Supply curves for using powder river basin coal to reduce sulfur emissions

Supply curves were prepared for coal-fired power plants in the contiguous United States switching to Wyoming's Powder River Basin (PRB) low-sulfur coal. Up to 625 plants, representing approximately 44% of the nameplate capacity of all coal-fired plants, could switch. If all switched, more than dollars 8.8 billion additional capital would be required and the cost of electricity would increase by up to dollars 5.9 billion per year, depending on levels of plant derating. Coal switching would result in sulfur dioxide (SO2) emissions reduction of 4.5 million t/yr. Increase in cost of electricity would be in the range of 0.31-0.73 cents per kilowatt-hour. Average cost of S emissions reduction could be as high as dollars 1298 per t of SO2. Up to 367 plants, or 59% of selected plants with 32% of 44% nameplate capacity, could have marginal cost in excess of dollars 1000 per t of SO2. Up to 73 plants would appear to benefit from both a lowering of the annual cost and a lowering of SO2 emissions by switching to the PRB coal.     

Flue gas desulfurization: the state of the art

Coal-fired electricity-generating plants may use SO2 scrubbers to meet the requirements of Phase II of the Acid Rain SO2 Reduction Program. Additionally, the use of scrubbers can result in reduction of Hg and other emissions from combustion sources. It is timely, therefore, to examine the current status of SO2 scrubbing technologies. This paper presents a comprehensive review of the state of the art in flue gas desulfurization (FGD) technologies for coal-fired boilers. Data on worldwide FGD applications reveal that wet FGD technologies, and specifically wet limestone FGD, have been predominantly selected over other FGD technologies. However, lime spray drying (LSD) is being used at the majority of the plants employing dry FGD technologies. Additional review of the U.S. FGD technology applications that began operation in 1991 through 1995 reveals that FGD processes of choice recently in the United States have been wet limestone FGD, magnesium-enhanced lime (MEL), and LSD. Further, of the wet limestone processes, limestone forced oxidation (LSFO) has been used most often in recent applications. The SO2 removal performance of scrubbers has been reviewed. Data reflect that most wet limestone and LSD installations appear to be capable of approximately 90% SO2 removal. Advanced, state-of-the-art wet scrubbers can provide SO2 removal in excess of 95%. Costs associated with state-of-the-art applications of LSFO, MEL, and LSD technologies have been analyzed with appropriate cost models. Analyses indicate that the capital cost of an LSD system is lower than those of same capacity LSFO and MEL systems, reflective of the relatively less complex hardware used in LSD. Analyses also reflect that, based on total annualized cost and SO2 removal requirements: (1) plants up to approximately 250 MWe in size and firing low- to medium-sulfur coals (i.e., coals with a sulfur content of 2% or lower) may use LSD; and (2) plants larger than 250 MWe and firing medium- to high-sulfur coals (i.e., coals with a sulfur content of 2% or higher) may use either LSFO or MEL.     

Supply Curves for Using Powder River Basin Coal to Reduce Sulfur Emissions

Abstract

Supply curves were prepared for coal-fired power plants in the contiguous United States switching to Wyoming's Powder River Basin (PRB) low-sulfur coal. Up to 625 plants, representing ～44% of the nameplate capacity of all coal-fired plants, could switch. If all switched, more than $8.8 billion additional capital would be required and the cost of electricity would increase by up to $5.9 billion per year, depending on levels of plant derating. Coal switching would result in sulfur dioxide (SO₂) emissions reduction of 4.5 million t/yr. Increase in cost of electricity would be in the range of 0.31-0.73 cents per kilowatt-hour. Average cost of S emissions reduction could be as high as $1298 per t of SO₂. Up to 367 plants, or 59% of selected plants with 32% of 44% nameplate capacity, could have marginal cost in excess of $1000 per t of SO₂. Up to 73 plants would appear to benefit from both a lowering of the annual cost and a lowering of SO₂ emissions by switching to the PRB coal.     

Flue Gas Desulfurization: The State of the Art

ABSTRACT

Coal-fired electricity-generating plants may use SO₂ scrubbers to meet the requirements of Phase II of the Acid Rain SO₂ Reduction Program. Additionally, the use of scrubbers can result in reduction of Hg and other emissions from combustion sources. It is timely, therefore, to examine the current status of SO₂ scrubbing technologies. This paper presents a comprehensive review of the state of the art in flue gas desulfurization (FGD) technologies for coal-fired boilers.

Data on worldwide FGD applications reveal that wet FGD technologies, and specifically wet limestone FGD, have been predominantly selected over other FGD technologies. However, lime spray drying (LSD) is being used at the majority of the plants employing dry FGD technologies. Additional review of the U.S. FGD technology applications that began operation in 1991 through 1995 reveals that FGD processes of choice recently in the United States have been wet limestone FGD, magnesium-enhanced lime (MEL), and LSD. Further, of the wet limestone processes, limestone forced oxidation (LSFO) has been used most often in recent applications.

The SO₂ removal performance of scrubbers has been reviewed. Data reflect that most wet limestone and LSD installations appear to be capable of ~90% SO₂ removal. Advanced, state-of-the-art wet scrubbers can provide SO₂ removal in excess of 95%.

Costs associated with state-of-the-art applications of LSFO, MEL, and LSD technologies have been analyzed with appropriate cost models. Analyses indicate that the capital cost of an LSD system is lower than those of same capacity LSFO and MEL systems, reflective of the relatively less complex hardware used in LSD. Analyses also reflect that, based on total annualized cost and SO₂ removal requirements: (1) plants up to ~250 MW_e in size and firing low- to medium-sulfur coals (i.e., coals with a sulfur content of 2% or lower) may use LSD; and (2) plants larger than 250 MW_e and firing medium- to high-sulfur coals (i.e., coals with a sulfur content of 2% or higher) may use either LSFO or MEL.     

Some Technical and Economic Aspects of Residual Fuel Oil Desulfurization

Combustion of residual, the most common type of fuel oil used in industrial and commercial steam generating plants, accounts for about 600,000 tons or 37 percent of the sulfur oxide emissions in New York state. On the average, residual oil available in New York state contains about 2.2 percent sulfur and is consumed at an annual rate of approximately 85 million barrels. The removal of sulfur from many types of residuals should become economically feasible as a result of the development of the HDS and H-Oil hydrodesulfurization processes. From studies recently made, these methods of desulfurization have been estimated to vary from a minimum of no appreciable increase in overall cost to a maximum of about one cent per gallon. The by-product distillates produced in hydrodesulfurization are a very significant factor in making the process economical and the demand for these is increasing at a greater rate than residual.     

Transferable Discharge Permits for Control of SO2 Emissions from Illinois Power Plants

A large scale simulation model was employed in evaluating various policy alternatives for reducing SO₂ emissions from Illinois electric power plants for a broad range of nuclear power capacity addition scenarios. A dynamic simulation of a transferable discharge permit (TDP) program suggests a market oriented management system can assure an acceptable level of environmental quality while achieving typical cost savings of 40-60 percent over a program based on uniform decreases in existing emission standards. This cost advantage can be realized without any major decline in the demand for coal generally or indigenous coals in particular. Several options for initiating the TDP market are evaluated. The analysis concludes that initiating the market by government sales may not constitute a major financial burden on the electric utilities or their customers.     

Performance Standards in Zoning

Burning of western low sulfur coal, to reduce sulfur oxide emissions, has resulted in decreased electrostatic precipi-tator collection efficiencies. In an effort to restore pre-cipitator performance a flue gas conditioning program was established by the company. This paper is a brief history of Commonwealth Edison Company’s experience with sulfur trioxide as a flue gas conditioning agent. Testing at State Line Station has proven that sulfur trioxide conditioning can effectively be used to improve precipitator performance when burning low sulfur coals. Although the first phase of the conditioning program is not completed, information has been gained which is being used as a basis in design and evaluation of future systems.     

A Computer Plot for a High Temperature Psychrometric Chart

This paper presents results of multivariate regression models developed to estimate the properties and cost of U.S. coals washed for varying degrees of sulfur removal using commercially available physical coal preparation processes. The models allow washed coal characteristics to be predicted from information on coal origin, heating value, ash, and sulfur content. The models were developed by first "processing" each of the 710 coals in the U.S. Bureau of Mines (USBM) coal washability data base through a coal preparation plant computer model which optimizes plant performance to achieve a desired washed coal quality. Washability data are adjusted to account for the inefficiencies of coal washing equipment, and the actual coal sizes treated by various plant wash streams. Since different plant designs may be capable of achieving a given level of sulfur removal, three nominal levels of plant complexity (Levels 2, 3, 4) were included to identify the most economical alternative. The washed coal characteristics thus derived were then analyzed using standard statistical techniques to develop regression equations linking washed coal properties and cost to raw coal properties for each of 18 geographical regions encompassing the entire U.S. These regression models are incorporated in the Advanced Utility Simulation Model (AUSM) to estimate the economic potential of coal washing as a sulfur abatement strategy, in conjunction with other options available to coal-fired power plants. Modeling results for Pennsylvania showed that washed coals frequently were selected as part of a cost-effective control strategy, accounting for 10 to 30 percent of the total emissions reduction, and that "local coal" restrictions significantly increase the use of washed coal as an SO₂ control strategy. Hypothetical requirements for mandatory coal cleaning, however, were found to be costly and ineffective.     

Sulfur Dioxide Emissions and Market Effects under the Clean Air Act Acid Rain Program

ABSTRACT

The Clean Air Act Amendments of 1990 (CAAA90) established a national program to control sulfur dioxide (SO₂) emissions from electricity generation. CAAA90's market-based approach includes trading and banking of Soumissions allowances. We analyzed data describing electric utility SO₂ emissions in 1995, the first year of the program's Phase I, and market effects over the 1990-1995 period. Fuel switching and flue-gas desulfurization were the dominant means used in 1995 by targeted generators to reduce emissions to 51% of 1990 levels. Flue-gas desulfur-ization costs, emissions allowance prices, low-sulfur coal prices, and average sulfur contents of coals shipped to electric utilities declined over the 1990-1995 period. Projections indicate that 13-15 million allowances will have been banked during the program's Phase I, which ends in 1999, a quantity expected to last through the first decade of the program's stricter Phase II controls. In 1995, both allowance prices and SO₂ emissions were below pre-CAAA90 expectations. The reduction of SO₂ emissions beyond pre-CAAA90 expectations, combined with lower-than-expected allowance prices and declining compliance costs, can be viewed as a success for market-based environmental controls.     

An Appraisal of Epidemiologic Data Concerning the Effect of Oxidants,Nitrogen Dioxide and Hydrocarbons upon Human Populations

A procedure is developed for determining costs to reduce air pollution emissions in a metropolitan area. Methods are. sufficiently general to be applicable in any region and sufficiently comprehensive to include analysis of all major sources, future trends, control limitations, and other factors of importance in a dynamic community. The analytical procedure examines relationships among emission inventories, regional growth, control trends, alternate control schemes, control costs, and optimum cost-effectiveness.

The cost analysis procedure is tested by application to the Delaware Valley. Costs are determined for reducing emissions to various levels between the years 1960 and 2000. Emissions from private automobiles are projected to decrease below the 1960 emission rate by 1980, at a cost of 150 million dollars per year. Stationary source emissions of sulfur dioxide and particulates can be reduced to 1960 levels by 1980 for 37 million dollars per year if "least cost" procedures are used (selective abatement). Uniform conversion to 0.5% sulfur fuel oil (equiproportional abatement) can effect a similar reduction in emissions for about 94 million dollars per year in 1980. Other cost analysis comparisons are made and projections to the year 2000 are included.     

The Relationship of Carbon Dioxide Emissions with Coal Rank and Sulfur Content

Carbon dioxide emissions, on an equivalent energy basis, were calculated for 504 North American coals to explore the effects of coal rank and sulfur content on CO₂ emissions. The data set included coals ranging in rank from lignite through low-volatile bituminous from 15 U.S. states and Alberta, Canada. Carbon dioxide emissions were calculated from the carbon content and gross calorific value of each coal. The lowest CO₂ emissions are calculated for the high-volatile bituminous coals (198 to 211 lbs CO₂/MMBtu) and the highest for lignites and subbituminous coals (209 to 224 lbs CO₂/MMBtu). The lower CO₂ emissions from the high-volatile bituminous coals result in part from their generally higher sulfur content. However, even at equivalent sulfur contents the high-volatile bituminous coals give lower CO₂ emissions than the lower-rank coals. On average, the lowerrank coals produce 5 percent more CO₂ upon combustion than the highvolatile bituminous coals, on the basis of gross calorific value. This difference increases to 9 percent on the basis of estimated net calorific value. The net calorific value is better indicator of power plant energy production than the gross calorific value. The difference in CO₂ emissions resulting from the use of high-volatile bituminous coals and lower-rank coals is of the same order of magnitude as reductions expected from near-term combustion efficiency improvements. These results are useful to those interested in current and future CO₂ emissions resulting from coal combustion.     

Environmental Irradiation Test Facility

Results from a detailed analysis of sulfur dioxide (SO₂) reductions achievable through “deep” physical coal cleaning (PCC) at 20 coal-fired power plants in the Ohio-Indiana-Illinois region are presented here. These plants all have capacities larger than 500 MWe, are currently without any flue gas desulfurization (FGD) systems, and burn coal of greater than l%sulfur content (in 1980). Their aggregate emissions of 2.4 million tons of SO₂ per year represents 55% of the SO₂ inventory for these states. The principal coal supplies for each power plant were identified and characterized as to coal seam and county of origin, so that published coal-washability data could be matched to each supplier. The SO₂ reductions that would result from deep cleaning each coal (Level 4) were calculated using an Argonne computer model that assumes a weight recovery of 80%. Percentage reductions in sulfur content ranged from zero to 52%, with a mean value of 29%, and costs ranged from a low of $364/ton SO₂ removed to over $2000/ton SO₂ removed. Because coal suppliers to these power plants employ some voluntary coal cleaning, the anticipated emissions reduction from current levels should be near 20%. Costs then were estimated for FGD systems designed to remove the same amount of SO₂ as was achieved by PCC through the use of partial scrubbing with bypass of the remaining flue gas. On this basis, PCC was more cost-effective than FGD for about 50% of the plants studied and had comparable costs for another 25% of the plants. Possible governmental actions to either encourage or mandate coal cleaning were identified and evaluated     

Air Pollution Assessments Of New Fossil Energy Technologies

This paper presents an overview on air pollution assessments of new fossil energy technologies for baseload electric generating plants. The discussion is oriented towards those who must understand the broad issues affecting the design and performance of such power plants. It is motivated by the potential air pollution problems caused by the near doubling of coal use projected for the next 15 years.

The paper first reviews the applicable emissions performance standards for these plants, as well as predictions of likely future standards needed to protect the environment. The conclusion is reached that significantly tighter emissions standards will apply in the future.

Next, the cost, emissions performance, and development status of the three major technology groups for coal fired baseload plants are reviewed. It is observed that while all of the technologies can meet the current standards, only the Baseline plant with Advanced Control Technology can meet future standards, without unreasonable increases in electrical generation costs. Furthermore, since Advanced Direct Combustion Technologies and Fuel Conversion Technologies are in very early stages of development, only the Baseline plant with Advanced Control Technology will be available to the utilities in the near term. This is because it will be evolved from the current commercial Baseline Technology.

Hence, it is concluded that the utilities will use mainly the Baseline coal fired plant with Advanced Control Technology to protect the environment for the next 15-20 years.     

Sulfur dioxide and nitrogen oxides emissions from U.S. pulp and paper mills, 1980-2005

Comprehensive surveys conducted at 5-yr intervals were used to estimate sulfur dioxide (SO,) and nitrogen oxides (NO.) emissions from U.S. pulp and paper mills for 1980, 1985, 1990, 1995, 2000, and 2005. Over the 25-yr period, paper production increased by 50%, whereas total SO, emissions declined by 60% to 340,000 short tons (t) and total NO, emissions decreased approximately 15% to 230,000 t. The downward emission trends resulted from a combination of factors, including reductions in oil and coal use, steadily declining fuel sulfur content, lower pulp and paper production in recent years, increased use of flue gas desulfurization systems on boilers, growing use of combustion modifications and add-on control systems to reduce boiler and gas turbine NO, emissions, and improvements in kraft recovery furnace operations.     

Sulfur Dioxide and Nitrogen Oxides Emissions from U.S. Pulp and Paper Mills, 1980–2005

Abstract

Comprehensive surveys conducted at 5-yr intervals were used to estimate sulfur dioxide (SO₂) and nitrogen oxides (NO_x) emissions from U.S. pulp and paper mills for 1980, 1985, 1990, 1995, 2000, and 2005. Over the 25-yr period, paper production increased by 50%, whereas total SO₂ emissions declined by 60% to 340,000 short tons (t) and total NO_x emissions decreased approximately 15% to 230,000 t. The downward emission trends resulted from a combination of factors, including reductions in oil and coal use, steadily declining fuel sulfur content, lower pulp and paper production in recent years, increased use of flue gas desulfurization systems on boilers, growing use of combustion modifications and add-on control systems to reduce boiler and gas turbine NO_x emissions, and improvements in kraft recovery furnace operations.     

Emissions of Sulfur Trioxide from Coal-Fired Power Plants

Abstract

Emissions of sulfur trioxide (SO₃) are a key component of plume opacity and acid deposition. Consequently, these emissions need to be low enough to not cause opacity violations and acid deposition. Generally, a small fraction of sulfur (S) in coal is converted to SO₃ in coal-fired combustion devices such as electric utility boilers. The emissions of SO₃ from such a boiler depend on coal S content, combustion conditions, flue gas characteristics, and air pollution devices being used. It is well known that the catalyst used in the selective catalytic reduction (SCR) technology for nitrogen oxides control oxidizes a small fraction of sulfur dioxide in the flue gas to SO₃. The extent of this oxidation depends on the catalyst formulation and SCR operating conditions. Gas-phase SO₃ and sulfuric acid, on being quenched in plant equipment (e.g., air preheater and wet scrubber), result in fine acidic mist, which can cause increased plume opacity and undesirable emissions. Recently, such effects have been observed at plants firing high-S coal and equipped with SCR systems and wet scrubbers. This paper investigates the factors that affect acidic mist production in coal-fired electric utility boilers and discusses approaches for mitigating emission of this mist.     

Control strategies of atmospheric mercury emissions from coal-fired power plants in China

Atmospheric mercury (Hg) emission from coal is one of the primary sources of anthropogenic discharge and pollution. China is one of the few countries in the world whose coal consumption constitutes about 70% of total primary energy, and over half of coals are burned directly for electricity generation. Atmospheric emissions of Hg and its speciation from coal-fired power plants are of great concern owing to their negative impacts on regional human health and ecosystem risks, as well as long-distance transport. In this paper, recent trends of atmospheric Hg emissions and its species split from coal-fired power plants in China during the period of 2000-2007 are evaluated, by integrating each plant's coal consumption and emission factors, which are classified by different subcategories of boilers, particulate matter (PM) and sulfur dioxide (SO2) control devices. Our results show that the total Hg emissions from coal-fired power plants have begun to decrease from the peak value of 139.19 t in 2005 to 134.55 t in 2007, though coal consumption growing steadily from 1213.8 to 1532.4 Mt, which can be mainly attributed to the co-benefit Hg reduction by electrostatic precipitators/fabric filters (ESPs/FFs) and wet flue gas desulfurization (WFGD), especially the sharp growth in installation of WFGD both in the new and existing power plants since 2005. In the coming 12th five-year-plan, more and more plants will be mandated to install De-NO(x) (nitrogen oxides) systems (mainly selective catalytic reduction [SCR] and selective noncatalytic reduction [SNCR]) for minimizing NO(x) emission, thus the specific Hg emission rate per ton of coal will decline further owing to the much higher co-benefit removal efficiency by the combination of SCR + ESPs/FFs + WFGD systems. Consequently, SCR + ESPs/FFs + WFGD configuration will be the main path to abate Hg discharge from coal-fired power plants in China in the near future. However advanced specific Hg removal technologies are necessary for further reduction of elemental Hg discharge in the long-term.     

Process Modifications for Air Pollution Control in Neutral Sulfite Semi-Chemical Mills

The body of information presented in this paper is directed to those individuals concerned with the air pollution control problems of the pulp and paper industry operation. Process modifications introduced at two Company mills, at Big Island, Va. and Tomahawk, Wis., where neutral sulfite semichemical pulping of hardwoods is performed at rates of 550 and 630 tons per day, respectively, are discussed. The methodology and concepts used to minimize total reduced sulfur and total sulfur oxide emissions from the recovery furnace of one of the operations are explained. In another major improvement already implemented in the Big Island Mill conventional hydrogen sulfide emissions from the sulfiting tower, on the order of 8–10 lb as sulfur per ton of pulp, have been completely eliminated by a process modification technique. Other aspects of the operations are described, and a forecast of possible emission levels for mills with a newer technology is made.     

Air impacts from three alternatives for producing JP-8 jet fuel

To increase U.S. petroleum energy independence, the University of Texas at Arlington (UT Arlington) has developed a direct coal liquefaction process which uses a hydrogenated solvent and a proprietary catalyst to convert lignite coal to crude oil. This sweet crude can be refined to form JP-8 military jet fuel, as well as other end products like gasoline and diesel. This paper presents an analysis of air pollutants resulting from using UT Arlington's liquefaction process to produce crude and then JP-8, compared with 2 alternative processes: conventional crude extraction and refining (CCER), and the Fischer-Tropsch process. For each of the 3 processes, air pollutant emissions through production of JP-8 fuel were considered, including emissions from upstream extraction/production, transportation, and conversion/refining. Air pollutants from the direct liquefaction process were measured using a LandTEC GEM2000 Plus, Draeger color detector tubes, OhioLumex RA-915 Light Hg Analyzer, and SRI 8610 gas chromatograph with thermal conductivity detector.

According to the screening analysis presented here, producing jet fuel from UT Arlington crude results in lower levels of pollutants compared to international conventional crude extraction/refining. Compared to US domestic CCER, the UTA process emits lower levels of CO₂-e, NOx, and Hg, and higher levels of CO and SO₂. Emissions from the UT Arlington process for producing JP-8 are estimated to be lower than for the Fischer-Tropsch process for all pollutants, with the exception of CO₂-e, which were high for the UT Arlington process due to nitrous oxide emissions from crude refining. When comparing emissions from conventional lignite combustion to produce electricity, versus UT Arlington coal liquefaction to make JP-8 and subsequent JP-8 transport, emissions from the UT Arlington process are estimated to be lower for all air pollutants, per MJ of power delivered to the end user.

Implications: The United States currently imports two-thirds of its crude oil, leaving its transportation system especially vulnerable to disruptions in international crude supplies. At current use rates, U.S. coal reserves (262 billion short tons, including 23 billion short tons lignite) would last 236 years. Accordingly, the University of Texas at Arlington (UT Arlington) has developed a process that converts lignite to crude oil, at about half the cost of regular crude. According to the screening analysis presented here, producing jet fuel from UT Arlington crude generates lower levels of pollutants compared to international conventional crude extraction/refining (CCER).     

Electric Utility Applications Of Fabric Filters

Encouraged by the successes attained with fly ash control by fabric filters in Pennsylvania Power & Light and Colorado Ute, other utilities are installing, planning, and/or considering baghouses as a practical and economical means for controlling emissions from the burning of low sulfur coals. Where deposits of alkaline reagents (i.e. nahcolite) are available, some power plants are also considering a process for dry scrubbing SO₂ from the flue gas. By introducing such reagents with the emission ahead of the fabric collector, both partlculates and SO₂ are removed.