Pipelines for Carbon Dioxide Control in the United States
Carbon capture and storage (CCS) is of great interest because potentially large amounts of carbon dioxide (CO2) emitted from the industrial burning of fossil fuels in the United States could be suitable for sequestration. Carbon capture technologies can potentially remove 80%-95% of CO2 emitted from an electric power plant or other industrial source. Power plants are the most likely initial candidates for CCS because they are predominantly large, single-point sources, and they contribute approximately one-third of U.S. CO2 emissions from fossil fuels.
Note: This article contains information that was originally published in the Congressional Research Service reports Pipelines for Carbon Dioxide (CO2) Control: Network Needs and Cost Uncertainties (January 10, 2008) by Paul W. Parfomak and Peter Folger and Carbon Dioxide (CO2) Pipelines for CarbonSequestration: Emerging Policy Issues (July 31, 2009) by Paul W. Parfomak, Peter Folger, and Adam Vann. Topic editors and authors for the Encyclopedia of Earth may have edited its content or added new information. The use of information from the Congressional Research Service should not be construed as support for or endorsement by that organization for any new information added by EoE personnel, or for any editing of the original content.
There are many technological approaches to CCS. However, one common requirement for nearly all large-scale CCS schemes is a system for transporting CO2 from capture sites (e.g., power plants) to storage sites (e.g., underground reservoirs). Transporting captured CO2 in relatively limited quantities is possible by truck, rail, and ship, but moving the enormous quantities of CO2 implied by a widespread implementation of CCS technologies would likely require a dedicated interstate pipeline network.
As CO2 pipelines get longer, the state-by-state siting approval process may become complex and protracted, and may face public opposition. Because CO2 pipeline requirements in a CCS scheme are driven by the relative locations of CO2 sources and sequestration sites, identification and validation of such sites must explicitly account for CO2 pipeline costs if the economics of those sites are to be fully understood. Since transporting CO2 to distant locations can impose significant additional costs to a facility’s carbon control infrastructure, facility owners may seek regulatory approval for as many sequestration sites as possible and near to as many facilities as possible. If CCS moves to widespread implementation, government agencies and private companies may face challenges in identifying, permitting, developing, and monitoring the large number of localized sequestration reservoirs that may be proposed. However, even as viable sequestration reservoirs are being identified, it is unclear which CO2 source facilities will have access to them, under what time frame, and under what conditions. Given the potential size of a national CO2 pipelines network, many billions of dollars of capital investment may be affected by policy decisions made today.
Carbon sequestration policies are inextricably tied to the function and availability of the necessary technologies. Consequently, discussion of CCS policy alternatives benefits from a basic understanding of the physical processes involved, and relevant experience with existing
infrastructure. This section provides a basic overview of carbon sequestration processes overall, as well as specific U.S. experience with CO2 pipelines.
Carbon Capture and Sequestration
Carbon capture and sequestration is essentially a three-part process involving a CO2 source facility, a long-term CO2 storage site, and an intermediate mode of CO2 transportation.
The first step in direct sequestration is to produce a concentrated stream of CO2 for transport and storage. Currently, three main approaches are available to capture CO2 from large-scale industrial facilities or power plants:
- pre-combustion, which separates CO2 from fuels by combining them with air and/or steam to produce hydrogen for combustion and CO2 for storage,
- post-combustion, which extracts CO2 from flue gases following combustion of fossil fuels or biomass, and
- oxyfuel combustion, which uses oxygen instead of air for combustion, producing flue gases that consist mostly of CO2 and water from which the CO2 is separated.
These approaches vary in terms of process technology and maturity, but all yield a stream of extracted CO2 which may then be compressed to increase its density and make it easier (and cheaper) to transport. Although technologies to separate and compress CO2 are commercially available, they have not been applied to large-scale CO2 capture from power plants for the purpose of long-term storage
Pipelines are the most common method for transporting large quantities of CO2 over long distances. CO2 pipelines are operated at ambient temperature and high pressure, with primary compressor stations located where the CO2 is injected and booster compressors located as needed further along the pipeline. In overall construction, CO2 pipelines are similar to natural gas pipelines, requiring the same attention to design, monitoring for leaks, and protection against overpressure, especially in populated areas. Many analysts consider CO2 pipeline technology to be mature, stemming from its use since the 1970s for Enhansed Oil Recovery (EOR) and in other industries.
Sequestration in Geological Formations
In most CCS approaches, CO2 would be transported by pipeline to a porous rock formation that holds (or previously held) fluids where the CO2 would be injected underground. By injecting CO2 at depths greater than 800 meters in a typical reservoir, pressure keeps the injected CO2 in a supercritical state and thus less likely to migrate out of the geological formation. Injecting CO2 into such formations uses existing technologies developed primarily for oil and natural gas production which potentially could be adapted for long-term storage and monitoring of CO2.
Other underground injection applications in practice today, such as natural gas storage, deep injection of liquid wastes, and subsurface disposal of oil-field brines, also provide potential technologies and experience for sequestering CO2. Three main types of geological formations are being considered for carbon sequestration:
- oil and gas reservoirs;
- deep saline reservoirs; and,
- unmineable coal seams.
The overall capacity for CO2 storage in such formations is potentially huge if all the sedimentary basins (large depressions in the Earth’s surface filled with sediments and fluids) in the world are considered. The suitability of any particular site, however, depends on many factors, including proximity to CO2 sources and other reservoir-specific qualities like porosity, permeability, and potential for leakage. Marine transportation may also be feasible when CO2 needs to be transported over long distances or overseas; however, many manmade CO2 sources are located far from navigable waterways, so such a scheme would still likely require pipeline construction between CO2 sources and port terminals. Rail cars and trucks can also transport CO2, but these modes would be logistically impractical for large-scale CCS operations.
Existing U.S. CO2 Pipelines
The oldest long-distance CO2 pipeline in the United States is the 225 kilometer Canyon Reef Carriers Pipeline (in Texas), which began service in 1972 for EOR in regional oil fields. Other large CO2 pipelines constructed since then, mostly in the Western United States, have expanded the CO2 pipeline network for EOR. These pipelines carry CO2 from naturally occurring underground reservoirs, natural gas processing facilities, ammonia manufacturing plants, and a large coal gasification project to oil fields. Additional pipelines may carry CO2 from other manmade sources to supply a range of industrial applications. Altogether, approximately 5,800 kilometers (3,600 miles) of CO2 pipeline operate today in the United States.
The locations of the major U.S. CO2 pipelines are shown below. By comparison, nearly 800,000 kilometers (500,000 miles) of natural gas and hazardous liquid transmission pipelines crisscross the United States.
Major CO2 Pipelines in the United States. Sources: Denbury Resources Inc., “EOR: The Economic Alternative for CCS,” Slide presentation (October 2007). U.S. Dept. of Transportation, National Pipeline Mapping System, Official use only. (July 2009).
CO2 Pipeline Requirements for Carbon Capture and Storage
The Department of Energy estimates that the United States has enough capacity to store CO2 for tens to hundreds of years. However, the large-scale CO2 experiments needed to acquire detailed data about potential sequestration reservoirs have only just begun.
Although any widespread CCS scheme in the United States would likely require dedicated CO2 pipelines, there is considerable uncertainty about the size and configuration of the pipeline network required. This uncertainty stems, in part, from uncertainty about the suitability of geological formations to sequester captured CO2 and the proximity of suitable formations to specific sources.
If CO2 can be sequestered near where it is produced then CO2 pipelines might evolve in a decentralized way, with individual facilities developing direct pipeline connections to nearby sequestration sites largely independent of other companies’ pipelines. The resulting network might then consist of many relatively short and unconnected pipelines with a small number of longer pipelines for facilities with no sequestration sites nearby. Alternatively, if only very large, centralized sequestration sites are permitted, the result might be a network of interconnected long distance pipelines, perhaps including high-capacity trunk lines serving a multitude of feeder pipelines from individual facilities. A third scenario envisions CO2 sequestration, at least initially, at active oil fields where injection of CO2 may be profitably employed for enhanced oil recovery (EOR).
One analysis concludes that 77% of the total annual CO2 captured from the major North American sources may be stored in reservoirs directly underlying these sources, and that an additional 18% may be stored within 100 miles of additional sources. If this were the case, the need for new CO2 pipelines would be limited to onsite transportation and a relatively small number of long-distance pipelines (only a subset of which might need to be interstate pipelines).
Other analysts have suggested that captured CO2 may need to be sequestered, at least initially, in more centralized reservoirs to reduce potential risks associated with CO2 leaks. They suggest that, given current uncertainty about the suitability of various on-site geological formations for long-term CO2 storage, certain specific types of formations (e.g., deep saline aquifers) may be preferred as CO2 repositories because they have adequate capacity and are most likely to retain sequestered CO2 indefinitely.
Others suggest that scale economies in seqestration site acquisition, validation, development, or monitoring may drive the choice of large, centralized sequestration sites. There are also significant scale economies for large, integrated CO2 pipeline networks that link many sources together rather than single, dedicated pipelines between individual sources and storage reservoirs. As geologic formations are characterized in more detail and suitable repositories identified, CO2 sources can be mapped against storage sites with increasing certainty.
The current uncertainty over proximity of sources to storage sites, however, implies a wide range of possible pipeline configurations and a wide range of possible costs. Whether CCS policies ultimately lead to centralized or decentralized storage configurations remains to be seen; however, pipeline requirements and storage configurations are closely related. A 2007 study at the Massachusetts Institute of Technology (MIT) concluded that “the majority of coal-fired power plants are situated in regions where there are high expectations of having CO2 sequestration sites nearby.” In these cases, the MIT study estimated the cost of CO2 transport and injection to be less than 20% of total CCS costs. However, the study also stated that the costs of CO2 pipelines are highly non-linear with respect to the quantity transported, and highly variable due to “physical ... and political considerations.” Another 2007 study, at Duke University, concluded that “geologic sequestration is not economically or technically feasible within North Carolina,” but “may be viable if the captured CO2 is piped out of North Carolina and stored elsewhere.”23 More recent studies continue to suggest a range of possible scenarios for CO2 pipeline development.
Case Study: Hypothetical CO2 Pipelines in the U.S. Midwest
Infrastructure requirements and policy implications related to CO2 pipelines become clearer when considering what actual pipeline projects might look like. This section outlines contrasting scenarios for hypothetical CO2 pipeline development in the region covered by the Midwest Regional Carbon Sequestration Partnership (MRCSP). The MRCSP is one of seven regional partnerships of state agencies, universities, private companies, and non-governmental organizations established by the Department of Energy to assess CCS approaches. The MRCSP serves as a good illustration of CO2 pipeline issues because it has a varied mix of CO2 sources and potential geologic sequestration sites, and because geologists have completed a number of focused studies relevant to CCS in this region.
Sequestration in the Rose Run Formation
The MRCSP has identified key CO2 sources and geologic formations potentially suitable for carbon sequestration within its seven-state region encompassing northeast Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, and West Virginia. Figure 1 shows the locations of 11 of the largest CO2 sources located in the MRSCP region — all coal-fired electric power plants emitting over 9 million metric tons of CO2 annually.There are numerous other CO2 sources in this region, including many other power plants and large industrial facilities, but the 11 power plants in this analysis include the very largest in terms of annual CO2 emissions.
Figure 1 also shows the locations of the Rose Run sandstone, a deep saline formation identified by the MRCSP as a potential carbon sequestration site. As the figure shows, the plants all lie above or near to this formation, so suitable CO2 injection sites presumably could be located very near to each of these plants. If the Rose Run formation proves to be viable for large-scale CO2 sequestration, then some plants may be able to inject CO2 directly below their facilities, and CCS pipeline requirements for some of the other 11 power plants could be small. If this were the case, then the CCS CO2 pipeline network for the 11 plants might appear as shown in Figure 2.
The hypothetical pipeline layout in Figure 2 assumes that a 25-mile diameter, non-overlapping reserve area is needed for each plant’s sequestration site and that any location within the Rose Run formation is viable for sequestration. Figure 2 also assumes that each power plant is either located at or is connected to the center of its respective sequestration field by a large trunk pipeline built along existing rights of way and capable of carrying its peak CO2 output. Smaller pipelines branching from the centrally-located plant or from the trunk line distribute the CO2 to multiple injection wells in the sequestration site. These smaller pipelines are not considered in detail in this report.
Figure 2 shows that the longest trunk pipeline for CO2 transportation is 32 miles long, and the average pipeline is approximately 11 miles long. According to models developed at Carnegie Mellon University (CMU), the capital costs to construct an 11-mile pipeline in the Midwestern United States with a capacity of 10 million tons of CO2 annually would be approximately $6 million. The levelized cost would be approximately $0.10 per ton of transported CO2, including costs for operation (e.g., compression) and maintenance.
Potential Barriers to Rose Run Sequestration. Although the Rose Run formation is identified by the MRCSP as a major potential sequestration site, it has characteristics which may ultimately limit its viability for large-scale CO2 sequestration. The most important of these is overall sequestration capacity. Because the Rose Run formation has low to moderate permeability and thickness, geologic models show that it is unlikely all of the CO2 emitted in the Rose Run region can be efficiently sequestered in the Rose Run formation. The Rose Run formation is also relatively fractured. Geologists have concluded that injecting pressurized CO2 into the Rose Run formation potentially could induce minor earthquakes along certain preexisting (but undetected) faults in otherwise seismically stable areas. Faults and fractures can, in some cases, provide additional sequestration capacity and be beneficial for sequestration. But faults or fractures can also be permeable conduits for leakage and “can be a significant pathway for the loss of sequestered CO2.” While studies are not yet available to establish the validity of any of these concerns, future research may conclude that significant parts of the Rose Run formation would be unsuitable for large scale, permanent CO2 sequestration.
Alternatives to CO2 Sequestration in Rose Run
The CO2 sequestration capacity of the Rose Run formation may turn out to be too limited because of its of overall size or integrity. If the policy goal is to sequester CO2 from all major sources in the region, then at least some of the largest power plants in the MRCSP will need to sequester their carbon emissions elsewhere. The alternative sites for potential CO2 sequestration nearest to Rose Run are unmineable coal beds, oil and natural gas fields, and another large saline formation — the Mount Simon sandstone.
Unmineable Coal Beds. The MRCSP region contains unmineable coal beds underlying the same general geographic footprint as the Rose Run formation, but located at different depths underground. Studies suggest that such coal beds may be suitable for sequestration. In some cases injected CO2 could replace methane trapped in the coal seam, increasing natural gas available for extraction wells in a process similar to EOR known as enhanced coal-bed methane recovery. However, the potential capacity for storing CO2 in regional coal beds is only about 5% compared to the Rose Run sandstone, and the practicability of storing CO2 in coal seams is virtually untested. In addition, removing groundwater from coal seams prior to CO2 injection may create environmental problems related to water disposal, and some studies indicate that coal swelling associated with CO2 injection may curtail the permeability of the coal seam, limiting its overall capacity to store CO2.
Oil and Natural Gas Fields. The MRCSP region includes a number of oil and natural gas fields which may offer opportunities for CO2 sequestration. The region also includes a number of natural gas storage reservoirs, both natural and human-made, which suggest that CO2 could be similarly stored. However, according to the MRCSP, the ten largest oil and gas fields in the region have an average CO2 sequestration potential of only 251 million tons. By comparison, the 30-year CO2 output of the 11 plants in this analysis would range from 270 to 491 million tons at current emission levels. The oil and gas fields in the MRCSP region, therefore, even if they could achieve their stated sequestration potential, may not individually have sufficient capacity to sequester CO2 from one of the 11 power plants in this analysis operating with current emissions over a 30-year period. Multiple fields possibly could be used by individual power plants to achieve adequate long-term sequestration, but this would require multiple pipeline networks and, consequently, could increase CO2 transportation costs and complexity.
Oil and gas production fields also present CO2 sequestration challenges due to numerous boreholes from historical well-drilling activity. Geologists are concerned that old oil and gas wells may be inadequately sealed and that their locations may be uncertain. Increased leakage risks from old wells, as well as associated mitigation and monitoring costs, may reduce the economic CCS sequestration potential in oil or gas fields. Although revenues from CO2 sales for EOR projects could offset CO2 transportation and sequestration costs for some source facilities, long-term CO2 emissions in the MRCSP region would far exceed CO2 requirements for EOR. It is possible, therefore, that because of their limited sequestration capacity and wellbore leakage concerns, oil and natural gas fields in the MRCSP region may not be viable sequestration sites for the largest CO2 sources either.
Mt. Simon Formation. If neither the Rose Run formation nor regional coal, oil, or gas fields can provide adequate CO2 sequestration for the major power plants in the MRCSP region, the next best potential CO2 sequestration site is the Mt. Simon formation. This formation is a deep saline aquifer like the Rose Run formation, but it is over four times larger in terms of sequestration capacity and is less fractured.
Figure 3 shows hypothetical CO2 pipelines which might be required if any of the major power plants in this analysis were required to transport CO2 to the Mount Simon formation. As in the Rose Run case, Figure 3 assumes pipelines use existing rights of way and that a 25-mile diameter, non-overlapping reserve area is needed for each plant’s sequestration site. However, consistent with the Rose Run limitations, the Mt. Simon scenario assumes that the thinnest parts of the formation (the easternmost contours on the contour map) are unsuitable sequestration sites. As the figure shows, the pipelines required in such a scenario could be substantial, ranging in length from 130 to 294 miles, and averaging 234 miles. According to estimates from CMU, the approximate capital costs for these pipelines would range from $70 million to $180 million, and would average $150 million. The average levelized cost would be approximately $2.00 per ton of transported CO2.
Although Figure 3 shows a pipeline route for all the 11 power plants in question, how many of these pipelines might be needed depends upon which plants may be able to sequester their CO2 emissions closer to home. Furthermore, there are potential scale economies for large, integrated CO2 pipeline networks that link many sources together rather than single, dedicated pipelines between individual sources and sequestration reservoirs. The individual pipelines required in Figure 3 may be so large on their own that combining multiple CO2 flows from multiple plants through shared trunk lines may be limited.
While the Mt. Simon scenario in Figure 3 is far less favorable in terms of cost and siting requirements than the Rose Run scenario in Figure 2, it is not necessarily the “worst” case in terms of overall pipeline requirements. Future work on sequestration capacity may conclude that the Mt. Simon sequestration sites should be located in thicker parts of the formation (in central Indiana and Michigan) to absorb the tremendous volumes of CO2 generated by these power plants. Such a westward shift would require even longer pipelines than those illustrated here.
Economic regulation of interstate pipelines by the federal government is generally intended to ensure pipelines fulfill common carrier obligations by charging reasonable rates; providing rates and services to all upon reasonable request; not unfairly discriminating among shippers; establishing reasonable classifications, rules, and practices; and interchanging traffic with other pipelines or transportation modes. If interstate CO2 pipelines for carbon sequestration are ultimately to be developed, it will raise important regulatory questions in this context because federal jurisdiction over hypothetical interstate CO2 pipeline siting and rate decisions is not clear. Based on their current regulatory roles, two of the more likely candidates for jurisdiction over interstate pipelines transporting CO2 for purposes of CCS are the Federal Energy Regulatory Commission (FERC) and the Surface Transportation Board (STB). However, both agencies have at some point expressed a position that interstate CO2 pipelines are not within their purview.
If CCS technology develops to the point where interstate CO2 pipelines become more common, and if FERC and the STB continue to disclaim jurisdiction over CO2 pipelines, then the absence of federal regulation described above may pose policy challenges. In particular, with many more pipeline users and interconnections than exist today, complex common carrier issues might arise. One potential concern, for example, is whether rates should be set separately for existing pipelines carrying CO2 as a valuable commercial commodity (e.g., for EOR), versus new pipelines carrying CO2 as industrial pollution for disposal. Furthermore, if rates are not reviewed prior to pipeline construction, it might be difficult for regulators to ensure the reasonableness of CO2 pipeline rates until after the pipelines were already in service. If CO2 pipeline connections become mandatory under future regulations, such arrangements might expose pipeline users to abuses of potential market power in CO2 pipeline services, at least until rate cases could be heard. Presiding over a large number of CO2 rate cases of varying complexity in a relatively short time frame might also be administratively overwhelming for state agencies, which may have limited resources available for pipeline regulatory activities.
The cost of CO2 transportation is a function of pipeline length (among other factors), which in turn is determined by the location of sequestration sites relative to CO2 sources. The Midwest scenarios illustrate how different assumptions about sequestration site viability in the MRCSP region can lead to a 20-fold difference in CO2 pipeline lengths and, therefore, similarly large differences in capital costs. (In this regard, CO2 pipeline costs may present the cost component in integrated CCS schemes with the greatest potential variability.) At the international and national policy levels, some studies have recognized this potential variability. For example, an MIT analysis states that the costs of CO2 pipelines are highly variable due to “physical ... and political considerations.” The IPCC report likewise estimates total costs of CO2 mitigation of $31- $71 per ton of CO2 avoided for a new pulverized coal power plant, assuming CO2 pipeline transportation costs, including operations and maintenance costs, of $0 to $5 per ton. Recent increases in the global price of steel used to make line pipe could push CO2 pipeline costs above this range. At $5 per ton of transported CO2, pipeline costs account for a modest share of aggregate carbon control costs — between 7% and 16% based on the IPCC estimates. Nonetheless, if CCS technology were deployed on a national scale, overall CO2 pipeline costs could be in the billions of dollars. Minimizing these costs while achieving environmental objectives may therefore be an important public policy objective.
From the perspective of individual power plants, or other CO2 sources, highly variable costs for CO2 pipelines may have more immediate ramifications. If CO2 pipeline costs for specific regions reach hundreds, or even tens, of millions of dollars per plant, then power companies may have difficulty securing the capital financing or regulatory approval needed to construct or retrofit fossil fuel-powered plants in these regions. For example, in August 2007, the Minnesota Public Utilities Commission rejected a developer’s proposal to construct a new coal-fired power plant in the state, in large part because the associated costs of a 450-mile CO2 pipeline to an EOR site in Alberta, over $635 million, were not viewed to be in the public interest. To the extent that other, lower-cost power plant options are available, the failure of a costly project like the Minnesota plant may not be a problem. However, if other generation sources are constrained (e.g., nuclear, renewable), then the inability to construct a new fossil-fueled power plant may negatively impact the regional balance of electricity supply and demand. Higher electricity prices or reliability concerns might ensue.
Some analysts believe that CO2 pipeline costs will be moderated in the future because generating companies will construct new power plants geographically near sequestration sites. Recent network cost models suggest otherwise. On a mile-for-mile basis, these models show that electricity transmission costs (including capital, operations, maintenance, and electric line losses) generally outweigh CO2 pipeline costs in new construction. Accordingly, the least costly site for a new power plant tends to be nearer the electricity consumers (cities) rather than nearer the sequestration sites if the two are geographically separated. Analysts have therefore concluded that “a power system with significant amounts of CCS requires a very large CO2 pipeline infrastructure.”
In states where traditional rate regulation exists, construction and operation of CO2 pipelines for CCS could raise questions about cost recovery for electric utilities under state utility regulation. If, for example, a CO2 pipeline is constructed for the exclusive use of a single power plant for onsite (or nearby) CO2 sequestration, and is owned by the power plant owners, it logically could be considered an extension of the plant itself. In such cases, the CO2 pipelines could be eligible for regulated returns on the invested capital and their costs could be recovered by utilities in electricity rates. Alternatively such a CO2 pipeline could be owned by third parties and considered a non-plant asset providing a transportation service for a fee. In the latter case, the costs could still be recovered by the utility in its rates as an operating cost.
Two complications arise with respect to pipeline cost recovery. First, because utility regulation varies from state to state (e.g., some states allow for competition in electricity generation, others do not), differences among states in the economic regulation of CO2 pipelines could create economic inefficiencies and affect the attractiveness of CO2 pipelines for capital investment. Second, if CO2 transportation infrastructure is intended to evolve from shorter, stand-alone, intrastate pipelines into a network of interconnected interstate pipelines, pipeline operators wishing to link CO2 pipelines across state lines may face a regulatory environment of daunting complexity. Without a coherent system of economic regulation for CO2 pipelines, whether as a commodity, pollutant, or some other classification, developers of interstate CO2 pipelines may need to negotiate or litigate repeatedly issues such as siting, pipeline access, terms of service, and rate “pancaking” (the accumulation of transportation charges assessed by contiguous pipeline operators along a particular transportation route). It is just these kinds of issues which have complicated and impeded the integration of individual utility electric transmission systems into larger regional transmission networks.
Oil industry representatives frequently point to EOR as offering a market-based model for profitable CO2 transportation via pipeline. It should be noted, however, that much of the existing CO2 pipeline network in the United States for EOR has been established with the benefit of federal tax incentives. Although current federal tax law provides no special or targeted tax benefits specifically to CO2 pipelines, investments in CO2 pipelines do benefit from tax provisions targeted for EOR. They also benefit from accelerated depreciation rules, which apply generally to any capital investment including petroleum and natural gas (non-CO2) pipelines. For example, the Internal Revenue Code provides for a 15% income tax credit for the costs of recovering domestic oil by one of nine qualified EOR methods, including CO2 injection (I.R.C. §43). Also, extraction of naturally occurring CO2 may qualify for percentage depletion allowance under I.R.C. § 613(b)(7). Prior federal law, both tax and nontax, also provided various types of incentives for EOR which stimulated investment in CO2 pipelines. In particular, oil produced from EOR projects was exempt from oil price controls in the 1970s. Development of CO2 pipeline infrastructure in the 1980s benefitted from tax advantages to EOR oil under the crude oil windfall profits tax law, which was in effect from March 1980 to August 1988.
Although there were never incentives explicitly for CO2 pipelines under federal tax and price control regulation in the 1970s and 1980s, it is clear that CO2 pipeline infrastructure development benefitted from these regulations. In a CCS environment where some captured CO2 is a valuable commodity, but the remainder is not, establishing similar regulatory incentives for CO2 pipelines becomes complex. One initial proposal, for example, would allow seven-year accelerated depreciation for qualifying CO2 pipelines. As debate continues about the economics of CO2 capture and sequestration generally, and how the federal government can encourage CCS infrastructure investment, Congress may seek to understand the implications of CCS incentives specifically on CO2 pipeline development.
Pipeline Siting Challenges
Any company seeking to construct a CO2 pipeline must secure siting approval from the relevant regulatory authorities and must subsequently secure rights of way from landowners. There is no federal authority over CO2 pipeline siting, so it is regulated to varying degrees by the states (as is the case for oil pipelines). The state-by-state siting approval process for CO2 pipelines may be complex and protracted, and may face public opposition, especially in populated or environmentally sensitive areas. Securing rights of way along existing easements for other infrastructure (e.g., gas pipelines), as the scenarios in this report assume, may be one way to facilitate the siting of new CO2 pipelines. However, questions arise as to the right of easement holders to install CO2 pipelines, compensation for use of such easements, and whether existing easements can be sold or leased to CO2 pipeline companies. Although these siting issues may arise for any CO2 pipeline, they become more challenging as pipeline systems become larger and more interconnected, and cross state lines. If a widespread, interstate CO2 pipeline network is required to support CCS, the ability to site these pipelines may become an issue requiring new federal initiatives.
Due to potential CO2 transportation costs, individual generating plants have a strong interest in the selection of specific sequestration sites under future CCS policies. Since transporting CO2 to distant locations can impose significant additional costs to a facility’s carbon control infrastructure, facility owners may seek regulatory approval for as many sequestration sites as possible and near to as many facilities as possible. Furthermore, capacity limitations at favorably located sequestration sites (like the Rose Run formation) may lead to competition among large CO2 source facilities seeking to secure the best local sequestration sites before others do. How the development of sequestration sites will be prioritized and how competition for such sites may evolve have yet to be explored, but they may create new and significant economic differences among facilities.
Because CO2 pipeline requirements in a CCS scheme are driven by the relative locations of CO2 sources and sequestration sites, identification and validation of such sites must explicitly account for CO2 pipeline costs if the economics of those sites are to be fully understood. Proposals such as S. 2323, which would require an integrated evaluation of CO2 capture, sequestration, and transportation (Sec. 3(b)(5)), appear to promote such an approach, although the details of future sequestration site selection have yet to be established. If CCS moves from pilot projects to widespread implementation, government agencies and private companies may face challenges in identifying, permitting, developing, and monitoring the large number of localized sequestration reservoirs that may be proposed.
Advantaged and Disadvantaged Regions
Geologists have long recognized that some regions in the United States have high potential for carbon sequestration and others do not. For example, a 2007 study at Duke University concluded that “geologic sequestration is not economically or technically feasible within North Carolina,” but “may be viable if the captured CO2 is piped out of North Carolina and stored elsewhere.” Likewise, states in the Northeast, Minnesota, Wisconsin, and possibly parts of other states appear to lack geological formations with potential for large-scale sequestration of the volumes of CO2 they produce. If national CCS policies are implemented, power plants and other CO2-producing facilities in these states may face more extensive, and more costly, pipeline requirements than other states if they are to sequester their CO2. States such as North Carolina, with limited sequestration potential and a relatively high proportion of coal or natural gas in their electric generation fuel mix, may face particular challenges in this regard. The Duke study, for example, estimated it would cost $5 billion to construct an interstate pipeline network for transporting CO2 from North Carolina’s electric utilities to sequestration sites in other states.
One particular concern among some stakeholders is that high CO2 transportation costs could increase electricity prices in “sequestration-poor” regions relative to regions able to sequester CO2 more locally. For states like Massachusetts, for example, which has some of the highest electricity prices in the country and may have little sequestration potential, CO2 transportation costs could raise electricity prices even higher above the national average. Moving beyond this illustrative example to evaluate comprehensively the distribution of CO2 transportation costs across the United States is beyond the scope of this report. Nonetheless, these kinds of regional price impacts, and their implications for regional economies, may become an issue for Congress.
Commodity vs. Pollutant Classification
Under a comprehensive CCS policy, captured CO2 arguably could be classified as either a commodity or as a pollutant. CO2 used in EOR is considered to be a commodity, and is regulated as such by the states. Because captured CO2 may be sold as a valuable commodity for EOR, and may have further economic potential for enhanced recovery of coal bed methane (ECBM), some argue that all CO2 under a CCS scheme should be classified as a commodity. However, it is unlikely that the quantities of CO2 captured under a widely implemented CCS policy could all be absorbed in EOR or ECBM applications. In the long run, significant quantities of captured CO2 will have to be disposed as industrial pollution, with negative economic value. Furthermore, on April 2, 2007, the U.S. Supreme Court held that the Clean Air Act gives the U.S. Environmental Protection Agency (EPA) the authority to regulate greenhouse gas emissions, including CO2, from new motor vehicles. The court also held that EPA cannot interpose policy considerations to refuse to exercise this authority. While the specifics of EPA regulation under this ruling might be subject to agency discretion, it has implications for the regulation of CO2 emissions from stationary sources, such as power plants.
Separately, EPA has also concluded that geologic sequestration of captured CO2 through well injection meets the definition of “underground injection” in § 1421(d)(1) of the Safe Drinking Water Act (SDWA). EPA anticipates protecting underground sources of drinking water, through its authority under the SDWA, from “potential endangerment” as a result of underground injection of CO2 in anticipated CCS pilot projects. EPA’s assertion of authority under SDWA for underground injection of CO2 during CCS pilot studies may contribute to uncertainty over future classification of CO2 as a commodity or a pollutant.
Conflicting classification of captured CO2 as either a commodity or pollutant has important implications for CO2 pipeline development. For example, classifying all CO2 as a pollutant not only would contradict current state and BLM treatment of CO2 for EOR, but might also undermine an interstate commerce rationale for FERC regulation of CO2 pipelines. On the other hand, classifying all CO2 as a commodity would create other policy contradictions, for example, in regions like New England where EOR may be impracticable. Under either scenario, legislative and regulatory ambiguities would arise—especially for an integrated, interstate CO2 pipeline network carrying a mixture of “commodity” CO2 and “pollutant” CO2. Resolving these ambiguities to establish a consistent and workable CCS policy could likely be an issue for Congress.
CO2 Pipeline Safety
CO2 occurs naturally in the atmosphere, and is produced by the human body during ordinary respiration, so it is commonly perceived by the general public to be a relatively harmless gas. However, at concentrations above 10% by volume, CO2 may cause adverse health effects and at concentrations above 25% poses a significant asphyxiation hazard. Because CO2 is colorless, odorless, and heavier than air, an uncontrolled release may accumulate and remain undetected near the ground in low-lying outdoor areas, and in confined spaces such as caverns, tunnels, and basements. Exposure to CO2 gas, as for other asphyxiates, may cause rapid “circulatory insufficiency,” coma, and death. Such an event occurred in 1986 in Cameroon, when a cloud of naturally-occurring CO2 spontaneously released from Lake Nyos killed 1,800 people in nearby villages.
The Secretary of Transportation has primary authority to regulate interstate CO2 pipeline safety under the Hazardous Liquid Pipeline Act of 1979 as amended (49 U.S.C. § 601). Under the act, the Department of Transportation (DOT) regulates the design, construction, operation and maintenance, and spill response planning for CO2 pipelines (49 C.F.R. § 190, 195-199). The DOT administers pipeline regulations through the Office of Pipeline Safety (OPS) within the Pipelines and Hazardous Materials Safety Administration (PHMSA). Although CO2 is listed as a Class 2.2 (non-flammable gas) hazardous material under DOT regulations (49 C.F.R. § 172.101), the agency applies nearly the same safety requirements to CO2 pipelines as it does to pipelines carrying hazardous liquids such as crude oil, gasoline, and anhydrous ammonia (49 C.F.R. § 195).
To date, CO2 pipelines in the United States have experienced few serious accidents. According to OPS statistics, there were 31 leaks from CO2 pipelines reported from 2002 through 2008—none resulting in injuries to people. By contrast, there were 2,059 accidents causing 106 fatalities and 382 injuries related to natural gas and hazardous liquids (excluding CO2) pipelines during the same period. It is difficult to draw firm conclusions from these accident data, because CO2 pipelines account for less than 1% of total natural gas and hazardous liquids pipelines, and CO2 pipelines currently run primarily through remote areas. Based on the limited sample of CO2 incidents, analysts conclude that, mile-for-mile, CO2 pipelines appear to be safer than the other types of pipeline regulated by OPS. Additional measures, such as adding gas odorants to CO2 to aid in leak detection, may further mitigate CO2 pipeline hazards. Nonetheless, as the number of CO2 pipelines expands, analysts suggest that “statistically, the number of incidents involving CO2 should be similar to those for natural gas transmission.” If the nation’s CO2 pipeline network expands significantly to support CCS, and if this expansion includes more pipelines near populated areas, more CO2 pipeline accidents are likely in the future.
Criminal and Civil Liability
There are no special provisions in U.S. law protecting the pipeline industry from criminal or civil liability. In fact, criminal liability has been at issue in a handful of recent pipeline incidents. For example, in 2007, BP reportedly agreed to pay Alaska $20 million in fines and restitution to resolve criminal liability for a 2006 pipeline spill at its Prudhoe Bay oilfield. In 2003, the Justice Department announced over $100 million in civil and criminal penalties against Olympic Pipeline and Shell Pipeline resolving claims from a fatal gasoline pipeline fire in Bellingham, WA, in 1999. In March 2003, emphasizing the environmental aspects of homeland security, Attorney General John Ashcroft reportedly announced a crackdown on companies failing to protect against possible terrorist attacks on storage tanks, transportation networks, industrial plants, and pipelines.
Even if no federal or state regulations are violated, CO2 pipeline operators could still face civil liability for personal injury or wrongful death in the event of an accident. In the Bellingham accident, the pipeline owner and associated defendants reportedly agreed to pay a $75 million settlement to the families of two children killed in the accident. In 2002, El Paso Corporation settled wrongful death and personal injury lawsuits stemming from a natural gas pipeline explosion near Carlsbad, NM, which killed 12 campers. Although the terms of those settlements were not disclosed, two additional lawsuits sought a total of $171 million in damages. The MIT study concluded that operational liability for CO2 pipelines, as part of an integrated CCS infrastructure, “can be managed within the framework that has been successfully used for decades by the oil and gas industries.” Nonetheless, as CCS policy evolves, Congress may seek to ensure that liability provisions for CO2 pipelines are adequate and consistent with liability provisions in place for other CO2 infrastructure.
In addition to the issues discussed above, additional policy issues related to CO2 pipelines may arise as CCS policy evolves. These may include addressing technical transportation problems related to the presence of other pollutants, such as sulfuric and carbonic acid, in CO2 pipelines. Some have also suggested the use or conversion of existing non-CO2 pipelines, such as natural gas pipelines, to transport CO2. Coordination of U.S. CO2 pipeline policies with Canada, with whom the United States shares its existing pipeline infrastructure, may also become a consideration. Finally, the potential impacts of CO2 pipeline development overseas on the global availability of construction skills and materials may arise as a key factor in CCS economics and implementation.
Policy debate about the mitigation of climate change through some scheme of carbon capture and sequestration is expanding quickly. To date, debate among legislators has been focused mostly on CO2 sources and storage sites, but CO2 pipelines are a vital connection between the two. Although CO2 transportation by pipeline is in some respects a mature technology, there are many important unanswered questions about the socially optimal configuration, regulation, and costs of a CO2 pipeline network for CCS. Furthermore, because CO2 pipelines for enhanced oil recovery (EOR) are already in use today, policy decisions affecting CO2 pipelines take on an urgency that is, perhaps, unrecognized by many. It appears, for example, that federal classification of CO2 as both a commodity (by the BLM) and as a pollutant (by the EPA) potentially could create an immediate conflict which may need to be addressed not only for the sake of future CCS implementation, but also to ensure consistency between future CCS and today’s CO2 pipeline operations.
In addition to these issues, Congress may examine how CO2 pipelines fit into the nation’s overall strategies for energy supply and environmental protection. The need for CO2 pipelines ultimately derives from the nation’s consumption of fossil fuels. Policies affecting the latter, such as energy conservation, and the development of new renewable, nuclear, or hydrogen energy resources, could substantially affect the need for and configuration of CO2 pipelines. If policy makers encourage continued consumption of fossil fuels under CCS, then the need to foster the other energy options may be diminished—and vice versa. Thus decisions about CO2 pipeline infrastructure could have consequences for a broader array of energy and environmental policies.
- ^ Intergovernmental Panel on Climate Change, Special Report: Carbon Dioxide Capture and Storage, 2005 (2005): 190. (Hereafter referred to as IPCC 2005.)
- ^ U.S. Dept. of Transportation, National Pipeline Mapping System database (July 2009).
- ^ Bureau of Transportation Statistics (BTS), National Transportation Statistics 2009 (2009), Table 1-10. This figure includes pipelines for petroleum and other hazardous liquids such as gasoline, jet fuel, diesel fuel, and propane.
- ^ R.T. Dahowski, J.J. Dooley, C.L. Davidson, S. Bachu, N. Gupta, and J. Gale, “A North American CO2 Storage Supply Curve: Key Findings and Implications for the Cost of CCS Deployment,” Proceedings of the Fourth Annual Conference on Carbon Capture and Sequestration (Alexandria, VA: May 2-5, 2005). The study addresses CO2 capture at 2,082 North American facilities including power plants, natural gas processing plants, refineries, cement kilns, and other industrial plants.
- ^ Jennie C. Stevens and Bob Van Der Zwaan, “The Case for Carbon Capture and Storage,” Issues in Science and Technology, vol. XXII, no. 1 (Fall 2005): 69-76. (See page 15 of this report for a discussion of safety issues.)
- ^ John Deutch, Ernest J. Moniz, et al., The Future of Coal. (Cambridge, MA: Massachusetts Institute of Technology: 2007): 58. (Hereafter referred to as MIT 2007.)
- ^ Ibid.
- ^ Eric Williams, Nora Greenglass, and Rebecca Ryals, “Carbon Capture, Pipeline and Storage: A Viable Option for North Carolina Utilities?” Working paper prepared by the Nicholas Institute for Environmental Policy Solutions and The Center on Global Change, Duke University (Durham, NC: March 8, 2007): 4.
- ^ See, for example: ICF Internaional, Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and Challenges, Prepared for INGAA Foundation (Washington, DC: February, 2009); Michael Murphy, “Carbon Sequestration Options In The Ohio River Valley,” Proceedings of the 42nd Annual Meeting of the Geological Society of America, North-Central Section (Evansville, IN: April 25, 2008).
- ^ Model found in: Sean T. McCoy and Edward S. Rubin, “An Engineering-Economic Model of Pipeline Transport of CO2 with Application to Carbon Capture and Storage,” International Journal of Greenhouse Gas Control, In press (November 19, 2007). Cost estimates were provided by Sean McCoy at the request of CRS.
- ^ M.D. Zoback, H. Ross, and A. Lucier, “Geomechanics and CO2 Sequestration,” GCEP Technical Report 2006, Stanford Univ., Global Climate and Energy Project (2006):11. 
- ^ U.S. Dept of Energy, Office of Fossil Energy, Carbon Sequestration Atlas of the United States and Canada, (2007):38.
- ^ Amie Lucier, Mark Zoback, Neeraj Gupta, and T. S. Ramakrishnan, “Geomechanical Aspects of CO2 Sequestration in a Deep Saline Reservoir in the Ohio River Valley Region,” Environmental Geosciences (June 2006), 13(2):85-103.
- ^ S. Julio Friedmann, Site Characterization and Selection Guidelines for Geological Carbon Sequestration, Lawrence Livermore National Laboratory, UCRL-TR-234408 (September 7, 2007); K. Prasad Saripalli, B. Peter McGrail, and Mark D. White, “Modeling the Sequestration of CO2 in Deep Geological Formations,” Proceedings of the First National Conference on Carbon Sequestration, National Energy Technology Laboratory (May 14-17, 2001):11.
- ^ For an example of such research, see: L. Chiaramonte, M. Zoback, M., S.J. Friedmann, and V. Stamp, “Seal Integrity and Feasibility of CO2 Sequestration in the Teapot Dome EOR Pilot: Geomechanical Site Characterization,” Environmental Geoscience, v. 53 (2007).
- ^ According to the DOE Carbon Sequestration Atlas (pp. 38-39), there are one billion metric tons of total potential capacity for CO2 in coal seams versus nearly 20 billion metric tons for the Rose Run sandstone.
- ^ Cui, X., R. M. Bustin, and L. Chikatamarla, “Adsorption-induced Coal Swelling and Stress: Implications for Methane Production and Acid Gas Sequestration into Coal Seams,” Journal of Geophysical Research, vol. 112, B10202 (2007).
- ^ U.S. Dept of Energy (2007):36.
- ^ IPCC 2005:215; Charles W. Zuppann, “Too Much Fun? — Tales of ‘Field Checking’ at the Indiana Geological Survey,” The PGI Geology Standard, No. 48 (April 2007): 6-9. 
- ^ U.S. Dept of Energy, (2007):38.
- ^ Sean T. McCoy and Edward S. Rubin (November 19, 2007). Cost estimates were provided by Sean McCoy at the request of CRS.
- ^ MIT 2007: 58.
- ^ Gemma Heddle, Howard Herzog, and Michael Klett, “The Economics of CO2 Storage,” MIT Laboratory for Energy and the Environment, Working Paper MIT LFEE 2003-003 RP (August 2003): 23.
- ^ MIT 2007: 58.
- ^ IPCC report: 347.
- ^ For further information about steel prices, see CRS Report RL32333, Steel: Price and Policy Issues, by Stephen Cooney.
- ^ Minnesota Public Utilities Commission, Order Resolving Procedural Issues, Disapproving Power Purchase Agreement, Requiring Further Negotiations, and Resolving to Explore the Potential for a Statewide Market for Project Power under Minn. Stat. § 216b.1694, Subd. 5, Docket No. E-6472/M-05-1993 (August 30, 2007):15; Minnesota Public Utilities Commission, Staff Briefing Papers — Appendix I, Docket No. E-6472/M-05-1993 (July 31, 2007):78. Cost estimate in 2011 U.S. dollars.
- ^ Jeffrey M. Bielicki and Daniel P. Schrag, “On the Influence of Carbon Capture and Storage on the Location of Electric Power Generation,” Harvard University, Belfer Center for Science and International Affairs, Working paper (2006).
- ^ Adam Newcomer and Jay Apt, “Implications of Generator Siting for CO2 Pipeline Infrastructure,” Carnegie Mellon Electricity Industry Center, Working Paper CEIC-07-11 (2007).
- ^ National Commission on Energy Policy, Siting Critical Energy Infrastructure: An Overview of Needs and Challenges. (Washington, DC: June 2006): 9. (Hereafter referred to as NCEP 2006.)
- ^ Partha S. Chaudhuri, Michael Murphy, and Robert E. Burns, “Commissioner Primer: Carbon Dioxide Capture and Storage” (National Regulatory Research Institute, Ohio State Univ., Columbus, OH: March 2006): 17.
- ^ For further discussion, see CRS Report RL34307, Regulation of Carbon Dioxide (CO2) Sequestration Pipelines: Jurisdictional Issues, by Adam Vann and Paul W. Parfomak.
- ^ Williams, et al., (2007): 4.
- ^ Williams, et al., (2007): 20.
- ^IOGCC 2005: 41.
- ^S.M. Frailey, R.J. Finlay, and T.S. Hickman, “CO2 Sequestration: Storage Capacity Guideline Needed,” Oil & Gas Journal (Aug. 14, 2006): 44.
- ^Massachusetts v. EPA; at http://www.supremecourtus.gov/opinions/06pdf/05-1120.pdf. For further information see CRS Report RL33776, Clean Air Issues in the 110th Congress: Climate Change, Air Quality Standards, and Oversight, by James E. McCarthy.
- ^U.S. Environmental Protection Agency, memorandum (July 5, 2006). Available at http://www.epa.gov/OGWDW/uic/pdfs/memo_wells_sequestration_7-5-06.pdf.
- ^ J. Barrie, K. Brown, P.R. Hatcher, and H.U. Schellhase, “Carbon Dioxide Pipelines: A Preliminary Review of Design and Risks,” Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies (Vancouver, Canada: Sept. 5-9, 2004): 2.
- ^ Airco, Inc., “Carbon Dioxide Gas,” Material Safety Data Sheet (Aug. 4, 1989). http://www2.siri.org/msds/f2/byd/bydjl.html
- ^ Kevin Krajick, “Defusing Africa’s Killer Lakes,” Smithsonian, v. 34, n. 6. (2003): 46—55.
- ^ PHMSA succeeds the Research and Special Programs Administration (RSPA), reorganized under P.L. 108-246, which was signed by the President on Nov. 30, 2004.
- ^ Office of Pipeline Safety (OPS), “Distribution, Transmission, and Liquid Accident and Incident Data,” (2009). Data files available at http://ops.dot.gov/stats/IA98.htm.
- ^ John Gale and John Davidson. (2004): 1322.
- ^ Barrie et al. (2004): 2.
- ^ Gale and Davidson (2004): 1321.
- ^ Chris Baltimore, “BP to Pay $373 Million to Settle Charges,” Reuters News Service, (Oct. 25, 2007).
- ^ “Shell, Olympic Socked for Pipeline Accident,” Energy Daily (Jan. 22, 2003).
^ John Heilprin, “Ashcroft Promises Increased Enforcement of Environmental Laws for Homeland Security,”
Associated Press, Washington dateline (Mar. 11, 2003).
^ Business Editors, “Olympic Pipe Line, Others Pay Out Record $75 Million in Pipeline Explosion Wrongful Death
Settlement,” Business Wire (April 10, 2002).
- ^ National Transportation Safety Board, Pipeline Accident Report, PAR-03-01. (Feb. 11, 2003).
^ El Paso Corp., Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, Form 10-Q,
Period ending June 30, 2002. (Houston, TX: 2002). The impact of these lawsuits on the company’s business is unclear,
however; the report states that “our costs and legal exposure ... will be fully covered by insurance.”
- ^ MIT 2007: 58.
- ^ An example is the Gwinville, MS-Lake St. John, LA natural gas pipeline purchased by Denbury Resources, Inc. in 2006 and converted to CO2 transportation for EOR in 2007.