Thank you, Mr. Chairman and members of the Subcommittee, for the opportunity to testify today. My name is Steve Benson, and I am a Senior Research Manager at the Energy & Environmental Center (EERC) at the University of North Dakota in Grand Forks, North Dakota. I have conducted and managed research, development, and demonstration projects on combustion and environmental control systems for the past 25 years.

The EERC has worked in the area of mercury research for over 20 years through projects supported by U.S. Department of Energy (DOE), the U.S. Environmental Protection Agency (EPA), state agencies, and industry and is recognized as a world leader on mercury measurement and control. One result of this work has been the establishment of the Center for Air Toxic Metals (CATM). Specifically, the EERC has conducted work in the following areas related to mercury emissions from coal-fired power plants:

* Mercury science and chemistry * Mercury sampling, measurement, and speciation in flue gases * Transformations of mercury forms during combustion and gas cooling * Mercury sorbent development and testing * Bench-, pilot-, and field-scale demonstrations of mercury control technologies * Mercury oxidation technologies * Coal properties impacts on mercury control

Today, I plan to provide a perspective on the challenges of controlling mercury emissions from power plants, with a focus on the issues related to western low-rank coals. Specifically, I will discuss the impacts of coal type on mercury speciation and control, options for control, and challenges to overcome.

Mercury Speciation and Control

Mercury emissions from utilities burning U.S. coals were determined under EPA’s Information Collection Request (ICR), which mandated mercury and chlorine analyses on coal shipped to units larger than 25 MWe during 1999 and required emissions testing on 84 units selected to represent different categories of air pollution control equipment and coal rank.

Based on ICR data, western coals (lignite and subbituminous) on average contain lower levels of mercury, chlorine, and sulfur than either eastern Appalachian or interior bituminous coals. Western coals are also distinguished by their much higher calcium and sodium contents. These differences in constituents have been shown to have important effects on the quantity and form of mercury emitted from a boiler and on the capabilities of different control technologies to remove mercury from flue gas.

The high chlorine content that is characteristic of eastern bituminous coals has been consistently shown to increase the fraction of the more easily removable oxidized form of mercury in the total mercury emission, as reported both in ICR tests and other mercury emission studies. Conversely, the experimental results indicate that the low chlorine content of western coals is associated with the emission of predominantly elemental mercury that is substantially more difficult to remove. The high calcium content of western coals appears to further reduce the oxidizing effect of the already low chlorine content by removing part of the chlorine throughout the combustion process. In short, distinctive differences for western coals result in significantly different mercury conversion mechanisms in the combustion process that present a unique challenge and employment of effective control technologies.

Measurements of total mercury and speciated mercury forms were made before and after the last pollution control device in the plants selected for testing under the ICR. These data provide a good starting point and valuable guidance for an experimental program targeted at developing mercury control technology for western coals. The changes in mercury speciation and removal measured across different pollution control devices have been correlated with fuel properties. Mercury removals were consistently lower for low-chlorine coals and, therefore, for western coals. For example, removals across a cold electrostatic precipitator (ESP) averaged about 35% for bituminous coal compared to 10% for western low-rank coal (lignite and subbituminous), and removals across a cold ESP followed by wet flue gas desulfurization (FGD) averaged 65% for bituminous coal compared to 35% for low-rank coal.

The percentage of elemental mercury in the flue gas leaving the furnace and ahead of the pollution control system tended to drop sharply, from over 85% to about 10% at coal chlorine contents greater than 150 to 200 ppm, which distinguishes western coal from eastern bituminous coal. In general, plants burning coals with low levels of chlorine did not reduce oxidized mercury across particulate control devices, whereas plants burning coals with high levels of chlorine did show some removal of oxidized mercury across particulate control devices. Additionally, fabric filters were the only particulate control devices that appeared to remove any appreciable amount of elemental mercury, but again, significant removal occurs only at coal chlorine contents above 200 ppm.

Both spray dryer absorbers and wet scrubbers remove approximately 90% of the oxidized gaseous mercury entering but essentially none of the elemental mercury. Therefore, they can be quite effective for mercury removal overall for high-chlorine coals but ineffective for low-chlorine coals.

In summary, the available experimental and field data indicate that existing pollution control technologies are not effective in controlling the emissions of elemental mercury emitted by low-chlorine western coals.

Mercury Control Options Being Investigated

Currently, the mercury control strategies for western coal-fired power plants involve, first, the enhancement of existing control technologies and, second, the investigation and development of new control technologies. The enhancement strategies include sorbent injection with and without flue gas modifications upstream of an ESP or fabric filter, and mercury oxidation upstream of a wet or dry FGD. The new technologies include mercury capture using the gold-coated materials, baghouse inserts, and carbon beds.

Sorbent injection upstream of an ESP or fabric filter. Many potential mercury sorbents have been evaluated, including carbon-based, calcium-based, and metal-based (i.e., gold, silver, etc.) sorbents. Activated carbon injection is the most promising and mature technology available for mercury control. However, the commercial experience is primarily from application of the technology at waste incinerators where very high chlorine levels are present. The projected annual cost for activated carbon adsorption of mercury in a duct injection system for a coal-fired utility is significant. Carbon-to-mercury weight ratios of 3000–18,000 (lb of carbon injected per lb of mercury in flue gas) have been estimated to achieve 90% mercury removal from a coal combustion flue gas containing 10 µg/Nm3 of mercury. Lower-cost and noncarbon-based sorbents that have less impact on fly ash sales and more effectively designed sorbent injection processes are needed to reduce costs of sorbent injection.

Recently pilot-scale testing of mercury removal efficiencies for activated carbon injection upstream of an ESP only and an ESP–baghouse (fabric filter) was conducted for a Fort Union lignite coal. The results, illustrated in Figure 1, for the ESP only were compared to those obtained at full-scale utility boilers, while injecting activated carbons into a bituminous coal combustion flue gas upstream of a ToxiconTM (pulse-jet FF) and into bituminous and Powder River Basin (PRB) subbituminous coal combustion flue gases upstream of an ESP. For the ESP cases, the pilot-scale lignite and utility-scale eastern bituminous coal tests showed mercury removal efficiency increased with increasing activated carbon injection rates. Conversely, mercury removal efficiency was never greater than 70%, regardless of the activated carbon injection rate into the PRB subbituminous coal combustion flue gas. This limitation is probably caused by the low amount of acidic flue gas constituents such as chlorides that promote mercury-activated carbon adsorption.

The use of the ESP–fabric filter showed good control efficiencies for lignite and bituminous coal because of the longer contact time with the activated carbon sorbents. However, testing conducted at a lignite-fired power plant equipped with a spray dryer baghouse firing Fort Union lignite indicated poor performance of conventional activated carbon injection to control mercury. The results indicate poor control efficiency for two different types of activated carbons. Mercury removal efficiencies were less than 35%. The poor results are due to the low chlorine containing flue gas and the high proportion of elemental mercury in the flue gas stream. These results re-emphasize the challenges associated with mercury control for low-rank western coals.

Researchers are striving to attain a more thorough understanding of mercury species reactions on activated carbon surfaces in order to produce more efficient sorbents. Sorbents for elemental mercury control must both oxidize the mercury and provide a binding site.

Figure 1. Pilot-scale ESP and full-scale ToxiconTM (ESP–FF) and ESP mercury removal efficiencies as a function of activated carbon injection rate.

Mercury oxidation upstream of wet and dry scrubbers. Mercury oxidation technologies being investigated include catalysts, chemical agents, and cofiring materials. The catalysts that have been tested include selective catalytic reduction (SCR) catalysts for NOx reduction, noble (palladium) metal-impregnated catalysts, and oxide-impregnated catalysts. The chemical agents include chlorine-containing salts and cofiring fuels that contain oxidizing agents.

SCR catalysts have been tested for their ability to oxidize mercury. The ability to oxidize mercury has shown mixed results. Mercury speciation sampling has been conducted upstream and downstream of SCR catalysts at power plants that fire bituminous and subbituminous coals. The results of testing indicate evidence of mercury oxidation across SCR catalysts when firing bituminous coals. However, when firing subbituminous coal, the results indicate limited oxidation. This is based on a limited number of tests, and more testing needs to be conducted on low-rank coals. The ability of SCR systems to contribute to oxidation appears to be coal specific and is related to the chloride, sulfur, and calcium content of the coal as well as temperature, specific operation of the SCR catalyst, and duration of exposure to flue gas. Western coal ash can cause blinding of the SCR catalyst and, therefore, limit the use of SCR for western coals.

Noble metal-impregnated catalysts have shown high potential to oxidize elemental mercury. Results from a slipstream device at a North Dakota power plant indicated that over 80% conversion to oxidized mercury is possible for periods of up to 6 months. Additional larger-scale, longer-term tests are still needed to determine if the technology is feasible. Tests were also conducted using iron oxides and chromium, with little success of oxidation.

Fuel additives for mercury oxidation have shown the potential to oxidize mercury. Chemical additives or oxidants such as chlorine-containing salts added to the lignite have shown the ability to convert elemental mercury to more reactive oxidized forms. Recent short-term testing conducted at a full-scale pulverized-coal-fired North Dakota power plant indicated the injection chloride salts resulted in increased mercury oxidation in the flue gas. Mercury oxidation of up to 70% was observed at a salt injection rate that resulted in an HCl concentration of 110 ppm in the flue gas. In addition, the injection of salt resulted in enhanced removal of mercury across the spray dryer baghouse with removal efficiencies of up to 50% in short-term field testing. Significant operational impacts were observed during the short-duration testing. Pressure drop across the spray dryer baghouse increased with salt addition. Air heater pluggage was observed with some of the salt compounds. The short tests also do not show the potential long-term impact on corrosion, operations, and waste disposal.

Conclusions

Currently, there is no single best technology that can be applied broadly to control mercury emissions from coal-fired power plants. Combinations of available control methods may be able to provide up to 90% control for some plants but not for others, depending upon coal type. Lignite- and subbituminous coal-fired power plants are faced with the most significant challenge because reliable, demonstrated control technologies for highly unreactive elemental mercury are not commercially available. Only limited short-term tests have been performed to date. Significant research, development, and field testing are required to prepare the electric utility sector for implementation of mercury standards.