preparing for mercury regulations

, Sargent & Lundy LLC

After more than a decade of studies, proposals, meetings, drafts, and re-drafts U.S.EPA is poised to regulate mercury emissions from coal-fired power plants. Final mercury control regulations were expected to be issued by March 15, 2005. (Editor’s Note: Magazine printed prior to March 15, 2005.) Whether the final rules impose command-and-control mercury emission limits or establish a mercury cap-and-trade program remains to be seen. Either way, the era of mercury regulations is nearing and utilities need to aggressively evaluate and prepare for the new rules.

EPA has proposed two regulatory schemes for controlling mercury emissions from coal-fired power plants (see, Federal Register, vol. 69, page 4652, January 30, 2004). The first alternative would require power plants to install maximum achievable control technologies (MACT) to meet specific mercury emission limits. The second alternative would establish emission limits for new units, and create a market-based cap-and-trade program for all units. Highlights of the proposed rules are summarized in table 1 and table 2.

Although emission caps, allowance allocation procedures, and heat input adjustments may change in the final mercury rule, the emission rates summarized in table 1 and table 2 are being used as the starting point in many mercury compliance studies.

Approximately 75 tons of mercury are found in the coal delivered to U.S. power plants each year. Currently, about two-thirds of this mercury (48 tons) is emitted to the air, and one-third (27 tons) is captured in the power plant boilers and existing pollution control systems. Companies developing mercury compliance strategies need to evaluate mercury removal being achieved with existing control equipment, and the potential mercury removal efficiency of several alternative control strategies.

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The effectiveness of existing and potential control systems depends largely on flue gas chemistry and mercury speciation in the flue gas as it passes through the control device. Studies conducted by EPA indicate that mercury tends to speciate in boiler flue gas into three forms: particulate mercury (Hgp), oxidized mercury (Hg++) and elemental mercury (Hg0). Mercury speciation appears to be a function of several plant-specific variables, including boiler efficiency, fuel characteristics and the presence of trace elements, especially chlorine. Generally, mercury from high chlorine Eastern bituminous coals tends to speciate as oxidized mercury, while mercury in subbituminous coals tend toward elemental mercury. The figure provides generalized ranges of mercury speciation in boiler flue gas based on coal rank.

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Although mercury speciation can be estimated based on coal rank and fuel characteristics, actual mercury speciation can only be determined through site-specific stack testing. Once mercury speciation is established, the effectiveness of existing and potential control technologies can be more accurately evaluated.

In general, particulate bound mercury will be captured in particulate control devices. Studies indicate that both electrostatic precipitators (ESPs) and fabric filters effectively capture particulate mercury. Oxidized mercury is water soluble, and will be captured in flue gas desulfurization (FGD) systems. However, under some circumstances oxidized mercury initially captured in an FGD system may be re-emitted as elemental mercury. Elemental mercury is more problematic, and may require mercury-specific control strategies.

Depending on the type of coal being fired and the existing control technologies, individual units may already be achieving significant mercury reductions. If it appears that additional mercury reductions will be needed, companies should evaluate potential mercury reductions that will be realized as a co-benefit of adding NOx and/or SO2 control technologies to comply with other regulatory programs, as well as the feasibility and cost-effectiveness of mercury-specific control systems. Some of the mercury-specific emission control technologies actively being studied are briefly described below.

system types

Sorbent injection systems involve the addition of a sorbent, typically activated carbon, to the flue gas to adsorb gaseous mercury. The sorbent/mercury is then collected in a downstream particulate control device such as an ESP or baghouse. Activated carbon injected upstream of the primary particulate control device could have an impact on the salability or reuse of flyash. Therefore, many plants are considering sorbent injection downstream of the existing ESP or baghouse, with a separate baghouse to collect the sorbent/mercury.

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Mercury oxidation systems are designed to reduce elemental mercury in the flue gas and increase the percentage of oxidized mercury, which is more easily captured in FGD systems. Oxidation systems using chemical injection, catalysts and energy fields are being studied. Selective catalytic reduction (SCR) systems designed to reduce NOx emissions may also promote the formation of oxidized mercury. Tests indicate that the SCR catalyst may facilitate the reaction between mercury and chlorine to form oxidized mercury.

Other control systems are also being studied. For example, fuel blending (adding Eastern bituminous coal to subbituminous coal) may provide the chlorine necessary to promote mercury oxidation in general and across an SCR. Adding halogens to coal or injecting them directly into the boiler may also promote mercury oxidation. The effect of unburned carbon in the flue gas is being studied. Unburned carbon may act as a sorbent and increase the percentage of mercury captured in the particulate control device. Field tests are continuing on sorbent injection technologies, including variations that use halogenated activated carbon or substitute amended silicates for activated carbon. Multi-pollutant control systems, such as Enviroscrub’s Pahlman Process Technology and Powerspan’s Electro-Catalytic Oxidation System, are also being studied for capturing mercury as well as NOx and SO2.

The era of mercury regulation is near. Companies should already be evaluating their mercury control options and developing compliance strategies. Mercury compliance strategies should take into consideration the proposed mercury regulations as well as regulations limiting other pollutants. Mercury reductions achieved with existing particulate, NOx, and SO2 control systems, and the effectiveness of control technologies needed for future NOx and SO2 control, should be evaluated based on the type of coal burned and mercury speciation in the flue gas. The ideal compliance strategy should ensure cost-effective compliance with all emission control regulations in a manner consistent with the unit’s operating history, fuel variability and cycling patterns.

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