Implementation of fine PM standards, EPA's Interstate Air Quality Rule, Utility MACT rulemaking to control mercury emissions from utility boilers, the Clear Skies legislation and other multi-pollutant reduction bills in the Congress are focusing on future reductions of NOx, SO2, and mercury emissions from power plants. Also, a significant fraction of existing boiler capacity already has wet or dry scrubbers for SO2 control and /or SCR for NOx control. As such, multipollutant control approaches capable of providing SO2/NOx/Hg reductions are of great interest. These approaches and their potential impact on mercury reductions are discussed below.
Multipollutant Removal in Wet FGD
More than 20 percent of coal-fired utility boiler capacity in the United States uses wet FGD systems to control SO2 emissions. In such systems, a PM control device is installed upstream of the wet FGD scrubber. Wet FGD systems remove gaseous SO2 from flue gas by absorption. For SO2 absorption, gaseous SO2 is contacted with a caustic slurry, typically water and limestone or water and lime.
Gaseous compounds of Hg2+ are generally water-soluble and can absorb in the aqueous slurry of a wet FGD system. However, gaseous Hg0 is insoluble in water and therefore does not absorb in such slurries. When gaseous compounds of Hg2+ are absorbed in the liquid slurry of a wet FGD system, the dissolved species are believed to react with dissolved sulfides from the flue gas, such as H2S, to form mercuric sulfide (HgS); the HgS precipitates from the liquid solution as sludge.
The capture of Hg in units equipped with wet FGD scrubbers is dependent on the relative amount of Hg2+ in the inlet flue gas and on the PM control technology used. ICR data reflected that average Hg captures ranged from 29 percent for one PC-fired ESP plus FGD unit burning subbituminous coal to 98 percent in a PC-fired FF plus FGD unit burning bituminous coal. The high Hg capture in the FF plus FGD unit was attributed to increased oxidization and capture of Hg in the FF followed by capture of any remaining Hg2+ in the wet scrubber.
RD&D Needs for Wet FGD Systems to Enhance Mercury Capture
• Achieving high Hg removal efficiencies in a wet scrubber depends on mercury in the flue gas being present in the soluble Hg2+ form. While the majority of mercury in bituminous coal-fired boilers exists as Hg2+, the fraction available as Hg2+ varies. Further, as discussed above, flue gases from subbituminous and lignite coal-fired boilers predominantly contain Hg0, which is insoluble. Therefore, to ensure high levels of mercury capture in wet scrubbers in a broad range of applications, process means for oxidizing Hg0 in coal combustion flue gas are needed. RD&D efforts should be conducted with the objective of making available oxidizing catalysts and reagents by 2015. Also, RD&D efforts should be undertaken to examine coal blending as a means to increase oxidized mercury content in flue gas.
• Scrubber design and operating conditions may require modification to optimize Hg dissolution in the scrubber liquor. Therefore, optimization research should be undertaken at pilot-scale and then demonstrated at full-scale.
• It has been noted that in some scrubbers dissolved Hg2+ is reduced to Hg0, which can be stripped from the scrubbing liquor and entrained in the stack gas. RD&D efforts should be conducted in this area with additives developed in bench- and pilot-scale testing and demonstrated at full-scale.
• Since a significant portion of the absorbed Hg may end up in the spent scrubber liquor in the form of dissolved aqueous-phase Hg2+, RD&D should be conducted to develop Hg removal techniques from wastewater.
• RD&D efforts be should be conducted to make available multipollutant scrubbers capable of removing SO2, Hg, and NOx from flue gases of coal-fired boilers. Research conducted in the 1970s through 90s has investigated removal of NOx in wet scrubbers. Since use of wet scrubbers at power plants is expected to increase in the near future in response to regulatory requirements, it is very desirable to develop wet scrubber-based technologies capable of providing simultaneous SO2-Hg-NOx control. Such technologies would not only make wet scrubbers more cost-effective, but would avoid the need for installing additional control equipment, especially at constrained plant layouts.
• Full-scale demonstrations should be conducted to achieve high levels of mercury control using ACI with wet FGD, with or without additional oxidizing agents. This is especially relevant to subbituminous- and lignite-fired boilers.
Multipollutant Removal in Dry Scrubbers
More than 10 percent of the U.S. coal-fired utility boiler capacity uses spray dryer absorber (SDA) systems to control SO2 emissions. An SDA system operates by the same principle as a wet FGD system using a lime scrubbing agent, except that the flue gas is mixed with a fine mist of lime slurry instead of a bulk liquid (as in wet scrubbing). The SO2 is absorbed in the slurry and reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate. Hg2+ may also be absorbed. Sorbent particles containing SO2 and Hg are captured in the downstream PM control device (either an ESP or FF). If the PM control device is a FF, there is the potential for additional capture of gaseous Hg0 as the flue gas passes through the bag filter cake composed of fly ash and dried slurry particles.
ICR data reflected that units equipped with SDA scrubbers (SDA/ESP or SDA/FF systems) exhibited average Hg captures ranging from 98 percent for units burning bituminous coals to 24 percent for units burning subbituminous coal.
RD&D Needs for Dry Systems to Enhance Mercury Capture
• SDA is considered to be quite effective in removing Hg2+ from flue gases. Full-scale demonstrations of SDA and ACI should be conducted to achieve high levels of SO2 and mercury controls on subbituminous and lignite-fired boilers. These demonstrations should include both ESP and FF PM controls.
• Circulating fluidized bed absorber technology appears promising to provide high levels of SO2 and Hg control. Recent applications of this technology reflect SO2 control in excess of 90%. As for mercury control, limited pilot-scale experience has shown high mercury removal rates. This technology, with or without ACI, should be demonstrated for mercury control in several full-scale tests using a range of coals.
Multipollutant Removal Via SCR and Wet FGD
As mentioned above, the speciation of mercury is known to have a significant impact on the ability of air pollution control equipment to capture it. In particular, the oxidized form of mercury, mercuric chloride (HgCl2), is highly water-soluble and is, therefore, easier to capture in wet FGD systems than Hg0 which is not water-soluble. SCR catalysts can act to oxidize a significant portion of the Hg0, thereby enhancing the capture of mercury in downstream wet FGD.
Several studies have suggested that oxidation of elemental mercury by SCR catalyst may be affected by the following:
• The space velocity of the catalyst;
• The temperature of the reaction;
• The concentration of ammonia;
• The age of the catalyst; and
• The concentration of chlorine in the gas stream.
DOE, EPRI, and EPA have co-sponsored a field test program that evaluated mercury oxidation across full-scale utility boiler SCR systems. Testing was performed at four coal-fired electric utility plants having catalyst age ranging from around 2500 hours to about 8000 hours. One plant fired subbituminous coal and three other plants fired Eastern bituminous coal. The test results showed high levels of mercury oxidation in two of the three plants firing eastern bituminous coal and insignificant oxidation at the other two plants (one firing bituminous coal and the other, subbituminous). For the bituminous coal-fired plant with low mercury oxidation, over 50 percent of the mercury at the SCR inlet was already in the oxidized form. It is also noted that the SCR system at this plant was operated with significantly higher space velocity (3930 hr-1) that those of the other plants (1800-2275 hr-1). Finally, ammonia appeared to have little or no effect on mercury oxidation.
The two bituminous coal-fired plants at which high levels of mercury oxidation across SCRs was observed were retested in the following year (2002). Again, similar high levels of oxidation were observed. Two additional plants firing bituminous coals were also tested in 2002. Results of the tests showed high levels of mercury oxidation, similar to the two plants tested previously. Currently, a DOE-sponsored field test program is further evaluating the potential effect of SCRs and FGDs on mercury removal.
RD&D Needs for SCR and Wet FGD Systems to Enhance Mercury Capture
• Aging of SCR catalyst with regard to mercury oxidation should be examined in bench-, pilot-, and field tests.
• SCR impact on mercury oxidation should be examined for subbituminous and lignite-coal-fired boilers and boilers firing coal blends. These impacts should be evaluated on pilot- and field-scales.
• Bench- and pilot-scale research on understanding the science behind SCR-Hg interactions should be continued. This research has the potential to provide valuable information for optimizing SCR catalysts for combined NOx and mercury control.
0 comments:
Post a Comment