Post-combustion Mercury Control Techniques

Mercury capture in existing emissions control equipment offers a cost effective mercury control option for coal-fired power plants. The incidental capture of mercury from coal-fired power plants varies significantly depending on the existing emissions control configuration and type of coal being burned. In post-combustion technique, there are three basic methods of flue gas treatment to capture mercury: first, capture of particulate-bound mercury in particulate matter (PM) control devices; second, adsorption of elemental and oxidized mercury onto sorbents for subsequent capture in PM control devices, and; third, removal of soluble oxidized mercury in wet scrubbers (including processes to convert elemental to oxidized mercury for subsequent capture in wet scrubbers).

Mercury speciation along the convective flue gas path determines the mode of mercury capture using these traditional pollution control devices. Figure 2.4 shows the various species of mercury present in the flue gas at different stages of a typical plant layout.

More than 20 percent of coal-fired utility boiler capacity in the United States uses wet FGD systems to control SO2emissions. Wet FGD systems remove gaseous SO2from 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 ESP plus FGD unit burning subbituminous coal to 98 percent in a fabric filter (FF) plus wet flue gas desulfurization (WFGD) unit burning bituminous coal [19]. The high Hg capture in the FF plus WFGD unit was attributed to increased oxidization and capture of Hg in the FF followed by capture of any remaining Hg2+in the wet scrubber.

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 SO2and 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 Hg0as 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 [4].

There has been increasing number of generators installing selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) systems to reduce NOx emissions. SCR devices for reduction of NOx emissions have long been expected to enhance mercury capture by particulate collection devices and SO2 scrubbers through increased oxidation of mercury. Conversion of more of the elemental mercury to Hg2+ would increase the potential removal in a wet FGD, but is not expected to significantly increase removal by precipitators and fabric filters.

The catalyst in SCR system provides sites for mercury oxidation, and the effect of 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.

Confounding issues that surround SCR usage in quantifying the degree of oxidation are that when SCR is in place, increase of both unburned carbon (LOI in ash, due to low NOx burner applications) and of excess ammonia (ammonia slip) are both generally present. The increase in unburned carbon may function as a synthetic “activated carbon” that results in direct “carbon” capture of both Hg0 and Hg2+ species. Un-reacted ammonia (slip) is adsorbed onto particulate surfaces and may also enhance sulfur mercury

reactions, again with the result being that HgP bound onto ash particulates is subjected to more effective removal by particulate control devices. A negative aspect impacting SCR usage is that de-activation, or poisoning, of catalytic function of SCR has been reported associated with lignite coals.

Summary of post combustion type of mercury emission control devices are presented in table 2.7 which shows varying effectiveness percentage of mercury capture. The effectiveness of mercury capture is particular to a specific plant operation, hence wide variation is observed over different configurations of plant layout and also type of coal burnt in the reactor.

Table 2.7 Average mercury capture by existing post-combustion control configurations used for PC-fired boilers [20]