Development of Mercury Emissions Control Technologies for the Power Industry

Concern over the difficulty of limiting the emission of trace amounts of hazardous air pollutants in large flue gas streams to meet potential environmental regulations has been a driving force for the development and characterization of control technologies for utility boilers. In cooperation with the U.S. Department of Energy and the Ohio Coal Development Office, Babcock & Wilcox/McDermott Technology, Inc. has been conducting the Advanced Emissions Control Development Program to investigate the formation and control of these emissions from coal combustion in the 10 MWe-equivalent Clean Environment Development Facility. This paper discusses results recently obtained on mercury speciation and removal, and their potential implications on the applicability of such conventional technologies as electrostatic precipitators, baghouses, sorbent injection, and wet flue gas desulfurization for cost-effective control of mercury emissions. Introduction The combustion of coal in U.S. power generation facilities has historically represented the source potentially responsible for the largest quantities of pollutant emissions in the country. Because of this, the power industry has been, and continues to be, the focal point for the development and implementation of emission control technologies. The control of mercury emissions presents technical challenges not faced in earlier developmental efforts to capture fly ash, sulfur dioxide (SO2), and nitrogen oxides (NOx) that are all normally generated at relatively high concentrations in flue gas. Visible particulate emissions, resulting from coal’s ash content in the range of 3–20 weight percent, first received attention decades ago and are now routinely controlled at efficiencies of 99.7 percent and more by electrostatic precipitators (ESPs) and baghouses. Concern over the acid rain precursors SO2 (generated at concentrations of several hundred to several thousand parts per million (ppm) in proportion to the 0.2–6 weight percent of sulfur in the fuel) and NOx (compounds also typically found in the hundreds of ppm concentration range, usually as a function of combustion conditions) fostered the development of control methods for each. Wet flue gas desulfurization (FGD) technology has evolved from a typical 90 percent removal capability in the 1970s to more reliable and lower cost systems that can achieve 95–98 percent capture in systems being installed today. Because high NOx levels are typically more a combustion byproduct than something resulting only from fuel nitrogen content, efforts focused first on identifying low-NOx burner designs. This, sometimes combined with modifications of combustion techniques such as “reburn” technology, results in roughly 50 to 75 percent emissions reduction over those characteristic of earlier combustion techniques. Beyond these, overall NOx reductions in the 90 to 95 percent range are possible today with the addition of Selective Non-catalytic Reduction (SNCR, typically designed at 30 to 50 percent reduction) and/or Selective Catalytic Reduction systems (SCR, typically designed at 70 to 90 percent reduction). Passage of the Clean Air Act Amendments of 1990 significantly raised the degree of sophistication required for identification and possible control of extremely low concentrations of George A. Farthing Deborah Madden Yurchison Michael J. Holmes Babcock & Wilcox /McDermott Technology, Inc. Alliance, Ohio, U.S.A.