Mercury Control Issues

The U.S. Environmental Protection Agency (EPA) is in the process of developing regulations for the control of mercury emissions from coal- and oil-fired utility boilers. Regulations are scheduled to be proposed in late 2003, and should be final by late 2004, with a compliance date of late 2007. These regulations will affect all new and existing units. EPA has not yet determined the level of control that will be required. However, several bills have been proposed in the 107th Congress that would dictate the control efficiency requirements for mercury from these sources.

In addition, several states have begun developing their own mercury control regulations, and in some cases these identify specific control efficiency requirements.

In order to assess the ability of existing air pollution control equipment to meet the expected range of mercury control efficiency requirements to be imposed by the upcoming regulations, data from EPA's Information Collection Request (ICR) was evaluated. The ICR test program represents the most comprehensive mercury testing effort ever undertaken on full-scale utility boilers, and it was specifically designed to provide information on the control capabilities of various types of air pollution control (APC) equipment.

This article presents the results of a comparison between the control efficiency capabilities of existing APC equipment as evidenced by the ICR test data and the expected range of control efficiency that will be required by upcoming federal and state mercury control programs for utility boilers.

Federal Regulatory Program

On December 14, 2000, EPA announced its determination to regulate mercury emissions from coal- and oil-fired electric utility boilers. This culminated a long process of study, evaluation and reporting as dictated in the Clean Air Act Amendments of 1990 with regard to this specific pollutant and this specific source category. The timing of the determination was several years later than that which was stipulated in the amendments, and ultimately was dictated by a court-ordered settlement agreement resulting from a lawsuit filed by the Natural Resources Defense Council (NRDC), Natural Resource Defense Council v. U.S. Environmental Protection Agency, et al, (No. 92-1415, D.C. Circuit).


Dry FGD systems on boilers firing bituminous coal and wet FGD systems preceded by fabric filters on boilers firing bituminous coal are likely to be able to meet a 90 percent control requirement.

MACT Regulation Development

EPA regulations for mercury emissions control from coal-fired and oil-fired utility boilers will be developed under the provisions of Section 112 (Hazardous Air Pollutants) of the Clean Air Act. This means that the form of the regulatory program must follow the same guidelines as those developed for the other source categories that have already been regulated for control of hazardous air pollutants (HAPs). One of these rules, based on the requirements of Section 112(d), is that the emission standards developed for mercury control must require the maximum achievable control technology (MACT).

For new sources, MACT cannot be less stringent than the emission control that is achieved in practice by the "best controlled similar source," as determined by EPA. Although EPA has yet to make its MACT determination for this case, our evaluation of the ICR data indicates that the maximum control achieved in practice is well above 90 percent reduction in mercury emissions leaving the boiler.

For existing sources, Section 112(d) requires that MACT shall not be less stringent than the average emission limitation achieved by the best-performing 12 percent of the existing sources in the category for which EPA has emissions information. Based on evaluation of the entire ICR data set as a single source category, our interpretation of the 12 percent group requirement, as applied on a removal efficiency basis, is that the MACT floor level of control for existing coal-fired boilers may also be near 90 percent.

The utility boiler mercury MACT standard may take advantage of the provisions of Section 112 that allow for subcategorization within individual source categories that have been identified for regulation. In its regulatory finding announcement (65 Federal Register 79825), EPA indicated that it anticipates the establishment of subcategories for this MACT standard, possibly to be based on fuel type. Based on our analysis of the ICR data, a fuel-based subcategorization would be appropriate. This would allow MACT floor requirements for subbituminous and lignite coal types to be significantly below the 90 percent level that is indicated for bituminous coal.

Proposed Federal Legislation

EPA's determination to regulate mercury emissions from utility boilers came much later than the Clean Air Act Amendments of 1990 had anticipated. In response to this, several bills were introduced in the last Congress to amend the Clean Air Act specifically to require mercury control for this source category. As the 107th Congress began, the sponsors of these bills again submitted them into the legislative process. There are at least five bills pending in Congress that would require regulation of mercury emissions from utility boilers. Of those bills that would establish a percentage reduction requirement for mercury, the reduction is consistently stated as 90 percent.

The Bush administration announced, in its National Energy Policy released in May 2001, that it intended to propose multi-pollutant legislation, including a "cap and trade" program for mercury. President Bush announced his plan for multi-pollutant legislation, known as the "Clear Skies Initiative," on February 14. The plan calls for a 26-ton cap on utility boiler mercury emissions by 2010, with a lowering of the cap to 15 tons in 2018. These caps correspond to 46 percent reduction from current levels by 2010 and 69 percent reduction by 2018.

The Bush plan is based on market-based emissions trading. Emissions trading for mercury is a controversial issue, and several of the bills currently moving through Congress would specifically prohibit the establishment of any trading program for mercury emissions.

State Programs

Several states have advanced well ahead of EPA in the development of regulatory programs to limit the emissions of mercury from utility boilers. In some cases, these programs require lower levels of control than those described above for the federal program. Additional information on the mercury control requirements of these state programs is provided below.

States Developing Mercury Control Requirements

The following states are known to be among those developing regulatory programs intended to reduce emissions of mercury from sources within their boundaries:

  • Connecticut;
  • Maine;
  • Massachusetts;
  • Minnesota;
  • New Hampshire;
  • New Jersey; and
  • Wisconsin.

Example State Program Requirements

Wisconsin has proposed a phase-in of mercury reductions over the next 15 years, beginning with 30 percent reduction by 2006 and extending to 50 percent by 2011 and 90 percent by 2016. These reduction requirements would apply specifically to utility boilers.

New Hampshire's mercury control requirements for electric utility boilers in that state are also expressed in a step-wise approach. A reduction of 50 percent in emissions from this source category will be required by 2003. This will increase to 75 percent control by the year 2005.

Target Control Efficiency

Based on analysis of the anticipated federal and state requirements for mercury control from electric utility boilers, it was determined that, for purposes of our evaluation, an assessment would be made of the ability of existing air pollution control equipment to achieve three different levels of control. The levels chosen are

  • 50 percent;
  • 75 percent; and
  • 90 percent.

The display of ICR data on Figures 1 through 4 is formatted to readily determine whether individual APC equipment types can meet any or all of these target levels of emission reduction.

The ICR Data on Mercury Control Performance of APC Equipment

In the Mercury Study Report to Congress, dated December 1997, fossil fuel fired power plants were identified as the largest source of anthropogenic mercury emissions in the United States. This triggered EPA to gather more data from coal-fired power plants about mercury emissions. Data from coal-fired power plants was collected and compiled via the "Electric Utility Steam Generating Unit Mercury Emissions Information Collection Effort Information Collection Request" (the ICR). Part III of the ICR involved simultaneous speciated mercury sampling (stack testing) before and after the final control device at 86 selected electric utility boiler units.


Several states have advanced well ahead of EPA in the development of regulatory programs to limit the emissions of mercury from utility boilers.

Analysis Methodology

Data Set Used

The data used to determine the mercury removal efficiency of individual air pollution control equipment types was taken directly from the "Extracted Data" document (rawdata1.xls) located on the EPA's Utility Air Toxics Web site (www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html), in the "Speciated Mercury Testing" area.

Calculation of Removal Efficiencies

The raw test data from the speciated mercury testing is presented in the data set as mercury concentration in the flue gas expressed as micrograms of mercury species per dry standard cubic meter. Fractional removal efficiency was calculated as the quantity (1 - (outlet / inlet)), using the total mercury at the inlet and outlet of the control device as reported in the EPA's ICR data set. It should be noted that, in accordance with the procedure established in the design of the ICR test program, the tests for dry flue gas desulfurization (FGD) systems were conducted at the inlet of the spray dryer absorber (SDA) and at the outlet of the downstream particulate collector. The tests for wet FGD systems were conducted at the inlet and outlet of the wet scrubber.

Results and Analysis

The results of the analysis are displayed on Figures 1 through 4. Each plot displays the removal efficiency data for a different air pollution control equipment type in bar chart format. Each boiler tested is displayed as an individual data bar. Separate groupings are provided on each graph for bituminous coal, subbituminous coal and lignite. Horizontal lines are superimposed over the data to allow easy viewing of the performance of each equipment type in comparison to the three control levels of interest.

Within some categories of APC equipment, there are subcategories that make for natural groupings for evaluation purposes. These are explained in the discussion for each type of equipment in the sections below.

Electrostatic Precipitators

Figure 1 displays the comparison of mercury removal performance for boilers with an electrostatic precipitator (ESP) as the only control device. This is an important category in the ICR test data, because the majority of coal-fired boilers in the United States currently have this same control equipment configuration. The data for the bituminous and subbituminous coal groupings are separated into two subgroups based on the ESP location in the gas path relative to the air heater. The two subcategories are cold-side (CS), which is the typical situation in which the ESP is located after the air heater, and hot-side (HS), in which the ESP is located upstream from the air heater. No hot-side ESPs are included in the ICR data set for lignite-fired boilers.

In general, it can be seen that the mercury removal capability of existing ESPs typically does not even reach to the 50 percent control level. One exception to this found on the plot. The one cold-side ESP in the bituminous coal group, in which mercury removal extends to the 90 percent is on a unit that is equipped with a Selective Non-Catalytic Reduction (SNCR) system for NOx control. This may be related to the improved mercury control performance for this boiler.

Fabric Filters (Baghouses)

Figure 2 displays the ICR test results for boilers having a baghouse as the only control device. This is a much smaller subset of the U.S. boiler population than that represented in Figure 1. The striking thing about this data plot is the significant effect of coal type on mercury removal performance of these fabric filters. The bituminous coal cases consistently show about 85 percent mercury removal, but the other two coal types indicate significantly poorer performance. The fabric filters on boilers firing subbituminous coal or lignite appear to be capable of 50 percent mercury control, but generally cannot approach the 75 percent control level.

Dry FGD Systems

Figure 3 shows the mercury removal of the dry flue gas desulfurization (FGD) systems as determined from the ICR test runs. Recall that the ICR tests for dry FGD systems were always conducted to measure mercury removal from the inlet of the Spray Dryer Absorber (SDA) to the outlet of the downstream particulate collector. There are two types of particulate collectors used in the ICR test boilers firing subbituminous coal and using dry FGD systems. The data plot differentiates the systems using an ESP as the downstream collector from those using a fabric filter (FF). Somewhat surprisingly, the ICR test data does not indicate a dramatic difference between the mercury removal performance for dry FGD systems using a baghouse for particulate collection and that for systems using an ESP.

The differentiation in mercury control performance as a function of coal type is even more dramatic for the dry FGD cases than it was for the baghouse cases shown in Figure 2. All dry FGD systems on boilers firing bituminous coal show attainment of the 90 percent mercury control benchmark. The same type of system, when applied to a boiler firing subbituminous coal, can generally not reach even to the 50 percent control level.

Wet FGD Systems

The mercury removal across wet FGD systems from the ICR test data is plotted on Figure 4. It is important to note that although most of the wet FGD systems included in the ICR test program had ESPs or fabric filters located upstream, the tests were conducted only at the inlet to the wet FGD absorber and at the wet FGD system outlet (which in most cases was in the stack). Thus this data displayed on Figure 4 is not representative of the total mercury removal downstream from the boiler, but only the removal across the wet scrubbing system. This is an artifact of the test protocol established by EPA for the ICR tests. Rather than guess at the contribution of the upstream particulate collector to the total mercury removal, we present the data as it exists in the raw ICR test results.

Due to the factors noted above, it is not possible to directly compare the results for wet FGD systems as shown on Figure 4 to those for dry FGD systems as shown on Figure 3. However, the wet FGD mercury removal test runs have been differentiated within each coal grouping on Figure 4 by indication of the type of device used for upstream particulate control. The mercury removal of that device is not directly reflected, but there appears to be an indirect effect on the wet FGD mercury removal performance nonetheless.

It can be seen from the bituminous coal group that the wet FGD systems that had fabric filters located upstream generally achieved higher mercury removal efficiency than those with ESPs upstream. Although only two boilers (six test runs) are represented here, this could be reflective of some additional oxidation of elemental mercury in the flue gas as it passed through the dust cake on the bags in the fabric filter. It is known that wet FGD systems can easily remove mercury that is in the oxidized form. By comparison to Figure 2 it can be surmised that the combined mercury removal for a baghouse / wet FGD combination on a bituminous coal-fired boiler, although not directly tested in the ICR program, would certainly be at or above 90 percent.

Figure 4 also shows that the ICR test data for subbituminous coal-fired boilers with wet FGD systems experienced a significant percentage of tests runs in which negative removal efficiency for mercury is indicated. The data presented in the ICR "rawdata1.xls" file occasionally results in the calculation of negative removals (see Figures 1 and 3, for example), but the frequency of occurrence of this anomaly within this coal data subset is surprising.

Finally, Figure 4 shows that those boilers which featured a combination particulate matter scrubber / wet FGD system failed to achieve good mercury removal, and accounted for the majority of the runs in which negative removal efficiencies are indicated.

Conclusions

A review of the federal and state programs for regulation of mercury emissions from the utility boiler source category indicates that it is likely 90 percent control of mercury emissions leaving the boiler will be required by the end of the decade. A review of the mercury removal efficiency test data from EPA's extensive ICR test program indicates that existing air pollution control systems are not currently achieving this level of mercury control.

The exceptions to this are that dry FGD systems on boilers firing bituminous coal and wet FGD systems preceded by fabric filters on boilers firing bituminous coal are likely to be able to meet a 90 percent control requirement.

e-sources

Status of Mercury Control Legislation -- thomas.loc.gov

U.S. Environmental Protection Agency's Utility Air Toxics Web site -- www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html

This article originally appeared in the 03/01/2002 issue of Environmental Protection.

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