Source: POWER Engineering
The optimal selection of control technologies to limit mercury emissions depends on the type of coal-fired unit (new or existing), the rank of the coal and existing emission control systems.
Mercury in coal varies from 0.05 to 0.25 parts per million by weight, depending on the type of coal. The established regulatory limits on mercury emissions depend on the type of unit and the type of coal. The limits for new coal-fired units are 0.04 lb/GWh for units that burn low-rank coal such as lignite with a higher heating value (HHV) of less than 8,300 Btu/lb, and 0.003 lb/GWh for units burning high-rank coal with an HHV of more than 8,300 Btu/lb. For existing units, the corresponding limits are 0.12 lb/GWh or 11.0 lb/TBtu and 0.013 lb/GWh or 1.2 lb/TBtu, respectively. These emission limits translate to removal efficiency ranges of 65 percent to more than 80 percent for new units using low-rank coals and 95 percent to more than 98 percent for new units burning high-rank coals. The removal efficiency ranges for existing units are 15 percent to more than 50 percent for low-rank coals and 85 percent to 95 percent for high-rank coal.
Because the removal requirements are based solely on lb/GWh, operators of new units may find that low-mercury coal and the ultra super-critical steam cycle, which yield very low heat rates in the range of 8,000 Btu/KWh, offer substantial benefit. For existing units, the control technology selection depends on the removal requirement, mercury concentration and speciation, and type of existing emission control system.
During combustion, mercury in coal is first released as elemental mercury (Hg0), before it is converted to ionic or oxidized species (Hg++) and as particulates. The conversions depend on many factors, such as the rate of cooling, concentrations of halogens and sulfur trioxide (SO3), amount of fly ash, fly ash properties and unburned carbon in fly ash. The concentration of elemental mercury and ionic mercury varies from 20 percent to 80 percent, depending on the coal, its halogen content and the particulate mercury content. Elemental mercury is not water soluble and is difficult to remove in downstream flue gas desulfurization (FGD) systems. Ionic mercury, on the other hand, is very water soluble and is easily removed in FGD systems, both wet and dry. The particulate mercury is also removed by devices such as an electrostatic precipitator (ESP) or a fabric filter (FF) with fly ash.
Mercury can be removed through chemical adsorption on powdered activated carbon (PAC). Activated carbon is injected upstream of an ESP or FF and is removed along with fly ash. Because it is also adsorbed and removed by PAC, the presence of SO3 adversely affects mercury removal. If SCR is used for nitrogen oxides (NOx) control, it can exacerbate this problem; SCR tends to oxidize sulfur dioxide (SO2) to SO3 and increases SO3 concentration in the flue gas. Low-oxidation catalysts can be used to minimize this problem. SO3 can also be removed by injecting alkali such as trona or lime/hydrated lime upstream of PAC injection. The main drawback of the PAC system is its potential adverse effect on ESP performance when ESP is used for particulate collection and to improve the salability of fly ash. A new market entrant, injection of amended silicates, can potentially negate both increased SO3 concentration in the flue gas and the attendant adverse effect on ESP performance. The long-term viability of amended silicate has not yet been demonstrated, however.
Halogen compounds such as bromine or hydrogen bromide added to flue gas increase the conversion of elemental mercury to ionic mercury, thereby facilitating mercury capture in downstream FGD. Halogen salts can also be added to coal before the pulverizers. During combustion, bromide salts decompose and release bromine ions, which in turn oxidize elemental mercury to ionic mercury that is removed in FGD. Bromine ions can potentially increase fireside corrosion. Some ionic mercury collected in the FGD can revert back to elemental mercury and can be re-emitted into the flue gas. Although chemicals can be added to minimize re-emission, the exact mechanisms of the re-emission reactions and the mitigation measures are not clearly established.
Given the complexity of choosing control technologies for limiting mercury emissions, a comprehensive site-specific study may be necessary to help your company choose the optimal solution.
Because the removal requirements are based solely on lb/GWh, operators of new units may find that low-mercury coal and the ultra super-critical steam cycle, which yield very low heat rates in the range of 8,000 Btu/KWh, offer substantial benefit. For existing units, the control technology selection depends on the removal requirement, mercury concentration and speciation, and type of existing emission control system.
During combustion, mercury in coal is first released as elemental mercury (Hg0), before it is converted to ionic or oxidized species (Hg++) and as particulates. The conversions depend on many factors, such as the rate of cooling, concentrations of halogens and sulfur trioxide (SO3), amount of fly ash, fly ash properties and unburned carbon in fly ash. The concentration of elemental mercury and ionic mercury varies from 20 percent to 80 percent, depending on the coal, its halogen content and the particulate mercury content. Elemental mercury is not water soluble and is difficult to remove in downstream flue gas desulfurization (FGD) systems. Ionic mercury, on the other hand, is very water soluble and is easily removed in FGD systems, both wet and dry. The particulate mercury is also removed by devices such as an electrostatic precipitator (ESP) or a fabric filter (FF) with fly ash.
Mercury can be removed through chemical adsorption on powdered activated carbon (PAC). Activated carbon is injected upstream of an ESP or FF and is removed along with fly ash. Because it is also adsorbed and removed by PAC, the presence of SO3 adversely affects mercury removal. If SCR is used for nitrogen oxides (NOx) control, it can exacerbate this problem; SCR tends to oxidize sulfur dioxide (SO2) to SO3 and increases SO3 concentration in the flue gas. Low-oxidation catalysts can be used to minimize this problem. SO3 can also be removed by injecting alkali such as trona or lime/hydrated lime upstream of PAC injection. The main drawback of the PAC system is its potential adverse effect on ESP performance when ESP is used for particulate collection and to improve the salability of fly ash. A new market entrant, injection of amended silicates, can potentially negate both increased SO3 concentration in the flue gas and the attendant adverse effect on ESP performance. The long-term viability of amended silicate has not yet been demonstrated, however.
Halogen compounds such as bromine or hydrogen bromide added to flue gas increase the conversion of elemental mercury to ionic mercury, thereby facilitating mercury capture in downstream FGD. Halogen salts can also be added to coal before the pulverizers. During combustion, bromide salts decompose and release bromine ions, which in turn oxidize elemental mercury to ionic mercury that is removed in FGD. Bromine ions can potentially increase fireside corrosion. Some ionic mercury collected in the FGD can revert back to elemental mercury and can be re-emitted into the flue gas. Although chemicals can be added to minimize re-emission, the exact mechanisms of the re-emission reactions and the mitigation measures are not clearly established.
Given the complexity of choosing control technologies for limiting mercury emissions, a comprehensive site-specific study may be necessary to help your company choose the optimal solution.
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