Product Gudie/1987

A computer program has been written to determine the cost of building and operating wet scrubbers on individual coal fired utilities in the states where emissions are likely to affect the acid rain problem in the eastern United States. The program differs from many other estimates since it calculates the cost for each of 831 individual sites. The capital costs for installing scrubbers on the top fifty sulfur oxide emitting plants will be about $20 billion. This will result in an increase in the cost of electricity on an average of 0.88 cents/kWh and a reduction of sulfur oxide emissions from 1980 of 7,100,000 tons per year. An additional reduction of at least 1,000,000 tons per year can be obtained by requiring all plants burning oil to burn low sulfur oil. These figures assume utilities will use least emissions dispatching and will use local coals containing at least 3.5 percent sulfur. The use of local coals should result in a further saving of at least 0.2 cents/kWh. This should make available a large supply of low sulfur coal which could reduce emissions of sulfur oxides by up to 1,000,000 tons per year. The SO₂ reductions will be continued for at least the next thirteen years and have a very significant effect through the year 2010.     

Panel Calls Beneficiation-FGD Combination “Most Economical,Best Ail-Around Choice”

The Commerce Technical Advisory Board (CTAB) Panel on Sulfur Oxide mission Control Technology was established in the spring of_1975 by the Secretary of Commerce in response to the urgent need for the use of coal to meet the Nation’s energy requirements, while maintaining the SO₂ emission standards resulting from the Clean Air Act of 1970.

The Panel’s 20 members and 11 consultants, drawn broadly from industry, government, and academia are highly qualified in the diverse fields pertinent to SO_x control technologies. They committed themselves to make an objective analysis of how soon, at what cost, and with what trade-offs commercially available SO₂ continuous emissions controls can be installed, with arrangements for waste disposal, in all coal-fifed electricity generating plants in the populous Northeastern quadrant of the United States.

In its final report, submitted on September 10, 1975 to Dr. Betsy Ancker-Johnson, Assistant Secretary for Science and Technology, U. S.Department of Commerce, and Chairman of the Commerce Technical Advisory Board, the Panel concludes that installation and operation of continuous SO_x emission controls on all Northeastern coal-fired electricity generating plants cannot be met until the early 1980’s, and then only with a maximum effort beginning immediately. Specific site and market constraints will determine the most economical and practical control technology for any given plant. The Panel believes that coal beneficiation, alone where it meets standards, or combined with lime/limestone flue gas desulfurization, often represents the lowest cost control technique.     

Effectiveness of Odor Counteractants for the Treatment of Stack Gases

Successful control of some contaminant sources is extremely difficult to achieve technically and there remains a need for more information specific to control procedures. The cost of air cleaning equipment installations can be exceedingly high depending upon the performance standards to be satisfied and the physical and chemical characteristics of the contaminants. Control of emissions from the foundry cupola, the steel mill, metal refining operations, coal burning utilities, and incinerators still presents imposing cost and operational and performance problems—despite the technological progress made in recent years. The interrelationship of the source, the degree of control necessary, the equipment available to do the job, and the costs are discussed.     

Effect of nuclear power on CO<Subscript>2</Subscript> emission from power plant sector in Iran

Introduction  

It is predicted that demand for electricity in Islamic Republic of Iran will continue to increase dramatically in the future due to the rapid pace of economic development leading to construction of new power plants. At the present time, most of electricity is generated by burning fossil fuels which result in emission of great deal of pollutants and greenhouse gases (GHG) such as SO₂, NO_x, and CO₂. The power industry is the largest contributor to these emissions. Due to minimal emission of GHG by renewable and nuclear power plants, they are most suitable replacements for the fossil-fueled power plants. However, the nuclear power plants are more suitable than renewable power plants in providing baseload electricity. The Bushehr Nuclear Power Plant, the only nuclear power plant of Iran, is expected to start operation in 2010. This paper attempts to interpret the role of Bushehr nuclear power plant (BNPP) in CO₂ emission trend of power plant sector in Iran.     

Operating History and Current Status of Fabric Filters in the Utility Industry

Electric utilities have made significant progress in recent years in designing and operating baghouses for collection of coal fly ash. As a result, early concerns with high operating and maintenance requirements and short bag lives are no longer an issue. With increasingly stringent air emissions regulations and imminent revision of the Clean Air Act, baghouses have become an attractive particulate collection option for utilities.

In order to keep its member utilities apprised of the latest design and operation and maintenance experience with baghouses, the Electric Power Research Institute has been conducting surveys of utility baghouse user experience. This paper presents results from the latest survey, conducted in 1989. A previous survey was conducted in 1985. The 1989 survey was conducted using questionnaires mailed to the utilities, telephone inquiries, and plant visits. This paper discusses the general trends observed in baghouse design, performance, operation and maintenance.     

The Use of Combined-Cycle Power Systems in Nonpolluting Central Stations

The body of information presented in this paper is directed to power engineers oncerned with reducing pollution from future electric utility power stations. An Air Pollution Control Office sponsored study of advanced-cycle power systems and methods of desulfurizing fuels investigated a large number of conventional and nonconventional power systems for use by electric utilities. These systems included current and advanced steam systems, steam systems with topping and bottoming cycles, closed-cycle gas turbines, and open-cycle gas turbines alone and combined with steam systems. Also considered were various methods for desulfurizing coal and residual oil, such as mechanical and chemical separation, hydrodesulfurization and gasification followed by gas clean up. The major conclusion of this study is that the most effective and economical means of reducing objectionable effluents from future fossil-fueled power stations appears to be gasification of high-sulfur fuel to produce a low-heating-value fuel gas for use in a combined gas turbine and steam (COGAS) power system. Recent and prospective advances in military and commercial aircraft gas turbine technology, particularly in the area of high-temperature operation, can be applied to industrial gas turbines to yield the high-performance, low-cost, and long-lifetime characteristics desired for base-load power generation.

A COGAS pilot plant burning gasified coal should be built at the earliest possible time. Experience gained in the pilot plant could allow introduction of commercial sized stations within this decade.     

The Nationwide Program for Maintenance of Air Quality

The initial state implementation plans concentrated on attainment of the ambient air quality standards in the relatively polluted areas of the country. Many of these plans must now be modified to ensure that the ambient standards will be maintained for the foreseeable future, and to ensure that significant deterioration of air quality in clean areas of the country is prevented.

The existing implementation plans currently contain many measures which are applicable to the maintenance and deterioration efforts, but additional measures must also be developed. Many of these additional measures will involve future planning activities—most common of which will be land use planning activities.

The point is made that, after existing sources have reduced their emissions to the lowest practical level, further air pollution control can only be accomplished by implementing rational planning procedures for management of any new sources of air pollution. This will require extensive cooperation among the air pollution control community; regional, state, and local planning agencies; state and local governments; and the general public in order to ensure that future land use plans include appropriate air quality considerations.     

Atmospheric emissions of mercury from Australian point sources

The UN Global Mercury Assessment (GMA) estimates that atmospheric emissions of mercury from Australian stationary combustion sources were 97.0 tonnes for the year of 1995. This is more than 90% of the estimated emissions from stationary combustion for the whole of North America, and seems abnormally high for a country with a population of around 20 million, in spite of the fact that most of Australia's stationary energy supply is provided by coal. It is also significantly larger than previous estimates of mercury emissions from Australian sources. New estimates of Australian mercury emissions from stationary energy sources, based on both a top down and bottom up approach, are presented. These estimates can be reconciled for black coal fired power stations, but suggest that the bottom up approach (the Australian National Pollutant Inventory) significantly under-estimates emissions from brown coal fired plant, if mercury capture efficiencies in these plants are low, as observed for lignite-fired plant. The major uncertainties in these estimates are the coal mercury content in coals burnt in Australian power stations, and the mercury capture efficiency in particulate control devices used at these stations. Based on these estimates, Australian emissions of mercury from stationary energy are currently 2–8 tonnes/year, significantly lower than the GMA estimate.     

PISCES: Tracking Trace Chemicals in Power Plants

PISCES, Power Plant Integrated Systems: Chemical Emissions Studies, is a multimedia chemical species project on plant emissions. Products generated in the PISCES project will help utilities design and operate their plants to minimize chemical species emissions. PISCES takes a holistic approach to the control of toxics by acknowledging that a chemical removed from a gas stream will appear in a liquid or solid stream.     

Advanced Concepts in FGD Technology: The SHU Process with Cooling Tower Discharge

The growing awareness of ecological issues in Europe, reinforced by the public debate surrounding acid rain, has led to the enactment of laws and regulations in West Germany relating to emissions from large coal fired combustors.

Flue gas desulfurization (FGD) units have been compulsory for new coal fired power plants in West Germany for about 12 years. The new legislation enacted in 1983, to be met by the middle of 1988, applies not only to new plants but, unlike in the United States, also to. existing power plants (>30MW).

The law currently specifies a residual SO2 emission level of 400 mg/Nm³ (0.311b MM/BTU) for large power plants (>100 MW), but a level of 200 mg/Nm³ (0.15 lb MM/BTU) is already under discussion in some cases. The legally binding emission standards stipulate that none of the daily averages, calculated on the basis of half hour averages may exceed the concentration allowed. SO2 removal efficiencies of 90 percent to 95 percent are normally provided. Since 1983, more than 35,000 MW of retrofit FGD units have been installed in Germany to meet this SO₂ standard.

The regulations also do not allow for the ponding of calcium sulfite scrubber sludge, but stipulate the production of gypsum from limestone slurry processes. Additionally the regulations require flue gases to have a minimum temperature in the stack of 72° C (162°F) after desulfurization. Treated flue gases do not have to be reheated if discharged via a cooling tower.     

Issues and Trends in Electrostatic Precipitation Technology for U.S. Utilities

The pace and direction of electrostatic precipitator (ESP) technology evolution in the United States will be governed by two key forces. The first is new clean air legislation passed by the U.S. Congress and signed by President Bush on November 15,1990. This law requires electric utilities to further reduce SO₂ and NO_x emissions, which may impact particulate controls. In addition, very fine (< 10 micron) participates and potentially toxic trace emissions from utility power plants may be regulated. The second major factor is the expected upsurge in new plant construction beginning in the late 1990s. Together, these forces should define the performance requirements and market for new ESPs.

This paper identifies and briefly describes technologies that the Electric Power Research Institute (EPRI) is developing to help U.S. utilities meet these challenges cost-effectively. Among the technologies addressed are: advanced digital voltage controls, flue gas conditioning, intermittent energization, temperature-controlledprecharging (i.e., two-stage ESP), wide plate spacing, positive energization of corona electrodes for hot-side ESPs, and integration of conventional ESPs with pulse-jet baghouses.     

Reduction of Air Pollution Potential through Environmental Planning

Amelioration of the air pollution problem, whether the result of mobile or stationary source emissions, will depend primarily upon mechanical controls and fuel and process changes. Urban and transportation planning, however, may provide supplementary means for reducing both emissions of pollutants and the exposure of persons to undesirably high ambient concentrations. The body of information in this paper is directed to the planners and policy-makers whose decisions influence the nature of our environment. Three general areas are identified in which the policies, plans, and standards developed by environmental planners influence the air pollution problem : 1. Long-term, large-scale urban planning involving entire or substantial parts of metropolitan areas.

2. Design and operation of transportation systems.

3. Location, design, and construction of individual roadways and structures.

In each of these three areas, the Air Pollution Control Office has initiated projects that will assist planners in evaluating the air pollution implications of their activities. One study estimates motor vehicle emissions for two alternative metropolitan land use plans proposed for the Puget Sound Region. Because land-use patterns differ, the location and intensity of transportation demands also differ. Total motor vehicle pollutant emissions are found to vary appreciably between the two plans. A second study measures the variation in pollutant concentrations at various vertical and horizontal distances from existing roadways. Relationships are being established between meteorological factors, traffic flow characteristics, and pollutant concentrations that will assist in predicting the environmental impact of proposed roadways.     

Gaseous Emissions from Unregulated Mobile Sources

The impact of gaseous exhaust emissions is determined for the following categories of mobile sources which are currently not covered by national emission regulations: 1) farm equipment, 2) merchant vessels, 3) locomotives, 4) lawn and garden implements, 5) snowmobiles, 6) outboard motors, 7) transport refrigeration units, and 8) helicopters. Mass emission rates of each category are tabulated and compared to other emissions from both mobile and stationary sources in selected Air Quality Control Regions. Also, projections are made as to the expected increase of emissions from each source category through 1990. The results show that in the near future some categories of mobile sources will be contributing substantial amounts of pollutants, on a mass basis, in regions with critical air pollution problems. As stricter emission standards on regulated sources continue to be implemented, the relative significance of these unregulated sources will increase. The major conclusion is that broad generalizations as to the amounts of air pollution contributed by these unregulated mobile sources nationwide may be grossly misleading. The only effective way to assess their impact is on a region-by-region basis. To this end, generalized computer programs are developed which permit the estimation of each category’s present and future mass emission rates in any Air Quality Control Region in the country     

ESP Performance with Atmospheric Fluidized-Bed Combustion

Electric utilities considering atmospheric fluidized-bed combustion (AFBC) as an economic way to reduce SO₂ and NO_x emissions at coal-fired power plants must evaluate the impact AFBC will have on existing or planned plant systems and components. Because fly ash in AFBC units can have characteristics significantly different from that generated in pulverized-coal-fired boilers, a particular concern in this regard is the performance of the plant's particulate control equipment.     

燃煤工业锅炉排放二氧化硫对大气的污染及工业固硫型煤的应用

本文论述了我国燃煤工业锅炉排放ＳＯ２对大气污染的状况及发展趋势,以及应用工业固硫型煤控制燃煤工业锅炉对大气的污染。燃煤工业锅炉燃烧工业固硫型煤时,可明显地降低ＳＯ２和烟尘的排放量,并节约煤炭。在当前及今后相当长的时期内,推广和发展工业固硫型煤,是防治燃煤工业锅炉大气ＳＯ２污染的一条投资少、见效快、简便易行的实用措施,其经济效益及环境效益相当可观。     

Acid Rain Emission Allowances and Future Capacity Growth in the Electric Utility Industry

While the new source emission offset provision contained in recent acid rain proposals would result in increasing utility costs over time, the demand for emission offsets from new powerplant units should be satisfied even under conditions of high future growth in electrical generating capacity. This is because the amount of emissions from new generating units will be small relative to the quantity of offsets that could be made available in the emission “allowance” market.

Under the President’s July 1989 proposal, most utilities would be able to reduce their emissions well below their allowance levels via fuel switching, the installation of control technology, or the use of other emission reduction techniques, in order to create more “headroom” for the construction of new generating units. Retirements and decreasing utilization of existing power plants over time would liberate other emission allowances for use by new units. Industrial sources could “opt in” to the acid rain program and provide allowances for new generating units as well. A number of provisions in the recently passed Senate and House bills would make still further sources of allowances available to offset emissions from new generating capacity.

Hoarding of allowances by utilities is unlikely to be a problem since allowances would be distributed to at least 88 utilities in 34 states, and many of these utilities would have the ability to cost-effectively free up more allowances through “overcontrol” than they would need to cover their own future growth. Even a relatively small number of utilities in a limited number of states would have the ability to supply all of the allowances needed to cover new capacity growth from those entities that could not otherwise provide their own offsets. At projected prices of up to $800/ton, the incentives for utilities to sell allowances would be considerable. Moreover, if hoarding did begin to occur, the price of allowances would respond by rising to higher levels and the incentives for utilities to sell allowances would become even more compelling, as greater opportunities would develop for reducing costs (and electricity rates).     

Simplified Models of U.S. Acid Rain Control Costs

Simplified algorithms are presented for estimating the cost of controlling sulfur dioxide (SO₂) emissions from existing coal-fired power plants on a state-by-state basis. Results are obtained using the detailed Utility Control Strategy Model (UCSM) to calculate the Impacts of emission reductions ranging from approximately 30 percent to 90 percent of projected 1995 emissions for 18 different scenarios and 36 states. Scenarios include the use of two dry SO₂ removal technologies (lime spray dryers and LIMB) as potential options for power plant retrofit, in addition to currently available emission control options including coal switching, coal cleaning and wet flue gas desulfurization (FGD). Technical assumptions relating to FGD system performance and the upgrading of existing cold-side electrostatic precipitators (ESP) for reduced sulfur levels are also analyzed, along with the effects of interest rates, coal prices, coal choice restrictions, plant lifetime, and plant operating levels. Results are summarized in the form of a 3-term polynomial equation for each state, giving total annualized SO₂ control cost as a function of the total SO₂ emissions reduction for each scenario. Excellent statistical fits to UCSM results are obtained for these generalized equations.     

Air Quality Management in Los Angeles: Perspectives on Past and Future Emission Control Strategies

The 1988 Air Quality Management Plan was approved by the Board of the California South Coast Air Quality Management District in March 1989. The District comprises the counties of Los Angeles, Orange, and Riverside, and the non-desert portion of San Bernardino county. Emissions reductions in the past have lead to significant improvement in air quality despite large increases in growth. However, the District, largely because of continuous growth, currently violates the air quality standards for ozone, carbon monoxide, nitrogen dioxide, and respirable particulate matter (PM₁₀). Based upon the AQMP, reduction of approximately 80 percent in emissions of oxides of nitrogen and volatile organic compounds is required to bring the District into compliance with all air quality standards in the next twenty years.

Achieving compliance will necessitate the use of advanced technologies, as well as some changes in lifestyle and management practices. Advanced technologies, including the use of electric vehicles powered by batteries or fuel cells, the use of cleaner burning fuels and advanced combustion modifications, and treatment of surface coatings and solvents are included in the AQMP. The Technology Advancement Office in the District was created to work with industry, universities, research institutes, and other local, state and federal agencies to identify, evaluate, and promote low emitting fuels and technologies. In addition to electricity, fuels burning cleaner than conventional gasoline or diesel are being tested to obtain emissions and durability data so that rational choices can be made for the future. Compressed natural gas, methanol and liquefied petroleum gas are considered to be cleaner burning fuels for current applications. Ethanol, butane, and various oxygenated blends are being evaluated, and the broader application of solar energy and hydrogen are being investigated.

The impact of various cleaner burning fuels on air quality is being addressed. To date, methanol is the only fuel for which results are available. These results indicate that methanol use in vehicles—with control of formaldehyde emissions below 15 mg/mile for light-duty vehicles—can provide air quality benefits for all criteria pollutants and certain air toxics. These benefits are greater for M₁₀₀ than M₈₅.

Several District advanced technology programs are described, including a reduction in emissions from paints and coatings, and the demonstration of electric vehicles.     

Problems of Meeting Multiple Air Quality Objectives for Coal-Fired Utility Boilers

Gaseous wastes and particulate emissions are produced in the process of burning coal to produce electrical energy. In attempting to control these gaseous wastes, changes in the operation efficiency of boilers and secondary equipment are likely to result, and in addition liquid and solid waste streams are produced. The interrelationships among the various forms of wastes and the effects of air quality control on process efficiency are often overlooked in studies of environmental quality management.

The study was undertaken to evaluate the technical alternatives for handling gaseous and particulate emissions from coal-fired boilers and to determine the feasibility of meeting several standards simultaneously. The gaseous emissions of major importance in the combustion of coal are parti culates, oxides of sulfur, and oxides of nitrogen. Particulates can be controlled by a tradeoff among further preparation at the mine (for additional ash removal), type of boiler, use of dust control equipment and high stacks for dispersion of residual emissions, if ambient air standards are considered. Oxides of sulfur reduction depends currently on fuel substitution, limestone additives in the boiler and some form of contact process such as wet scrubbing, or the use of high stacks. Oxides of nitrogen control in coal fired boilers is restricted to small reductions by either changes in boiler operation, such as lower excess air levels, adsorption during wet scrubbing or by dispersion from high stacks.     

Modeling Atmospheric Mercury Deposition in the Vicinity of Power Plants

Abstract

Two mathematical models of the atmospheric fate and transport of mercury (Hg), an Eulerian grid–based model and a Gaussian plume model, are used to calculate the atmospheric deposition of Hg in the vicinity (i.e., within 50 km) of five coal–fired power plants. The former is applied using two different horizontal resolutions: coarse (84 km) and fine (16.7 km). More than 96% of the power plant Hg emissions are calculated with the plume model to be transported beyond 50 km from the plants. The grid–based model predicts a lower fraction to be transported beyond 50 km: >91% with a coarse resolution and >95% with a fine resolution. The contribution of the power plant emissions to total Hg deposition within a radius of 50 km from the plants is calculated to be <8% with the plume model, <14% with the Eulerian model with a coarse resolution, and <10% with the Eulerian model with a fine resolution. The Eulerian grid–based model predicts greater local impacts than the plume model because of artificially enhanced vertical dispersion; the former predicts about twice as much Hg deposition as the latter when the area considered is commensurate with the resolution of the grid–based model. If one compares the local impacts for an area that is significantly less than the grid–based model resolution, then the grid–based model may predict lower local deposition than the plume model, because two compensating errors affect the results obtained with the grid–based model: initial dilution of the power plant emissions within one or more grid cells and enhanced vertical mixing to the ground.