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What is the status of various capture technologies and the timeline for completion of each technology? |
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The categories of capture technologies are typically listed as post-combustion, pre-combustion, and oxy-fuel combustion. The important factors in selecting the capture system are: the concentration of CO2 in the gas stream, the pressure of the gas stream, and whether the fuel is solid or gas. Post-combustion capture of CO2 is used to capture CO2 from part of the flue gases, and is in use at some power plants. Separation of CO2 is a common practice in the natural gas processing industry, using a similar technology. Pre-combustion capture technology is widely applied in fertilizer manufacturing and in hydrogen production. Although the fuel conversion steps of pre-combustion are costly, the higher concentrations of CO2 in the gas stream and higher pressure make the separation easier. Oxy-fuel combustion is still in the demonstration phase. It has great potential because its use of high purity oxygen results in high CO2 concentrations in the gas stream, making it easier to separate the CO2. |
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What is the status of pre-combustion R&D and the timeline for completion? |
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Pre-combustion CO2 capture relates to gasification plants, where fuel such as coal is converted into gaseous components by applying heat under pressure in the presence of steam. In a gasification reactor, the amount of air or oxygen (O2) available inside the gasifier is carefully controlled so that only a portion of the fuel burns completely. This “partial oxidation” process provides the heat necessary to chemically decompose the fuel and produce synthesis gas (syngas), which is composed of hydrogen (H2), carbon monoxide (CO), and minor amounts of other gaseous constituents. The syngas is then processed in a water-gas-shift reactor, which converts the CO to CO2 and increases the CO2 and H2 molecular concentrations to 40 percent and 55 percent, respectively, in the syngas stream. |
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At this point, the CO2 has a high partial pressure (and high chemical potential), which improves the driving force for various types of separation and capture technologies. After CO2 removal, the H2 - rich syngas can be used to produce electrical or thermal power. One application is to use H2 as a fuel in a combustion turbine to generate electricity. Additional electricity is generated by extracting the energy from the combustion turbine flue gas via a heat recovery steam generator. Another application, currently being developed under the DOE Fuel Cell Program, is to utilize the H2 to power fuel cells with the intent of significantly raising overall plant efficiency. Because CO2 is present at much higher concentrations in syngas than in post-combustion flue gas, CO2 capture should be less expensive for pre-combustion capture than for post-combustion capture. Currently, however, there are few gasification plants in full-scale operation, and capital costs are higher than for conventional pulverized coal plants. |
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Near-term applications of CO2 capture from pre-combustion systems will likely involve physical or chemical absorption processes, with the current state of the art being a glycol-based solvent called Selexol. Mid-term to long-term opportunities to reduce capture costs through improved performance could come from membranes and sorbents currently at the laboratory stage of development. Analysis conducted at NETL shows that CO2 capture and compression using Selexol raises the cost of electricity from a newly built IGCC power plant by 30 percent, from an average of 7.8 cents per kilowatt-hour to 10.2 cents per kilowatt-hour. Research being conducted by the DOE Gasification Research Program is expected to improve gasification technology such that its costs without capture will be comparable to electricity costs from pulverized coal without capture, potentially reducing further the cost of pre-combustion CO2 capture in the future. |
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Under DOE-funded research, ionic liquid membranes and absorbents are being developed for capture of CO2 from power plants. Ionic liquid membranes have been developed at NETL for pre-combustion applications that surpass polymers in terms of CO2 selectivity and permeability at elevated temperatures. |
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NETL's CO2 Capture pre-combustion focus area calls for the following R&D goals:
- By 2007, identify capture technologies that increase cost of energy services by less than 20 percent for pre-combustion systems.
- By 2014, initiate at least two slipstream tests of novel CO2 capture technologies that offer significant cost reductions.
- By 2018, initiate large-scale field testing of promising novel CO2 capture technologies.
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What is the status of Post-combustion R&D and the timeline for completion? |
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Post-combustion CO2 capture mainly applies to conventional coal-fired power generation, but may also be applied to gas-fired generation using combustion turbines. In a typical coal-fired power generation system, fuel is burned with air in a boiler to produce steam; the steam drives a turbine to generate electricity. The boiler exhaust, or flue gas, consists mostly of nitrogen (N2) and CO2. Separating CO2 from this flue gas stream is challenging for several reasons:
- CO2 is present at dilute concentrations (13-15 volume percent in coal-fired systems and 3-4 volume percent in gas-fired turbines) and at low pressure (15-25 pounds per square inch absolute [psia]), which dictates that a high volume of gas be treated.
- Trace impurities (particulate matter, sulfur dioxide, nitrogen oxides) in the flue gas can degrade sorbents and reduce the effectiveness of certain CO2 capture processes.
- Compressing captured or separated CO2 from atmospheric pressure to pipeline pressure (about 2,000 psia) represents a large auxiliary power load on the overall power plant system.
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Absorption processes based on chemical solvents such as amines have been developed and deployed commercially in certain industries. To date, however, their use in pulverized coal (PC) power plants has been restricted to slipstream applications, and no definitive analysis exists as to the actual costs for a full-scale capture plant. Preliminary analysis conducted at NETL indicates that CO2 capture via amine scrubbing and compression to 2,200 psia could raise the cost of electricity from a new supercritical PC power plant by 65 percent, from 5.0 cents per kilowatt-hour to 8.25 cents per kilowatt-hour. |
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NETL's CO2 Capture post-combustion focus area calls for the following R&D goals:
- By 2007, identify capture technologies that increase cost of energy services by less than 45 percent for post-combustion systems.
- By 2014, initiate at least two slipstream tests of novel CO2 capture technologies that offer significant cost reductions.
- By 2018, initiate large-scale field testing of promising novel CO2 capture technologies.
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What is the status of Oxy-combustion R&D and the timeline for completion? |
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The objective of oxygen-fired pulverized coal combustion is to combust coal in an enriched oxygen environment using pure oxygen diluted with recycled CO2 or H2O. Under these conditions, the primary products of combustion are CO2 and H2O, and the CO2 can be captured by condensing the water in the exhaust stream. Oxy-combustion offers several additional benefits, as determined through large-scale laboratory testing and systems analysis:
- A 60-70 percent reduction in nitrogen oxides (NOx) emissions compared with air-fired combustion, mainly due to flue gas recycle, but also from reduced thermal NOx levels due to lower available nitrogen. Some nitrogen is still available from coal nitrogen and air infiltrations.
- Increased mercury removal. Boiler tests of oxy-fuel combustion using Powder River Basin coal resulted in increased oxidation of mercury, facilitating downstream mercury removal in the electrostatic precipitator and flue gas desulfurization systems.
- Applicability to new and existing coal-fired power plants. The key process principles involved in oxy-combustion have been demonstrated commercially (including air separation and flue gas recycle).
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Both pre-combustion and oxy-combustion utilize air separation to combust coal in an enriched oxygen environment. However, it is important to note that the amount of oxygen required in oxy-combustion is significantly greater than in pre-combustion applications, increasing CO2 capture costs. Oxygen is typically produced using low-temperature (cryogenic) air separation, but novel oxygen separation techniques such as ion transport membranes and chemical looping systems are being developed to reduce costs. |
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NETL's CO2 Capture oxy-combustion focus area calls for the following R&D goals:
- By 2007, identify capture technologies that increase cost of energy services by less than 45 percent for post-combustion systems.
- By 2014, initiate at least two slipstream tests of novel CO2 capture technologies that offer significant cost reductions.
- By 2018, initiate large-scale field testing of promising novel CO2 capture technologies.
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What capture technology can be used at my local power plant? |
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In the future, emerging R&D will provide numerous cost-effective technologies for capturing CO2 from power plants. At present, however, state-of-the-art technologies for existing power plants are essentially limited to “amine absorbents.” Such amines are used extensively in the petroleum refining and natural gas processing industries. |
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Here’s how amine absorption works: Flue gas that would normally go out the stack is bubbled through a solution of water and amines. The amines in the water react with the CO2 in the flue gas to form an intermediate chemical called a rich amine. The rich amine is soluble and stays in the water solution. Some of the flue gas bubbles out of the top of the amine solution and is emitted to the air just like the flue gas was before, but a portion of the CO2 has reacted with the amines and remains in solution. The rich amines are pumped to another vessel where they are heated to make them decompose back into regular (lean) amines and CO2 gas. The pure CO2 gas is collected from this vessel, and the regular amines are recycled to the flue contactor gas vessel. |
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Amine solvents are effective at absorbing CO2 from power plant exhaust streams—about 90 percent removal—but the highly energy-intensive process of regenerating the solvents decreases plant electricity output by about 15 percent. In addition, over a short time, the amine solvent eventually degrades and cannot be reused. An additional concern is the corrosive nature of amines. |
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