October 15, 2006

Technology options for capturing CO2

Lance C. Elwell and Willard S. Grant, MPR Associates Inc.

If the U.S. regulates CO₂ emissions in the future, the power generation industry is likely to be a prime target. As the table shows, electricity production accounts for nearly one-third of total U.S. carbon emissions. Capturing CO₂ from coal-fired plants is of particular interest for two reasons: coal fuels about 50% of U.S. electricity production, and burning coal emits more carbon per kilowatt-hour than burning other power generation fuels. Oil-fired power plants are about two-thirds as carbon-intensive as coal-fired plants, and natural gas-fired combined-cycle plants are about half as carbon-intensive.

 

The technical challenges of CO₂ capture appear to be similar in scope and complexity to those of removing sulfur dioxide (SO₂) and nitrogen oxides (NO_x) from flue gas—processes that many power plants now perform routinely and cost-effectively. However, the relative economic impact of capturing CO₂ will be much greater, primarily because the "overhead" of CO₂ capture reduces a plant's rated capacity by 25% to 33%. Furthermore, because of the large quantity of CO₂ that must be captured (about 3,000,000 lb/hr for a 1,000-MW plant), on-site storage of the captured gas is not feasible. Some means will have to be developed for transporting the captured CO₂ off-site at the same rate at which it is captured.

The following paragraphs summarize the technical and economic aspects of the three currently feasible methods for minimizing or eliminating the carbon emissions of power plants.

Postcombustion capture of CO₂ from flue gases (using proven chemical absorption methods) could be implemented at existing coal-fired power plants, but the impact on O&M and capital costs would be significant. Although the size and cost of the required absorber would be comparable to those of an SO₂ scrubber, the absorber would consume one-quarter to one-third of the total steam produced by the plant, reducing its generating capacity by the same amount. Deploying chemical absorbers across the U.S. coal-fired fleet would require only the scaling up of units now used for applications other than power generation. An alternative postcombustion CO₂ capture method might be the use of gas separation membrane technologies, which are now in the early prototyping stage.

Oxygen-fired combustion, which produces a 90% CO₂ exhaust stream, provides some multipollutant control, but the technology is less mature and its O&M and capital costs would be comparable to those of postcombustion capture. Specifically, the oxygen separation plant would consume about 23% to 37% of the total plant output and cost about the same as a chemical absorber. This option is most appropriate for new plant projects and would become attractive only when new plant development becomes more desirable than retrofitting existing coal-fired plants. Significant technical challenges will have to be addressed before oxygen-fired combustion can be implemented.

Precombustion capture, which involves capturing CO₂ from synthesis gas (syngas) generated by a coal gasifier, is potentially less expensive than postcombustion capture. It is considered a promising long-term option, but the required technology is still being developed. Power plants that capture CO₂ precombustion also are attractive because they can be based on a combined-cycle (Brayton and Rankine) design that is inherently more efficient than the Rankine cycle employed by pulverized coal-fired plants. Another plus: Because hydrogen production would also be possible, precombustion capture would be compatible with a hydrogen economy. Precombustion capture technologies would be appropriate only for new plant projects.
 

Postcombustion capture

The high cost of gas compression and storage dictates that CO₂ be separated from other flue gases prior to sequestration. Postcombustion capture poses two significant design challenges: the relatively low partial pressure of the carbon dioxide in the flue gas and the relatively high temperature of the flue gases.

Figure 1 is a schematic/mass-balance representation of a typical 1,000-MW coal-fired power plant whose CO₂ capture equipment is installed downstream of systems for reducing emissions of NO_x, particulates, and SO₂. Note the supply of low-pressure steam to the "CO₂ removal" box at upper right; it would not be required if the removal vehicle were gas separation membranes rather than a chemical absorber. The steam would normally be extracted from the steam cycle, decreasing the net plant output. After compression, the CO₂ stream exiting bottom right of the figure would be available for sequestration.

The mass-balance numbers shown in Figure 1 illustrate the following:

• The CO₂ emission rate is four times that of the coal flow.
• The concentration of CO₂ may be low, but the quantities of CO₂ are very large relative to other streams in the power plant.
• The CO₂ concentrations are low because the air flow is an order of magnitude greater than coal flow.

Chemical absorption. Existing commercial applications of chemical absorption—the most widely used method of commercial CO₂ capture for more than 60 years—include enhancing oil recovery by injecting CO₂ into oil wells.

Figure 2 is a simplified schematic/flow diagram of the process. The flue gas stream enters at the left side of the figure. The chemical solvent and CO₂ are exposed to each other in the absorber, where they chemically react to form a loosely bonded intermediate compound. This compound, in liquid form, is then isolated by transferring it to the regenerator (stripper), where heating causes its breakdown into separate streams of CO₂ and solvent. The CO₂ is then condensed and dehydrated and compressed before being stored for commercial use or sequestration.

The stream of solvent—typically, monoethanolamine (MEA)—produced in the regenerator is recycled back to the absorber, enabling the process to be repeated. The storage tank in the solvent return line allows for constant CO₂ removal despite variations in solvent recycling rates. The booster pump in the same line provides the pressure gradient required to transport the solvent. The heat exchanger transfers heat from the relatively hot fluid returning from the regenerator to the relatively cool fluid flowing to the regenerator.

The chemical absorption process uses pressure vessels, storage tanks, pumps, and heat exchangers similar to those of many other industrial processes. The absorber module is a gas/liquid contactor located within a carbon steel vessel or duct. This component is similar to the wet scrubber modules that have been retrofitted onto many coal-fired power plants. During operation, the absorber module pressure and temperature are approximately equal to those of the exhaust entering the module. Unlike a wet scrubber, the absorber module generates no significant waste product.

Chemical absorption has two big advantages: It produces a relatively pure carbon dioxide stream, and its technology is mature and commercially available today. However, the process has two equally big disadvantages: It imposes an "energy penalty" of 25% to 37% on power plants burning coal, and the large size of the required components not only makes the equipment expensive, but it also increases the footprint of the host plant by about 60%.

Following are some potential issues that could affect the cost of implementing chemical absorption systems:

• Existing chemical absorption equipment and processes would have to be scaled up for application to utility power generation.
• The SO₂ and oxygen contained in flue gas will degrade amine solutions. An effective way to counter these mechanisms in large-scale installations that do not have effective SO₂ scrubbers will have to be developed.
• Reliable operation of packed towers used in chemical absorption systems needs to be demonstrated.

In 2000 the National Energy Technology Laboratory (NETL) estimated that postcombustion capture using chemical absorption would increase the cost of electricity production by 70%. Improved sorbents may reduce the energy penalty and the capital cost of the chemical absorption process. The focus of efforts to reduce the energy penalty is on reducing the high regeneration energy requirement. It may be possible to reduce capital costs through design and technological advancements targeting the size of the absorber module and other major components. It is NETL's goal to reduce the electricity production penalty of postcombustion CO₂ capture to 20%.

Gas separation membranes. Membranes can capture CO₂ by separating it from the other exhaust gases. The two most promising separation methods are solution-diffusion and molecular sieving. In the former, the gas is dissolved into the surface of the membrane and then diffused through it by mass transfer. Molecular sieving involves physically separating smaller molecules from larger ones via a very fine mesh.

Membranes are categorized by their material, of which polymeric and inorganic are the two most common types. Polymeric membranes transfer gases by the solution-diffusion mechanism. They are effective and inexpensive because their high ratio of membrane surface area to separation module volume reduces capital cost. However, polymeric membranes are susceptible to degradation and their performance is not good for certain gas flow characteristics. There appears to be a practical limit to the development of polymeric membranes for separation of CO₂.

Because inorganic membranes can implement any of several separation methods, they could allow for some optimization of the process. Although inorganic membranes outperform polymeric membranes in some respects, they are much more expensive because their ratio of membrane surface area to separation module volume is much lower than that of polymeric membranes. Nonetheless, inorganic membranes are considered more promising vehicles for CO₂ capture on the basis of their greater flexibility.

It may be possible to use gas separation membranes to capture CO₂ from synthesis gas produced by a coal gasification process. This application is discussed in more detail in the section titled "Precombustion capture."

Overall, gas separation membranes are in an early stage of development. It has not yet been demonstrated that they can be practically applied to large-scale carbon capture.
 

---