Emission Control, Power Plant
Emission Control, Power Plant
EMISSION CONTROL, POWER PLANT
Power plant emissions result from the combustion of fossil fuels such as coal, gas, and oil. These emissions include sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter, and hazardous air pollutants, all of which are subject to environmental regulations. Another emission is carbon dioxide (CO2), suspected of being responsible for global warming.
Historically, under both federal and state regulations, the demand for gas to heat homes and to meet needs of business and industry took priority over utility use to generate electricity. These restrictions have been eased by amendments to the Fuel Use Act in 1987, and, as a result, new gas-fired generation units are being constructed. However, coal-fired units continue to provide over 50 percent of the total utility generation of electricity.
Until the late 1960s, a typical electric utility scenario was one of steadily growing electricity demand, lower costs of new power plants through technological advances, and declining electricity prices. Utility companies appeared before Public Utility Commissions (PUCs) to request approval for rate reductions for customers. In the 1970s, multiple factors caused costs to increase dramatically: fuel costs escalated, primarily because of oil embargoes; legislators passed more stringent environmental laws requiring huge investments in emissions control technology; and these costs escalated as inflation and interest rates soared. When utility companies requested rate increases to cover these higher costs, PUC hearings were no longer sedate and routine. Cost recovery pressures continued throughout the 1980s as environmentalists succeeded in lowering emissions limits.
FORMATION OF POLLUTANTS IN UTILITY BOILERS
Sulfur is found in coal in organic forms as well as inorganic forms such as pyrites, sulfate, and elemental. Organic sulfur is the most difficult to remove, and reliable analytical methods are required to support coal-cleaning technologies designed to remove the sulfur prior to burning the coal. At the present time, most utilities burn "uncleaned" coal, and, upon combustion, most of the sulfur is converted to SO2, with a small amount further oxidized to form sulfur trioxide (SO3)
The sulfur content of coals available to utilities ranges from about 4 percent in high-sulfur coals to less than 1 percent in some Western coals. Although transportation costs may be higher for Western coals, many Eastern utilities elect to burn Western coals to comply with increasingly stringent SO2 regulations.
NOx emissions are less dependent on the type of coal burned, and two oxidation mechanisms are associated with the release of NOx into the atmosphere during the combustion process. Thermal NOx results from the reaction of nitrogen in the combustion air with excess oxygen at elevated temperatures, and fuel NOx is a product of the oxidation of nitrogen chemically bound in the coal.
Hazardous air pollutants (HAPs) are substances that may cause immediate or long-term adverse effects on human health. HAPs can be gases, particulates, trace metals such as mercury, and vapors such as benzene. For coal-fired power plants, the HAPs of most concern are metals such as mercury, arsenic, and vanadium.
All combustion processes produce particulate matter. Amounts and size distribution of the particulates emitted depend on a number of factors, including fuel burned, type of boiler, and effectiveness of collection devices.
A wide variety of control technologies have been installed by utilities throughout the United States to reduce the emissions of these pollutants. At the same time, research on new technologies is being conducted to ensure compliance with future environmental standards.
The legislation most responsible for addressing power plant emissions is the Clean Air Act. Initially established in 1970 with major amendments in 1977 and 1990, it provides for federal authorities to control impacts on human health and the environment resulting from air emissions from industry, transportation, and space heating and cooling. In the original 1970 programs, National Ambient Air Quality Standards (NAAQS) were established for six "criteria" air pollutants—SO2, NOx, particulate matter, ozone, lead, and carbon monoxide—at a level to protect human health and welfare and the environment with a "margin of safety." New Source Performance Standards (NSPS) were set for major new facilities projected to emit any pollutant in significant amounts. To receive an operating permit, a new unit must meet or exceed control standards established by the Environmental Protection Agency (EPA). In the 1977 Amendments, permits required control levels for new plants that were not only as stringent as NSPS but also reflected the best available technologies.
The reduction of atmospheric concentrations of the sulfur and nitrogen oxides blamed for acid rain was a major issue in the debate that led to the 1990 Clean Air Act Amendments (CAAA). The final legislative action is one of the most complex and comprehensive pieces of environmental legislation ever written.
- The 1990 CAAA contain the following sections:
- Title I: Provisions for Attainment and Maintenance of National Ambient Air Quality Standards
- Title II: Provisions Relating to Mobile Sources
- Title III: Hazardous Air Pollutants
- Title IV: Acid Deposition Control
- Title V: Permits Title
- VI: Stratospheric Ozone Protection
- Title VII: Provisions Relating to Enforcement.
Titles I and IV are most relevant to SO2 and NOx control. Title I establishes a 24-hour average ambient air standard for SO2 of 0.14 ppm. The NOx provisions require existing major stationary sources to apply reasonably available control technologies and new or modified major stationary sources to offset their new emissions and install controls representing the lowest achievable emissions rate. Each state with an ozone nonattainment region must develop a State Implementation Plan (SIP) that includes stationary NOx emissions reductions.
Title IV, the Acid Rain Program, addresses controls for specific types of boilers, including those found in coal-fired power plants. A two-phase control strategy was established. Phase I began in 1995 and originally affected 263 units at 110 coal-burning utility plants in twenty-one eastern and midwestern states. The total of affected units increased to 445 when substitution or compensating units were added. In Phase II, which began January 1, 2000, the EPA has established lower emissions limits and also has set restrictions on smaller plants fired by coal, oil, and gas. For example, the Phase I SO2 emissions limit is 2.5 lb/million Btu of heat input to the boiler whereas the Phase II limit is 1.2 lb/million Btu. In both phases, affected sources will be required to install systems that continuously monitor emissions to trace progress and assure compliance.
One feature of the new law is an SO2 trading allowance program that encourages the use of market-based principles to reduce pollution. Utilities may trade allowances within their system and/or buy or sell allowances to and from other affected sources. For example, plants that emit SO2 at a rate below 1.2 lb/million Btu will be able to increase emissions by 20 percent between a baseline year and the year 2000. Also, bonus allowances will be distributed to accommodate growth by units in states with a statewide average below 0.8 lb/million Btu.
The Clean Air Act of 1970 and the Amendments of 1977 failed to adequately control emissions of hazardous air pollutants, that are typically carcinogens, mutagens, and reproductive toxins. Title III of the 1990 Amendments offers a comprehensive plan for achieving significant reductions in emissions of hazardous air pollutants from major sources by defining a new program to control 189 pollutants.
Although the petrochemical and metals industries were the primary focus of the toxic air pollutants legislation, approximately forty of these substances have been detected in fossil power plant flue gas. Mercury, which is found in trace amounts in fossil fuels such as coal and oil, is liberated during the combustion process and these emissions may be regulated in the future. EPA issued an Information Collection Request (ICR) that required all coal-fired plants to analyze their feed coal for mercury and chlorine. Since these data will be used in making a regulatory decision on mercury near the end of the year 2000, it is critical that the power industry provide the most accurate data possible.
In 1987, health- and welfare-based standards for particulate matter (measured as PM10, particles 10 micrometers in diameter or smaller) were established. A 10 micrometer (micron) particle is quite small; about 100 PM10 particles will fit across the one millimeter diameter of a typical ballpoint pen. For PM10 particles, an annual standard was set at 50 micrograms per cubic meter (50 μg/m3) and a 24-hour standard was set at 150 μg/m3.
Since these PM10 standards were established, the EPA has reviewed peer-reviewed scientific studies that suggest that significant health effects occur at concentrations below the 1987 standards. In addition, some studies attributed adverse health effects to particles smaller than 10 microns. In July 1997, the EPA, under the National Ambient Air Quality Standards (NAAQS), added standards for particulate matter with a diameter of 2.5 microns or less (PM2.5). The annual PM2.5 standard was set at 15 μg/m3 and the 24-hour PM2.5 standard was set at 65 μg/m3.
Through implementing new technologies and modifying unit operating conditions, the electric utility industry has significantly reduced the emissions of SO2, NOx, and particulates since passage of the 1970 Clean Air Act and its subsequent amendments. With full implementation of Title IV of the 1990 CAAA, the 1990 baseline level of more than 14.5 million tons of SO2 will be reduced to 8.9 million tons per year. NOx emissions during Phase I will be reduced by 400,000 tons per year, and Phase II will result in a further reduction of 1.2 million tons per year. Particulate control devices, installed on nearly all coal-fired units, have reduced particulate emissions from more than three million tons per year in 1970 to less than 430,000 tons per year in 1990.
Over the years, utilities have funded research to develop technologies that not only will meet existing standards but also will meet future emissions reductions based on continuing concerns about acid rain, ozone, fine particulates, and other environmental issues. To remain competitive in the global economy, utilities must seek technologies that balance the conflicting drivers of productivity demands, environmental concerns, and cost considerations. Engineering designs should minimize costs and environmental impact, and, at the same time, maximize factors such as reliability and performance.
CLEAN COAL TECHNOLOGY PROGRAM
The Clean Coal Technology (CCT) Program, a government and industry cofunded effort, began in 1986 with a joint investment of nearly $6.7 billion. The recommendation for this multibillion dollar program came from the United States and Canadian Special Envoys on Acid Rain. The overall goal of the CCT Program is to demonstrate the commercial readiness of new, innovative environmental technologies. The program is being conducted through a multiphased effort consisting of five separate solicitations administered by the U.S. Department of Energy. Industry proposes and manages the selected demonstration ventures. Many of the projects funded in the first stages of the program are generating data or have finished their testing program. Within the next few years, the United States will have in operation a number of prototype demonstration projects that promise to meet the most rigorous environmental standards.
The CCT projects, in general, are categorized as follows:
- Advanced electric power generation
- a. Fluidized bed combustion
- b. Integrated gasification combined cycle
- c. Advanced combustion systems
- Environmental control technologies
- a. Sulfur dioxide control technologies
- b. NOx control technologies
- c. Combined SO2/NOx control technologies
- Coal processing for clean fuels
- a. Coal preparation technologies
- b. Mild gasification
- Indirect liquefaction
- Industrial applications.
The following sections describe the various compliance options for controlling emissions from utility power plants.
SULFUR DIOXIDE CONTROL TECHNOLOGIES
Three major compliance options for SO2 emissions available to utilities using coal-fired boilers are to switch fuels, purchase/sell SO2 allowances, or install flue gas desulfurization (FGD) technologies. Costs, availability, and impact on boiler operation must be considered when evaluating switching to low-sulfur coal or natural gas. As more utilities enter the free market to purchase SO2 allowances, prices will rise. Therefore, to minimize costs and, at the same time, meet environmental standards, power producers should continuously monitor the tradeoffs among these three options.
Although FGD processes, originally referred to as scrubbing SO2 from flue gas, have been available for many years, installations in the United States were quite limited until passage of the Clean Air Act of 1970. Even then, installations were usually limited to new facilities because existing plants were exempt under the law.
Projects in the CCT program demonstrated innovative applications for both wet and dry or semidry FGD systems. The wet FGD systems, which use limestone as an absorber, have met or exceeded the 90 percent SO2 removal efficiency required to meet air quality standards when burning high-sulfur coal. The dry or semidry systems use lime and recycled fly ash as a sorbent to achieve the required removal.
In wet FGD systems, flue gas exiting from the particulate collector flows to an absorber. In the absorber, the flue gas comes into contact with the sorbent slurry. The innovative scrubbers in the CCT program featured a variety of technologies to maximize SO2 absorption and to minimize the waste disposal problems (sludge).
A number of chemical reactions occur in the absorber beginning with the reaction of limestone (CaCO3) with the SO2 to form calcium sulfite (CaSO3). The calcium sulfite oxidizes to calcium sulfate (CaSO4) which crystallizes to gypsum (CaSO4 • 2H2O). The gypsum crystals are either stored in on-site waste disposal landfills or shipped to a facility where the gypsum is used in manufacture of wallboard or cement. The scrubbed gas then passes through mist eliminators that remove entrained slurry droplets. Recovered process water is recycled to the absorption and reagent preparation systems.
In the dry or semidry FGD system, the sorbent, usually lime, is injected into the flue gas stream before the particulate collection device. The lime, fed as a slurry, quickly dries in the hot gas stream and the particles react with the SO2. The resulting particles are then removed, along with the fly ash, by the particulate collection device.
NOX CONTROL TECHNOLOGIES
Combustion modifications and postcombustion processes are the two major compliance options for NOx emissions available to utilities using coal-fired boilers. Combustion modifications include low-NOx burners (LNBs), overfire air (OFA), reburning, flue gas recirculation (FGR), and operational modifications. Postcombustion processes include selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR). The CCT program has demonstrated innovative technologies in both of these major categories. Combustion modifications offer a less-expensive approach.
Because NOx formation is a function of the temperature, fuel-air mixture, and fluid dynamics in the furnace, the goal of a combustion modification is to mix fuel and air more gradually to reduce the flame temperature (lower thermal NOx production), and to stage combustion, initially using a richer fuel-air mixture, thus reducing oxidation of the nitrogen in the fuel. LNBs serve the role of staged combustion.
Overfire air (OFA) is often used in conjunction with LNBs. As the name implies, OFA is injected into the furnace above the normal combustion zone. It is added to ensure complete combustion when the burners are operated at an air-to-fuel ratio that is lower than normal.
Reburning is a process involving staged addition of fuel into two combustion zones. Coal is fired under normal conditions in the primary combustion zone and additional fuel, often gas, is added in a reburn zone, resulting in a fuel rich, oxygen deficient condition that converts the NOx produced in the primary combustion zone to molecular nitrogen and water. In a burnout zone above the reburn zone, OFA is added to complete combustion.
By recirculating a part of the flue gas to the furnace, the combustion zone turbulence is increased, the temperature is lowered and the oxygen concentration is reduced. All of these factors lead to a reduction of NOx formation.
Boilers can be operated over a wide range of conditions, and a number of operational changes have been implemented to reduce NOx production. Two promising technologies for staged combustion are taking burners out-of-service (BOOS) and biased firing (BF). With BOOS, fuel flow is stopped but air flow is maintained in selected burners. BF involves injecting more fuel to some burners while reducing fuel to others. Another operational modification is low excess air (LEA) which involves operating at the lowest excess air while maintaining good combustion. Depending on the type of boiler and the orientation of the burners, operators have viable choices to reduce NOx production. Advances in boiler control systems enable operators to minimize NOx and maximize performance.
Postcombustion processes are designed to capture NOx after it has been produced. In a selective catalytic reduction (SCR) system, ammonia is mixed with flue gas in the presence of a catalyst to transform the NOx into molecular nitrogen and water. In a selective noncatalytic reduction (SNCR) system, a reducing agent, such as ammonia or urea, is injected into the furnace above the combustion zone where it reacts with the NOx to form nitrogen gas and water vapor. Existing postcombustion processes are costly and each has drawbacks. SCR relies on expensive catalysts and experiences problems with ammonia adsorption on the fly ash. SNCR systems have not been proven for boilers larger than 300 MW.
COMBINED SO2/NOX/PARTICULATE CONTROL TECHNOLOGIES
The CCT program involves a number of projects that achieve reduction of SO2, NOx, and particulate emissions in a single processing unit. The technologies described are uniquely combined to achieve project goals and, at the same time, to provide commercial-scale validation of technologies for utilities to consider in order to meet environmental standards.
PARTICULATE CONTROL TECHNOLOGIES
The two major compliance options for particulate control are electrostatic precipitators and fabric filters (baghouses). Dust-laden flue gas enters a precipitator and high voltage electrodes impart a negative charge to the particles entrained in the gas. These negatively charged particles are then attracted to and collected on positively charged plates. The plates are rapped at a preset intensity and at preset intervals, causing the collected material to fall into hoppers. Electrostatic precipitators can remove over 99.9 percent of the particulate matter.
Fabric filters (baghouses) represent a second accepted method for separating particles from a flue gas stream. In a baghouse, the dusty gas flows into and through a number of filter bags, and the particles are retained on the fabric. Different types are available to collect various kinds of dust with high efficiency.
FUTURE INTEGRATED FACILITY
As the global economy expands and worldwide population increases, the demand for additional electric power will grow. The Utility Data Institute (UDI), a Washington, D.C.-based trade organization, estimates that new generating plants totalling 629,000 MW in capacity will be built worldwide by 2003. UDI projects that 317,000 MW, or more than half of this new capacity, will be installed in Asia. Estimates for other regions are: North America, 81,000 MW; European Union, 78,000 MW; Latin America, 55,000 MW; the Middle East, 34,000 MW; Russia and former Soviet Union, 34,000 MW; and other, 30,000 MW. UDI forecasts that fossil fuels will account for 57 percent of the new generating plants, with coal taking 31 percent, gas 19 percent, and oil 7 percent.
The opportunities and threats of the 1990s and for the foreseeable future are related to competition and deregulation. The challenge for utilities will be to produce electric power as cheaply as possible while still complying with environmental regulations.
The Electric Power Research Institute (EPRI), founded by the electric utility industry to manage technology programs, envisions the evolution of a fully integrated facility that produces numerous products in addition to electricity. The first step is to remove mineral impurities from coal. Some of the clean coal could be gasified to provide not only fuel for fuel cells but also products such as elemental sulfur and chemical feedstocks. The remainder of the clean coal can be used in conventional boilers or fluidized bed combustion systems to generate process steam and electricity. The ash resulting from the combustion process can be mined for valuable trace metals before it is used in applications such as road construction. By employing advances from the CCT program, the integrated facility will allow utilities to provide their customers with reliable electrical service and to meet present and future environmental standards.
Charles E. Hickman
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