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National Research Council (US) Chemical Sciences Roundtable. Carbon Management: Implications for R&D in the Chemical Sciences and Technology: A Workshop Report to the Chemical Sciences Roundtable. Washington (DC): National Academies Press (US); 2001.

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Carbon Management: Implications for R&D in the Chemical Sciences and Technology: A Workshop Report to the Chemical Sciences Roundtable.

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8Industrial Carbon Management: An Overview

David W. Keith

Carnegie Mellon University

It is possible to use fossil fuels without atmospheric emissions of CO2. I call the required technologies industrial carbon management (ICM)—defined as the linked processes of capturing the carbon content of fossil fuels while generating carbon-free energy products, such as electricity and hydrogen, and sequestering the resulting carbon dioxide. Although many of the component technologies currently exist at large scale, the idea that ICM could play a central role in our energy future is a radical break with recent thinking about energy systems and the climate problem.

This chapter aims at a synoptic view. I first introduce the core technologies required to implement ICM and describe their roots in the existing fossil fuel infrastructure. I then speculate about how these technologies might diffuse into the current infrastructures for energy distribution and use and about how the existence of viable ICM technologies might affect the overall cost of mitigating CO2 emissions. Finally, I consider the implications of ICM, first for the management of R&D in the chemical sciences and then for the broader politics of the CO2-climate problem.


The CO2-climate problem is not new. Although for many of us this topic appeared only yesterday, you may judge its age by reading a few of the beautifully written reports of the 1960s and 1970s. Restoring the Quality of Our Environment (President's Science Advisory Committee, 1965) has a chapter on CO2 and climate that demonstrates the problem in its modern form. The report first analyzes the growth of atmospheric CO2 by comparing the Keeling record of accurate concentration measurements (initiated in 1958) with estimates of global fossil fuel combustion and then makes crude estimates of future concentrations. It then combines concentration estimates with early radioactive connective models to estimate temperature change, and compares estimated changes to observed changes with consideration given to intrinsic climate variability. Finally, it speculates about possible impacts beyond temperature such as the CO2 fertilization of plant growth.

The National Academy of Sciences 1977 report on Energy and Climate serves as another demonstration of the consistency in our understanding of the climatic implications of transferring large quantities of carbon from fossil reservoirs to the atmosphere. When compared to recent Intergovernmental Panel on Climate Change (IPCC) reports, these older studies show that although there is a wealth of new science, what is really new is the growing will toward real action—and sadly an unambiguous trend to toward increasing in the length and opacity of climate assessment reports.

Are we seeing an anthropogenic climate signal yet? What signal will we see if we double or triple CO2 concentrations? These are the two crucial scientific questions. Although they are often deliberately blurred in public debate, they are sharply distinct. On the first, my answer is we cannot yet claim to have seen an unambiguous anthropogenic signal. Although we can measure the signal (the climate record) reasonably well, the crux of this so-called detection and attribution problem is our uncertainty about the climate's unforced variability over decade-to-century time scales—the climate's noise spectrum—and our uncertainty about the magnitude of natural forcing such as solar variability. Without robust understanding of the noise we can't calculate the signal-to-noise ratio very confidently and thus cannot yet answer the detection question unequivocally.

It is the second question, however, that ought to matter for policy: If we double or triple CO2, will we see a big signal? Here the answer is an unequivocal yes. With the exception of a few outspoken individuals, there is essentially no serious scientific dissent on this question.

When you move beyond the climate science to consider the impacts of climate change, the answer bifurcates again. If you ask, “will there be substantial impacts on many lightly managed ecosystems and on some human populations?” the answer is unequivocally yes. Examples include the ecosystems of the high Arctic and the inhabitants of low-lying islands.

If, however, you want to know about the net economic impacts of climate change, the answer is much less certain. Most economic modeling studies suggest that if we do nothing to abate climate change, we will suffer a loss of a few percent of global gross domestic product (GDP) by 2100 and that modest efforts at abatement are capable of reducing this loss (e.g., the benefits of abatement can outweigh the costs). Modeling our economic future on 100-year time scales is, however, an uncertain and untested art; both the costs of mitigation and the estimates of impact are highly uncertain.

When judged in gross economic terms, climate change will not be catastrophic and is in fact (arguably) minor compared to other economic uncertainties such as the rate of technological change or the evolution of the inequality in distribution of the world's wealth. Despite some overheated rhetoric, our civilization will not collapse if we fail to act aggressively to counter climate change. Humans are very robust. Nevertheless, climate change poses very serious environmental problems. If we double or triple carbon dioxide—as many business-as-usual projections suggest we will within this century—we will see substantial climate change and very substantial changes to many natural ecosystems. Many of us value these ecosystems and value the rights of human communities that will be most affected. We have shown by other actions that we are willing to pay a price to protect such values. I hope and expect that we will take strong action to stabilize CO2 concentrations. The history of pollution control technologies gives reason to hope that the price of achieving deep cuts in CO2 emissions will be lower than we predict. The topic of this meeting gives us an explicit basis for that hope.


Use of fossil fuels with minimal emissions of CO2 requires two steps. The energy content of the fuels must first be separated from their carbon content in a process that takes a fuel with high carbon-to-energy ratio as input and produces a low-or zero-carbon output along with a carbonaceous stream with low free energy to be sequestered away from the atmosphere. In practice, this generally means a system that uses coal or gas to produce electricity or hydrogen with sequestration of the resulting CO2, but other options may prove important (Figure 8.1). Separation and sequestration together comprise industrial carbon management.

FIGURE 8.1. Industrial carbon management: a schematic illustrating the definitions of sequestration and separation adopted here.


Industrial carbon management: a schematic illustrating the definitions of sequestration and separation adopted here. The output stream is labeled carbon free for simplicity; separation includes processes that take a high-carbon stream in and produce a (more...)

These technologies are not laboratory theory; on the contrary, many of the required components exist at the largest industrial scales. Among the most important such technologies are the gasification of coal, the capture of CO2 using aqueous amines, the steam reforming of methane, and finally, the longrange transport of CO2 by pipeline and its injection into geological formations. We have, in essence, a sizable basket of component parts out of which we might assemble a system for carbon management.

Although ICM makes sense only as part of a broad portfolio of greenhouse gas mitigation technologies, it may nevertheless transform the politics of the CO2-climate problem. By lowering the cost of emissions mitigation, ICM may enable stabilization of atmospheric concentrations at acceptable cost. By weakening the link between fossil energy and atmospheric CO2 emissions, ICM makes it feasible to consider a fossil-based global economy through the next century. By reducing the severity of the threat that emission reduction poses to fossil industries and fossil-rich nations, ICM may ease current dead-locks in both domestic and international abatement policy.

There are, however, no magic bullets with which to slay the CO2-climate problem. All current options—ICM included—either are impracticably expensive or involve significant environmental risks. Moreover, global energy systems are highly heterogeneous, making it implausible that any single technology will triumph everywhere. Finally, the history of energy policy is full of technologies that seemed to their advocates to be too cheap to meter, yet are now irrelevant. Thus, although I will tell you a (mostly) optimistic story about the potential role of ICM in mitigating CO2 emissions, skepticism is wise. The very fact that ICM was not on the energy policy agenda even a decade ago should make one cautious about any predictions for the next century.


There are three broad paths to separation:2

  1. Postcombustion capture (PCC): Burn the fuel in air then capture CO2 from the combustion products.
  2. Oxyfuel. Separate oxygen from air, burn the fuel in pure oxygen, and then capture CO2 from the combustion products.
  3. Precombustion decarbonization. (PCDC). Reform fuel to make hydrogen and CO2.

The first two, PCC and oxyfuel, involve complete combustion to CO2 and water and so are limited to producing electricity and heat, whereas PCDC produces hydrogen that may be combusted in an integrated system to produce electricity and heat or may be distributed for use elsewhere.

Most discussion of ICM has focused on large-scale electricity generation, where PCC is perhaps the most obvious route to separation because it is closely analogous to existing environmental control technologies, such as flue gas desulfurization, that remove pollutants from power plant exhaust streams. Amine solvents are now used to capture CO2 from power plant exhaust streams for commercial uses such as the carbonation of beverages. Using current technology, amine systems are able to capture about 90% of the CO2, but the energy cost of solvent regeneration reduces plant electrical output by about 15%. A host of other capture methods have been proposed, and there is evidence that amine technologies can be significantly improved. In comparison to other routes to separation, PCC has the great advantage that it requires little modification to existing power plants and so could in principle be applied as a retrofit; its disadvantage is that the separation is performed at atmospheric pressure on a gas stream that is only 4 to 15% CO2 and contains a multitude of reactive combustion products. From a coal-fired plant, for example, the exhaust gas is at most about 15% CO2 and contains SOx, NOx, and various metals so that a CO2 separation system must either be tolerant of impurities or the impurities must be removed. Significant opportunities exist for co-optimization of the multiple emissions control technologies that must be applied to coal-fired plants.

Instead of separating CO2 from the combustion gases, you can first separate the O2 from air and then do the combustion in pure O2, producing an exhaust stream that is CO2, H2O, and impurities from which the water can easily be removed by condensation. Compared to PCC, Oxyfuel schemes offer the advantage of doing the primary separation step on a clean gas mixture (air) that is free from the many reactive impurities in combustion gases. The leading disadvantage of Oxyfuel is the high energy and capital cost associated with oxygen production. Oxyfuel systems also offer higher combustion temperatures that yield higher Carrot efficiencies. The flame temperature from pure Oxyfuel is too high, however, so all Oxyfuel schemes must use a diluent to reduce the temperature and increase the volume of working fluid. The leading choices are direct injection of water or recycle CO2. The direct (i.e., without reforming to produce H2) use of methane in high-temperature fuel cells may be considered an Oxyfuel route to separation because an oxygen-permeable membrane is used to transport O2 to CH4 for oxidation. This analogy is particularly apt because one of the leading methods to produce O2 in combustion-based Oxyfuel schemes involves the use of air separation membranes that are closely related to the membranes used in solid oxide fuel cells.

PCDC is most obviously accomplished by steam reforming of methane followed by the water-gas shift reaction to produce a CO2-H2 mixture. Separation of CO2 from such gas streams is much easier than it is from combustion air in PCC systems because of the higher working pressures and higher fraction of CO2. As described below, this method is now used to produce hydrogen from methane at very large scale. Many other methods are possible. For methane, one can, for example, produce synthetic gas using partial oxidation instead of steam reforming. For coal, a multitude of gasification reactions are possible including, for example, H2 rather than O2-blown gasification. Even in a electric power plant, PCDC systems appear to be competitive with other methods whether the fuel is coal or natural gas. In addition, PCDC has the important advantage that a power plant could sell zero-CO2-emission hydrogen “over the fence” to support the development of a hydrogen infrastructure (Ogden, 1999).


Although much is uncertain about geological sequestration, the essence of current knowledge is easily stated: (1) it is possible to put very large volumes of CO2 underground at comparatively low cost; (2) it appears that a capacity of greater than 1,000 gigatonnes carbon (GtC) exists in reasonably well understood geological structures; and, (3) while the fate of CO2 is highly dependent on the specific geological character of the injection site, it seems highly likely that a large fraction of CO2 could be confined underground for time scales in excess of a thousand years.

As we now envision it, the CO2 would be injected into geological formations similar or identical to the formations from which we now extract oil and gas, and the technologies employed would be readily derived from current systems used in the oil and gas industry. The most likely sequestration sites and their estimated capacities are shown in Figure 8.2.

FIGURE 8.2. Carbon reservoirs and sinks.


Carbon reservoirs and sinks. The resource base (the sum of reserves and resources) is used for fossil fuels [Rogner, 1997]. The consumption box shows worldwide cumulative consumption of fossil fuels. The upper section of the atmosphere box shows the increase (more...)

While geological sequestration will build generally on the totality of experience with fossil fuel extraction, it will be most directly built on current practice of CO2 injection for enhanced oil recovery (EOR). Conventional extraction methods typically leave substantial oil in place. This oil may be extracted using EOR. Carbon dioxide injection (or “flooding” in industry jargon) is particularly effective because, as an organic solvent, the CO2 acts to reduce the viscosity of the residual oil and in addition causes the oil to expand thus helping to free it from the porous rock in which it is embedded. Typical EOR floods operate at pressures above the critical point of CO2 so that fluid flow is facilitated by the absence of a liquid-gas interface.

The use of CO2 for EOR will provide early sequestration opportunities at negative cost as EOR operations pay of order $50/tC for CO2. Most assessments suggest that absent EOR, the cost of geological sequestration will be of order $10-25/tC. At this price, the overall cost of ICM is dominated by the cost of separation. There are reasons, however, to expect that these estimates may be too optimistic and that sequestration cost will consume a rising fraction of the total cost of ICM. Costs of CO2 sequestration may be higher than predicted from the EOR experience due to the additional costs involved in monitoring and verification. Depending on our experience with CO2 injection and on the regulatory framework that is adopted (which will likely be different for current regulation of CO2 EOR) the costs of monitoring could be very high. Moreover, sequestration cost estimates have tended to assume injection into previously characterized high-permeability structures, but in the long run these will be saturated and we will have to turn to lower permeability structures and to include the full cost of subsurface characterization. Arguably this could drive sequestration costs closer to the cost of natural gas extraction (currently of the order $100/tC).

Carbon need not be sequestered as CO2; instead, it can be sequestered as a stable and immobile carbonate. The process mimics the natural weathering of magnesium and calcium silicates that ultimately react to form carbonate deposits. Integrated power plant designs have been proposed, in which a fossil fuel input would be converted to carbon-free power (electricity or hydrogen), with simultaneous reaction of the CO2 with serpentine rock (magnesium silicate) to form carbonates (Lackner et al., 1995). Carbonate formation is exothermic; thus, in principle, the reaction requires no input energy. Ample reserves of the required serpentine rocks exist at high purity. The size of the mining activities required to extract the serpentine rock and dispose of the carbonate are comparable to the mining activity needed to extract the corresponding quantity of coal. The difficulty is in devising an inexpensive and environmentally sound industrial process to perform the reaction.

The importance of geochemical sequestration lies in the permanence with which it removes CO2 from the biosphere. Unlike carbon that is sequestered in organic matter or as CO2 in geological formations, once carbonate is formed the only important route for it to return to active biogeochemical cycling is by thermal dissociation following the subjection of the carbonate-laden oceanic crust beneath the continents, a process with a time scale of more than 107 years.


The risks of large-scale underground sequestration of CO2 are poorly understood, and there has been little or no systematic effort at risk assessment. The risks may be roughly divided into two kinds: (1) the direct risks to humans and local environments, and (2) the risk of slow leaks that return the sequestered carbon to the atmosphere.

The most obvious of the direct risks is due to catastrophic release of CO2, but there are also hazards from slow leaks and possible risks stemming from underground movement of displaced fluids such as induced seismically or contamination of potable aquifers. Experts in the upstream oil and gas industry are generally confident that the risks are small, and this confidence is strongly supported by the long history of CO2 injection for EOR and of underground storage of other gases, including the very large scale storage of natural gas. Nevertheless, the basis for concern is clear. Natural gas storage facilities have leaked to the surface causing dangerous buildup of gas in buildings, and natural emissions of CO2 can pose serious risks. In 1986, for example, Lake Nyos (Cameroon) released a dense CO2-rich cloud that killed more than 1,700 people by suffocation. Here in the United States, widespread deaths of trees and one possible human fatality in the last decade have been linked to degassing of CO2 from the Long Valley Caldera in the Mammoth Lakes area, California. A very recent death (July 2000) in a naturally occurring soda springs bath at Clear Lake, California, underlines the constant danger posed by CO2 emissions from the ground.

All separation technologies extract an energy penalty so that more fuel must be consumed—and more CO2 produced—per unit of delivered energy than would be the case if the CO2 were not captured. In the worst case, therefore, if the CO2 is rapidly returned to the atmosphere, ICM can increase future concentrations of CO2. Simple modeling of underground transport suggests that lifetimes in excess of 1,000 years can readily be achieved, and evidence from natural CO2 formations suggests that retention times can be orders of magnitude longer. While there is ample reason to expect that sufficiently low leak rates can be achieved, it is not yet possible to specify with confidence the site characteristics and injection technology required to ensure (within a defined level of uncertainty) that a given leak rate will be achieved. Such knowledge will be necessary in order to devise a robust technical and institutional system for sequestering CO2.


Industrial carbon management will be built atop the existing fossil fuel infrastructure. Building an effective ICM system will require adaptation and improvement of existing technologies as well as the development of new technologies to fill the gaps. We have a box of tools that have been proved by previous experience. We could assemble these tools today, with minimum modification, to build an ICM infrastructure for the production of electricity and hydrogen, but the cost of CO2 mitigation would be relatively high, perhaps $100 to $250/tC. With the design of a few new components and careful optimization of components in integrated systems, it seems reasonable to suppose that the cost could fall substantially.

One can argue that the costs of many low-CO2-emission technologies could be reduced with a bit more R&D, so how is ICM different? The answer lies in the close connection between ICM and the existing energy infrastructure and consequently in the scale at which the enabling technologies already exist. Consider four key examples:

  1. Coal gasification. Integrated gasification combined cycle (IGCC) electric generation, a point of departure for many coal-based ICM designs, has not been adopted commercially despite decades of R&D; nevertheless, there is a large fleet of gasifiers now in operation with a worldwide syngas capacity equivalent to 50 GW thermal.
  2. Hydrogen production. Steam methane reforming to produce hydrogen now consumes almost 2% of U.S. primary energy. Leading uses for the hydrogen are the production of ammonia and the reformulation of gasoline. Some current applications involve the long-range transport of hydrogen in pipelines.
  3. EOR. In the United States about 7 MtC per year of CO2 is used for enhanced oil recovery, most of it is supplied by pipeline from natural CO2 formations. The longest pipeline runs 800 km. If the CO2 were derived from fossil fuels, it would account for about 0.5% of U.S. primary energy.
  4. CO2 capture with MEA. Monoethanolamine (MEA) solvents are used today for CO2 capture from exhaust gases in more than 10 facilities worldwide and are also widely used for striping CO2 from natural gas.

In addition to these enabling technologies, several integrated systems are important examples of nascent ICM. The first large project that sequesters CO2 to avoid emissions is in Norway, where Statoil operates one of largest gas fields in Europe in which the produced gas contains about 10% CO2, which must be reduced to 2.5% for sale to customers. The CO2 is separated on an offshore platform and injected into a high-permeability aquifer under the seabed. The offshore capture and sequestration project was developed in response to Norway's offshore carbon tax of $170/tC. Statoil has sequestered about 0.3 MtC per year of CO2 since 1996, and the transport of the sequestered CO2 is now being monitored by an international research team (Herzog et al., 2000). A similar project planned in Indonesia at the Natuna field will inject 30 MtC per year, roughly 0.5% of present global emissions.

A project using the CO2 from the Dakota Gasification plant to enhance oil recovery at Pan Canadian's Weyburn field is (arguably) the existing project that most resembles ICM. The Dakota plant has produced synthetic natural gas from coal since 1984. It is the largest facility of its kind and was a product of the Synfuels programs of the 1970s. Weyburn is a large oil field in Saskatchewan that is nearing the end of conventional production; with CO2 EOR, the amount of recoverable oil will be increased by about 30%. A 325-km pipeline now transports 0.5 MtC of CO2 per year from the gasification plant to Weyburn (Hattenback et al., 1999).

It is instructive to compare the scale of these technologies with current low-CO2-emission alternatives. Nuclear and biomass are both used at very large scale, accounting for 9% and 3% of U.S. primary energy, respectively, but solar and wind are much smaller—0.08% and 0.04% respectively (Energy Information Administration, 1998). In comparison the Dakota Weyburn project alone sequesters 0.03% of U.S. CO2 emissions, and all of the key enabling technologies listed above are in use at scales that far exceed the current scale of wind and solar.


Industrial carbon management may be used to mitigate CO2 emissions throughout most of the energy system; however, the heterogeneity of energy distribution and use means that the comparative advantage of ICM over other CO2 mitigation technologies will vary widely. Most analysis of ICM has focused on electricity generation, but ICM can also be used to produce hydrogen, enabling deep reductions in CO2 emissions via the substitution of hydrogen for natural gas or petroleum.

There are several good reasons to focus on electricity generation as an early application of ICM technologies:

  • Electric power plants are among the largest point sources of CO2.
  • New electric generating technologies can be introduced without affecting the end user (other than by changing the cost of production).
  • Most coal is used for electric generation (93% in the United States), and coal has the highest carbon-to-energy ratio of the fossil fuels.

Given existing technologies, the cost of electricity with ICM is estimated to be about 5-7 cents/kWh, about 2-3 cents/kWh more that the cost from current technologies (Herzog et al., 1997), and roughly comparable to the cost of electricity from wind, biomass, or nuclear power. Figure 8.3 illustrates the relationship between cost of electricity and intensity of CO2 emissions for various technologies. For new coal plants, the cost of reducing CO2 emission is about $100/tC. It is difficult, however, to estimate the real cost of reducing emissions from static cost comparisons because in real electric markets the introduction of ICM competes with fuel switching (coal to natural gas) and depends on the dynamics of plant dispatch. Figure 8.4 illustrates the cost of emissions reduction in a simple dynamic electric supply model.

FIGURE 8.3. The cost of electricity versus carbon intensity.


The cost of electricity versus carbon intensity. The x-axis shows CO2 emissions (in kilograms of carbon per unit of electricity generation [in gigajoules]). The y-axis shows the approximate cost of electricity from new generating units including costs (more...)

FIGURE 8.4. Carbon mitigation supply curves.


Carbon mitigation supply curves. These results are derived from the author's dynamic optimization model applied to a representative U.S. electricity market. Each point on the graph reflects the decrease in carbon emissions compared to a baseline scenario (more...)

Given open competition between electricity technologies under a carbon tax (or equivalent regulatory mechanism) and the assumption that carbon sequestration can meet environmental permitting requirements, there are significant structural reasons to expect sequestration to be adopted in preference to nonfossil alternatives even if the cost of electricity were similar. Unlike wind power and other distributed renewables, ICM plants would match the existing distribution system with respect to sizing and ease of dispatch. Moreover, ICM plants with likely be constructed with existing suppliers, and established upstream fossil energy companies (the oil majors) could provide both fuel and CO2 sequestration. While nuclear power could, in principle, play a central role in reducing CO2 emissions, absent sweeping changes in the industry, its regulators, and public perception, it seems likely that utilities would find ICM less risky.

In sharp contrast to the introduction of new electric generating technologies, the introduction of hydrogen into dispersed stationary uses requires the development of a hydrogen distribution infrastructure—a serious challenge—while the introduction of hydrogen into transportation requires the development of effective hydrogen-fueled vehicles and a refueling infrastructure—likely an even greater challenge. Yet as a means to mitigate CO2 emissions, the potential advantage of ICM over nonfossil energy sources (other than biomass) is due to the intrinsic advantages of thermochemical over electrochemical production of hydrogen. A crude comparison of energy costs serves to illustrate the point. At current prices, coal and natural gas, likely the most important fuels for ICM systems, have energy costs of roughly $1 and $3/GJ, respectively. Either feedstock can be used to generate electricity with ICM at a producer cost of $15 to $25/GJ (5-7 cents/kWh). As noted above, the cost of electricity produced from wind (absent all subsidies) arguably lies in the same range. In contrast, the price of H2 produced from wind via electrolysis would be $20 to $30/GJ, while the price of H2 produced from fossil fuels via ICM would be $4 to $7/GJ; a relative cost advantage of roughly 1:3 for ICM-hydrogen over wind-hydrogen despite the assumed equality of electricity costs. Similar disadvantages apply to the production of hydrogen from nuclear or solar power, though not from biomass. Moreover, large-scale production of hydrogen from fossil fuel and its long-range transport are already mature technologies in the petrochemical industry.

The relative ease of producing hydrogen via ICM implies that wherever hydrogen could replace oil or natural gas, the potential exists for comparatively inexpensive mitigation of CO2 emissions. Realizing this potential, however, will not be easy. Substantial technical and economic barriers will hinder the diffusion of hydrogen fuel technologies across the energy system. Technical barriers range from the comparatively straightforward problems of constructing hydrogen-capable gas distribution systems to the serious engineering challenges that stand in the way of hydrogen-powered transportation systems. The economic barriers—including both economies of scale and network effects—are no less daunting. Consider the introduction of hydrogen-capable distribution systems; even if costs were low for both the distribution system and the end-user technology, the introduction of new distribution systems will likely be slow because distribution and end-user equipment must evolve together against the economy-of-scale advantages of existing systems.

Global Models

Although we have a limited understanding of the role of ICM technologies in bringing down the cost of CO2 mitigation in the electric sector, very little is known about the influence of ICM on the overall cost of mitigating climate change. The uncertainty arises from the need to combine global economic models with models of technological change in time scales of the order of a century. Looking back 30 years at previous attempts to model the evolution of energy systems does not inspire confidence. Forecasting technological change would be difficult enough if one wanted to predict the evolution of a single technology, such as large-scale electric power generation. Predicting technological change over century time scales is still harder, however, because clusters of technologies evolve as tightly coupled systems and the evolution of the full system is highly path dependent.

Two extreme scenarios for the future of centralized electric generation serve to illustrate this path dependence. First suppose that electric power generation is rapidly decentralized, driven by the diffusion of small natural gas-fired combined heat-and-power generators—the technology that offers the most cost- effective near-term CO2 mitigation. This would initially prevent diffusion of ICM because CO2 cannot be effectively collected from distributed sources, but it would enable a later wave of decarbonization as ICM hydrogen (produced from cheap coal) competed against expensive natural gas. Alternatively, the economies of scale in large ICM electric generation might lower the relative cost of electricity—under a system-wide carbon tax—and cause acceleration of the fraction of primary energy converted to electricity at centralized facilities.

Despite the daunting challenges, several groups have used integrated assessment models (see Parson and Fisher Vanden, 1997, for a review of such models) to study the effect of ICM on the overall costs of stabilizing CO2 concentrations. These models allow one to compute the reduction in CO2 emissions resulting from imposing a price on emissions that approximates the effect of a carbon tax or similar regulatory mechanism. The models may be used to find a trajectory of carbon price over time that most efficiently stabilizes CO2 concentrations at a given level. Conventional economic models suggest that peak marginal carbon prices of order $500 to $1,000/tC will be necessary to stabilize CO2 concentrations at around 450 parts per million (ppm).4 As we have seen above, simple technology cost estimates suggest that ICM could be used to mitigate a substantial fraction of total CO2 emissions at much lower costs. The global model results in Figure 8.5 show decreases in mitigation cost of roughly a factor of two when ICM is included.

FIGURE 8.5. The effect of ICM on the global cost of stabilizing CO2 concentrations.


The effect of ICM on the global cost of stabilizing CO2 concentrations. The y-axis shows the carbon price (set by a tax or equivalent regulatory mechanism) required to keep atmospheric CO2 concentrations below about 550 ppm (twice preanthropogenic levels). (more...)


The oil crisis of the early 1970s intensified concerns that the world would soon run short of fossil fuels. Energy experts theorized that a global transition to nonfossil energy would be necessary within decades. Three decades later, although new discoveries and new recovery technologies have increased estimated fossil reserves and put to rest fears of their rapid exhaustion, concern about climate change has again led many experts to conclude that a rapid transition to nonfossil energy is required.

Part of the reason fears of oil scarcity proved exaggerated was that analysts failed to anticipate the potential for technical and managerial innovation to drive down the cost of petroleum exploration and extraction. We may have made a similar error in considering the link between fossil fuel use and climate. It has been assumed that the transfer of carbon from geologically isolated fossil reservoirs to the biosphere was a fundamental geophysical consequence of fossil energy use. Geological sequestration of CO2 negates this assumption and raises the prospect that the long history of technical mitigation of the environmental impacts of fossil fuels can be extended to the climate problem.

By weakening the link between fossil energy and CO2 emissions, carbon management makes it feasible to consider a fossil-based global economy through the next century, even in a greenhouse-constrained world. By reducing the severity of the threat that emission reduction poses to fossil industries and fossil-rich nations, carbon management may ease current political deadlocks. Stated bluntly, if carbon management is widely adopted and if existing fossil energy industries can extend their dominance into the new markets for carbon sequestration, then the increase in total energy costs will benefit industries that would otherwise lose by actions to abate emissions.

It is likely that carbon management will be a profoundly divisive issue for environmentalists. It may be opposed for at least two reasons. First, carbon management is only as good as the reservoirs in which the carbon is sequestered. If CO2 leaks out much more quickly than we expect, then we leave our descendants with the double problem of uncontrollably rising CO2 emissions and an economy still dependent on fossil energy. The history of toxic and nuclear waste disposal gives reason to be skeptical of expert claims about the longevity of underground disposal. Second, carbon management is a technical fix on a grand scale. It was first proposed as “geoengineering,” a term now shared by proposals to engineer the global climate, for example, by cooling the planet by the injection of aerosols into the stratosphere to reflect solar radiation (Keith, 2001). In addition to a reasonable distaste for technical fixes, carbon management collides with the deeply rooted assumption among many environmentalists that fossil fuels are the “problem” and that renewable energy is the “solution.” Yet, the rationale for support of carbon management is also strong. It may be that large-scale adoption of carbon management will allow the world to make aggressive CO2 emissions cuts at a politically acceptable cost.5


This research was supported by the Center for Integrated Study of the Human Dimensions of Global Change, a joint creation of the National Science Foundation (SBR-9521914) and Carnegie Mellon University with additional support from the Department of Energy, Environmental Protection Agency, National Oceanic Atmospheric Association, Electric Power Research Institute, Exxon, and Applied Precision Inc.


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Dave Cole, Oak Ridge National Laboratory: I wonder if you might elaborate on two points regarding the environmental aspect. First, elaborate a little bit on this issue of ocean sequestration and then on geologic storage of CO2. Where do the environmentalists stand on these issues?

David Keith: With a few exceptions, CO2 capture and sequestration is just are not on the radar screens of the environmental groups. But that is beginning to change. Several of the large environmental nongovernmental organizations NGOs know they need to grapple with CO2 sequestration.

Concerning ocean sequestration, Norway is now separating out the roughly 10% of CO2 that is in the gas on an off-shore platform from its largest gas field and shoving it down into a sandstone aquifer, whereas otherwise they would have been venting it. I have heard rumors that Greenpeace is going to try and get some other country to bring suit in the World Court to stop it because they believe it breaks the London Dumping Convention. I think, from my cursory reading, that Greenpeace is correct, that it does break the London Dumping Convention, because the Convention prohibits dumping industrial waste, not just in the ocean, but under the seafloor. If it's correct that Greenpeace would like to block Norwegian project, which in my view is an obvious environmental benefit, then that gives you a sense of how strongly people feel about the ocean.

I should add that not only has there been a huge Japanese research investment in oceanic sequestration, but there is a project that will run next year, funded by (I think) the Canadians, the Americans, and Japanese that will actually attempt to inject CO2 at a rate of a kilogram per second. The project will run off Hawaii and will be used to model plume formation and so on. This experiment has got environmental groups to think about, and critique the idea of ocean sequestration.

Dave Cole: Just one quick comment to follow on that. The federal government is spending a fair bit of money examining the issue of ocean sequestration in terms of the geoenvironment.

David Keith: The overall budget for CO2 mitigation is still small. As Bob Frosch said at a meeting we had at Harvard two years ago, we need to add a couple of zeros.

Dave Cole: Yes, I understand, but nonetheless, on these issues of policy and issues of environmental concern, I am concerned about the feedback between community interest or lack thereof and what really guides the research that we perform or the research that the federal government supports. There seems to be somewhat of a disconnect here.

David Keith: I couldn't agree more. I don't have any magic answer. There are more than a few disconnects both on the climate science side and on mitigation technology.

Dave Cole: The last part of my question concerns terrestrial sequestration. Are we going to encounter the same kinds of Greenpeace environmental concerns there—where people are actually within walking distance of where this stuff is being dumped?

David Keith: We just don't know because it is so early, but I think the answer is yes, but not as much for terrestrial as for oceanic CO2 sequestration. At Carnegie Mellon, we had done a preliminary open-ended elicitation of knowledge and opinions about sequestration, with about 10 non-technical members of the community. While it is not representative, we found divergent views on geological sequestration where we found strong resistance to ocean sequestration.

Several folks I have talked to in the environmental community are willing to talk seriously about geological sequestration. But it is still in its early days. There are still no attempts at systematic risk assessment, and there is little sense of how, where, under what regulatory framework, and with what incentive sequestration would actually occur. All of these factors will likely influence people's reaction to geological sequestration.

Dan DuBois, National Renewable Energy Laboratory: I am a little more supportive of renewable energy than you are, but on the issue of how much CO2 you could use, I think you are saying 0.1% or something like this. I think you misunderstand what people who worked with CO2 would really like to do. They want to use CO2 as an energy vector, much as you would use water splitting. When the CO2 community talks about making a fuel from CO2, we want to do much the same thing, only we want to make a liquid fuel. So if you have a nuclear source or a renewable energy source of electricity in the future, then you could provide not only hydrogen, which is a gaseous fuel, but also methanol a liquid—high-energy-density liquid fuels as well.

David Keith: I am quite skeptical that synthesis of fuels from CO2 with energy provided by nuclear or carbon-free renewables can ever compete. But it is clear that we need systematic analysis that would come from some of you in the chemical sciences community. You can't arbitrarily start with nuclear or solar PV energy, which costs a lot, and only think about the subsequent analysis. You have to do a real analysis, which starts with fossil-free energy at a certain price or fossil energy at a certain price.

Dan DuBois: The question is, What price are you going to use and what assumptions are you going to make? This is a problem for 50 years in the future. You are saying that economic analyses 50 years in the future are very difficult. If you say that, on what basis are you going to make this economic analysis?

David Keith: All I am saying is that we should produce some robust analyses with transparent assumptions that address both sides of the problem. You clearly see the choice between either offsetting emissions, that is, using nonfossil energy to simply displace CO2, or going to the CO2 route to make fuels. A nice study like that could realistically be done with several assumptions, and if they are clearly laid out, would be a big help to DOE managers.

Panel Discussion

John Turner, National Renewable Energy Laboratory: Let me comment first on life-cycle assessment. The National Renewable Energy Lab (NREL) is doing life-cycle assessment for all renewable energy technologies, including photovoltaic (PV), wind, hydrogen—the whole thing, cradle to grave, energy balance, materials balance, all those things. The numbers are going to be available, and they are complete in a number of different issues. I think they have also done the biomass one.

Next, in terms of renewable energy for developing countries, India is one of the largest wind users in the world now and it is growing at a very high rate. One of the reasons for this is that even though renewable energy has a high initial capital cost, it is incremental. So, you can afford small increments at a time, and this helps developing countries implement renewable energy technologies. It is particularly true of wind.

It turns out that it is also true of PV. Even in India, people can afford small PV units, which give them a few hours of light in the evening. These units typically cost four or five hundred dollars and somehow they come up with the money. So, I think renewable energy technologies for developing nations are very useful because they can put them in at small quantities and afford them that way.

David Thomas, BP-Amoco: A couple of weeks ago I participated in another National Research Council (NRC) workshop on carbon dioxide sequestration that was coming at it from the biological point of view, which is terrestrial sequestration—soil carbon and standing trees and shrubs and so on. The real question to Dave Keith and perhaps the others that are involved in renewables is, Where do you see this fitting into the idea of sequestration? Terrestrial sequestration is driven primarily by the Department of Agriculture. It was talking about five- and ten-year contracts with the farmer to, “sequester carbon in his soil or on his land.” What are your thoughts about this is the general question?

David Keith, Carnegie Mellon University: It seems increasingly clear that you can get a lot of bang for your buck for a while. What I mean by this is that it is clear that by reasonably inexpensive changes especially to agricultural practices and also to forestry, you can suck up a significant amount of CO2. The new Intergovernmental Panel on Climate Change (IPCC) report, not yet released, will say something like a gigaton a year by such methods, which is a big deal clearly.

Of course, you don't suck it up for all time, and therein lie both a scientific and managerial problems. If farmers change their management practices so that they are sucking up a metric ton per hectare per year or something, this would be a really great number. However, carbon in soils is very labile. If you change the management practices, carbon can easily be oxidized back to CO2.

So we need to invent financial instruments where there is some kind of perpetual lease and accounting procedure. A lot of the talk at the Conference of the Parties (COP) meeting in the last few weeks was about inventing such instruments. Everybody now agrees that we need to deal with the fact that you can't just pay somebody for their credit and then hope that it will stay there.

Effectively, I think, and many would agree, that we are going to need several colors of poker chips if we are going to trade carbon, where one color—the kind of gold standard—is just not emitting anything; another color is geological sequestration, which we think will stay there for 10,000 years or longer; and another color is biological sequestration, which is very easy to do but stays there for time scales of decades to a century.

David Thomas: One of the concerns that I had after participating in that meeting was the fact that there were three congressional aides present, all of who were beholden to fairly influential senators from agricultural states. It concerns me that the feedback to Congress through that group is going to be very strongly toward soil sequestration as the way to go. This could be a real issue for those that are concerned about the long term, as we are.

David Keith: Yes.

Andrew Kaldor, ExxonMobil: Let me ask a question concerning hydrogen storage. It seems to me that the central issue in changing over to different technology is a significant improvement in hydrogen storage. It appears that very high-pressure hydrogen is useful in commercial systems, whereas it is probably particularly difficult for individual drivers' fueling their vehicles.

So, the question I have is, Do you think the research ideas for hydrogen storage in solids are adequate or should we be putting more resources into this, perhaps approaching hydrogen storage in a significantly different way?

James Spearot, General Motors: In regard to how much we need to store, our goal is basically 10 weight percent (wt%) hydrogen as a fraction of the total fuel system weight. We believe that at this level we could operate a fuel cell sport utility vehicle (SUV). We could give the customer what he wants; he could drive a large vehicle, pull a trailer, whatever, and would still have a reasonable range with 10% hydrogen storage fuel cell vehicle.

In terms of the options that are out there at the moment, I mentioned gaseous storage developments. Some of the tank suppliers using advanced lightweight carbon fiber tanks are getting to—or at least contemplating—10,000 pounds per square inch. This gets us into the 7% range.

Liquid cryogenic hydrogen storage would get us to our 10% range if we wanted to develop an infrastructure to pump cryogenic hydrogen around. Obviously, producing cryogenic hydrogen requires a lot of energy itself. So you really have to talk about a renewable energy source not only to create the hydrogen, but also to compress it and to liquefy it.

Liquid cryogenic hydrogen is a leading option in Germany at the present time. There are demonstration programs going on at present, and they believe that this is a true end game for their particular economy at some point in the future. We haven't reached the point where we believe the same thing.

We would like to see the development of high-weight-percent hydrogen storage. This includes solid absorption tanks. The other technologies that are out there right now include chemical hydrides that are complexed with water, which give a little extra kick in terms of hydrogen availability. Then, of course, there are the carbon materials, primarily carbon nanotubes, although we believe some of the things that have been reported in the literature may not be nanotubes.

Right now, some tremendous claims are being made. We are struggling to reproduce those claims, and I think this solid storage is a longer-range option. We will be well into the second decade of this century before we are going to have solid absorption tanks out there. They would represent the safest system that we could develop. The question is, Could either compressed or cryogenic be made safe? We are looking at this very carefully.

John Turner: Just to comment on hydrogen, we have to differentiate between two areas. You are talking about vehicle storage. Stationary storage of hydrogen is really not an issue. You can use the standard compressed tanks, or you can even pump it underground and do other sorts of things. So stationary hydrogen storage for long-term energy storage is not an issue. Storage of hydrogen on mobile vehicles is certainly an issue.

The numbers I saw recently out of Thiacol using its tank was more like 11 wt% at 5,000 psi. If you added all the system to this, it brings the percentage down, but that is the latest number I saw, about six months ago, when Thiacol announced its new tank.

In terms of carbon additives, I think the leaders are NREL. Mike Heben, in research funded by Honda, is showing 7% hydrogen storage with nanotubes, but he still has some issues with regard to manufacturability.

I think nanotubes will work. We have seen enough experimental data. The problem is how do you take something now that costs a thousand bucks a gram and turn it into a commodity chemical at $2 a kilogram, especially something as engineered as a carbon nanotube. This is a big issue right now.

David Keith: Another reason I am not that worried about hydrogen storage involves where in the transport infrastructure you would first introduce hydrogen. The conventional view, of course, is in personal automobiles. Our view at Carnegie Mellon is different. We suggest a focus on heavy transport systems, such as ships, heavy trucks, and rail.

There are several reasons. First, the storage problem is much reduced for heavy transport because there isn't such a volumetric constraint. Second, many of these modes are now very dirty with respect to conventional pollutants because we haven't regulated them hard. You want to pick up the benefit of mitigating both CO2 and conventional pollutants if you are going to justify an expensive, risky technology. So, for example, ships account for 2% of global CO2 emissions and 14% of global NOx emissions because they have these incredible NOx-producing engines. It is the same for sulfur. So, if you want to have a double environmental win, there is a reason to start on heavy transport modes than rather than on personal autos. Third, a lot of these technologies are in operation for most of the day, which means more effective amortization of capital cost. You can afford to spend more capital on an expensive technology that will lower your operating cost (under a carbon tax) if the technology utilization is high. Cars aren't used that many hours a day, so they are very sensitive to capital cost. If you are being rational about putting hydrogen into the transport system, I don't think you start with cars.

James Spearot: I basically agree with this. You will see some in cars, but they will be early prototype demonstrations and limited product applications to get the knowledge base developed, but clearly center-city buses make an ideal application for hydrogen fuel cells.

Richard Foust, Northern Arizona University: I have a question relating to policy about renewable energies. From what I remember, the price of solar photovoltaics in the late 1970s and early 1980s was not a lot different in real dollars from what it is right now. If we were to increase the amount of money directed to research, would it significantly advance the time that the prices of renewable energies would fall?

John Turner: For photovoltaics, it depends on the technology. If you wanted to talk about thin-film technologies, which have perhaps the highest possibility of really low costs in terms of their systems, then, yes, more funding for research would definitely be in order.

For single-crystal silicon, the problem is in manufacturing. Scaling-up manufacturing would decrease costs. I don't remember what the costs were in the 1970s and 1980s but right now if you are a large buyer, the parking lot I showed in Sacramento costs about $4 a watt installed.

Manufacturers are making panels. The lowest cost is about $1.50 per watt. The average was $2.73 last year. They are projected to come down as manufacturing volume goes up. However, thin-film technologies, which have the opportunity to lower the costs to 6 cents/kWh almost as soon as they go into full production, could certainly use a lot of research dollars. We don't understand not only how to make the technology work, but even why it works the way it does.

Richard Foust: So it is basic research money that needs to be spent, not engineering research?

John Turner: For thin-film photovoltaics, it is basic research money. For single-crystal silicon, it is engineering research and reducing manufacturing costs.

Richard Foust: Has the price dropped relative to funding for research?

John Turner: There is a program at the Department of Energy called PV Materials that has been a significant player in lowering the manufacturing costs of photovoltaic panels.

David Keith: It is clear that spending money can buy down the price of a lot of energy technologies, and for many, if you do historical studies and you plot the log of the total amount we built so far versus the cost, you get a nice line. It is a power law. This is true for gas turbines, and it is beautifully true for solar photovoltaics, but it is important to compare apples with apples—to compare technologies with the same assumptions. Analysts who wish to advocate a given technology often apply a learning curve model to it, but not to the competition. We are still far from a robust understanding of technological innovation and diffusion in the real world.

Klaus Lackner, Los Alamos National Laboratory: I would like to point out that in all of these discussions of what energy form is better or worse or which one we should use, our ultimate goal has been to take into consideration that there will be 10 billion people who would like to have a standard of living as high as we have today, and if we were to get there over the next hundred years, it would be a factor of 10 increase in energy consumption.

I would argue that we really need cheap, clean energy and we need a large amount of it. I think every little bit we can get to mustering this is worthwhile. I don't view alternate energy forms as competing approaches, but as multiple alternatives to get to the goal. I would argue that we cannot exclude any of them.

Fossil energy, on the one side, is 86% of the total right now. If we pull the rug out from under that, we would have a catastrophe. On the other side, I think renewables could grow a lot and make a big difference, particularly in the distributed energy market. The market is so large that if we can all get the prices down, we do a service to the world because people do need energy. I believe there are 2 billion people without electricity right now.

Robert Wilson, SRI: I would like to go back to the question of the utilization of biomass and its gasification of combined with sequestration. In all the discussions we have had today, we focused on land utilization issues. The question hasn't come up about utilizing ocean resources for farming biomass for the same purpose.

The second question is, David, you mentioned that gasification of this biomass was easy and I would like to know the basis for that assertion.

David Keith: “Easy” was the wrong word. I meant to say easier than coal. Even this may be overstated. While biomass has less problems with sulfur, less ash, and gasifies at lower temperatures, it has other challenges that compensate for many of these advantages.

The ocean answer is that the ocean productivity is not so big, and it is actually hard to extract substantial energies from the oceanic biota.

Robert Wilson: We are not talking about the natural productivity of the ocean. We are talking about farming—ocean farming.

David Keith: Farming, meaning fish farms?

Robert Wilson: No, well—

David Keith: Hard to do.

Robert Wilson: The growth rates of some of these ocean materials are far greater than the growth rate of some of the grasses that people are talking about today. So, this is why it is of interest to some people.

Alan Wolsky, Argonne National Laboratory: This is a comment prompted by some of the things that have been said, but the comment is really directed to the organizers of the meeting and the National Academies. Our field does not have a cumulative literature that would help in these discussions. For example, 20 years ago, people tried to grow kelp and they were successful because kelp grows like crazy, but 19 years ago, they found out that when a storm came they couldn't protect the kelp and they lost their crop. This is a factoid I know about, but the absence of a general knowledge of it illustrates the lack of continuity in our literature.

The difference between the science and this quasi-policy discussion is that in science, there are usually indices and a way to benefit from the work already done. In policy I know many cubic feet of reports—and many of these cubic feet discuss topics we are touching on here—but we have failed to benefit from past work, just as our discussions may not be accessible to the future. So just to do one more study without thinking about how the present interest in climate change can be made accessible to those who come after us misses an opportunity to really make a contribution.

Tom Baker, Los Alamos National Laboratory: The thing that has been disappointing for chemists in the issue of carbon sequestration has been the lack of interest in the United States in expanding funding for the fundamental chemistry of carbon dioxide. In Europe, there is a lot of focus on CO2 reuse and recycling. Here, instead, the attitude has been that it is never going to be large enough to make a difference in the sequestration area, so let's spend our money elsewhere where we are going to solve the larger problem. In fact, there is a lot of chemistry that needs to be worked out with CO2. We still really don't know much about the very basic fundamentals, and in spite of the thermodynamics, there is still a lot of chemistry that could be done with higher-energy coreactants. So how do you think we could go about getting the United States to pay a little more attention to the fundamental chemistry of CO2?

Carol Creutz, Brookhaven National Laboratory: I agree with your assessment and do not have any new ideas on how to focus attention on fundamental CO2 chemistry. I would also comment that within even the Office of Science at the Department of Energy, there seems to have been a much more dominant role of the Office of Biological and Environmental Research (OBER) in attacking the carbon management problem and identifying sequestration as the solution. I don't know if this reflects a whole community or the local response within the United States. Yet the problem has been taken on as a sequestration problem, which—to me as a chemist—doesn't make sense. It seems to me that there would be a lot of things we could be doing and benefiting from.



This essay is loosely based on a presentation at the National Academy of Sciences' Chemical Sciences Roundtable. In transforming it to published form, I have attempted to preserve some of the informality of a verbal presentation while (I hope) improving its organization and content. There was considerable skepticism expressed during the meeting about the scientific basis for concern about climate. I tried to answer this skepticism with brief opening comments; I have included them here, although they differ in style and content from the rest of this essay.


The process is often called CO2 capture rather than separation, but I prefer separation because not all processes end with CO2. It is also possible to produce carbonates or even pure carbon.


Oceanic sequestration is possible, and perhaps important, but I omit discussion of it here.


Including other radiative forcings, 450 ppm CO2 is approximately equivalent to a doubling of CO2 over preanthropogenic levels.


Several review articles cover much of the material presented here (Herzog et al., 1997, 2000, Socolow, 1997; Parson and Keith, 1998; Freund, 2000).

Copyright © 2001, National Academy of Sciences.
Bookshelf ID: NBK44136


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