriations for several programs authorized by P.L. 116-260, and established new CCS and DAC programs. As is also true for other DOE applied research programs, some criticize such activities as an inappropriate role for government, arguing the private sector is better suited to develop technologies that can compete in the marketplace.⁹²

Council on Environmental Quality 2021 CCS Report to Congress and 2022 CCS Guidance

In response to the USE IT Act, in 2021, the White House Council on Environmental Quality (CEQ) provided Congress with a report on carbon capture, utilization, and sequestration project permitting and review.⁹³ One of several reports required by Congress in the Consolidated Appropriations Act, 2021 (P.L. 116-260), this report provides information on federal permitting and regulations for CCS projects and examines technical, financial, and policy-related issues for project deployment. In its key findings, CEQ states that "CCUS has a critical role to play in decarbonizing the global economy" and that "President Biden is committed to accelerating the responsible development and deployment of carbon capture, utilization, and permanent sequestration as needed to decarbonize the U.S. economy by mid-century."⁹⁴ CEQ also finds that to be beneficial, CCS projects must be "well-designed and well governed."⁹⁵ Regarding governance, CEQ also finds that the existing federal regulatory framework is "rigorous and capable of managing permitting and review actions while protecting the environment, public health, and safety as CCUS projects move forward."⁹⁶

In February 2022, CEQ released an interim guidance, Carbon Capture, Utilization, and Sequestration Guidance, also as directed by Congress in the USE IT Act.⁹⁷ The interim guidance includes recommendations for federal agencies that would support "the efficient, orderly, and responsible development and permitting of CCUS projects at an increased scale in line with the Administration's climate, economic, and public health goals."⁹⁸ In the document, CEQ provides guidance to federal agencies on the processes for permitting and review of CCS projects and CO₂ pipelines, public engagement, and assessing environmental impacts of CCS projects.

Other CCS Policy Issues

With respect to other issues for congressional consideration, costs have been, and remain, a key challenge to CCS development in the United States. In recent years, Congress has attempted to address this challenge in two main ways—federal R&D and federal tax credits. P.L. 116-260 and P.L. 117-169 also extended the start of construction deadline for facilities claiming the 45Q tax credit. In January 2021, the IRS promulgated regulations establishing requirements for carbon storage under Section 45Q. Congress remains interested in the efficacy of the tax credit in promoting CCS development and could consider additional adjustments.

The issue of expanded CCS deployment is closely tied to the issue of reducing greenhouse gas emissions to mitigate human-induced climate change. In 2021, the Biden Administration announced climate change mitigation goals and strategies, and new climate-focused groups and initiatives that may also be of interest when considering CCS-related oversight, appropriations, or legislation. In two executive orders signed in January 2021, President Biden outlined new federal climate policies; created new White House and Department of Justice climate offices; and established new task forces, workgroups, and advisory committees on climate change science and policy.⁹⁹ At this early stage, the implications of these executive branch policies and actions on CCS project development and deployments are unclear.

The use of CCS technology as a greenhouse gas emissions reduction approach is not uniformly supported by advocates for actions to address climate change.¹⁰⁰ Some argue that CCS supports continued reliance on fossil fuels, which runs counter to their view of how to reduce greenhouse gas emissions and meet other environmental goals. They tend to prefer policies that phase out the use of fossil fuels altogether. Others raise concerns about the long-term safety and environmental uncertainties of injecting large volumes of CO₂ underground.