10

CO₂ Utilization Infrastructure

10.1 STATUS AND GOALS OF CO₂ UTILIZATION INFRASTRUCTURE

As noted in the preceding chapters, CO₂ utilization (i.e., conversion) can play a role in developing a circular carbon economy, in storing carbon dioxide, and in enabling a net-zero-emissions future. Expanding CO₂ utilization requires developing or repurposing infrastructure for CO₂ capture, transportation of CO₂ and other feedstocks and inputs, CO₂ conversion, and transportation of products and wastes. Such infrastructure for the full life cycle of CO₂ utilization is of limited extent today. Congress and the Department of Energy (DOE) requested this study to assess infrastructure needs to enable CO₂ utilization, focused on a future where carbon wastes are fundamental participants in a circular carbon economy with net-zero carbon emissions to the atmosphere (U.S. Congress 2020). Over two reports, the committee was instructed to analyze challenges in expanding carbon utilization infrastructure, mitigating environmental impacts, accessing capital, overcoming technical hurdles, and addressing geographic, community, and equity issues. The first report’s analysis, summarized below, focused on the current state of CO₂ transportation, use, and storage infrastructure, and identified priority opportunities to develop, improve, and expand that infrastructure to enable utilization (NASEM 2023a). This final report builds off the first report and assesses infrastructure updates needed to ensure safe and reliable CO₂ transportation, use, and storage for carbon utilization purposes. The committee considers how carbon utilization fits into larger needs and opportunities for carbon capture and storage (CCS) infrastructure and describes the economic, climate, and environmental impacts of a well-integrated CO₂ pipeline system as applied to carbon utilization. The committee’s analysis includes suggestions for policies that could improve the economic impact of the system and mitigate its climate and environmental impacts.

10.1.1 Summary of First Report’s Infrastructure Analysis

The committee’s first report (NASEM 2023a) assessed the state of existing infrastructure for CO₂ transportation, use, and storage; outlined considerations for developing new CO₂ utilization infrastructure; and identified priority opportunities for the development of such infrastructure. Currently, CO₂ utilization¹ occurs on a commercial scale for the synthesis of urea, and to a lesser extent salicylic acid, methanol, and organic and inorganic carbon-

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¹ CO₂ utilization, for the purposes of this report, includes chemical conversion of CO₂ into products, and excludes uses of CO₂ that do not result in a chemical transformation, such as use of CO₂ as a working fluid for enhanced oil recovery, or in beverage carbonation or fire suppression.

ates. Other CO₂-derived products, such as hydrocarbon fuels, are the target of research or pilot-scale activities, but expanded market opportunities for CO₂ conversion are limited by the high energy requirements and lack of financial incentives and policy mechanisms to use CO₂ as a feedstock in place of fossil carbon. Most existing CO₂ capture and transportation infrastructure has been developed for enhanced oil recovery (EOR), connecting geologic or fossil CO₂ sources with depleted oil reservoirs. Limited opportunities exist to use this infrastructure for sustainable (i.e., net-zero or net-negative emissions) CO₂ utilization processes. However, the anticipated build-out of additional infrastructure for CCS over the coming decades potentially could enable sustainable CO₂ utilization, depending on the CO₂ source, utilization product, and other energy and feedstock requirements (NASEM 2023a). Expanding CO₂ utilization to produce net-zero- or net-negative-emissions materials, chemicals, and fuels would necessitate significant expansion of infrastructure for clean electricity and clean hydrogen in a safe, environmentally benign, and sustainable manner.

In its first report, the committee laid out considerations for developing CO₂ utilization infrastructure to serve a net-zero future. It noted that “the economics of infrastructure placement will be dictated in part by the ease of transporting CO₂, hydrogen, electricity, and other inputs, versus the ease of transporting the carbon-based products” (Finding 4.9, NASEM 2023a, p. 100) and “the optimal CO₂ transport and delivery infrastructure to enable utilization depends on the product type” (Finding 4.10, NASEM 2023a, p. 100). For example, chemicals and fuels production might benefit from centralized CO₂ capture, transportation, and conversion infrastructure, potentially taking advantage of existing chemical production facilities, while concrete and aggregate production preferably may occur in a distributed manner, with smaller-scale CO₂ capture and distribution networks, to serve localized needs for these products. Decisions about CO₂ transportation method(s) for a given project should consider the location and type of CO₂ source as well as the site of utilization and estimated product volumes, with a goal of minimizing cost, environmental, and justice impacts, and addressing safety concerns.

Overarching recommendations from the committee’s first report provided opportunities to integrate CO₂ utilization infrastructure with infrastructure for CCS, clean electricity, clean hydrogen, and other enabling inputs. For example, the committee recommended that CCS infrastructure be designed with the flexibility to connect to CO₂ utilization processes and technologies in the future (Recommendation 6.2, NASEM 2023a, p. 134) and that studies to identify the most promising CO₂ utilization opportunities “determine the value of co-locating specific CO₂ utilization activities with specific source types of CO₂, as well as the value of minimizing transport, identifying those that maximize climate benefits” (Recommendation 6.5, NASEM 2023a, p. 134). Additionally, DOE, as part of its industrial decarbonization efforts, should provide technical and financial support for development of carbon capture, utilization, and storage (CCUS) clusters, which “should involve best practices for community engagement and allow for flexibility in utilization scenarios over the long term, for example, by incorporating hydrogen production, chemical and fuel manufacturing, and low-carbon electricity generation” (Recommendation 6.3, NASEM 2023a).

This chapter expands on the committee’s prior findings and recommendations by providing an update on CCUS infrastructure under development in the United States, discussing opportunities and challenges for CO₂ utilization infrastructure planning at the regional or national scale, including multimodal transport of the captured CO₂, and evaluating potential economic, climate, environmental, health, safety, justice, and societal impacts of CO₂ utilization infrastructure.

10.1.2 What Are the Infrastructure Needs for CO₂ Utilization to Contribute to a Net-Zero Energy System?

As CO₂ utilization is developed to enable 2050 net-zero goals, it is imperative to chart a course toward the scale of infrastructure required to meet these targets. Several analyses have examined the infrastructure capacity required, including for capture and removal of CO₂, expansion of transportation networks, establishment of secure storage sites, and development of CO₂ conversion facilities. Although momentum has been growing, the disparity between present capacity and the required infrastructure is evident from a comparison of different scenarios (see Table 10-1).

The largest disparity remains in CO₂ capture. The current and announced capacity of point source CO₂ capture facilities is 161 million tonnes per annum (MTPA), significantly lower than—and likely not on track to meet—the amount estimated to be required by 2050, which ranges from a few hundred to a few thousand MTPA in the United States (Table 10-1). Moreover, current and announced capacities for direct air capture (DAC) are less than 8 MTPA, while the

TABLE 10-1 Summary of Published Modeling and Planning for National- or Regional-Scale CCUS Infrastructure

^a From Figures 5 and 16 of DOE (2023a).

^b Clune et al. (2022).

^c Ennis and Levin (2023).

^d Larson et al. (2021).

^e Abramson et al. (2020).

^f Decarb America Research Initiative (2021); range reflects all modeled net-zero scenarios in 2050.

^g CETI (2023).

^h Includes carbon capture from biogasification, cement and lime, and power generation.

ⁱ Kammer et al. (2023); Mid-Atlantic region includes Delaware, Kentucky, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia, and the District of Columbia.

^j As of November 2023; includes Heirloom (Heirloom 2023) and Global Thermostat facilities (Global Thermostat 2023).

^k As of November 2023; includes Project Bison, Stratos, Project Cypress, and the South Texas DAC Hub.

^l Larsen et al. (2019).

^m PHMSA (2023a).

ⁿ As of November 2023; includes Summit Carbon Solutions and Wolf Carbon Solutions projects (Summit Carbon Solutions n.d.(b); Wolf Carbon Solutions n.d.).

^o DOE (2023a).

^p From Table 4.3 of EIA (2023a).

^q Total capacity from nuclear, hydro, wind (onshore and offshore, and paired with storage), and solar (including solar paired with storage) in the interconnection queue as of the end of 2022 from LBNL (n.d.).

^r Includes onshore wind, offshore wind, solar, and nuclear.

^s Estimated as <5 percent of 2022 hydrogen production, per Figure 2 of DOE (2023b).

^t As of end of year 2022.

^u DOE (2023c).

^v Includes Archer Daniels Midland (EPA 2023a), Blue Flint (Harvestone Group 2023), and Red Trail (Red Trail Energy LLC 2022) sequestration sites.

^w Includes Wabash Carbon Services (EPA 2023a), Carbon TerraVault JV Storage Company Sub 1, LLC (EPA 2023a), Eastern Wyoming Sequestration Hub (Tallgrass 2023), Sweetwater Carbon Storage Hub (Frontier Carbon Solutions LLC 2022), DCC West Center Broom Creek (DCC West Project LLC 2023), Project Tundra (Minnkota Power Cooperative 2022a), Minnkota Center MRYS Deadwood (Minnkota Power Cooperative 2022b), and Great Plains CO₂ Sequestration Project (Dakota Gasification Company 2023).

^x Base case storage capacity, per Annex I of Larson et al. (2021).

required capacity by 2050 is estimated to be as much as 300 times these announcements, per Larsen et al. (2019). Carbon capture continues to represent a significant cost component of CO₂ utilization, as well as a large cost reduction potential. Various challenges limit widespread deployment of CO₂ capture infrastructure, as described in NASEM (2023a).

Another significant gap in the CO₂ utilization supply chain is CO₂ transportation infrastructure, which is dominated by pipeline transport. The current capacity is just over 5000 miles, mostly supporting the transport of CO₂ from natural reservoirs, power plants, and industrial sources to nearby oil fields for EOR applications in sparsely populated areas (NASEM 2023a; NPC 2019). The scale and geographic distribution of present transport capacity does not support the creation of a nationwide CO₂ utilization network. Adopting mixed modes of CO₂ transport, such as pipelines, ships, trains, and trucks, can be an efficient solution to address the transportation gap, and this approach is explored in Section 10.3.1.

Enabling infrastructure in the form of clean electricity and clean hydrogen production capacity must scale up significantly to achieve net-zero goals. Although most models do not establish specific electricity and hydrogen targets for CO₂ utilization, these inputs are vital for converting CO₂ into valuable products such as synthetic fuels and chemicals. Furthermore, the United States has significant capacity to store CO₂ underground that is currently underutilized, and the infrastructure built for CO₂ storage can be leveraged to support CO₂ utilization projects.

Substantial amounts of capital investment are necessary to close the gap in CO₂ infrastructure development. DOE has estimated that between $300 billion and $600 billion of total investment along the carbon management value chain is required until 2050 to meet net-zero decarbonization goals (DOE 2023a). The private sector’s long-term commercial investments require supportive policy measures and regulatory frameworks that can provide market certainty and encourage investments in CCUS infrastructure. Additionally, public–private partnerships offer a vital approach to leveraging the expertise, resources, and funding of both sectors to scale up CO₂ utilization infrastructure to meet the net-zero targets indicated by different modeling scenarios. Section 10.2 describes numerous CCUS infrastructure announcements since the committee’s first report, indicating that plans are gaining momentum. Nonetheless, the current pace of development remains insufficient to achieve most of the referenced analysis models’ targets.

10.2 CCUS INFRASTRUCTURE UNDER DEVELOPMENT

As noted above, the committee’s first report described the status of existing infrastructure for CCUS in the United States (Chapter 2 of NASEM 2023a). This section briefly discusses new developments in infrastructure for CO₂ capture, transport, utilization, and storage, as well as hydrogen production, since the first report was published.

10.2.1 Direct Air Capture Hubs

In August 2023, DOE selected two (of four total to be chosen) DAC projects for award negotiations as part of the Regional Direct Air Capture Hubs program authorized and appropriated in the Infrastructure Investment and Jobs Act (IIJA) (DOE-OCED 2023a). Both projects—Project Cypress, which will be located in Calcasieu Parish, Louisiana, and the South Texas DAC Hub, which will be located in Kleberg County, Texas—plan to capture 1 million tonnes of CO₂ per year for sequestration in a saline aquifer (DOE-OCED n.d.(a)). DOE is also supporting feasibility and design studies for DAC projects located throughout the United States (DOE-FECM 2023a). Figure 10-1 shows the locations and relative funding amounts of DOE-funded DAC projects.

In addition to the DOE selections, private companies are developing commercial-scale DAC facilities in the United States. Examples include Occidental and 1PointFive’s Stratos plant under construction in the Texas Permian Basin (1PointFive 2023b; Oxy 2022), Heirloom’s operational DAC-to-concrete facility in California (Heirloom 2023), CarbonCapture, Inc.’s announced Project Bison project in Wyoming (CarbonCapture Inc. 2023), and Global Thermostat’s demonstration plant in Colorado (Global Thermostat 2023).

10.2.2 Hydrogen Hubs

In October 2023, DOE announced the selection of seven Regional Clean Hydrogen Hubs for award negotiations, as authorized in the IIJA. Figure 10-2 shows the locations of these projects, and Table 10-2 summarizes their plans for hydrogen generation and use, expected job creation, and estimated emissions reductions. The seven hubs aim collectively to produce more than 3 million metric tons (megatonnes, Mt) of hydrogen annually and reduce CO₂ emissions from end uses by 25 Mt per year (DOE-OCED 2023b; White House 2023). Given the importance of hydrogen for many CO₂ utilization applications, project developers may consider proximity to hydrogen producers in their siting decisions. The committee’s first report recommended that project planners consider co-locating hydrogen generation with facilities that capture and use CO₂ to reduce the need for additional costly and complex infrastructure for hydrogen storage and transport (Recommendation 4.5, NASEM 2023a). The Gulf Coast Hydrogen Hub, which is targeting the use of hydrogen as a feedstock in refineries and petrochemicals, and the South Texas DAC Hub could be considered co-located, in the sense that only short trunklines of H₂ or CO₂ would be required to connect facilities for H₂ generation, CO₂ capture, and CO₂ utilization. The Midwest Hydrogen Hub lists sustainable aviation fuels as one of its use cases and is located near proposed sites for CO₂ pipelines and geologic storage, so that location may be a prime opportunity for coordination of H₂ and CO₂ utilization infrastructure.

10.2.3 CO₂ Pipelines

The United States currently has 5354 miles of CO₂ pipeline infrastructure² concentrated in the Gulf Coast, Permian Basin, and Wyoming, which primarily transports supercritical CO₂ from geological sources to depleted oil reservoirs for EOR (PHMSA 2023a). At the start of the committee’s writing, three major new CO₂ pipeline projects were under way in the Midwest, being developed by Summit Carbon Solutions, Navigator CO₂ Ventures, and Wolf Carbon Solutions. Summit Carbon Solutions plans to build about 2000 miles of pipeline to transport CO₂ captured from 57 ethanol plants to permanent geological storage in North Dakota (Summit Carbon Solutions n.d.(a)). The pipeline network would traverse five states—Iowa, Minnesota, Nebraska, North Dakota, and South Dakota—and transport about 18 million tons of CO₂ annually for storage (Summit Carbon Solutions n.d.(b)). Navigator CO₂ Ventures’ Heartland Greenway project, now canceled, would have been a 1300-mile pipeline network across Illinois, Iowa, Minnesota, Nebraska, and South Dakota that would have captured 15 Mt of CO₂ per year from ethanol and fertilizer facilities for permanent geologic storage in Illinois, with the option of off-takes for CO₂ use (Navigator Heartland Greenway LLC 2021; Voegele 2023). The Mt. Simon Hub project being developed by Wolf Carbon Solutions would transport 12 million tons of CO₂ per year from two ethanol plants in Iowa to permanent geological storage in Illinois via 280 miles of pipeline (Wolf Carbon Solutions n.d.).

All three projects have faced legal and regulatory challenges and have seen pushback from local communities concerned about safety and use of eminent domain for pipeline siting (see, e.g., Ahmed 2023; Peterson 2023; Ramos

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² For scale and context, the United States has about 190,000 miles of petroleum pipelines (API 2021) and 3 million miles of natural gas pipelines (EIA 2024).

TABLE 10-2 Summary of Hydrogen Hub Selections

SOURCES: Based on data from DOE-OCED (n.d.(b)) and White House (2023).

2023; Soraghan 2023). For example, regulators in North and South Dakota denied permits to Summit Carbon Solutions and Navigator CO₂ Ventures, respectively, although North Dakota plans to reconsider the permit request (Dura 2023a, 2023b; Dura and Karnowski 2023). In October 2023, Navigator announced its cancellation of the Heartland Greenway project (Douglas 2023), Summit announced a delay in its pipeline start-up date from 2024 to early 2026 (Anchondo 2023), and the Illinois Commerce Commission staff recommended that state regulators reject Wolf Carbon Solutions’ pipeline application (Tomich 2023).

At a public meeting on CO₂ pipeline safety hosted by the Pipeline and Hazardous Materials Safety Administration (PHMSA) in Des Moines, Iowa, from May 31 to June 1, 2023, public comments centered on a lack of trust in pipeline companies, the limited capacity of volunteer emergency response teams in rural areas, appropriate setback distances, the potential for induced seismicity from CO₂ injection for sequestration, and the durability of pipeline materials in Iowa’s geographic and environmental conditions (e.g., freeze/thaw cycles, soil composition, ground vibrations from farm equipment) (PHMSA 2023b). During the same meeting, members of the public made several requests of PHMSA as it develops updated safety regulations for CO₂ pipelines, including (1) place a national moratorium on CO₂ pipelines until the updated safety regulations are in place, (2) provide guidance on regulatory jurisdictions and clear definitions of CO₂ (supercritical, gaseous, and liquid phases) in regulations, (3) establish clear guidelines on disclosure of emergency response plans and mandate that pipeline companies pay for the necessary emergency response equipment, and (4) in the case of a pipeline emergency, require that companies notify all customers and emergency planning departments within a reasonable distance of the route (PHMSA 2023b).

In addition to opposition by individuals and communities directly affected by pipeline projects, some groups also oppose CO₂ pipelines as a means to block the development of CCUS projects, which they consider a moral hazard

owing to their potential to perpetuate fossil fuel development and use. Opposition is not unique to CO₂ pipelines. Other net-zero energy system infrastructure projects have been opposed owing to the concerns of host or neighboring communities (e.g., solar and wind developments and transmission lines), or owing to the moral hazard of fossil fuel development, or both (e.g., H₂ hubs) (Christol et al. 2021; Gordon et al. 2023; Romero-Lankao 2023). See Chapter 4 for more detail on the policy, regulatory, and societal aspects of CO₂ utilization infrastructure development.

10.2.4 Update on Commercial CO₂ Capture, Utilization, and Storage Projects

Since the committee’s first report was released in December 2022, additional CCUS projects have been and continue to be announced. As this is a rapidly evolving space, producing a comprehensive list of projects and facilities is impractical. Rather, the committee points the reader to resources that continually update information on carbon management projects (see Table 10-3).

In addition to individual projects, several CCS hub developments have been announced. Examples include the Midland Basin hub (Milestone Carbon 2023), Bayou Bend CCS hub (OGCI n.d.), and Bluebonnet Hub (1PointFive 2023a) in Texas; the Cameron Parish CO₂ Hub offshore of Louisiana (Carbonvert and Castex 2023);

TABLE 10-3 Resources with Information on Commercial Carbon Capture, Utilization, and Storage Projects

the Central Louisiana Regional Carbon Storage Hub (“CENLA Hub,” CapturePoint 2024), and the Eastern Wyoming Sequestration Hub (Tallgrass 2022). These could be prime locations for future CO₂ utilization infrastructure development, in line with the committee’s recommendations in its first report to support development of industrial clusters for CCUS and identify opportunities to co-locate utilization with existing CO₂ transport infrastructure (Recommendations 6.3 and 6.5, NASEM 2023a).

10.3 INTEGRATED CO₂ UTILIZATION INFRASTRUCTURE PLANNING AND DEVELOPMENT AT THE REGIONAL OR NATIONAL SCALE

10.3.1 Optimal Multimodal, Regional CO₂ Transportation Infrastructure

As part of the CCUS chain, pressurized pipelines are generally considered to be the most economical and safest method for large-scale CO₂ transport. However, as indicated in Section 10.2.3, CO₂ pipeline development faces regulatory challenges and public opposition. The recent cancellation of a 1300-mile CO₂ pipeline project aiming to transport 15 Mt of CO₂ annually from Midwest ethanol plants for geological storage (Tomich et al. 2023) owing to opposition of residents along its route highlights such barriers. As a result, ships, river barges, trucks, and trains are becoming increasingly attractive, as they have shorter timelines for implementation and likely face fewer regulatory and public acceptance barriers, especially when passing through or near more densely populated areas. Such forms of transportation also will likely be needed to collect and distribute CO₂ at the origin and destination of pipelines, or for smaller, distributed sources or conversion facilities, even if a larger system of CO₂ pipelines is built (Pett-Ridge et al. 2023).

The combination of different CO₂ transport modes can, in many cases, represent a better alternative to a single transport mode, especially for small, dispersed emitters that are not within easy reach of industrial CCUS clusters enjoying shared transport infrastructure. From a societal perspective, the optimal design of multimodal CO₂ transport infrastructure for utilization and storage involves a cost-benefit analysis of the transport network with the aim of minimizing costs and environmental impact and reducing the risk of failure, while maximizing the CO₂ utilization potential in the region.

Meeting these complex challenges requires the development of dedicated mathematical optimization models that can determine key impact indices for each of the above factors, which in turn can be employed as a valuable decision-making tool for the design of the optimal CO₂ transport network. Parolin et al. (2022) propose a similar analytical tool for hydrogen delivery infrastructure, but the proposed methodology does not include factors related to safety and financial risks, nor environmental impacts during transportation, and only considers land-based transport of hydrogen. Lawrence Livermore National Laboratory’s “Roads to Removal” report presents a model aimed at identifying the most economical route of multimodal CO₂ transportation from the CO₂ source to a storage location using established cost models and literature data (Pett-Ridge et al. 2023). However, it assumes that fluid transportation conditions (e.g., temperature, pressure) are the same across the modular transport chain and thus adopts only one levelized cost associated with liquefaction. In practice, CO₂ may be transported in liquid form at different temperatures and pressures depending on transport mode, resulting in different conditioning costs and further conditioning stations when transferring across different transport modes (e.g., from trucks to barges or trains). Such requirements may significantly impact the optimal multimodal transport solution. Furthermore, although Pett-Ridge et al. (2023) discuss the need to evaluate the selected routes under different criteria—societal impact, in particular—they do not include calculations of risks and emissions associated with the different options. A more rigorous, all-encompassing, multiobjective approach is required to determine the optimal multimodal transport solution for transporting captured CO₂ gathered from small, dispersed emitters for utilization. The following text describes the main steps in developing such a tool.

Step 1. Mixed-Integer Linear Programming (MILP): Minimizing the Cost of Transport

First, a set of transport configurations for determining the minimum costs is selected via the construction of a MILP problem incorporating several considerations and constraints (Lee et al. 2017). These may include

the geographical locations of the emitters and utilization sites, the availability or accessibility of infrastructure for different modes of transport, along with the respective amounts of CO₂ and corresponding temperatures and pressures. Established techno-economic models are employed to determine the CO₂ transport and conditioning unit costs for the various transport modes, such as pipelines (Knoope et al. 2014), ships (Element Energy 2018; Roussanaly et al. 2021), and trucks (Stolaroff et al. 2021). The solutions proposed by MILP are expected to fall in a range of costs that are considered reasonable and might highlight different routes and a combination of different modes. A graphical representation is presented in Figure 10-3.

Step 2. Multimodal Transport of CO₂: Incorporating Safety and Environmental Impact Costs

Step 2 involves developing tools to quantify the safety and environmental impact costs associated with different modes of transportation. These tools can be in the form of a Safety and Reliability Index and an Environmental Index, as previously developed in several studies for the transportation of different goods (e.g., H₂) (Bevrani et al. 2020; d’Amore et al. 2018; Kim et al. 2011; Lee et al. 2017). The safety index considers factors such as failure rates for the various transportation modes, and failure consequence analysis takes account of the population density along the selected route. The environmental index considers emissions generated from the construction and implementation of the different transport modes, which also depends on distance covered and selected routes.

A multicriteria optimization model then has to be developed, which simultaneously analyzes the risk and environmental impact for each of the transport solutions identified by the MILP, as illustrated in Figure 10-4, and returns a set of possible solutions, indicating the necessary trade-off between the different selected criteria, covering cost, safety, and environmental impacts.

The following subsections describe a few case studies of CO₂ transportation infrastructure development at different locations and CO₂ emission scales, taking into account the optimization methodologies for multimodal transport described above. For each case study, implications and opportunities for CO₂ utilization are discussed.

10.3.1.1 Distributed Small- to Medium-Scale CO₂ Emitters

Small- to medium-scale CO₂ emitters, or those that emit less than 1 Mt CO₂ equivalents per year, span power plants, chemicals, minerals, breweries, paper and pulp, food, commercial, and public administration sectors. Such emitters are widely distributed across the United States, many in remote locations, and collectively contribute a significant proportion of overall U.S. CO₂ emissions. As shown in Figure 10-5, 92 percent of U.S. industrial and power plant facilities reporting emissions to the U.S. Environmental Protection Agency (EPA) in 2022³ emitted less than 1 Mt CO₂e, and these 6955 facilities accounted for 33 percent of reported emissions (EPA 2023b). The decarbonization of small- to medium-scale emitters is imperative in successfully meeting the 2050 net-zero-emission target and could involve CO₂ capture and utilization in addition to other decarbonization strategies like electrification and improvements in energy efficiency. Considering only the industrial sector, small- to medium-scale industrial emitters, defined as emitting between 12,500 and 60,000 tCO₂ per year, comprise 25 percent of all U.S. industrial point-source emissions (Moniz et al. 2023). Moniz et al. (2023) identified ten regional targets for clusters of small-to-midsize emitters that could share resources and risks, and develop economies of scale and effort. Three of that report’s identified clusters are in the same regions (Midwest and Gulf Coast) discussed as possible industrial clusters in Section 10.3.1.2.

For some small- to medium-scale emitters, deployment of renewable electricity and onsite utilization of captured CO₂ using modular technologies may be more cost-effective than process modification. New capture technologies based on membranes (Etxeberria-Benavides et al. 2018), enhanced adsorption processes (Crake et al. 2017; Wang et al. 2018), and molten carbonate fuel cells (FuelCell Energy 2023) are promising at small to medium scale because they are modular, able to be retrofitted on existing infrastructure, easy to scale up, and cost-competitive. They are also relatively simpler than conventional capture technologies, such as solvent-based post-combustion capture, which is not expected to be feasible at medium scale (50 ktCO₂ per year) owing to its large physical footprint (Sharma et al. 2019). The Advanced Research Projects Agency–Energy’s (ARPA-E’s) GREENWELLS program is exploring the feasibility of producing chemicals and fuels from CO₂ using intermittent renewable electricity and hydrogen (ARPA-E 2023), which, if successful, could be a valuable opportunity for onsite CO₂ utilization at small- to medium-scale emitters.

In cases where onsite utilization of captured CO₂ may not be a feasible option, deployment of optimal multimodal CO₂ transport solutions and “right-size” infrastructure is an attractive addition to the mitigation portfolio

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³ EPA’s Greenhouse Gas Reporting Program requires facilities that emit greater than 25,000 metric tons CO₂e per year to report their emissions annually.

for small-to-medium emitters, allowing CO₂ emissions to be substantially reduced and holistically integrated with electrification, hydrogen, and biomass technologies. This is particularly so as planned CCUS industrial clusters comprising large CO₂ emitters (e.g., cement and steel production) often cannot embrace distant small-to-medium-scale emitters, given the additional CO₂ transport infrastructure costs which may become unrealistic (Moniz et al. 2023). Moreover, when building pipelines for small sources is too costly, smaller companies are unable to take advantage of the 45Q tax credit, placing them at a financial disadvantage relative to larger companies. In these instances, transport of CO₂ by truck, rail, barge, or ship may offer a solution and be particularly important for early CCUS adopters.

10.3.1.2 Industrial Clusters for Large Volumes of CO₂

Given the multiple utility and feedstock needs for CO₂ capture and utilization, and the expense, challenge, and public concern over new pipelines, sites where all needed components are co-located are distinctly advantageous for CO₂ utilization deployment. Two promising opportunities for co-locating CO₂ capture and utilization are around bioethanol facilities in the Midwest and heavy industry and refining in the Gulf Coast. Midwest bioethanol facilities are small- to medium-scale emitters located in close enough proximity that shared infrastructure can aggregate CO₂ to obtain volumes suitable for conversion to products at scale. On the other hand, many industrial facilities in the Gulf Coast region are large emitters, each generating substantial volumes of CO₂ for utilization, but likewise

could benefit from shared infrastructure to reduce costs. Such infrastructure could also serve the numerous small- and medium-size emitters also located in the Gulf region, functioning as an “anchor tenant” around which larger CCUS networks could develop in the longer term.

Biogenic CO₂ from ethanol plants is advantaged for use in synthetic fuels and chemicals, as it is a sustainable CO₂ source with relatively low capture cost, around $0–$55 per tonne of CO₂ (Bennett et al. 2023; GAO 2022; Hughes et al. 2022; Moniz et al. 2023; NPC 2019). Most of the planned and operational CO₂ capture projects at bioethanol facilities are located in the Midwest, primarily in Iowa, Minnesota, Nebraska, and South Dakota (Figure 10-6). As discussed in Section 10.2.3, CO₂ pipeline projects are under development to transport this captured CO₂ to geologic sequestration sites, although they have experienced setbacks and delays. Some of this captured CO₂ instead could be diverted for utilization; however, given the small scale of individual bioethanol plants, captured CO₂ will likely need to be collected in a single location to enable conversion to chemicals and fuels at economies of scale. This could be done using local pipeline networks, along with other modes of transport—especially when passing through or close to populated areas—per the methodologies described above. CO₂ conversion to fuels will require hydrogen, which could be produced at the CO₂ collection site using electrolysis powered by clean electricity.

The U.S. Gulf Coast region is home to nearly 50 percent of U.S. refining and petrochemicals manufacturing (EIA 2023b), making it a prime opportunity for deployment of point-source carbon capture. These refining and petrochemicals facilities are co-located with an existing array of CO₂ and hydrogen pipelines; storage sites in well-characterized depleted hydrocarbon reservoirs, including offshore storage in federal waters where the U.S. government can have long-term ownership; and salt domes for low-cost hydrogen storage for use with renewable power, and are in close proximity to ports to allow export to markets (e.g., European Union, Japan) where low-carbon products are given market incentives (Bayer and Aklin 2020; Datta et al. 2020; LSU Center for Energy Studies 2023). Figure 10-7 shows planned and operational CO₂ capture projects in the Gulf Coast region from a variety of point sources, which could be aggregated and utilized or transported for geological storage.

Because most of the captured CO₂ from this region is of fossil origin, utilization products would have to be long-lived (e.g., mineral carbonates, solid carbon products) to ensure durable carbon sequestration. This could present a challenge, as mineral products are typically low value, and end-use of hydrocarbon products such as plastics typically cannot guarantee sequestration. On the other hand, carbon fibers, graphite, and other elemental carbon forms offer higher value (see Chapters 2 and 6). Use of fossil CO₂ to make short-lived products from large point sources could be considered in the near term, wherein fossil CO₂-based production replaces similar production from oil or natural gas in demand-limited market scenarios (see Section 10.4.5). Full market life cycle assessment (LCA) would be needed to ensure net fossil CO₂ mitigation. In any case, given that there will be a mix of CO₂ sources aggregated for utilization and storage, a rigorous accounting method will be required to determine the carbon intensity of utilization products. Such accounting methods for common carrier CO₂ infrastructure are discussed in Chapter 4.

10.3.1.3 Shared CO₂ Transport Pipeline Networks for CO₂ Storage and Utilization in CCUS Industrial Clusters

As the committee recommended in its first report, DOE should consider favorably the ability of CO₂ capture, transport, and storage demonstration projects to connect to future CO₂ utilization opportunities because allowing for shared use of CO₂ pipelines for both utilization and storage could take advantage of economies of scale (Recommendation 6.2, NASEM 2023a). In general, wider availability of CO₂ through improved transportation and storage infrastructure could open the CO₂ marketplace to traditional market demand dynamics and enable CO₂ pull from the market where its conversion is most affordable (e.g., near low-cost clean electricity and/or hydrogen) and where the resulting product can be used. For CO₂ transport pipeline networks in CCUS industrial clusters, depending on the CO₂ purity and market demand, some of the CO₂ stream destined for geological storage could be diverted for utilization. In addition, as the CO₂ emission rates in the cluster substantially decrease because of a transition to clean energy or electrification, it may be more economical to divert the entire CO₂ stream for utilization, taking account of the costs associated with any upstream CO₂ purification that may be required. Such plans already exist in Europe (see, e.g., C⁴U Project 2020) that could set the scene for the United States.

For example, as part of a CCUS industrial cluster commencing operation in 2025, the planned Fluxys CO₂ pipeline network in Belgium is expected to handle eventually more than 50 percent of the 40 MTPA total CO₂ emissions captured from several major industries along its route (Fluxys Belgium 2022). Several of these emitters,

such as the steel and cement industries, plan to divert some of the CO₂ for utilization to produce fuels such as e-methanol (see, e.g., the North CCU Hub; CO₂ Value Europe n.d.), with future potential opportunities for producing methane, e-kerosene, and polymers. The Belgian CO₂ CCUS value chain encompasses CO₂ capture and purification; multimodal transport involving pipeline, ship, train, and trucks; CO₂ liquefaction; CO₂ utilization; and CO₂ storage in disused gas fields under the North Sea seabed (Fluxys Belgium 2022).

As another example of shared CO₂ transport and utilization pipelines, OCAP (Organic CO₂ for Assimilation in Plants) currently supplies about 500,000 tons of CO₂ per year to enhance crop growth⁴ for approximately 600 greenhouse companies in the western part of the Netherlands via a 97-kilometer transport pipeline and distribution network of 250 kilometers (OCAP n.d.). This CO₂ is produced during the production of hydrogen at Shell in the Botlek area and during the production of bioethanol at Alco in Europoort Rotterdam. In situations where CO₂ supply exceeds demand, the surplus CO₂ may in future be diverted for nearby geological storage sites by joining existing CO₂ pipeline infrastructure.

To this end, the Porthos (Port of Rotterdam CO₂ Transport Hub and Offshore Storage) project intends to provide transport and storage infrastructure to energy-intensive industries in the Port of Rotterdam and, possibly, to industries in the Antwerp and North Rhine Westphalia areas at a later stage (Porthos 2023). The project will link CO₂ capture facilities and the existing OCAP pipeline with a new onshore pipeline, which will transport the aggregated CO₂ in a CO₂ hub in the Port of Rotterdam and subsequently via an offshore pipeline to a depleted gas field 20 kilometers off the coast for permanent storage. The final investment decision for Porthos was made in October 2023, construction of the Porthos infrastructure will start in 2024, and the system is expected to be operational starting in 2026.

10.3.2 Retrofitting Existing Infrastructure for CO₂ Capture, Transport, and Utilization

10.3.2.1 Addition of Carbon Capture to Existing Industrial Facilities to Enable CO₂ Utilization

DOE’s Industrial Decarbonization Roadmap (DOE 2022b) details research needs and challenges for decarbonizing the industrial sector, addressing CO₂ footprints for scope-1 and -2 emissions, which includes the process energy, heat, and utilities required for manufacturing products, but not emissions associated with use of products (e.g., as fuel) or production of feedstock. As shown in Figure 10-8, the U.S. industries with the largest energy-related CO₂ emissions are chemical manufacturing and petroleum refining. One opportunity for mitigating emissions from these industries is incorporating CO₂ capture paired with sequestration or utilization to form a long-lived product. Existing facilities in principle can be retrofitted for CO₂ capture, but achieving significant decarbonization may require capture from several places within the process, which is one reason the industrial sector can be considered “difficult to decarbonize.”

The cost of retrofitting an industrial facility with CO₂ capture is an important consideration for the feasibility of subsequent CO₂ utilization or storage. The National Energy Technology Laboratory and National Petroleum Council have performed rigorous cost estimates for CO₂ capture from industrial processes (Hughes et al. 2022; NPC 2019). A few processes, such as ethanol fermentation or petrochemical production of ethylene oxide, produce a relatively pure CO₂ stream, and capturing that CO₂ to produce a purified product has fairly low cost. For example, as mentioned earlier, costs to capture CO₂ offgas from ethanol fermentation range from $0–$55 per tonne⁵ (Bennett et al. 2023; GAO 2022; Hughes et al. 2022; Moniz et al. 2023; NPC 2019). The CO₂ stream from hydrogen production via steam reforming of natural gas, which accounts for approximately half of the CO₂ footprint of the process, has a capture cost on the order of $60–$115 per tonne CO₂ (DOE 2023a; NPC 2019). Capture of CO₂ from process furnaces used to provide heat and power comes at an even higher cost. Commercial CO₂ capture projects often only pursue capture from the most economical, high-concentration, high-pressure streams. For example, many current CO₂ capture demonstration projects for hydrogen production by steam methane

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⁴ CO₂ utilization for enhanced crop growth is out of scope for this report but is included here as a case example of shared utilization and storage infrastructure.

⁵ Range includes first-of-a-kind and nth-of-a-kind facilities.

reforming install a single capture unit at a point in the process that provides the lowest unit costs, and therefore only capture 40–60 percent of the overall CO₂ emissions. Many industrial processes entail CO₂ emissions from both process and utility streams, thus requiring capture from multiple point sources, which drives capture costs to as high as $200 per tonne CO₂ (NPC 2019).

In some cases, industry has constructed facilities that are “CO₂ capture ready” to facilitate tie-ins and space for CO₂ capture systems. Where CO₂ capture and mitigation is targeted, new technologies can be more efficient; for example, production of hydrogen from natural gas by autothermal reforming or partial oxidation can result in virtually complete decarbonization via capture from a single stream in the process unit. These technologies often require a complete rebuild of the production unit (Liu 2021; NPC 2019) or a substantial upgrade including addition of a partial oxidation reactor (Mahabir et al. 2022).

Until passage of the Inflation Reduction Act (IRA), the 45Q tax credits—at $50/tonne for geologic storage and $35/tonne for use in EOR by 2026 (Beck 2020)—were generally too low for industry to invest in CO₂ capture, except where the CO₂ had a coproduct value for utilization in EOR. (EOR can be economic at higher oil prices found prior to the discovery of unconventional shale oil production methods.) Recent increases in 45Q tax credits to $85 per tonne for storage and $60 per ton for utilization allow technologies with mid-range CO₂ capture costs, such as those involved in hydrogen production, to be considered, but they are still too low for the $100–$200 per tonne capture costs of many of the processes in the “difficult to decarbonize” industrial sector (NPC 2019). For capturing these industrial CO₂ streams for utilization or storage to be economical, there would need to be a further increase in the tax credits and/or additional research and development (R&D) on CO₂ capture technologies, such solid sorbents, to reduce costs. See Chapter 4 for more detail on policy options to support CO₂ utilization and Chapter 11 for more information about R&D needs for CO₂ capture.

10.3.2.2 Conversion of Existing Natural Gas and Oil Pipelines for Transporting CO₂, Hydrogen, or CO₂-Derived Products

The committee’s first report examined the feasibility of retrofitting natural gas pipelines for transporting CO₂, finding that this would have to be determined using rigorous systems analysis on a case-by-case basis given the large number of parameters involved (Finding 4.8, NASEM 2023a). Retrofit of natural gas pipelines for CO₂

service can be considered over shorter distances (trunklines, see, e.g., Tallgrass 2024), but pressure capabilities of existing pipelines will not be sufficient for large-scale, long-distance transport (Kenton and Silton n.d.; NPC 2019). CO₂ is normally transported as a supercritical fluid exhibiting the high density of liquid CO₂ but the low viscosity of a gas. Natural gas is generally transported in pipelines in gaseous form at pressures between 800 and 1160 psi. The critical point of CO₂ is at 30.9°C and 1070 psi, such that the pressure for CO₂ transportation must be at least 1200 psi to avoid phase changes from temperature fluctuation, which is much higher than the standard operating parameters for existing natural gas pipelines (Kenton and Silton n.d.). All major CO₂ pipelines today transport at pressures above 1900 psi. For retrofit, a dehydration system would be required to minimize water content, because wet CO₂ forms carbonic acid, which offers a high risk of corrosion. High-pressure CO₂ pipelines require crack arrestors to prevent catastrophic failure in the event of corrosion or external forces such as subsidence or collision damage. Modifications to the gaskets and nonferrous materials of the original pipeline may be required to prevent deterioration in the presence of concentrated CO₂ (Kenton and Silton n.d.).

Pipe-in-pipe technologies may be considered for laying new CO₂-compatible pipe within existing pipelines (Enbridge 2022). In principle, land used for pipeline rights of way can be used to lay new CO₂-compatible pipe; however, a formal right of way for transport of a given gas (e.g., natural gas) does not translate into a right of way for transport of a new gas (e.g., CO₂). CO₂ pipelines and rights of way have to be approved for the new CO₂ service on a case-by-case basis, including scenario modeling for release and risk of asphyxiation from release of a vapor that is heavier than air. Compatibility of pipeline metals and wetted components also has to be approved on a case-by-case basis, especially for retrofitted systems. CO₂ transportation challenges, including repurposing of existing pipelines to service CO₂, are described in more detail in a workshop report from DOE (DOE-FECM 2023b).

Retrofitting existing natural gas networks for hydrogen transport is also of interest, as hydrogen is an enabling input for many CO₂ utilization processes. However, there are challenges associated with doing so. For example, the existing natural gas network may not be able to handle the high pressures required for hydrogen transport. Additionally, hydrogen tends to embrittle metals, which may require upgrades to existing pipelines, such as adding a copper or polymer coating by retrofit pigging operations or installing pipe-in-pipe technologies. Coating technologies present concerns about long-term robustness and safety, while pipe-in-pipe technologies allow the preferred metallurgy to be installed but reduce capacity. For both options, the cost may be greater than new pipe installation. However, studies have shown that, in some cases, converting existing natural gas pipelines into dedicated hydrogen pipelines could reduce hydrogen transmission costs by 20–60 percent compared to constructing new hydrogen pipelines because of savings across the entire value chain of materials, the permitting and time expense, land use acquisition costs, construction costs, and costs of additional infrastructure (e.g., compression, power) (Cerniauskus et al. 2020). Thus, decisions will have to be made on a site-specific basis. Despite these challenges, there has been some progress in using existing gas networks for hydrogen transport. In the United Kingdom, for example, the H21 project is exploring the feasibility of converting the gas network in northern England to run entirely on hydrogen (Northern Gas Networks 2016). In the United States, unlike in Europe, there often is enough space to lay down more pipe in existing rights of way, perhaps reducing the need to retrofit existing infrastructure.

As infrastructure is built out to transport CO₂ for storage and utilization and to use hydrogen for decarbonization (including via its reaction with CO₂ to make hydrocarbon products), there may be competition between CO₂ and hydrogen for natural gas pipeline repurposing. Optimization of the existing gas pipeline network for future use by CO₂ and/or H₂ will require integrated coordination among usage options. Owing to this competition and other factors, there will likely be a need for new pipelines to transport CO₂ or H₂ beyond what can be accommodated by existing natural gas pipelines.

In addition to natural gas pipelines, over 190,000 miles of liquid petroleum pipelines traverse the United States (API 2021), and with the transition to renewable energy and electrification, many of these pipelines may become obsolete as demand for fossil fuels decreases. Given their extensive geographical spread, it is very likely that some will pass near CO₂ utilization facilities. Depending on their locations and taking account of any additional safety concerns that might arise in the event of an accidental release, there may be opportunities to use some of these pipelines to transport CO₂-derived fuels or chemicals. As with any pipeline retrofit, questions of safety, environmental impacts, technical feasibility, and economics would have to be addressed adequately before moving forward with the project.

10.3.2.3 Converting Fossil Facilities and Chemical Plants for CO₂ Utilization

The conversion of existing fossil facilities and chemical plants to accommodate CO₂ utilization depends on the specific project economics and thus has to be considered on a case-by-case basis. For example, converting a conventional methanol synthesis plant using syngas to one using CO₂ and H₂ as feedstocks would require a CO₂ purification unit and redesign of the reactor and methanol distillation column to separate excess water. Project developers would have to determine if such a conversion is cost-effective compared to construction of a new facility. Converting or rebuilding on existing facility sites could allow for reuse of the connected power, feedstock, and product offtake infrastructure, as well as retain the existing workforce associated with the facility.

10.3.3 Enabling Infrastructure Needs for Water, Hydrogen, and Electricity

CO₂ is a fully oxidized form of carbon, thermodynamically degraded and devoid of energy except when used for some mineralization reactions to form carbonates. Therefore, activating CO₂ for conversion requires inputs of energy in the form of electricity, hydrogen, and/or heat. As described in previous chapters, there are multiple pathways for converting CO₂ into useful products and chemical intermediates. For example, CO₂ can be electrochemically or thermochemically reduced to CO, which can be further reacted with H₂ to form hydrocarbon products, effectively reproducing the current hydrocarbon economy. Given finite conversion efficiency, using renewable wind or solar energy to power hydrogen production requires at least twice the amount of energy as current commercial processes for making hydrogen, while further conversion into hydrocarbon products requires two-fold more energy (Adolf et al. 2018, 2020). Land use can also be a significant issue for CO₂ utilization in systems where renewable electricity is used to provide both the energy and hydrogen required to upgrade CO₂ to valuable products (Gabrielli et al. 2023; Merrill 2021). At a national scale, water requirements for CO₂ utilization do not represent a significant increase over current usage, but local impacts need to be evaluated. The committee’s first report detailed these enabling infrastructure requirements to supply clean electricity, clean hydrogen, water, land, and energy storage for CO₂ utilization projects (Chapter 4 of NASEM 2023a), and the committee refers readers to that discussion for more information. This section covers additional aspects of CO₂ utilization enabling infrastructure not discussed in depth in the first report (e.g., transportation of hydrogen) and highlights regional considerations for electricity, hydrogen, and water infrastructure when developing CO₂ utilization facilities.

10.3.3.1 Hydrogen Pipelines

Clean hydrogen⁶ is a required feedstock for many approaches to convert captured CO₂ into synthetic fuels and chemicals. For dispersed CO₂ emitters, onsite production of clean hydrogen for CO₂ utilization may not always be a viable option. In such circumstances, to take advantage of economies of scale, hydrogen may be produced at a central facility for distribution to the various emitters. Given the large volumes involved, transportation of gas-phase hydrogen using high-pressure pipelines in combination with other modes of transport may be the most viable option. Developing infrastructure to supply clean hydrogen at large scale (e.g., for use in vehicles and power generation) would require an expansive hydrogen pipeline network (Parfomak 2021). Clean hydrogen for fuel cells or combustion will compete with battery electrification of vehicles and renewable power generation technologies, so it is not yet clear how much hydrogen fuel will be needed, and hence if any extensive hydrogen fuel infrastructure will be built. If hydrogen pipelines are built, some of them may also supply hydrogen to dispersed emitters for CO₂ utilization depending on their proximity.

To facilitate hydrogen infrastructure development, the Consolidated Appropriations Act, 2021 provided funding to DOE’s Hydrogen and Fuel Cell Technologies Office to support R&D for topics including hydrogen pipeline research. The IIJA appropriated $9.5 billion for clean hydrogen (DOE 2022a), including to develop the Regional Clean Hydrogen Hubs discussed in Section 10.2.2. The IRA provided additional beneficial policies and incentives for the U.S. hydrogen industry to take center stage in the clean energy transition (Webster 2022).

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⁶ DOE’s Clean Hydrogen Production Standard considers low-carbon (i.e., clean) hydrogen that which has “well-to-gate lifecycle greenhouse gas emissions of ≤4.0 kgCO₂e/kgH₂” (DOE 2023c, p. 2).

Experience with high-pressure transportation of hydrogen is relatively limited. It is currently done on a much smaller scale than other methods of transport, with only 1600 miles of pipelines in operation in the United States, mainly located in the Gulf Coast region (DOE-HFTO n.d.). More than 80 percent of these pipelines are in areas of low population density, defined as a class location unit 1 under current federal pipeline safety regulations (Kuprewicz 2022) (see Figure 10-9).

The anticipated increase in demand for hydrogen—for CO₂ utilization and other fuel and feedstock applications—could require the development of a national high-pressure hydrogen transport pipeline network. NPC (2024) provides an in-depth analysis of the technology, policy, and partnerships needed to build out hydrogen infrastructure that is safe, integrated, flexible, scalable, and resilient. In a large-scale system, some hydrogen pipelines would need to pass through or nearby populated areas, so their safe operation is of paramount importance. Hydrogen has a unique hazard profile, substantially different than those for CO₂ or hydrocarbons, which requires important and stringent modifications to minimum federal and state pipeline safety regulations (DOE 2023d; Kuprewicz 2022). Relevant risk factors to consider when drafting hydrogen pipeline regulations include the following (Kuprewicz 2022):

• Hydrogen has a much greater flammability range than natural gas and hence is more likely to combust.
• Because hydrogen is the smallest chemical element, it readily diffuses through most materials, and thus hydrogen pipelines are more susceptible to leaks than CO₂ or natural gas pipelines.
• On a weight-for-weight basis, hydrogen has more than double the energy intensity of natural gas.
• Hydrogen has a much lower autoignition temperature and faster burn velocity than natural gas, meaning that its accidental release is much more likely to lead to detonation and explosion as compared to natural gas.
• Over time, hydrogen can cause metal embrittlement, increasing the probability of pipeline failure.
• Hydrogen is an indirect greenhouse gas, with potentially 33 times the warming power of CO₂ in the first 20 years.

• Odorants are routinely added to natural gas to detect accidental leaks. Special odorants will need to be developed for hydrogen that do not lead to mixtures that adversely interact with pipeline materials, have minimal health and environmental impacts, and do not require costly separation depending on the end use (Murugan et al. 2019).

10.3.3.2 Regional Considerations for Clean Electricity, Hydrogen, and Water Infrastructure for CO₂ Utilization

Enabling infrastructure requirements for CO₂ utilization—in particular the needs for clean electricity, clean hydrogen, and water—are likely to impact siting decisions for CO₂ utilization facilities. For example, clean electricity is needed to power CO₂ capture and conversion, electrolytic hydrogen generation, and other processes to ensure that CO₂-derived products have lower emissions than incumbent products on a lifecycle basis. Grid emissions intensity varies regionally, and such variations are projected to continue through 2030 and 2050, as illustrated in Figure 10-10. Thus, in the absence of dedicated, onsite clean energy generation for a CO₂ utilization project, developers may preferentially site facilities in regions with lower average grid emissions. Alternatively, developers could contract for emissions-free electricity through a power purchase agreement or work with a utility to set up a tariff structure to obtain clean electricity for their project. In either case, robust LCA would be required to determine eligibility for renewable energy tax credits.

If a CO₂ utilization project developer decides to deploy dedicated renewable resources (e.g., onsite wind or solar) to obtain clean electricity, the varying resource potential across the country (see NREL n.d.) would need to be considered in site selection. Furthermore, as discussed in the committee’s first report, many regions with abundant renewable resources are water stressed (Finding 4.14, NASEM 2023a), which could limit deployment of CO₂ utilization projects that require water (e.g., some carbon capture technologies, algae cultivation, and hydrogen production).

The locations of planned hydrogen hubs (see Figure 10-2 and Section 10.2.2) could also impact CO₂ utilization infrastructure siting, given that many CO₂ utilization processes require clean hydrogen. To that end, the committee’s first report recommended that DOE consider co-locating hydrogen and DAC hubs (Recommendation 6.4, NASEM 2023a), which it could still consider for the two DAC hubs yet to be selected. As shown in Figure 10-11, a 2023 Great Plains Institute analysis identified promising locations for DAC technology deployment based on proximity to low-carbon electricity and heat, geological carbon storage, and existing CO₂ transport, as well as appropriate climate and atmospheric conditions for DAC operation (Abramson et al. 2023). An analysis by Cai et al. (2024) examined the effects of meteorological conditions (e.g., temperature, humidity, atmospheric pressure, and local

CO₂ concentration) on the performance of amine-based DAC systems, concluding that process optimization at a specific location can significantly improve system performance and that consideration of local atmospheric conditions may impact siting decisions for DAC facilities. Overlaying these results with the hydrogen hub locations could identify promising sites to develop infrastructure for production of chemicals and fuels from CO₂.

10.3.4 Timescale for Implementation and Potential Barriers

A number of factors will influence whether CO₂ utilization infrastructure can be deployed on a timeline that allows it to contribute effectively to midcentury decarbonization goals. Primary barriers to CO₂ utilization development are the cost of CO₂ capture and, in cases where onsite CO₂ utilization is not feasible, transportation infrastructure costs. The cost of CO₂ capture is inversely proportional to the CO₂ concentration in the gas stream, ranging from less than $20 per tonne CO₂ for some high-purity streams (e.g., ethanol fermentation off-gas and natural gas processing) to upward of $1000 per tonne CO₂ for low-concentration streams (e.g., DAC) (Budinis and Lo Re 2023; DOE 2023a). Transportation of captured CO₂ for utilization and/or storage also adds cost, estimated at $5–$25 per tonne CO₂ for pipeline transport, $14–$25 per tonne CO₂ for ship transport, and $35–$60 per tonne CO₂ for rail and truck transport (DOE 2023a). Purification requirements for different transport modes (see Table H-3 in Appendix H) could further increase costs.

The long lead times for developing and deploying CO₂ capture, transport, and storage infrastructure, as depicted in Figure 10-12, also could slow large-scale CO₂ utilization rollout. For example, a lack of operational

storage capacity may deter investments in pipeline infrastructure, which in turn could delay CO₂ utilization projects that plan to obtain CO₂ from a larger pipeline network. As another example, CO₂ utilization projects aiming to produce hydrocarbon fuels from low-cost, high-purity, biogenic CO₂ from ethanol fermentation facilities may not be feasible without a pipeline network in place that can aggregate CO₂ sources to achieve economies of scale for fuel production. In addition to having long lead times, pipeline development also faces challenges with public acceptance, as discussed in Section 10.2.3. Regional or national CO₂ infrastructure planning is also challenged by uncertain policy and business environments that will impact future availability and cost of CO₂ and other inputs to CO₂ utilization like clean electricity and hydrogen. For instance, legal challenges to EPA’s power plant emissions rule raise questions about the future availability, quantity, and location of CO₂ sourced from power plants, which affects business cases and decisionmaking on how, when, and where to build CCUS infrastructure. Uncertainty in the durability of state and national policies, regulations, and incentives for CO₂ pipelines, CO₂ use and storage, clean electricity, and clean hydrogen also impedes long-term investment decisions for infrastructure.

10.4 INFRASTRUCTURE IMPACTS

The committee’s statement of task asks it to “[d]escribe the economic, climate, and environmental impacts of any well-integrated national carbon dioxide pipeline system as applied for carbon utilization purposes.” Recognizing that pipelines are only one component of the infrastructure needed to support CO₂ utilization—and, in fact, may not be required for all CO₂ utilization opportunities—this section also considers impacts of carbon capture, enabling inputs like hydrogen and water, and industrial facility siting and development.

10.4.1 Economic and Cost Impacts of Infrastructure Development for CO₂ Utilization

Potential infrastructure deployment scenarios for utilization, such as those described in Section 10.3.1 above, are speculative. However, existing analyses of U.S. sources of CO₂ and geological storage locations (e.g., Abramson et al. 2022; Larson et al. 2021) can inform assumptions about where these projects and their needed infrastructure might be built first. As described in previous chapters, CO₂ utilization technologies have an inherent challenge of scale, making co-location with sites that are amenable to geological storage (see USGS 2013) an attractive option. Additionally, CO₂ pipeline infrastructure is expensive (capital costs of recently announced projects in Table 10-4 range from $1.8 million to $2.7 million per mile), which adds incentive to develop utilization projects in close proximity to existing projects that will capture, transport, and store large quantities of CO₂. As noted above, locating

CO₂ utilization projects near enabling infrastructure for clean electricity and hydrogen production also could be beneficial. Multiobjective optimization models can assist project developers in determining the best options for infrastructure co-location.

In the coming months and years, continued implementation of the IIJA and IRA will provide a better sense of where and how this infrastructure will be deployed. Federal incentives will likely shape future infrastructure development, as many early movers may use federal funding programs, loans, or tax incentives to begin their projects. By one estimate, incentives in the IRA will spur $90 billion–$126 billion of investments in CO₂ transport and storage infrastructure between 2023 and 2035 (Jenkins et al. 2023). Because IRA incentives improve the economic viability of carbon capture for steel, cement, refineries, and natural gas- and coal-fired power generation, around 200 million tons of CO₂ could be captured from industry and power generation per year by the mid-2030s (Jenkins et al. 2023). In a net-zero future, the CO₂ captured from these facilities will have to either be stored or used in long-lived products, as its use in short-lived products would result in net-positive CO₂ emissions to the atmosphere. In the near term, before net-zero is reached, the lower cost of CO₂ capture from fossil point sources versus DAC may enable more fossil CO₂ removal per unit of investment, given that substitution of synthetic fuels or chemicals derived from CO₂ reduce demand for petroleum or natural gas production. This possibility can be evaluated with a levelized cost of CO₂ abatement combined with a full LCA that accounts for the initial energy services that result in fossil CO₂ emissions, followed by capture and reuse.

When making net-zero infrastructure investment decisions, the levelized cost of CO₂ abatement is a valuable metric. It measures the cost of a specific policy, technology, or investment per amount of CO₂ reduced or removed, where the cost (including both capital and operating expenses) is annualized over the lifetime of the project. This accounting for cost of capital, amortization, and net present value across the project lifetime distinguishes the levelized cost of CO₂ abatement from marginal abatement calculations and enables more relevant comparisons across options (Friedmann et al. 2020). Additionally, unlike many marginal abatement cost calculations, levelized abatement costs take into account the emissions source(s) being displaced upon implementation of the new policy, technology, or investment, which adds more local or regional specificity to the calculation (Friedmann et al. 2020). Any comparisons between levelized costs of CO₂ abatement for different policy, technology, or investment options must use the same financing metrics and assumptions. Emissions reductions are estimated as the difference between the baseline condition and the “new” condition (i.e., the result of the policy, technology, or investment). As described in Friedmann et al. (2020), a simplified formula for calculating levelized cost (L) of CO₂ abatement is as follows:

$\text{L}\frac{\text{C}}{\left({\text{E}}_{\text{0}}{\text{-E}}_{\text{1}}\right)}$

where C is the levelized cost of the investment or change in policy or technology, E₀ is the emissions associated with the baseline condition, and E₁ is the emissions upon making the investment or change in policy or technology. A smaller positive value for levelized cost of CO₂ abatement indicates a more cost-effective action, although other factors beyond lowest cost (e.g., jobs, national security, equity implications) may also be important in making policy and technology decisions (Friedmann et al. 2020).

Public–private partnerships can also play a role in the development of large infrastructure such as a CCUS hub, as they facilitate sharing of resources. These partnerships can take different forms based on which entity owns and operates the various project components (e.g., capture infrastructure, utilization infrastructure, transport and storage infrastructure, possession of stored carbon, and title of stored carbon) (EFI Foundation and Horizon Climate Group 2023). As noted by the EFI Foundation and Horizon Climate Group, public–private partnerships for CCUS hubs could include “binding community benefits agreements for financial compensation, public authority or utility models for CO₂ transport and storage management, or government entities assuming long-term liability and postinjection site care responsibilities” (EFI Foundation and Horizon Climate Group 2023, p. 68).

The potential economic contributions from a regional CO₂ network for both storage and utilization can be substantial. CO₂ infrastructure development could contribute to the U.S. economy via an expansion of the local workforce (jobs), purchase of goods and services from local businesses (direct spend), and payment of federal, state, and local taxes (taxes). These benefits can be compounded through indirect and induced impacts. Indirect impacts refer to the secondary effects of infrastructure deployment, such as the changes in output, employment, or labor earnings of industries that support CO₂ utilization. Induced impacts emerge from the interaction between

the CO₂ utilization sector and other sectors. While development of a regional CO₂ pipeline network in the United States has been challenging (see Section 10.2.3), the experience of those project developers provides insight into the estimated economic benefits. Table 10-4 summarizes publicly available information from specific projects.

Despite these potential benefits, development of CO₂ utilization infrastructure also could have some negative impacts for local communities, project developers, and the existing CO₂ market. For instance, CO₂ infrastructure development could result in land use changes that affect local economies owing to changes in property values and/or tax base. Project developers wanting to obtain CO₂ from pipelines destined for storage could see high initial costs as pipeline capacity ramps up, which could deter investment or result in higher costs being passed along to the first customers. A nascent but growing CO₂ utilization industry could also raise the cost of CO₂ for direct use markets, such as food and beverage, where potential negative social impacts include an increase in cost of those products.

10.4.2 Climate and Environmental Impacts of Infrastructure for CO₂ Utilization

Regional- and national-scale infrastructure for CO₂ utilization will have benefits and impacts concurrent to those outlined in the committee’s first report (NASEM 2023a), which focused on enabling infrastructure. This section emphasizes the combined impacts of both CO₂ utilization and enabling infrastructure, and outlines gaps.

Decisions about the design and siting of CO₂ utilization facilities impact air emissions. LCA results for CO₂ utilization demonstrate a large range of climate and air pollution impacts, depending on the product and the way in which the LCA was conducted (see Chapter 3 for more detail). For CO₂ capture infrastructure, air pollution impacts may not be displaced unless operations are powered by renewable energy and the systems are designed

TABLE 10-4 Estimated Economic Benefits from Proposed CO₂ Pipeline Projects

^a Summit Carbon Solutions (2023, 2024).

^b Dakota Institute (2023).

^c Wolf Carbon Solutions U.S. LLC (2023).

^d Eller (2023); Navigator Heartland Greenway LLC (2021).

^e Despite project cancellation, included for reference of potential economic impacts of CO₂ pipeline projects.

to reduce or eliminate co-pollutants (Jacobson 2019). Systems designed to reduce both CO₂ and co-pollutant emissions could remove at least 75 percent of NO_x emissions, 98 percent of SO₂ emissions, and all condensable particulate matter (PM), alongside 90 percent capture of CO₂ emissions (Bennett et al. 2023). Figure 10-13 shows potential regional emissions reductions for CO₂, NO_x, SO₂, and PM_2.5 that could be achieved by deploying carbon capture on cement plants, providing a representative example of carbon capture co-benefits.

The transport of CO₂ through pipelines often requires compression for gas phase and pumping for dense phase, often involving intermediate boosting in the case of long distances (Doctor et al. 2005), which in turn requires energy. For natural gas pipeline transport, such demand is typically fueled using combined cycle gas turbines, which result in CO₂ emissions and other pollutants (e.g., volatile organic carbons [VOCs]); however, in the case of CO₂ pipelines, electricity may serve as a less carbon-intensive source of power, depending on the localized generation mix (Doctor et al. 2005). While metering has been recommended to account for any lost and unaccounted for gas, leak detection systems for CO₂ pipelines can reduce potential risks (Han et al. 2019; Santos 2012).

Hydrogen, comprising part of the enabling infrastructure for CO₂ utilization, has indirect global warming impacts, with an estimated global warming potential over a 100-year time horizon (GWP100) of 11.6 ± 2.8 (one standard deviation) (Sand et al. 2023). A recent review found that documented leaks across the present and future hydrogen value chain range widely; for example, from 0.5–1.0 percent for hydrogen production by steam methane reforming, 0.0–1.5 percent for hydrogen production by steam methane reforming with carbon capture, and 0.03–9.2 percent for hydrogen production by water electrolysis (Esquivel-Elizondo et al. 2023). If hydrogen production relies on natural gas, there may be additional upstream leaks that could further confound climate benefits, but these could be avoided if hydrogen is produced using renewable energy through electrolysis or other nonfossil methods (Bertagni et al. 2022). These findings present particular significance for developing measurement programs for enabling infrastructure involving hydrogen value chains.

Different types of CO₂ utilization operations can increase specific impacts other than climate change as well. For example, for CO₂ capture from thermal power plants, water requirements may increase owing to additional cooling needs and process water make-up (Magneschi et al. 2017; Ou et al. 2018). Net-zero scenarios that rely on CO₂ utilization may face land constraints without adequate planning, incurring ecosystem costs (Williams et al. 2021). Enabling infrastructure such as renewable power plants and transmission capacity will incur new land requirements and possibly damage to ecosystems without diligent siting analysis for new facilities (Hernandez et al. 2020). Furthermore, if the CO₂ supply is sourced from biomass, development may face additional land and water constraints.

10.4.3 Health and Safety Impacts of CO₂ Utilization Infrastructure

As more CO₂ utilization infrastructure is deployed, care will have to be taken to ensure safe operation of all technologies throughout the value chain, from CO₂ capture, to transport, to use in industry. The potential health hazards need to be understood and measures put in place to mitigate them. The sections below briefly describe health and safety considerations for CO₂ capture technologies, CO₂ transport in pipelines, and CO₂ use in industry.

10.4.3.1 CO₂ Capture Technologies

Solvent-based technologies remain one of the leading methods for large-scale post-combustion CO₂ capture. Research conducted at the Technology Centre Mongstad (TCM) has shed light on the potential harmful effects of amines used in carbon capture processes (Flø et al. 2017; Morken et al. 2014, 2017). During test campaigns with monoethanolamine between 2015 and 2018, solvent degradation and associated air emissions were observed. These degradation products include nitrosamine and nitramines, which are carcinogenic, toxic, and mutagenic compounds. The same studies at TCM also investigated strategies to reduce air emissions by addressing the main mechanisms for solvent degradation, namely exposure to heat (thermal degradation), oxygen (oxidative degradation), and reactions of the amine with flue gas contaminants such as SO_x, NO_x, halogenated compounds, and other impurities.

Advanced approaches to solvent management, flue gas pretreatment, and optimized plant process configuration have been shown to reduce solvent degradation. The initial concentration of solvent also has been shown to have a significant impact on degradation (Azarpour and Zendehboudi 2023). It is important to keep the solvent fresh by setting strict threshold limits for key indicators, such as ammonia concentration, and performing regular solvent exchange. Advanced novel process concepts have been developed to reduce and control amine emissions. A water wash section in the absorber and Brownian diffusion filter upstream from the absorber have been shown to remove greater than 95 percent aerosol contaminants that contribute to solvent degradation (Shah et al. 2018).

Other complications associated with amine-based CO₂ capture technology include the occupational hygiene risks associated with exposure of plant operators to amines, waste handling, and disposal of spent solvent and the risks associated with materials management, such as potential contamination of groundwater or surface water from unintended spills or leaks in the plant or in the chemical inventory. The absence of large-scale CCS facilities or reported data in the literature from pilot facilities make it difficult to estimate potential amine exposures and predict formation of and exposure to degradation products. Moreover, technology providers make use of proprietary amine blends that could have different impacts. However, with proper worker training and curbed containment areas surrounding the facility, these risks can be properly mitigated. Although amine solvents are the most commercially

prevalent technology today, other technologies are in various stages of development (NASEM 2023a; Pett-Ridge et al. 2023). Next-generation innovations in sorbents, membranes, looping cycles, and other novel concepts can mitigate health and safety risks associated with amine-based carbon capture systems.

A report from the Great Plains Institute highlighted health benefits of carbon capture facilities from the removal of co-pollutants and subsequent improvement of air quality (Bennett et al. 2023). As previously mentioned, amine-based capture systems require flue gas pretreatment to remove NO_x, SO₂, and PM_2.5 to reduce solvent degradation and improve capture performance. Bennett et al. (2023) developed a methodology to evaluate the co-benefits of applying pretreatment for these co-pollutants to amine-based carbon capture for seven industries. The analysis used the EPA CO-Benefits Risk Assessment (COBRA) Health Impacts Screening and Mapping tool to quantify changes in air quality from removal of these co-pollutants and calculate the changes in 12 different health outcomes, including adult and infant mortality, asthma exacerbations, and respiratory and cardiovascular-related hospital admissions. It then calculated the total monetary value of all impacts in millions of dollars per year. The analysis showed that co-pollutant removal resulted in health benefits across all industries and regions, with an economic value ranging from $6.8 million to $481.2 million per year, with the highest potential impact in the Mid-Atlantic and Appalachia regions (Bennett et al. 2023).

10.4.3.2 CO₂ Pipelines

Safety considerations for CO₂ transport were discussed in detail in the committee’s first report (Section 4.3.3, NASEM 2023a). The risks and hazards differ somewhat by mode of transport owing to pressure and temperature differences but are the same whether the CO₂ is being transported for utilization or storage. As noted above, for large quantities of CO₂, transport by pipelines is the safest and most cost-effective approach. The United States has been operating CO₂ pipelines safely since the 1970s, primarily to transport CO₂ for EOR (Wallace et al. 2015). CO₂ pipeline safety is overseen by PHMSA, which requires operators to follow specific guidelines for operations and maintenance, control room management, public awareness, damage prevention, operator qualification, and drug and alcohol testing (Thomley and Kammer 2023). For example, to ensure safe operation, pipeline operators have to pay attention to pipeline design, monitor for leaks, protect against corrosion, and safeguard against overpressure (Carbon Capture Coalition 2023).

While CO₂ pipelines have a strong safety record overall, incidents can be and have been significant. A primary example is the rupture of a CO₂ pipeline near Satartia, Mississippi, in February 2020, which required 45 individuals to seek medical attention and 200 to evacuate (Thomley and Kammer 2023). This rupture resulted in the formation of a crater owing to a high momentum CO₂ jet, as illustrated in Figure 10-14. The failure investigation of this incident, led by PHMSA, found that the plume dispersion model used as part of the risk assessment underestimated the safety distances (PHMSA 2022). PHMSA’s investigation indicated needs for improvements in (1) mitigation efforts to address “integrity threats owing to changing climate, geohazards, and soil stability issues” and (2) public and emergency responder awareness of CO₂ pipeline safety (PHMSA 2022, p. 2). As a result of this incident, PHMSA initiated a rulemaking process to update its safety standards for CO₂ pipelines, with plans to release a Notice of Proposed Rulemaking in 2024 (Parfomak 2023). In April 2024, pipeline developer Tallgrass established a community benefits agreement with Bold Alliance that includes $600,000 in funding for emergency response equipment and training in communities along the pipeline route, among other provisions (Hammel 2024). (See Chapter 4 for more on community benefits agreements and community engagement around CO₂ pipeline siting.) The Carbon Capture Coalition, a nonpartisan group working to facilitate commercial deployment of carbon management, proposed the following measures to increase CO₂ pipeline safety while supporting build-out of this infrastructure to meet net-zero emissions goals: “expand first responder training for CO₂ pipeline safety incidents; request that PHMSA conduct additional reporting on the public safety record of CO₂ pipelines; require that project proponents more rigorously consider potential geohazard impacts on CO₂ pipelines during design, siting, construction, and maintenance; carry out a national assessment of the CO₂ network necessary to meet net-zero emissions” (Carbon Capture Coalition 2023, p. 2).

Additional R&D on dispersion modeling for CO₂ and its typical stream impurities and on propagating brittle and ductile fractures in CO₂ pipelines also could help improve CO₂ pipeline safety. For example, while there are relatively accurate computer simulations that model CO₂ dispersion behavior following accidental release from a pipeline, more research is needed to model the dispersion of CO₂ and its impurities from a crater formed owing to the rupture of a

buried pipeline. Such research could inform the minimum safety distance required. Additionally, as highlighted in the committee’s first report (NASEM 2023a), the risk of propagating ductile and brittle fractures in CO₂ pipelines warrants significant research attention. Rigorous mathematical models need to be validated using realistic-scale test facilities to determine a pipeline’s susceptibility to these types of fractures and to identify the appropriate pipeline materials to mitigate these risks. Given the multidisciplinary nature of the expertise needed in understanding and modeling the behavior of CO₂ pipelines, coupled with the significant capital investment needed to conduct realistic field tests, international collaboration of the type funded by the European Commission’s Horizon Europe program (European Commission n.d.) can be a key enabler in accelerating the safe, large-scale implementation of CO₂ pipelines.

10.4.3.3 Industrial Use of CO₂

Carbon dioxide is a colorless, odorless, and tasteless gas at normal temperatures and atmospheric pressures, making it undetectable without monitoring devices (Airgas 2018; FSIS Environmental Health and Safety Group 2020; Spitzenberger and Flechas 2023). With a density of 1.98 kg/m³ at standard temperature and pressure, CO₂ is approximately 1.5 times heavier than air and can cause low-lying vapor clouds along the ground, or in depressed areas such as pits and cellars. CO₂ is typically transported, stored, and handled in its liquid form, either in cylinders or noninsulated storage tanks at ambient temperature, or under pressure in insulated tankers and storage tanks at temperatures between −35°C and −15°C (CO₂ Gas Company 2017). Many industries also utilize CO₂ in its solid form (dry ice) for chilling and packing product.

Workers that handle CO₂ storage or portable containers, dry ice, or operate near areas where CO₂ is produced or stored, risk CO₂ exposure. A CO₂ cylinder may rupture (or burst) if heated or if the container is overfilled.

Compressed CO₂ gas that is released from a cylinder can injure skin or eyes. Contact with solid CO₂ (dry ice) and refrigerated liquid CO₂ will cause frostbite upon contact owing to the extremely cold temperatures. Dry ice rapidly sublimes and off-gases CO₂, and levels as high as 30,000 ppm have been measured in rooms where dry ice is handled without adequate ventilation (FSIS Environmental Health and Safety Group 2020). A potential asphyxiation hazard exists when CO₂ is dispensed from transportation vessels to stationary, low-pressure storage tanks if there are inadequate transfer seals (OSHA 1996). Exposure to CO₂ gas can lead to negative health effects, which range from headaches and dizziness with minimal CO₂ exposure to difficulty breathing, malaise, increased heart rate, elevated blood pressure, asphyxia, convulsions, unconsciousness, and even death.

CO₂ generally is not found at hazardous levels, unless there is limited ventilation where gas is being stored or produced, or in confined or enclosed spaces. The industry has developed standards and procedures to minimize the development of hazardous conditions (OSHA 1996). These include adequate employee training; CO₂ safety warning signs around stored CO₂; gas detection and alarm systems that can alert building occupants of a CO₂ gas release; proper personal protective equipment such as cryogenic gloves and eye protection; as well as regular maintenance and inspection of CO₂ equipment by qualified personnel.

Owing to its potential to create a hazardous atmosphere, the transport, storage, and handling of CO₂ are regulated by several agencies, including the National Fire Protection Association, the National Board Inspection Code, the International Fire Code, the Occupational Safety and Health Administration (OSHA), and the National Institute for Occupational Safety and Health (Department of Labor 1974; EPA 2000). These organizations have agreed to workplace exposure limits for CO₂ set by OSHA that would likely be applicable to future CO₂ utilization markets (FSIS Environmental Health and Safety Group 2020).

10.4.4 Environmental Justice Considerations and Societal Support for CO₂ Utilization Infrastructure Development and Use

As discussed in more detail in Chapter 4, CO₂ utilization infrastructure development, siting, and selection will play impactful roles in determining the overall benefits of utilization projects, as well as broader societal support for them. Incorporating environmental and social justice tenets in the development of this infrastructure is not a guarantee for support but remains a foundational premise if the sector is to play an integral role in a more equitable circular economy and to avoid past and ongoing harms of linear economies that rely on extractive and disenfranchising principles.

Until the CO₂ utilization sector establishes itself in a consumer market in a tangible way, it will continue to be viewed primarily in the context of other carbon management infrastructure, especially CCS. Many individuals of historically marginalized backgrounds and disenfranchised communities consider carbon management to be a part of the extractive, carbon-based industries that concentrate economic and political power and harm their communities and the global environment (Chemnick 2023; Climate Justice Alliance 2019; Earthjustice and Clean Energy Program 2023; Just Transition Alliance 2020; New Energy Economy n.d.). The opposition to emerging carbon management technologies like carbon capture and carbon removal mirrors the themes seen in opposition to other emerging industries such as advanced nuclear and hydrogen (NASEM 2023b, 2024). However, most societal acceptance research has determined that the general public lacks information about CO₂ utilization and the carbon management sphere as a whole (Offermann-van Heek et al. 2018), which provides an opportunity both to embed environmental justice and community-centered principles into the build-out of the utilization sector and shape further discourse on the subject.

For infrastructure that has yet to be built out, there are opportunities for developers to consider incorporating and prioritizing specific environmental justice principles that may impact how the work gets done, including considerations around shared resources like energy, land, and water use. Best practices for community engagement around project development will differ across communities, but core tenets include avoiding past mistakes, building trust and maintaining relationships, centering enfranchising frameworks, providing resources for engagement, employing alternative ownership models, and sharing information transparently, all of which are elaborated upon further in Chapter 4.

Project siting has to take into account community history and perceptions around new infrastructure versus existing infrastructure, as well as aspects like pipelines that could substantially increase in number as the sector

builds out. The centering of strategies developed by minority and overburdened communities—especially those that have had significant intersections with resource management and pipeline development like U.S. Indigenous communities and Tribal nations—and lessons learned from past community experiences can play significant roles in ensuring that community concerns are adequately addressed. Similarly, opportunities to incorporate justice principles into permitting and workforce development in the utilization space must be considered. Lastly, the siting of utilization infrastructure needs to consider the role the end products will play in creating a more just circular economy; understand impacts from infrastructure and use frameworks, such as Community Benefit Agreements and Free, Prior, and Informed Consent, to encourage their just distribution; and incorporate these frameworks into decision-making processes.

10.4.5 CO₂ Utilization Infrastructure Considerations and Trade-Offs

Infrastructure development is a critical bottleneck for CO₂ utilization. Infrastructure decisions require considerations across the value chain to ensure safety and economic viability, minimize environmental impacts, engage with communities, and enable sustainable production of the chemicals and materials needed in a net-zero future. These decisions necessarily involve trade-offs—for example, where one solution might have lower cost, another might yield lower emissions—and decision makers will need to determine which factor(s) are more critical for a particular project. In this section, the committee highlights some considerations and trade-offs for CO₂ utilization infrastructure deployment.

The source of CO₂ utilized influences the life cycle carbon intensity and public acceptance of, and corporate investment in, different conversion processes, as well as the infrastructure required. For example, the largest point sources of CO₂ today are of fossil origin. They can enable economies of scale for CO₂-derived products and can avoid extensive use of CO₂ pipelines via co-locating CO₂ capture and production of CO₂-derived products. However, using such sources for production of short-lived products like hydrocarbon fuels would not be sustainable in a net-zero future, as the fossil-derived carbon would be reemitted quickly to the atmosphere, adding net-positive emissions. As discussed in the committee’s first report, atmospheric or biogenic CO₂ is a more sustainable feedstock for hydrocarbon products (NASEM 2023a). However, costs are high for CO₂ produced from DAC, and supply is limited from biogenic sources, which are orders of magnitude smaller than from petroleum refineries and require extensive agricultural land (and water) for corn-derived bioethanol fuel production, which simultaneously forms the CO₂ off-gas. CO₂ from fossil point sources at 4–25 percent by volume will always be less expensive to collect and purify than CO₂ from DAC at ~450 ppm CO₂. The cost of widely available fossil CO₂ from power plants or industrial heating and power applications ranges from $40–$290 per tonne (Bennett et al. 2023; GAO 2022; Hughes et al. 2022; Moniz et al. 2023; NPC 2019), compared to costs of $90–$1000 per ton CO₂ for DAC (Budinis and Lo Re 2023; DOE 2023a; NASEM 2019).

Additional questions surround the long-term viability of investments in CO₂ capture from fossil point sources and the related CO₂ transport, use, and storage infrastructure. For example, what, if any, fossil-powered electricity generation or industrial heat and power will remain in the net-zero future, requiring CO₂ capture and utilization or sequestration infrastructure? Which fossil-powered facilities will be last to be retired, thus making them better candidates for CO₂ capture retrofits? Will small emitters continue to emit and capture their CO₂, or change their processes to no longer emit? The answers to these questions might differ for emitters that produce pure streams of CO₂ versus those with CO₂ streams requiring purification prior to use or storage, or for utilization processes that can be done economically on a small scale (e.g., concrete and fertilizer production) versus those requiring larger scales for viability.

One scenario to consider is the development of a CO₂-to-fuels commercial plant, where the developer has a choice of using fossil point source CO₂ or DAC CO₂ (assuming that low-cost biogenic CO₂ is unavailable owing to volume or location constraints). The CO₂-derived liquid fuel product would reduce the use of petroleum to supply final global demand for liquid fuels.⁷ For a given investment, more CO₂-derived fuel can be made from fossil

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⁷ In the current policy environment, independent oil producers would respond to an increase in CO₂-derived fuels by reducing drilling operations, which would cause oil prices to decrease owing to oversupply until existing reservoirs decline to match the lower demand. Such actions would make it even harder for additional biofuels or CO₂-to-fuels projects to compete, may reduce the impetus for electrification of transportation, and could lead to enhanced liquid fuel use (assuming consumers limit gasoline or diesel use when prices are high). While relevant to note these nuances, this scenario presents investment considerations only between the two CO₂ sources.

point source CO₂ owing to the lower capital costs, so the lower-cost point source CO₂ reduces more petroleum than DAC CO₂ would. There are several risks to choosing fossil point source CO₂, however:

• Climate, energy, or tax policy may lead to early retirement of assets producing fossil CO₂.
• Public opinion and global policy⁸ favor use of DAC and biogenic CO₂; thus, these sources may be incentivized over fossil point source CO₂.

The net emissions reductions resulting from using either fossil or DAC CO₂ also need to be considered. Use of fossil point source CO₂ to produce fuel results in net positive fossil carbon emissions to the atmosphere, while producing at most twice the energy output.⁹ On the other hand, use of DAC CO₂ for hydrocarbon fuel production can result in a net-zero emissions fuel if all other inputs are also net-zero carbon emissions. Another complication with DAC CO₂-to-fuels plants is that, given the current high costs of DAC, investments in DAC CO₂-to-fuels facilities may only support a small plant capacity, which may also be less efficient than a larger fuels production facility. The levelized cost of CO₂ abatement (see Section 10.4.1) from fossil point sources may remain less than from DAC sources during the time when most fuel is still being produced from petroleum. Levelized cost of CO₂ abatement calculations can facilitate infrastructure investment decisions by indicating which facilities are likely to abate the most CO₂ per investment cost over their lifetime. Government policy and corporate climate goals may not be designed to use this relationship, and hence risk in the fossil point-source investment is higher than its levelized cost of abatement.

In general, CCUS infrastructure is best positioned in proximity to both CO₂ point sources and low-cost geologic storage sites, to enable sharing of infrastructure for CO₂ supply and transport (De Luna et al. 2023). Nonetheless, CO₂ utilization facilities have to be sited on a case-by-case basis, considering infrastructure needs, product type, market acceptance for the carbon-mitigation potential, and community acceptance of new facilities and infrastructure, all of which will vary across the nation and globally. Thus, infrastructure siting is best decided on a project basis, after development of a fully integrated technology and market plan, and engagement with local stakeholders. Public–private partnership funding can be provided to facilitate infrastructure costs for project development, as has been seen with some CCUS hubs under development in Europe (EFI Foundation and Horizon Climate Group 2023). Infrastructure investment in CCUS can contribute to local employment and support global CO₂ emissions reduction goals, although local communities may face burdens of construction, land use changes, and potential pipeline development that need to be addressed. As discussed in this committee’s first report, regulators need to assess distributional impacts, particularly for historically disadvantaged groups, in collaboration with affected communities and CO₂ utilization project developers and can consider compensation for those communities negatively impacted by the project or choose not to invest in the project if there are unavoidable and unacceptable equity implications (NASEM 2023a). Section 4.4 in Chapter 4 provides more information about considerations for selecting and siting projects with community input.

10.5 CONCLUSIONS

Building on the committee’s first report, this chapter provides an update on existing CO₂ utilization infrastructure and considers economic, climate, environmental, health, safety, and environmental justice impacts of further CO₂ utilization infrastructure development. Government and private sector investments in carbon management infrastructure continue to increase, notably through DOE’s Regional Direct Air Capture Hubs and Regional Clean Hydrogen Hubs and private development of CO₂ pipelines and CCS hubs. Nonetheless, for CO₂ capture, transport, storage, and utilization infrastructure, as well as for the enabling infrastructure of clean electricity and clean

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⁸ For example, the European Union requires that greenhouse gas (GHG) emissions savings for recycled carbon fuels (including CO₂-derived fuels) be at least 70 percent compared to a fossil-carbon-based fuel and notes that “capturing of emissions from nonsustainable fuels should not be considered as avoiding emissions indefinitely when determining the greenhouse gas emissions savings from the use of renewable liquid and gaseous transport fuels of nonbiological origin and recycled carbon fuels” (European Commission 2023).

⁹ As described in the committee’s first report, “The combustion of a hydrocarbon fuel yields the lower heating value of energy release and the associated CO₂ emissions. If renewable energy is used to capture the emitted CO₂ and convert it back into a hydrocarbon fuel, and then the fuel is combusted again, the same net emissions result but with twice the energy output. However, that 50 percent reduction in CO₂ footprint assumes that capture and conversion are 100 percent efficient, so in reality, the CO₂ footprint will be reduced by less than 50 percent compared to the ‘no recycling’ case” (NASEM 2023a, p. 132).

hydrogen generation, there are significant gaps between the current and announced capacity and the projected needs to meet midcentury net-zero targets.

Development of infrastructure to transport CO₂, H₂, and CO₂-derived products could be the limiting factor in scaling up CO₂ utilization given the significant costs, long lead times, and public concern. There may be opportunities to retrofit existing pipeline infrastructure to transport CO₂, H₂, or CO₂-derived products, but these determinations will have to be made on a case-by-case basis, as such retrofitting can be technically challenging and costly. Furthermore, additional research is needed to understand and mitigate risks with H₂ and CO₂ transport. This includes, for CO₂ pipelines, development of mathematical models and realistic-scale experiments to analyze issues with propagating brittle and ductile fractures and to examine CO₂ dispersion following accidental rupture of buried CO₂ pipelines that results in formation of a crater owing to the high-momentum CO₂ jet. For H₂ pipelines, safety concerns requiring attention include H₂ embrittlement and its propensity to leak.

Deployment of CO₂ utilization technologies can be facilitated by integrated infrastructure planning and development that balances cost, safety, and environmental impacts and prioritizes public engagement. Use of mathematical models to optimize multimodal CO₂ transportation networks, development of shared CO₂ pipelines for utilization and storage, establishment of public–private partnerships to facilitate resource sharing, and close coordination between developers of CO₂ capture, transport, utilization, and storage projects may accelerate the build-out of CO₂ utilization infrastructure. At the same time, the impacts of CO₂ utilization infrastructure development on pollutant emissions, human health and safety, and local communities must be taken into account. Clear, durable government policies are needed to facilitate long-term investment decisions by industry that meet these societal needs, align with net-zero objectives, and avoid stranded assets.

10.5.1 Findings and Recommendations

Finding 10-1: CO₂ utilization infrastructure development for midcentury net-zero targets—Although infrastructure to support CO₂ utilization (e.g., for CO₂ capture, transport, and storage, and generation of clean electricity and clean hydrogen) is expanding, the existing and announced capacities are not on track to meet the projected needs for achieving midcentury net-zero emissions targets. In cases where CO₂ utilization provides a competitive option to achieve net zero, CO₂ infrastructure development would require substantial amounts of capital investment—for example, across the carbon management value chain encompassing CO₂ capture, transport, utilization, and storage, the Department of Energy estimates upward of $300 billion–$600 billion through 2050.

Finding 10-2: Expansion of CO₂ pipeline infrastructure—The successful large-scale build-out of CO₂ capture and storage would require a significant increase in the current stock of CO₂ pipelines. Such pipelines could also enable CO₂ utilization projects. A main challenge to expanding this infrastructure is recent public concerns regarding CO₂ pipeline safety and siting for host communities. Opposition to pipelines is also seen by some groups as a means to block the development of CO₂ capture, utilization, and storage projects, which they consider a moral hazard that could perpetuate use of fossil fuels.

Recommendation 10-1: Enhance public engagement on CO₂ pipeline safety—In updating its safety standards for CO₂ pipelines, the Pipeline and Hazardous Materials Safety Administration should highlight the importance of proactively addressing public concerns regarding pipeline safety at the earliest opportunity through open forum consultations as part of the process for obtaining planning consent.

Finding 10-3: CO₂ utilization as a decarbonization option for small- to medium-scale emitters—Small- to medium-scale CO₂ emitters, estimated to number around 7000, are distributed throughout the United States and collectively contribute a significant amount (approximately 33 percent) of overall U.S. emissions. Given the unique challenges of small- to medium-scale emitters compared to large emitters, dedicated strategies for their decarbonization will need to be developed. In addition to other decarbonization approaches, like electrification and improvements in energy efficiency, such strategies could involve CO₂ capture and utilization using modular technologies that can accommodate smaller amounts of CO₂ to match the emissions of the facility.

Recommendation 10-2: Evaluate CO₂ capture and utilization for small- to medium-scale emitters—Small-to medium-scale emitters that cannot eliminate emissions through energy efficiency, electrification, and

other decarbonization strategies should evaluate the economic feasibility of performing CO₂ capture and utilization on site. This may involve deploying renewable electricity generation, clean hydrogen production, modular carbon capture technologies, and utilization processes suited to small-scale conversion. In cases where this is not possible, taking account of their emissions rates and geographical location, such emitters should seek multimodal transport solutions for the CO₂ and, if relevant, CO₂-derived product, striking a balance between cost, safety, and environmental impacts using established methodologies that also have been proposed for hydrogen delivery infrastructure development. Additionally, as recommended in this committee’s first report (Recommendation 4.2), the Department of Energy should develop dedicated methodologies for optimizing multimodal CO₂ transport to assist in these infrastructure planning efforts.

Finding 10-4: Shared CO₂ pipelines for utilization and storage—The development of shared CO₂ pipeline transportation infrastructure for utilization and storage with the flexibility of seamless switching between the two modes of application can significantly reduce infrastructure costs and environmental impacts. Such configurations are already being implemented in several carbon capture, utilization, and storage projects in Europe.

Recommendation 10-3: Support dual use of CO₂ pipelines for utilization and storage—Congress should direct the Department of Transportation to develop policies and regulations that support the dual use of CO₂ pipelines for both CO₂ sequestration and utilization.

Finding 10-5: Deployment of carbon capture on industrial facilities—Current industrial processes were designed without consideration of carbon capture, often leading to the need to capture CO₂ from multiple points in the process, or at low concentrations or pressures, which drives up the cost of carbon capture. Future commercial deployments that redesign and reconfigure processes to improve efficiency of heat integration and CO₂ capture (e.g., oxy-fuel combustion) could reduce CO₂ capture costs.

Finding 10-6: Hydrogen transport to support CO₂ utilization—Given the unique hazard profile of hydrogen, further research and development is needed before pressurized pipelines could play a major role as part of the hydrogen transport infrastructure for making chemicals, direct use as a fuel, or use as a CO₂ utilization feedstock. If such pipelines are developed, they could supply hydrogen to CO₂ utilization facilities. Examples of such planned dual purpose hydrogen pipeline transport infrastructure have already been approved in Europe.

Recommendation 10-4: Support flexible offtake agreements for hydrogen to facilitate CO₂ utilization—Congress should direct the Department of Transportation and Department of Energy to develop policies and regulations that would support flexible hydrogen pipeline offtake agreements to facilitate CO₂ utilization where co-location with hydrogen generation is impractical, thus avoiding the need to build dedicated hydrogen transport infrastructure for distributed CO₂ utilization.

Finding 10-7: Development of transportation infrastructure may limit the scale up of CO₂ utilization—Transportation infrastructure—for CO₂, hydrogen, CO₂-derived products, and other enabling inputs—may be the limiting factor in the scale up of the CO₂ utilization industry and consequently impact siting opportunities for CO₂ capture and utilization facilities. In particular, in the event of limited build-out of CO₂ pipelines, given cost, environmental, and safety considerations, opportunities for CO₂ utilization that do not require significant CO₂ transport infrastructure, such as distributed, onsite conversion of captured CO₂, would be favored.

Finding 10-8: Partnerships and coordination to accelerate build-out of CO₂ infrastructure—Establishing public–private partnerships could accelerate the build-out of a shared regional or national CO₂ transportation infrastructure network as a public good to achieve economies of scale for CO₂ capture, utilization, and storage. Close communication and coordination between developers of CO₂ capture, transport, utilization, and storage projects is necessary to develop such a regional- or national-scale network because of different costs, risks, and technical requirements across the value chain.

Finding 10-9: Modeling and experimentation needs to improve CO₂ pipeline safety—Relatively accurate computer simulations are already available for modeling the dispersion behavior of CO₂ following accidental releases. However, in the case of failure of buried CO₂ pipelines resulting in the formation of a crater owing to the high-momentum jet, more research is needed to model the subsequent dispersion behavior of the CO₂ plume exiting the crater. Preliminary evidence suggests that in such cases, the minimum safety distance is increased. A further issue related to CO₂ pipeline safety is the risk of propagating ductile and brittle fractures. Here rigorous mathematical models validated using realistic-scale test facilities are needed to determine pipeline susceptibility to such types of failure and hence enable the selection of pipeline materials with sufficient mechanical strength to avoid them.

Recommendation 10-5: Fund research on modeling and testing aimed at improving CO₂ pipeline safety—The Pipeline and Hazardous Materials Safety Administration should collaborate with national laboratories, university researchers, industry, and international partners to co-fund and implement research to develop rigorous mathematical models, which in turn should be extensively validated using realistic-scale experiments, to

1. Simulate the fluid/structure interaction and subsequent atmospheric dispersion of the escaping overground CO₂ plume following accidental rupture of buried CO₂ pipelines that results in the formation of a crater owing to the high-momentum jet impingement in order to determine minimum safe distances to populated areas and emergency response planning.
2. Understand and mitigate issues with propagating brittle and ductile fractures in CO₂ pipelines, as described in detail in Recommendation 4.3 of the committee’s first report, in order to select pipeline materials capable of resisting such types of failures.
3. Implement the validated mathematical models developed in (a) and (b) into robust and easy-to-use computer programs to be routinely used as a design and decision-making tool for pipeline developers in order to reduce and mitigate the risks associated with pipeline failures to as low as reasonably practicable.

Finding 10-10: Use of fossil CO₂ for short-lived products in the near, mid-, and long term—Production of short-lived products from fossil CO₂ rather than direct air capture (DAC) CO₂ could provide greater emissions reductions per dollar investment during the near- to mid-term decarbonization transition (i.e., a lower levelized cost of CO₂ abatement). However, in a net-zero future, short-lived products like fuels will need to be produced from biogenic, DAC, or direct ocean capture CO₂ sources. Current science, policy, and public opinion favor use of nonfossil CO₂ for products in which CO₂ is not permanently sequestered, placing investment risk on the development of a CO₂-to-fuels plant using fossil point source CO₂.

Recommendation 10-6: Establish durable policies to facilitate long-term decisions by industry—To facilitate long-term investment decisions by industry that are aligned with net-zero goals and that avoid stranded assets, Congress should establish clear, durable policies and direct federal agencies to develop metrics for the use of different CO₂ sources in the production of short- and long-lived products, the incentives available for enabling technologies like clean electricity and clean hydrogen, and the methodologies used to determine compliance with regulations and incentives.

10.5.2 Research Agenda for CO₂ Utilization Infrastructure

Table 10-5 presents the committee’s research agenda for CO₂ utilization infrastructure, including research needs (numbered by chapter), and related research agenda recommendations (a subset of research-related recommendations from the chapter). The table includes the relevant funding agencies or other actors; whether the need is for basic research, applied research, technology demonstration, or enabling technologies and processes for CO₂ utilization; the research theme(s) that the research need falls into; the relevant research area and product class covered by the research need; whether the relevant product(s) are long- or short-lived; and the source of the research need (chapter section, finding, or recommendation). The committee’s full research agenda can be found in Chapter 11.

TABLE 10-5 Research Agenda for CO₂ Utilization Infrastructure

NOTE: FECM = Office of Fossil Energy and Carbon Management; PHMSA = Pipeline and Hazardous Materials Safety Administration.

10.6 REFERENCES