Advantages of Gasification - Designs for CO2 Capture
CO2 Capture Technologies
NETL Carbon CO2 Capture and Storage Program
Recognizing the significance of carbon dioxide (CO2) emissions as related to fossil fuel usage, the U.S. DOE/NETL runs a very active Carbon Storage Program as a companion strategic activity to gasification, under the Coal and Power Systems Program.
The Carbon Storage Program is currently developing a portfolio of CO2 capture technologies, and has identified developmental pathways linking the various technology research and development (R&D) activities between advanced fossil fuel conversion and CO2 capture.1 The Program’s CO2 capture activity is being conducted in close coordination with that of advanced, higher-efficiency power generation and fossil fuel conversion technologies such as gasification.
CO2 capture systems may be classified into three categories: post-combustion, pre-combustion, and oxy-combustion, each of which are discussed in the following sections.
Post-Combustion CO2 Capture
Post-combustion CO2 capture is primarily applicable to conventional natural gas and pulverized coal-fired (PC) power generation. In a typical PC power plant, fuel is burned with air in a boiler to produce steam, which 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 concentration (typically 13 to 15 volume percent for PC power plants and 3 to 4 percent for natural gas-fired plants) and at low pressure (slightly above atmospheric); thus, a large volume of gas has to be treated.
- Trace impurities (e.g., particulate matter, sulfur dioxide [SO2], nitrogen oxides [NO2] in the flue gas can degrade sorbents and reduce the effectiveness of certain CO2 capture processes.
- CO2 is captured at low pressure. Compressing it from atmospheric to pipeline pressure (about 2,000 psia) will incur a large auxiliary power load on the overall power plant system.
A post-combustion CO2 capture absorption process based on chemical solvents such as amines is pictorially shown below. These types of processes have been developed and deployed commercially in the refinery and chemical industries. To date, however, their use in 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/kilowatt-hour (kWh) to 8.25 cents/kWh.1
Pre-Combustion CO2 Capture for Gasification Application
Pre-combustion CO2 capture related to a gasification plant is pictorially depicted below. As described in the Gasification in Detail section, 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 (WGS) reactor, which converts the CO to CO2 and increases the CO2 and H2 mole concentrations to about 40 percent and 55 percent, respectively, in the syngas stream.
At this point, the CO2 has a high partial pressure, which significantly improves the driving force for various types of separation and capture technologies. After CO2 removal, the H2 rich syngas can be converted to power. One application is to use H2 as a fuel in a combustion turbine to generate electricity, in the context of a combined cycle plant, where additional electricity is generated by extracting the energy from the combustion turbine flue gas via a heat recovery steam generator (HRSG). Another application, currently being developed under the DOE Fuel Cell Program, is to utilize the H2 for power generation using fuel cells, with the intent of significantly raising overall plant efficiency. Because the gasification process is operated at high pressure and CO2 is present at much higher concentrations in the syngas (i.e., in comparison with post-combustion flue gas), pre-combustion CO2 capture has the potential of being less expensive than post-combustion CO2 capture. For the same amount of CO2 captured, a much smaller volume of gas needs to be treated, leading to much smaller equipment size and lower capital costs.
NETL has identified various research pathways for pre-combustion CO2 capture. 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 physical 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. Preliminary 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 about 30 percent, from an average of 7.8 cents/kWh to 10.2 cents/kWh.1 Research being conducted by the NETL Gasification Systems Research Program is expected to improve gasification technology such that costs without capture are comparable to costs from pulverized coal without capture.
Oxy-Combustion CO2 Capture
The objective of pulverized coal oxygen-fired combustion is to combust coal in an enriched oxygen environment using pure oxygen diluted with recycled CO2 or water (H2O). The process is pictorially shown below. 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 NOX emissions compared to 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 introduced into the system as nitrogen inherent to the coal matrix, and through air infiltration.
- Increased mercury removal. Boiler tests of oxy-fuel combustion using Powder River Basin (PRB) 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).
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. A higher purity oxygen stream would also need to be used. 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.