Full-Scale carbon capture systems are expected to be the most complicated new environmental control technology introduction we have undertaken. The reasons are subtle, but ultimately based on the simple fact that carbon dioxide is not a very chemically reactive gas. In power generation, carbon capture (or recovery) is likely to demand a large chemical processing plant installed at the outlet/exhaust of a power plant, substantially raising the cost of what has been a relatively inexpensive source of energy. Power demands (or the loss of equivalent generation output) of 100-400 kW h/tonne of CO2 capture are expected.
The current stable of post-combustion carbon capture systems differ primarily in choice of solvents and the energy required for regeneration. Amine-based chemicals like monoethanol amine (MEA) rapidly absorb CO2 over a range of pressures. It is at higher pressures where volumes of gas are reduced due to compression where the process becomes most economic. Because the solvent is also relatively inexpensive, it has become an industry standard for treating natural gas (which is usually processed at pressures well above 1,000 psig). This experience of treating pressurized gas is one of the reasons for considering these solvents in an IGCC application. Capturing the CO2 at pressure could significantly reduce the capital equipment expense compared to a facility attempting the same feat near atmospheric conditions, but that's a big part of the problem—post combustion gases are not at high pressure, but rather at atmospheric conditions.
Amine-type solvents are widely used in the gas processing industry where natural gases are sweetened (i.e., sulfur is removed) by extracting both CO2 and H2S with solvents. This experience has led to MEA being the solvent of choice for most of the power plants considering carbon capture today. MEA binds tightly with CO2 tightly; incurring a generation loss of 200-400 kW h for each tonne of CO2 recovered . Ammonia-based solvents previously mentioned are being explored for post combustion exhaust gas treatment because much less energy is required to separate the bound CO2 from the solvent, with the added benefit that the carrying capacity of ammonia is greater than that of amine solvents. There is a give and take here, because ammonia's volatility demands very low operating temperatures. This too will require large energy expenditure to reduce the exhaust gas temperature, an energy penalty that is not easily missed in the accounting of plant output.
Compared to existing technologies, based on what we know today, carbon capture systems will be much more complex than the emission control systems designed to reduce emissions of priority pollutants (SO2, NOx, etc.). Conceptually, the idea is to use design features that include readily available solvents (either liquids or solids) and to duplicate the desirable features of a post combustion control system such as
Flue Gas Desulfurization (FGD). In contrast, CO2 specific controls will be required to process over 100 times the mass of material as the next largest emission control system (FGDs), while attempting to chemically treat a gas that is almost 1,000 times less reactive.2 It will require significant technical innovation to overcome five orders of magnitude in reactivity with an economically viable process. This is a critical point missed in most comparisons of post combustion environmental control technologies. The opportunities for innovation and the risks of failure are both enormous, suggesting that it could be incredibly difficult to determine in advance what the most effective method for CO2 mitigation would, or could, be. Twenty-five years from now, a power generation system equipped with CO2 separation capability may be entirely different from anything proposed today or constructed within the next decade, placing the initial wave of such facilities in the category of large-scale research facilities, with the potential of full-scale obsolescence in less than 10-15 years. We are still exploring the technology demonstrations: One large utility is experimenting with chilled ammonia for carbon capture, although an initial public announcement for a commercial CO2 capture plant will be based on a more conventional amine application. Oxy-fuel demonstration plants are continuing to be studied, although none has really made it to a stage of commercial availability. Numerous university laboratories are experimenting with even more developmental processes like chemical looping.
In addition to the process primary components, there are hidden environmental features that have not been widely discussed. Usually these aspects fall into the category of "unintended consequences." For example, water availability is expected to be a critical factor. This, during a period when supplies of water are expected to be declining, not increasing. A recent study by North American Electric Reliability Council (NERC) suggested that reducing the open loop cooling associated with much of the existing thermal fleet (about 400 GW) could result in a reduction of capacity on the order of 50 GW . Inclusion of a post combustion carbon capture plant is expected to increase water consumption to operate the regeneration steps in the process. Where water access is limited, or in short supply, the carbon capture process may be forced rely on less efficient mechanisms for heat transfer (e.g. air cooled condensers or hybrid systems), and potentially increase both the size and cost of the facility.
As we understand it today, simply adding a carbon capture system to an existing power generation unit will substantially lower its efficiency. Studies suggest in the range of 20-30% reduction in plant output . Meanwhile, demand for energy (MWhrs) and capacity (MWe) is increasing virtually everywhere . Summer peak demand increases annually, as does winter peak demand. While it may be counterintuitive, adding this level of emission controls to the fossil fleet would require mining and burning more fossil fuels to produce the same energy output. Identifying these unanticipated responses will be a daunting task for policy makers more accustomed to promoting local, regional, or national based incentives.
2 Assuming a gas concentration of SO2 of 1,000 ppm at 10% CO2.
However challenging it may be to capture CO2 from a fossil plant, it is even more difficult to place that burden on gas-fired generation based on the Brayton (gas turbine) cycle. First, the natural gas combined cycle typically has a much lower CO2 content in the exhaust than is found in a fossil steam plant (4% vs. 10-12%). The lower concentration implies a reduced uptake rate of CO2, suggesting that the overall capture system (spray towers or beds) would be physically larger (even though there would be less cleanup of sulfates required prior to carbon extraction). The additional back-pressure on the turbine will exact a large energy penalty.
Perhaps a more effective strategy using a gas turbine would be to increase the gas fired capacity of the entire system, possibly even by converting coal into substitute natural gas, another technology that is already well proven. As noted earlier, the CO2 emission profile of a gas-combined cycle is about one-third of a fossil steam plant (refer to the lower emission profile noted in Fig. 10.2), a 60% reduction with no penalty associated with add-on emission controls.
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