Utilities, sulfur dioxide emissions

National sulfur dioxide emissions by source category, 1997. Electric utilities account for almost two-thirds of SO2 emissions, even after initial implementation of the CAAA of 1990. Total SO2 emissions for 1997 were 18.5 million metric tons. 

For example, sulfur emissions from utility power plants in the United States are subject to an emissions cap and an allowance-trading system established under the Clean Air Act. An effective cap on annual sulfur dioxide emissions took effect in 2000, so no more than 8.95 million tons of SO can be emitted annually. Utilities that want to build another coal plant must purchase sulfur emission allowances from others who do not need them. This system provides a market incentive for utilities to reduce their sulfur emissions as long as the cost of such reductions is less than the price of purchasing the allowances. 

In the United States, amendments to the Clean Ait Act in November 1990 limited the amount of sulfur dioxide emissions that coal-based power utilities could produce. The cost of compliance incurred by the utilities was expected to be passed along to the power consumers. The U.S. Bureau of Mines estimated that the requirements to limit sulfur dioxide emissions would increase the operational cost of certain silicon producers by up to 0.02/kg (31). 

The 1990 Amendments to the U.S. Clean Air Act require a 50% reduction of sulfur dioxide emissions by the year 2000. Electric power stations are believed to be the source of 70% of all sulfur dioxide emissions (see Power generation). As of the mid-1990s, no utilities were recovering commercial quantities of elemental sulfur in the United States. Two projects had been announced Tampa Electric Company s plan to recover 75,000—90,000 metric tons of sulfuric acid (25,000—30,000 metric tons sulfur equivalent) annually at its power plant in Polk County, Florida, and a full-scale sulfur recovery system to be installed at PSI Energy s Wabash River generating station in Terre Haute, Indiana. Completed in 1995, the Terre Haute plant should recover about 14,000 t/yr of elemental sulfur. 

High sulfur content in coal hinders the use of coal resources because sulfur dioxide emissions from utility and industrial boilers are a cause of acid rain. Thus, research into the nature of sulfur in coal is important for improving coal utilization. Geochemical studies of sulfur in coal provide information about the abundance, distribution, and speciation of sulfur in coal. Many of these properties are determined by geological environments and processes of coal formation. 

While the development of flue gas clean-up processes has been progressing for many years, a satisfactory process is not yet available. Lime/limestone wet flue gas desulfurization (FGD) scrubber is the most widely used process in the utility industry at present, owing to the fact that it is the most technically developed and generally the most economically attractive. In spite of this, it is expensive and accounts for about 25-35% of the capital and operating costs of a power plant. Techniques for the post combustion control of nitrogen oxides emissions have not been developed as extensively as those for control of sulfur dioxide emissions. Several approaches have been proposed. Among these, ammonia-based selective catalytic reduction (SCR) has received the most attention. But, SCR may not be suitable for U.S. coal-fired power plants because of reliability concerns and other unresolved technical issues (1). These include uncertain catalyst life, water disposal requirements, and the effects of ammonia by-products on plant components downstream from the reactor. The sensitivity of SCR processes to the cost of NH3 is also the subject of some concern. 

The electric utilities were particularly opposed to legislation mandating expensive scrubbers to reduce sulfur dioxide emissions. The coal producers and miners wanted to ensure power plants continued to burn coal but had little concern about the costs imposed on the utilities. The United Mine Workers and some coal companies broke with the utilities in 1987 to support control measures that would have required scrubbers. 

Sulfur dioxide is a result of the combustion of fuels that contain sulfur, primarily coal and oil. Some coal has sulfur contents as high as 6% in the United States and 8% in China. Because of restrictions on sulfur dioxide emissions in the United States, most utilities now favor Western US coal, which is much lower in sulfur content than most Eastern coal. High concentrations of SO2 have many of the similar effects of other pollutants, including increased respiratory problems and the aggravation of cardiovascular illnesses. Electricity generation is responsible for over 60% of SO2 emissions in the United States. 

Regulations to reduce sulfur dioxide emissions result in the introduction of wet scrubber FGD systems, which can produce gypsum as a by-product. In 1990, overall annual sulfur dioxide (SOj) emissions from electric utility companies had fallen 46%. In 1990, the Clean Air Act Amendments were enacted, requiring electric utility companies nationwide to reduce their collective sulfur dioxide anissions. 

The biggest problem area in sulfur-dioxide emission control at smelters arises from converting which utilizes rotary (PS-) converters and the transfer of molten material in ladles, both open processes which release off-gases, including sulfur-dioxide into the working atmosphere. One... 

To further increase flexibility among electric utilities, Congress arranged an allowance trading system for sulfur dioxide emissions. Under this system, each power plant is allocated a number of allowances that represent how much sulfur dioxide it can emit each year. Each year, the number of allowances decreases. However, these allowances can be bought and sold among utilities. For example, a utility close to a mine with low-sulfur coal may decrease its emissions beyond what is required by switching to the cleaner coal. It may then sell its extra allowances to other utilities to pay for the difference in the cost of the coal. 

Acid deposition occurs when sulfur dioxide and nitrogen oxide emissions are transformed in the atmosphere and return to the earth in rain, fog or snow. Approximately 20 million tons of SOj are emitted annually in the United States, mostly from the burning of fossil fuels by electric utilities. Acid rain damages lakes, harms forests and buildings, contributes to reduced visibility, and is suspected of damaging health. 

Concerns about the environmental effects of emissions resulting from the combustion of fossil fuels, particularly coal, continue to increase as the utilization of these fuels grows. The large amounts of sulfur dioxide and nitrogen oxides emitted into the atmosphere and the attempts to tie these fossil-fuel-derived pollutants directly to the undeniably difficult problem of acid rain have caused heated debates, numerous research studies, government actions, and serious efforts to reduce pollution. The issues are extremely complex, and our understanding of the origin, properties, behavior, and effects of these pollutants is incomplete. Often, theories are contradictory. 

Two low-cost policies can jump-start this shift a renewable portfolio standard (rps) and a cap on co2 emissions in the electricity sector. An rps that requires 20 percent of U.S. electricity to be renewable by 2020 has very little net cost to the country and the huge benefit of reducing future natural gas prices.4 Under such an rps, electricity prices would be lower in 2020 than they are today, according to a 2001 study by the Energy Information Administration.5 Caps on electric utility emissions of sulfur dioxide, oxides of nitrogen, and mercury have been proposed by many policy makers because they will dramatically improve air quality and save the lives of tens of thousands of Americans. Analysis by the epa has shown that a relatively modest additional cap on grid co2 emissions—returning to 2001 levels by 2013—would add a mere two-tenths of a penny per kilowatt-hour in 2020, about 3 percent of electricity costs.6... 

Tn 1970, 20 million tons of sulfur dioxide emitted from steam electric-power plants. Without control measures these emissions will increase to 40 million tons by 1980. With typical SO2 concentrations in stack gas currently in the range of 1000-2000 ppm, target levels for future control legislation correspond to 50-150 ppm SO2 in the stack, and there are not sufficient low sulfur fuels to meet these standards. To fill the gap between projected supplies of low sulfur fuels and our nation s energy requirements, an economical, high efficiency process to remove SO2 from the fiue gases of power plants is required. Such a process must also recover SO2 in a form which can be readily handled and sold, in recognition of the quantities involved. Furthermore such a process must be compatible with the many constraints public utilities face in its installation and operation. 

Fig. 9 Integrated dry injection process utilizing both calcium hydroxide and sodium bicarbonate to reduce sulfur dioxide and nitrogen oxide emissions. Calcium hydroxide is added to the hot flue gases before they are cooled in the economizer and combustion air heater, while sodium bicarbonate is added to the cooled gases before they enter the electrostatic precipitator. (From Ref. l)...

Much of utiUty waste results from a combustion of fuel, whether for direct heating use, or indirect use in steam or electricity generation. Fuel combustion both depletes a resource and emits wastes wastes include carbon dioxide, sulfur dioxide, the oxides of nitrogen, and ash from unburned components of the fuel. The use of water in utility production results in water depletion and emission of aqueous wastes, often as purges necessary to avoid concentration of impurities. 

As the emission standards for sulfur dioxide become increasingly stringent and the fossil-fueled utilities become hard pressed to meet these standards, there is a strong incentive to improve the FGD system performance while minimizing the operating costs. 

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