- Email: [email protected]
Meeting emission standards with high-sulfur coals
Energy Vol. 11, No. 1 l/12, pp. 132551335, 1986 Printed in Great Britain
MEETING
0360-5442/86 Pergamon
$3.00 +O.OO Journals Ltd
EMISSION STANDARDS WITH HIGH-SULFUR COALS T. Y.
and C. S.
YAN
YANK
Mobil Research and Development Corporation, P.O. Box 1025, Princeton, NJ 08540, U.S.A. Abstract-The economics of strategies for meeting sulfur oxides (SO,) emission standards from furnaces fueled with high-sulfur coals has been assessed based on published data. The strategy of SO, control depends on how the coal is utilized. For large power plants, flue-gas desulfurization (FGD) is preferable to conversion of coal to clean fuel. In comparison with coal conversion, the total capital and operating costs for FGD are almost an order of magnitude lower, thermal efficiencies are higher, and utility requirements are lower. Even with possible breakthroughs in coal-conversion technologies, it appears that FGD will remain the economically preferred route to desulfurization. FGD has been in commercial operation since 1968, and the reliability of the process has reached an acceptable level. For industrial furnaces, direct combustion is preferred to gasification because gasification is inherently expensive. Fluidized-bed combustion is the only viable option for clean direct combustion of coal in small industrial furnaces. Fluidized-bed combustion has reached commercial status and is economically competitive in many parts of the world. For furnaces requiring gaseous or liquid fuels, gasification to medium-Btu gas is preferred. For domestic and commercial uses, coal can be gasified to clean, low-Btu gas. This is an old process and might be amenable to cost reduction through application of new technologies. The only other economically viable approach involves the production of clean solid fuel by compounding coal with additives such as limestone and manganese nodules.
INTRODUCTION
The U.S. National Environmental Policy Act (NEPA), signed into law on 1 January 1970, made environmental protection an official goal of national policy. Ambient air quality standards were set for the three most common pollutants: sulfur oxides (SO,), nitrogen oxides (NO,), and particulates (Table 1). To achieve these standards, the Environmental Protection Agency (EPA) specifications were set for new and modified fossil-fired steam generators. The most important pollutant pertaining to the use of high-sulfur coal is SO,. To comply with the latest Federal New Source Performance Standard promulgated in June 1979, SO, emission control has to be provided for all large systems utilizing coal fuels. Although not regulated under this law, the SO, emissions from small systems in industrial, commercial, and residential uses could become regulated in the future. In the United States, nearly 80% of coal consumption was for generation of electricity in 1979. This is not the case, however, in other parts of the world; for example, China depends on coal for about 70% of its commercial energy and as the primary fuel for domestic heating and cooking.’ There are strong interactions between environmental protection policies and energy po1icies.l An important factor in the limited growth of coal consumption as a fuel is the cost of meeting the environmental protection regulations. In this study, the economic and
Table 1. National Averaging time
Pollutant(s) Sulfur oxides
Particulates Nitrogen
oxides
Annual 24 hours” 3 hours! Annual 24 hours” Annualb 24 hours’
ambient
Primary ugms
air-quality
standards
Standard wm
Secondary up/m3
80.0
0.03
60.0
365.0
0.14
75.0 260.0 100.0 150.0
0.05 0.13
260.0 1300.0 60.0 150.0 100.0 250.0
‘Not to be exceeded more than once per year. bAlthough under consideration, this standard is not a requirement
at this time.
TDepartment of Economics, Drexel University, Philadelphia, U.S.A. 1325
Standard wm 0.02 0.1 0.5
0.05 0.13
T. Y. YAN and C. S. YAN
1326
technical merits of several methods for controlling SO, emissions are assessed and the most cost-effective strategies for SO, control are suggested for both large power plants and small-scale furnaces. Alternatives for sulfur emission control
Sulfur emission from power plants fueled with high-sulfur coal may be controlled: (1) prior to, (2) during, or (3) after combustion. Pre-combustion sulfur control can be accomplished by converting coal to clean fuels by gasification and liquefaction or by physical/chemical treatment of coal. The latter involves beneficiation via washing, flotation, and magnetic separation. Examples of chemical treatment include Meyers’ oxidative process and Battelle’s caustic treatment process. Since the technical viability of the various physical and chemical treatment methods has not yet been fully tested against stringent sulfur emission standards, only the coal gasification and liquefaction techniques are considered here. Sulfur emission control during combustion is exemplified by Consolidated Coal’s CO2 acceptor process2,3 and by Combustion Engineering’s process for boiler injection of limestone.4 Furnace injection systems tested by Tennessee Valley Authority (TVA) and Combustion Engineering indicated that the SO, removal efficiencies are limited with conventional equipment. However, the recent work performed by the U.S. Environmental Protection Agency and the Electric Power Research Institute (EPRI) in the area of Lime/Limestone Injection with multistage Burners (LIMB) has shown a great deal of progress in co-injection of lime or limestone with coal into boilers, and is now being tested at a utility scale. The other approach is fluidized-bed combustion, which has not yet been demonstrated in largescale utility uses. Programs are under way at TVA and EPRI for a utility demonstration plant projected to begin operation in the late 1980s. These processes are not included in this assessment for large power plants. However, fluidized-bed combustion appears to be a viable process for small-scale industrial and commercial complexes.5 Another possible method is to compound the coal with alkali oxides, such as lime, limestone, and dolomite, that react with SO, during combustion.6 SO, control after combustion, i.e. flue-gas desullurization (FGD), is represented by many processes at various stages of development, ranging from conceptual to commercial. The most advanced processes have been evaluated by McGlamery and Torstrick,7 and at Battelle Columbus Laboratories.8 Patterns
of coal utilization
and SO, control
In the United States, coal is mainly used for electricity generation. The consumption pattern in 1981 was electric utilities, 79.4%; industrial, 19.6%; residential and commercial, 1.0%; and transportation, 0 O /o. 9 It is expected, however, that as petroleum reserves are depleted in the future, the use of coal in industrial and residential applications will become more important. On the other hand, coal is now an important energy source for industries abroad. The coal consumption pattern in China is shown in Table 2.” The technical and economical viabilities, and thus the strategy for SO, control, depend Table 2. Fuel consumption pattern in China, 196&82 Total fuel consumption
Distribution (%)
Year
(104 ton coal eq.)
C0al
Oil
Gas
Hydropower
1960 1965 1970 1975 1980 1981 1982
30,180 18,901 29,291 45,425 60,275 59,447 61,937
93.9 86.4 80.9 71.9 71.8 72.7 13.9
4.1 10.3 14.7 21.1 21.1 19.9 18.7
0.5 0.6 1.0 2.5 3.1 2.9 2.6
1.5 2.1 3.5 4.6 4.0 4.5 4.9
Source: Chinese Annual Statistical Abstract, National Statistics Bureau, Chinese Statistics Publishing Co., p. 250, 1983.
Meeting emission standards with high-sulfur coals
1327
on how the coal is utilized. The important factors in determining the control strategy include process requirement, size, age, and physical arrangement of the equipment as well as environmental considerations. SO, control strategies will be discussed with respect to coal uses, namely, large power plants for electricity generation, industrial, and residential applications. The discussion will concentrate on large power plants for electricity generation because of their paramount importance. LARGE
POWER
PLANTS
The primary question for fueling a power plant with high-sulfur coal is: “What is the choice between FGD and conversion to clean fuels?“” In this assessment, the following processes that have been described and evaluated in the literature are considered as typical examples: (1) coal gasification yielding low-Btu, medium-Btu, or high-Btu gas; (2) coal liquefaction leading to SRC-I; (3) FGD using lime/limestone slurry scrubbing. Evaluation criteria Assessment of technology encompasses technical, economical, political, and social problems. Some of the factors can be quantified, but other equally important factors are intangible. The following factors must be considered and quantified: (1) the incremental cost for converting coal to clean gas or solvent-refined coal, and for desulfurizing the flue gas; (2) the thermal efficiencies as well as water and land requirements for alternatives; (3) the reliability and compliance with environmental regulations; and (4) the status of current technical developments and of commercial operations and their future potential in terms of alternatives. Incremental cost The cost effectiveness of SO, removal strategies is measured by incremental cost. The additional cost incurred in controlling SO, emissions is the incremental cost expressed in terms of $/MMBtu of thermal energy. For the conversion process to clean fuels, this includes all the costs associated with either gasification or liquefaction, as well as the loss in thermal efficiency. These can be obtained by subtracting the value of coal ($/MMBtu) from the product value ($/MMBtu). For FGD processes, incremental cost includes all of the scrubbing costs, as well as waste disposal costs and losses in thermal efficiency. Incremental cost is site specific. For our study, we surveyed published costs and used the average general range of costs. We included data from process inventors and developers, construction firms, operation firms, government agencies, and academic institutions. Because of variations in economics and methodology, estimates can differ when obtained from different sources. Although the details and accuracy of cost analyses are lost in such an approach, generally valid cost comparisons can be obtained with minimal risk of bias. In capital-intensive energy processes, the method of financing may be the most important economic factor.” An approach to decrease the impact of high investment is to use debt rather than equity financing. Utility companies have been using debt financing at a typical debt:equity ratio of 7525. The impact of financing method has been discussed by Dickenson,’ 3 and Siegel and Kalina. l4 An effort was made in this study to compare costs on utility type financing. Incremental cost also depends on the size of the process. For clean fuel processes, 250 x 10’ Btu/SD (k50,OOObbl/day of oil) is assumed to be the base size and is generally considered to be desirable for a commercial plant. It is further assumed that one such clean fuel plant will serve four 500-MW electric power plants simultaneously. To assess FGD, a dedicated system for a power plant of 500 MW was used in the base case. In terms of heat, this is equivalent to 120 x 109Btu/D if a heating rate of 10,000 Btu/kWh is used. The power plant is assumed to operate 6000 hr/yr. Both grass roots and retrofitted units were considered. The load factor is also important, particularly for capital-cost-intensive, clean-fuel processes. The projected cost of clean fuel is usually based on a 90% availability, which
1328
T. Y. YAN and C. S. YAN
is generally achieved in relatively mature processes. A general observation for typical cases is that the cost of clean fuels increases about 18% for each 10% decrease in plant availability. For the FGD process, loading factors of 60% and 80% are assumed for retrofitted and new units, respectively. An excellent review of economic and design factors for flue-gas desulfurization technology has been made by Dunlop.15 An analysis of variations in costs of FGD systems was also done by Bloom et a1.s In our study, a compound inflation rate of 8%/yr has been assumed, and the estimated costs were adjusted to 1981 as a reference year. The impact of process efficiency on cost is rather small so that the potential process improvements in the intervening years can be neglected. The incremental cost for FGD processes is about 75$/MMBtu. The incremental costs for clean fuels varies widely, ranging from 300 to 9OOb/MMBtu. The lowest cost for clean fuels is the low-Btu gas, which is still 4 times as expensive as the limestone or lime FGD process. From the incremental-cost point of view, FGD is clearly preferred over the clean fuel approaches. Resource requirement The resource requirement can be measured in terms of three aspects: capital investment cost, thermal efficiency, and utility requirements. Capital investment. Capital investment represents the physical resource on the surface but really means all the physical and manpower requirements for erecting the process plant. It is expressed in terms of $/MMBtu/D. The capital requirements for FGD processes are about $4OO/MMBtu/D, while the capital requirements for clean fuel process range from $1300 to 8200/MMBtu/D. The lowest estimate for the clean fuels is low-Btu gas, which is still 3.2 times more expensive than the lime/limestone FGD processes. As pointed out earlier, the low-Btu gas estimate appears to be too low due to optimistic estimates in early stages of development or improper cost escalation. From the capital investment point of view, FGD processes are clearly preferred over the clean fuel processes. This is especially important for the future when the demand for capital will greatly increase, particularly in the field of energy production. Thermal ejiciency. The thermal efficiency of the lime/limestone FGD process is 93%, and that for clean fuel processes is between 60 and 79%. This loss in thermal efficiency would be particularly crucial in areas of the world where coal is in short supply. Again, from the points of view of thermal efficiency and energy conservation, FGD processes are preferred over the clean fuel processes. Utility requirements. Among the utility requirements, water is the most crucial, particularly since the plants for conversion of coal to clean fuel need to be located near the mine mouth. The processes for converting coal to clean fuels use enough water to cause concern regarding its availability, particularly in the arid western states.’ ‘*I6 Relative costs The cost of FGD is likely to be always lower than the cost of converting coal to clean fuels. Glazer et aI.” have studied the cost of controlling emissions from clean fuel processes and expressed the cost of pollution control in terms of the percentage of the overall clean fuel cost. These percentages are 15-30%, 15-50%, and 6-28% for high-Btu gas, low-Btu gas, and liquid fuels, respectively. According to the average product costs, the corresponding emission controlling costs would be $1.052.10/MMBtu, %0&l-1.45/MMBtu, and $0.371.73/MMBtu, respectively. Such costs are in the same range of the FGD cost of $0.75l.OO/MMBtu. That is, the cost component for emissions control in clean fuel conversion processes is comparable to the total FGD cost. This is understandable because FGD is a pollution control step in fuel combustion and the pollution control steps in the fuel conversion processes could be equally or more costly than the FGD due to their increased complexity. It is tempting to conclude that under normal conditions fuel conversion processes will always be more expensive than FGD. The cost of clean fuel is typically between 4 and 6 times as expensive as coal in terms
Meeting emission standards with high-sulfur coals
1329
of heating value. This ratio has stood the test of time, including times of high inflation and of rapid technological development. The clean fuel/coal price ratio of 4-6 is reasonable enough to make the conversion process viable. Historical data show that the crude oil/coal price ratio has been around 3 since the turn of the century. As a result, coal conversion processes have never been economical until now. On the other hand, it is difficult to conceive how the FGD cost could increase from the estimated ratio of 1.75 to equal or exceed 4-6. In other words, it seems unlikely that the cost of FGD can equal or exceed the cost of coal conversion to synfuels. Choice of the control strategy Our literature survey indicates that FGD is the preferred strategy for SO, emission control in fuel power plants using high-sulfur coals. It involves lower incremental control costs, is less taxing on resources and capital requirements, is higher in thermal efficiency, and has lower utility requirements. Use of FGD scrubbing processes also leads to nearly complete control of particulate emissions and a substantial reduction in NO, emissions. While not competitive for fueling a conventional power plant, clean fuels can be employed advantageously in other systems. For instance, clean gas can be used in a combined-cycle system to improve thermal efficiency and reduce capital requirement. The economics of various gasification and combined-cycle systems have been investigated by Beckman et al.” Such schemes impro ve the economics of the clean fuel approach significantly but still remain noncompetitive with FGD. The Coolwater Gasification Combined-Cycle Power Generation project by Southern California Edison and EPRI has demonstrated its technical feasibility, but the early indication is that the power cost is 10% or so higher than the conventional coal-fired steam plant with FGD. The decision by Virginia Electric to proceed with 400-MWe utility gasification combined-cycle power plants may be based on sitespecific economics. Clean fuels could become attractive when they are used as turbine fuels in peak shaving and when the low capital cost of the turbine (vs a conventional steam power plant) is taken into account. Retrofit installation to existing power plants Retrofit installation of FGD systems in existing plants requires higher capital costs than in new plants. An FGD system for a new plant can be incorporated into the overall design of the plant, while a retrofit installation requires that the system be adapted to the rigid configurations of the existing plant. Thus, the cost of retrofitting is rather site specific. Burchard has quantitatively rated the difficulty of retrofitting various plants (Table 3) and expressed this in terms of a difficulty factor that can be used as a multiplier to the retrofit scrubber cost.lg The scale ranges from 1.0 for a new plant to 1.5 for a difficult retrofit case. That is to say, the more difficult to retrofit case can cost 50% more than a corresponding new plant. About 20% of the electrical capacity surveyed by Burchard had no space for scrubbers (thus making retrofitting impossible) or was rated above a difficulty factor of 1.5. Clean fuels from coal may find a pplication in such plants. The remainder was about uniformly distributed between 1.125 and 1.5. These results are consistent with those of DeVitt et al.” For existing plants with retrofit difficulty factors up to 1.5, which represent about 80% of the installed coal-fired electrical capacity in the United States, FGD remains the less costly alternative to SO, emission control, compared to clean fuel alternatives. The clean fuel processes are about an order of magnitude more expensive than FGD, so that a 50% increase in retrofitting costs will not affect the attractiveness of FGD. The difficulty of retrofit is strongly related to the age and size of boilers (Table 3). As would be expected, newer and larger units are easier to retrofit than older and smaller units. Besides the increased cost of retrofitting, the cost of FGD also depends on the life of the power plant itself, for the life of the newly retrofitted scrubbing unit will have a life equal to the remaining life of the power plant. Consequently, it probably will not be worthwhile to retrofit power plants substantially older than 15 yr.
T. Y. YAN and C. S. YAN
1330
Table 3. Average retrofit difficulty factors” as a function of plant size and age” Dificultyfactor, by unit age (yrs) Unit size (MW) o-99 loo-199 200-499 500+
o-9
10-19 -
1.33 1.26
20+ 1.51
1.34 1.29
“These factors are for application to direct scrubber cost.
Conversion of existing power plants from high-sulfur coal to clean fuels also requires certain modifications. The cost of such conversions, which has been studied by Schreiber et a1.21, also makes FGD more attractive relative to the clean fuel processes. Status and development of FGD
FGD systems are generally considered by the regulators to be the most effective method for controlling SO, emissions from power plants. The growth of FGD systems in terms of equivalent scrubbed capacity has been studied by DeVitt et al.” From the first installation in 1968, the capacity of FGD approached 20,000 MW equivalent in 1980, and is projected to exceed 70,OOOMW by 1988. The revised SO, New Source Performance Standards (NSPS), promulgated by the EPA in June 1979, require new coal-fired units to have some type of continuous control device. These regulations are stringent enough to require the use of FGD systems in nearly every case. Approximately 6% of total coal-fired power-generating capacity is now controlled by FGD; this is expected to increase to about 25% by 1988. The operating FGD units are mainly wet, calcium-based systems producing a sludge by-product that must be disposed of in an environmentally sound manner. They account for 90% of the total capacity. 22 The utility industry’s preference for limestone processes is expected to continue in the foreseeable future, primarily due to process economics, e.g. the incremental costs are 60 and $1.73/MMBtu for limestone and Welman-Lord processes, respectively. Since the first commercial application of FGD in 1968, the process of developing and improving the technology continues. The early calcium-based FGD systems were plagued with fouling and plugging of scrubbing hardware. In recent years, the process has been sufficiently improved to attain an acceptable reliability. On-stream factors exceeding 90% are now common. For example, factors of 94-96% and 90% are reported for the Colstrip Unit No. 1 of the Montana Power Company and the La Cygne Unit No. 1 of the Kansas City Power and Light, respectively. Building on experience gained in the operation of the first generating systems, suppliers and designers are providing better design configurations and construction materials. Further improvements in reliability and reductions in costs can be expected. Some promising second-generation calcium-based FGD systems are being developed. Among the most promising are: the lime-slurry spray-drier/fabric filter process and the Chiyoda Thoroughbred 121 process. The first process uses a slurry of hydrated lime Ca(OH),, calcium sulfite, and fly ash to sorb SO2 from the flue gas by contact with atomized droplets of the alkali slurry. This process appears to be most attractive for lowsulfur coal. Initial estimates show that the cost could potentially be as little as half that of lime/limestone slurry process. I5 The study at Argonne National Laboratory using a 20MW boiler also showed that the lime-based spray-drier scrub system is economical and reliable, and can be used for retrofitting the existing boilers.31 SO2 absorption, sulfite/bisulfite oxidation, and precipitation of calcium sulfate and gypsum are accomplished in a single reaction vessel. Virtually all of the sulfur is removed as an easily dewatered gypsum slurry that reduces waste disposal problems and improves reliability.
Meeting emission standards with high-sulfur coals INDUSTRIAL
1331
USE
Coal for industrial use is about 20% of use in the United States, or a quarter of that for power plant use. However, coal use in industry is expected to become more important in the future, for economic and political reasons. When coal is used, the replaced oil and gas can be used for transportation fuel. Depending on the process requirements, coal can be used as fuel in industry in two ways: direct combustion and conversion to clean fuel before combustion. For example, direct combustion can be used in boilers for generation of steam and electricity. More than 80% of coal in industrial use is for these purposes. On the other hand, direct coal combustion is difficult or impossible for process heating, manufacture and processing of ceramics and glass, and fabrication of steel, aluminum, and other metals.23 Direct combustion of coal, wherever applicable, is generally more economical than coal conversion to clean fuel for sulfur emission control. Direct combustion Unlike the large power plants where FGD can be economically used to control sulfur emissions, industrial furnaces and boilers for steam and power generation are generally too small to equip with FGD profitably, except in large industrial complexes. The real alternative for direct coal combustion in smaller furances and boilers is fluidized-bed combustion. The principles of operation, status of application, and economics of fluidizedbed combustion have been reported. 24-27 The SO, from coal combustion is trapped by the alkaline ash or added limestone or dolomite without being emitted to exhaust air. In such a scheme, the fluidized-bed combustor doubles as a high-temperature scrubber, thus eliminating the costly wet FDG and waste disposal, i.e. sulfur control during the combustion. For optimum reaction between sulfur and lime, the bed should be operated at about 1550 “F. At a calcium-to-sulfur mole ratio of 2, more than 80% of SO, can be trapped. At such temperatures, NO, emissions are also greatly reduced. The emission of other trace elements such as arsenic, antimony, and mercury can be lower than those from conventional furnaces and boilers. In addition to the advantages from the environmental point of view, fluidized-bed combustion is also economical. All kinds of coal, regardless of sulfur, ash, and heat content, and ash fusion temperatures, can be effectively combusted in fluidized beds.24 At the Great Lakes Naval Training Center, high-sulfur Illinois coal was used in a program jointly sponsored by Combustion Engineering and the DOE. In Wilkes-Barre, Pennsylvania, the DOE has successfully used a fluidized bed to fire anthracite crum, a by-product of mining. This flexibility is of utmost importance in boiler design for it allows the development of standard design boilers and combustion systems to a degree not possible before. Fluidized beds also permit the use of low-grade coal, even at low loads, without the need for expensive support fuels to ensure stable ignition. Because of the low-temperature operation, the corrosion of tubes by sodium, vanadium, and metal depositions is reduced as is the need for soot blowing. The turn-down ratio is high and the response time is short. The high heat-transfer coefficient between the boiling bed and heater tube leads to a greatly reduced surface-area requirement. These advantages lead to improved economics for fluidized-bed combustion. The economics of fluidized-bed combustion have been studied, particularly in comparison with conventional units with scrubbers. ’ 7 The results by Thurlow shown in Table 4 indicate that fluidized-bed combustion is more economical than the conventional boiler with scrubber, notwithstanding the fact that the scrubber is not economical to fit for small units. The same study showed that the fluidized bed is economically better than a conventional boiler without scrubber (Table 4). A similar optimistic comparison was made by Bagnulo et ~1.~~These estimates were made in the early 197Os, however, and may be somewhat optimistic. For instance, the cost of controlling particulate emission could have been underestimated. Nonetheless, it is believed that fluidized-bed combustion is economically viable and competitive with conventional boilers with scrubbers for SO, control.
T. Y. YAN and C. S. YAN
1332
Table 4. Comparative costs of fluidiied-bed boilers2’ Savings OWT Conventional Boiler (%) Operating cost Capital cost
Source
Atmospheric fluidized-bed Exxon study 100,000 # steaqhr 400,000 # steam/hr Westinghouse 1971 study British Columbia Hydro study ECAS study” Pressurized fluidized-bed Westinghouse 1971 British Columbia Hydro study” ECAS studyb
With scrubber
Without scrubber
With scrubber
Without scrubber
20 29 13-16
-5
15 18 10-13
-1
6 13-16
1 8-11
27
14
13
0
21 26
12-16 14
23
17
21 40 18
10-14 12
10
“Coal at %15/tori bCoal at S21.6iton
Besides improving the atmospheric units, research and development is continuing on pressurized fluidized-bed combustion to improve combustion efficiency to increase heatrelease rates, reduce coal-feed points, and couple with gas turbines for combined-cycle operation. There are many fluidized-bed combustion units in demonstration and commercial use. A market of 1400 units in the United States by the year 2000 has been predicted.2* There are thousands of fluidized-bed combustors of various sizes currently in use in China. These facts underscore the technical and economic viability of fluidized-bed combustion. Indirect
combustion
Coal can be converted to clean industrial fuels for indirect combustion to control SO, emissions and to serve furnaces and processes where direct combustion is impractical. The demand in this type of operation represents less than 20% of total coal used in the industrial sector, which, in turn, is only 20% of the total consumption in the country. However, this application can become more important as oil and gas reserves are depleted. The technology and economics of industrial gas from coal have been reviewed by Ferretti.2g Coal can be converted to the following fuel gases: (1) A low-Btu gas of about 150 Btu/SCF produced from an air-blown gasifier; (2) an intermediate-Btu gas of around 300Btu/SCF produced from an oxygen-blown gasifier; and (3) natural gas of about lOOOBtu, or an SNG derived from coal in an oxygen-blown gasifier and upgraded in heat value by employing additional steps, such as CO shift and methanation. The characteristics of these fuel gases are shown in Table 5. With low-Btu gas, the boilers have to be derated significantly because the flame temperature is lower and gas volume is larger than obtained when burning high-Btu or natural gas. On the other hand, the medium-Btu gas will not be detrimental to boiler performance. Thus, for existing furnaces at least, medium-Btu gas is preferred over low-Btu gas. It should be noted that the air-to-fuel ratios vary greatly between the different fuel gases; thus, a substitution of one gas for another will require mechanical changes in the burner system. As shown in Table 3, the clean fuel gases are expensive, and the cost of gases increases Table 5. Characteristics of fuel gases”
Type of gas Low-Btu gas Intermediate-Btu gas High-Btu gas *15% excess air
Heat value (SCF/Btu)
Flame temp. (“F)
Gas volume Fuel Air
(SCF/MBtu) Flue Gas
153 298
2853 3767
7043 3584
9860 8900
15,790 11,260
970
3279
1145
12,340
13,480
Meeting emission standards with high-sulfur coals
1333
in the order of low-Btu < medium-Btu < high-Btu, with the average cost of $2.90, $6.65, and $6.98/MMBtu, respectively. Ferretti calculated the cost of medium-Btu gas at $3.76 and $4.24/MMBtu, depending on economic assumptions. If these 1975 prices were to be escalated at 8%/yr to 1981, the costs will be $5.97 and $6.72/MMBtu, respectively. Thus, there appear to be opportunities to improve the gasification process to reduce the cost of gas production. Because of the extra processing steps required, the production cost of highBtu gas will always be higher than that of medium-Btu gas. Since high-Btu gas is more costly, the medium-gas will be preferred, particularly for local uses. Coal gasification is a capital-intensive process and will never be cheap. Thus, if it is at all technically feasible, coal should be combusted directly in an environmentally acceptable manner by use of available means rather than converting to clean fuel first. Size economy is an important factor in gas production cost. The gas cost decreases rapidly as the size of the operational unit is increased; it levels off at about 50-60 x 10’ Btu/day. The sharp rise in the cost of gas produced for the smaller plants results from a spare unit being provided in each case to ensure adequate availability. In addition, the off-site costs per unit of gas produced for the smaller plants is much higher than for the larger plants. Thus, it is desirable to consolidate several small units and to establish a large central gasification unit to supply industries within a radius of 3-l mile.
DOMESTIC
AND COMMERCIAL
USE
The domestic and commercial uses of energy are mostly for space heating. On-site cleaning processes such as FGD are not suitable for SO, emission control for these uses. Conversion of coals to clean fuels appears to be the only reasonable solution. There are two approaches to produce clean fuels from coal for domestic and commercial uses: gasification and compounding with additives Gasijication Coal can be gasified and cleaned in a community energy center for delivery to local users. The technical feasibility of this approach is apparent. In fact, in the late 192Os,there were more than 11,000 gasifiers in the United States to convert about 15 MM tons of coal per year into low-Btu gas for both industrial and domestic requirements.30 Typical lowBtu gas contains 20-25% of CO, which is toxic. Special provisions are required to ensure safety in the use of this gas. The cost of producing low-Btu gas at $2.90/MMBtu is considerably lower than for medium- and high-Btu gases. Pate1 et al. estimated the cost of low-Btu gas from the Institute of Gas Technology (IGT) process at $2.01/MMBtu in 1975 dollars.30 Upon escalation at 8% per year to 1981, this cost becomes $3.19/MMBtu. Thus, from a production cost point of view, low-Btu gas is preferred over medium- and high-Btu gases. It is particularly important to note that the capital investment of $13OO/MMBtu/D for low-Btu gas is only about a quarter of that for medium- and high-Btu gases. This is an important consideration for the future when capital resources are scarce. Compounded fuel High-sulfur coals can be compounded with additives such as lime, limestone, and dolomite that react with SO, during combustion to abate sulfur emissions.6 Other additives such as manganese nodules and iron oxides can be added to improve the combustion and ash properties of the product fuel. The product fuel can be in powder or briquette form.
Without question, the use of such fuels is much less convenient than the combustion of gas or oil when it comes to handling and controlling. However, the revival of wood stoves in recent years suggests that domestic coal stokers could be acceptable to the consumer if the price of fuel is lower than gas or oil and the effect on the environment is minimal. Improvements in coal stokers and an improved furnace design would further improve the
1334
T. Y. YAN and C. S. YAN
viability of this approach. Further research and development in the production of compounded clean fuels from coal appears justified because it is a less expensive alternative to SO, emission control than gasification. CONCLUSIONS
The technical and economical viabilities and thus the strategies of SO, control depend on how the coal is used. Based on the published data, it was concluded that for large power plants, FGD is favored over conversion of coal to clean fuels before combustion. The advantages of FGD are lower total and capital investment costs, higher thermal efficiency, and lower utility requirements. FGD will remain economically preferred even with possible improvements in coal conversion technology. The process reliability has reached an acceptable level, and about 80% of existing plants can be retrofitted with FGD. For industrial use, direct combustion of coal in fluidized beds is preferred. Fluidized bed combustion is economically viable and has reached commercial status. For applications requiring fluid fuels, gasification of coal to medium-Btu gas is preferred. Gasification is expensive but could be made more economical by taking advantage of the scale of economy through use of an energy center. For domestic and commercial use, coal can be gasified to low-Btu gas or compounded with additives to produce clean solid fuels. REFERENCES 1. T. A. Siddiqi, A. Rev. Energy 9, 81 (1984). 2. D. R. Mosher, U. D. Marwig and J. A. Phinney, “Basic Features of the CO2 Acceptor Process”, American Chemical Society, Washington, DC., Preprints Dio. Fuel Chem. 15(3), 40 (1971). 3. C. E. Fink, “CO, Acceptor Process Pilot Plant-1975”, Proceedings of the 7th Synthetic Pipeline Gas Symposium, p. 5, Chicago, Ill. (1975). 4. P. S. Lowell, “A Theoretical Description of the Limestone Injection-Wet Scrubbing Process”, National Technical Information Series PB-193029, Springfield, Va. (1970). 5. R. H. Essenhigh, “Coal Combustion in Coal Conversion Technology”, edited by C. Y. Wen and E. S. Lee, pp. 171-312, Addison-Wesley, Reading, Mass. (1979). 6. T. Y. Yan, “Solid Fuel for Use In Small Furnaces”, U.S. Patent 4,210,423, assigned to Mobil Oil Corporation (1980). 7. G. G. McGlamery and R. L. Torstrick, Fuel Gas Desulfurization Symposium (sponsored by U.S. Environmental Protection Agency), Atlanta, Ga. (1974). 8. S. G. Bloom, H. S. Rosenberg, D. W. Hissong and J. H. Oxley, “Analysis of Variations of Costs in FGD Systems”, Battelle Columbus Laboratories, final report prepared for Electric Power Research Institute, EPRI FP-909, Palo Alto, Calif. (1978). 9. U.S. Statistical Abstract, p. 573 (1982-83). 10. Chinese Annual Statistical Abstract, National Statistics Bureau, Chinese Statistics Publishing Company, p. 250 (1983). 11. T. Y. Yan, Energy 9, 265 (1984). 12. G. A. Mills and C. W. Knudsen, “Comparative Economics of Synthetic Hydrocarbon Sources”, Proceedings of the World Petroleum Congress, Bucharest, Vol. 3, p. 329 (1979). 13. R. L. Dickenson, “Synthetic Fuels: A Perspective on Commercialization”, American Chemical Society, Washington, D.C., Preprints Div. Fuel Chem. 22(7), 1 (1977). 14. H. M. Siegel and T. Kalina, Mech. Engng 95, 23 (1973). 15. W. Dunlop, “Economic and Design Factors for Flue-Gas Desulfurization Technology”, Electric Power Research Institute report CS1428, Palo Alto, Calif. (1980). 16. J. Harte and M. El-Grassier, Science 199, 623 (1978). 17. F. Glazer, A. Hershaft and R. Shaw, “Emission from Processes Producing Clean Fuels”, National Technical Information Series PB-245671, Springfield, Va. (1974). 18. R. Beckman, W. Hsu and J. Joiner, “Economics of Coal Gasification (An Update)“, Fluor Engineering and Constructors, urenared for Electric Power Research Institute. EPRI AP-1725. Palo Alto. Calif. 0981). 19. J. K. Burchard, “Some General Economic Considerations’ of Flue-Gas Scrubbing for Utilities”, ‘paper presented at the Electrical World Conference on Sulfur in Utility Fuels, Chicago, Ill. (1972). 20. T. W. DeVitt, B. A. Laseke and N. Kaplan, Chem. Engng Prog. 76, 45 (1980). 21. R. J. Schreiber, A. W. Davis, J. M. Delacy, Y. H. Chang and H. N. Lockwood, “Boiler Modification Cost Survey for Sulfur Oxides Control by Fuel Substitution”, National Technical Information Series PB-239455, Springfield, Va. (1974). 22. M. Smith, M. Melia and T. Koger, “EPA Utility FGD Survey: April-June 1979”, EPA-60017-79-002e, U.S. Government Printing Office, Washington, D.C. (1979). 23. R. H. Essenhigh, Chemtech 11, 351 (1981). 24. E. C. McKenzie, Chem. Engng 85, 116 (1978).
Meeting emission standards with high-sulfur coals
1335
25. A. H. Bagnulo, J. W. Bishop, S. Ehrlich and E. B. Robinson, “Development of Coal-Fired Fluidized-Bed Boilers”, Final Report vol. 1, Office of Coal Research and Development report No. 36, Contract no. 14-010001-478, prepared by Pope, Evans & Robbins, Division of Perathon, Inc. (1970). 26. W. C. Patternson and R. Griffin, “Fluidized-Bed Technology: Coming to a Boil”, Inform, 25 Broad St., New York. 27. G. G. Thurlow, Proc. Inst. Me&. Engrs 192, 145 (1978). 28. “Industry Takes to Burning Coal in Fluidized Beds”, Ckem. Week, p. 24 16 Sept. 1981). 29. E. J. Ferretti, “Technology and Economics of Industrial Fuel Gas from Coal”, in Synthetic Fuels Processing, Comparntioe Economics A. H. Pelofsky, ed., pp. 375-95. Marcel Dekker, New York (1977). 30. J. G. Patel, K. B. Burnham and J. W. Loeding, “The IGT Low-BTU Gas Process-Design and Economics”, in Synthetic Fuels Processing, Comparatioe Economics A. H. Pelofsky, ed., pp. 193-214, Marcel Dekker, New York (1977). 31. P. S. Farber, “Dry-scrubbing at Argonne’s 20-MW boiler”, DE84013457, Argonne National Laboratory, Ill., Department of Energy, Washington, D.C. (1984).
MEETING
0360-5442/86 Pergamon
$3.00 +O.OO Journals Ltd
EMISSION STANDARDS WITH HIGH-SULFUR COALS T. Y.
and C. S.
YAN
YANK
Mobil Research and Development Corporation, P.O. Box 1025, Princeton, NJ 08540, U.S.A. Abstract-The economics of strategies for meeting sulfur oxides (SO,) emission standards from furnaces fueled with high-sulfur coals has been assessed based on published data. The strategy of SO, control depends on how the coal is utilized. For large power plants, flue-gas desulfurization (FGD) is preferable to conversion of coal to clean fuel. In comparison with coal conversion, the total capital and operating costs for FGD are almost an order of magnitude lower, thermal efficiencies are higher, and utility requirements are lower. Even with possible breakthroughs in coal-conversion technologies, it appears that FGD will remain the economically preferred route to desulfurization. FGD has been in commercial operation since 1968, and the reliability of the process has reached an acceptable level. For industrial furnaces, direct combustion is preferred to gasification because gasification is inherently expensive. Fluidized-bed combustion is the only viable option for clean direct combustion of coal in small industrial furnaces. Fluidized-bed combustion has reached commercial status and is economically competitive in many parts of the world. For furnaces requiring gaseous or liquid fuels, gasification to medium-Btu gas is preferred. For domestic and commercial uses, coal can be gasified to clean, low-Btu gas. This is an old process and might be amenable to cost reduction through application of new technologies. The only other economically viable approach involves the production of clean solid fuel by compounding coal with additives such as limestone and manganese nodules.
INTRODUCTION
The U.S. National Environmental Policy Act (NEPA), signed into law on 1 January 1970, made environmental protection an official goal of national policy. Ambient air quality standards were set for the three most common pollutants: sulfur oxides (SO,), nitrogen oxides (NO,), and particulates (Table 1). To achieve these standards, the Environmental Protection Agency (EPA) specifications were set for new and modified fossil-fired steam generators. The most important pollutant pertaining to the use of high-sulfur coal is SO,. To comply with the latest Federal New Source Performance Standard promulgated in June 1979, SO, emission control has to be provided for all large systems utilizing coal fuels. Although not regulated under this law, the SO, emissions from small systems in industrial, commercial, and residential uses could become regulated in the future. In the United States, nearly 80% of coal consumption was for generation of electricity in 1979. This is not the case, however, in other parts of the world; for example, China depends on coal for about 70% of its commercial energy and as the primary fuel for domestic heating and cooking.’ There are strong interactions between environmental protection policies and energy po1icies.l An important factor in the limited growth of coal consumption as a fuel is the cost of meeting the environmental protection regulations. In this study, the economic and
Table 1. National Averaging time
Pollutant(s) Sulfur oxides
Particulates Nitrogen
oxides
Annual 24 hours” 3 hours! Annual 24 hours” Annualb 24 hours’
ambient
Primary ugms
air-quality
standards
Standard wm
Secondary up/m3
80.0
0.03
60.0
365.0
0.14
75.0 260.0 100.0 150.0
0.05 0.13
260.0 1300.0 60.0 150.0 100.0 250.0
‘Not to be exceeded more than once per year. bAlthough under consideration, this standard is not a requirement
at this time.
TDepartment of Economics, Drexel University, Philadelphia, U.S.A. 1325
Standard wm 0.02 0.1 0.5
0.05 0.13
T. Y. YAN and C. S. YAN
1326
technical merits of several methods for controlling SO, emissions are assessed and the most cost-effective strategies for SO, control are suggested for both large power plants and small-scale furnaces. Alternatives for sulfur emission control
Sulfur emission from power plants fueled with high-sulfur coal may be controlled: (1) prior to, (2) during, or (3) after combustion. Pre-combustion sulfur control can be accomplished by converting coal to clean fuels by gasification and liquefaction or by physical/chemical treatment of coal. The latter involves beneficiation via washing, flotation, and magnetic separation. Examples of chemical treatment include Meyers’ oxidative process and Battelle’s caustic treatment process. Since the technical viability of the various physical and chemical treatment methods has not yet been fully tested against stringent sulfur emission standards, only the coal gasification and liquefaction techniques are considered here. Sulfur emission control during combustion is exemplified by Consolidated Coal’s CO2 acceptor process2,3 and by Combustion Engineering’s process for boiler injection of limestone.4 Furnace injection systems tested by Tennessee Valley Authority (TVA) and Combustion Engineering indicated that the SO, removal efficiencies are limited with conventional equipment. However, the recent work performed by the U.S. Environmental Protection Agency and the Electric Power Research Institute (EPRI) in the area of Lime/Limestone Injection with multistage Burners (LIMB) has shown a great deal of progress in co-injection of lime or limestone with coal into boilers, and is now being tested at a utility scale. The other approach is fluidized-bed combustion, which has not yet been demonstrated in largescale utility uses. Programs are under way at TVA and EPRI for a utility demonstration plant projected to begin operation in the late 1980s. These processes are not included in this assessment for large power plants. However, fluidized-bed combustion appears to be a viable process for small-scale industrial and commercial complexes.5 Another possible method is to compound the coal with alkali oxides, such as lime, limestone, and dolomite, that react with SO, during combustion.6 SO, control after combustion, i.e. flue-gas desullurization (FGD), is represented by many processes at various stages of development, ranging from conceptual to commercial. The most advanced processes have been evaluated by McGlamery and Torstrick,7 and at Battelle Columbus Laboratories.8 Patterns
of coal utilization
and SO, control
In the United States, coal is mainly used for electricity generation. The consumption pattern in 1981 was electric utilities, 79.4%; industrial, 19.6%; residential and commercial, 1.0%; and transportation, 0 O /o. 9 It is expected, however, that as petroleum reserves are depleted in the future, the use of coal in industrial and residential applications will become more important. On the other hand, coal is now an important energy source for industries abroad. The coal consumption pattern in China is shown in Table 2.” The technical and economical viabilities, and thus the strategy for SO, control, depend Table 2. Fuel consumption pattern in China, 196&82 Total fuel consumption
Distribution (%)
Year
(104 ton coal eq.)
C0al
Oil
Gas
Hydropower
1960 1965 1970 1975 1980 1981 1982
30,180 18,901 29,291 45,425 60,275 59,447 61,937
93.9 86.4 80.9 71.9 71.8 72.7 13.9
4.1 10.3 14.7 21.1 21.1 19.9 18.7
0.5 0.6 1.0 2.5 3.1 2.9 2.6
1.5 2.1 3.5 4.6 4.0 4.5 4.9
Source: Chinese Annual Statistical Abstract, National Statistics Bureau, Chinese Statistics Publishing Co., p. 250, 1983.
Meeting emission standards with high-sulfur coals
1327
on how the coal is utilized. The important factors in determining the control strategy include process requirement, size, age, and physical arrangement of the equipment as well as environmental considerations. SO, control strategies will be discussed with respect to coal uses, namely, large power plants for electricity generation, industrial, and residential applications. The discussion will concentrate on large power plants for electricity generation because of their paramount importance. LARGE
POWER
PLANTS
The primary question for fueling a power plant with high-sulfur coal is: “What is the choice between FGD and conversion to clean fuels?“” In this assessment, the following processes that have been described and evaluated in the literature are considered as typical examples: (1) coal gasification yielding low-Btu, medium-Btu, or high-Btu gas; (2) coal liquefaction leading to SRC-I; (3) FGD using lime/limestone slurry scrubbing. Evaluation criteria Assessment of technology encompasses technical, economical, political, and social problems. Some of the factors can be quantified, but other equally important factors are intangible. The following factors must be considered and quantified: (1) the incremental cost for converting coal to clean gas or solvent-refined coal, and for desulfurizing the flue gas; (2) the thermal efficiencies as well as water and land requirements for alternatives; (3) the reliability and compliance with environmental regulations; and (4) the status of current technical developments and of commercial operations and their future potential in terms of alternatives. Incremental cost The cost effectiveness of SO, removal strategies is measured by incremental cost. The additional cost incurred in controlling SO, emissions is the incremental cost expressed in terms of $/MMBtu of thermal energy. For the conversion process to clean fuels, this includes all the costs associated with either gasification or liquefaction, as well as the loss in thermal efficiency. These can be obtained by subtracting the value of coal ($/MMBtu) from the product value ($/MMBtu). For FGD processes, incremental cost includes all of the scrubbing costs, as well as waste disposal costs and losses in thermal efficiency. Incremental cost is site specific. For our study, we surveyed published costs and used the average general range of costs. We included data from process inventors and developers, construction firms, operation firms, government agencies, and academic institutions. Because of variations in economics and methodology, estimates can differ when obtained from different sources. Although the details and accuracy of cost analyses are lost in such an approach, generally valid cost comparisons can be obtained with minimal risk of bias. In capital-intensive energy processes, the method of financing may be the most important economic factor.” An approach to decrease the impact of high investment is to use debt rather than equity financing. Utility companies have been using debt financing at a typical debt:equity ratio of 7525. The impact of financing method has been discussed by Dickenson,’ 3 and Siegel and Kalina. l4 An effort was made in this study to compare costs on utility type financing. Incremental cost also depends on the size of the process. For clean fuel processes, 250 x 10’ Btu/SD (k50,OOObbl/day of oil) is assumed to be the base size and is generally considered to be desirable for a commercial plant. It is further assumed that one such clean fuel plant will serve four 500-MW electric power plants simultaneously. To assess FGD, a dedicated system for a power plant of 500 MW was used in the base case. In terms of heat, this is equivalent to 120 x 109Btu/D if a heating rate of 10,000 Btu/kWh is used. The power plant is assumed to operate 6000 hr/yr. Both grass roots and retrofitted units were considered. The load factor is also important, particularly for capital-cost-intensive, clean-fuel processes. The projected cost of clean fuel is usually based on a 90% availability, which
1328
T. Y. YAN and C. S. YAN
is generally achieved in relatively mature processes. A general observation for typical cases is that the cost of clean fuels increases about 18% for each 10% decrease in plant availability. For the FGD process, loading factors of 60% and 80% are assumed for retrofitted and new units, respectively. An excellent review of economic and design factors for flue-gas desulfurization technology has been made by Dunlop.15 An analysis of variations in costs of FGD systems was also done by Bloom et a1.s In our study, a compound inflation rate of 8%/yr has been assumed, and the estimated costs were adjusted to 1981 as a reference year. The impact of process efficiency on cost is rather small so that the potential process improvements in the intervening years can be neglected. The incremental cost for FGD processes is about 75$/MMBtu. The incremental costs for clean fuels varies widely, ranging from 300 to 9OOb/MMBtu. The lowest cost for clean fuels is the low-Btu gas, which is still 4 times as expensive as the limestone or lime FGD process. From the incremental-cost point of view, FGD is clearly preferred over the clean fuel approaches. Resource requirement The resource requirement can be measured in terms of three aspects: capital investment cost, thermal efficiency, and utility requirements. Capital investment. Capital investment represents the physical resource on the surface but really means all the physical and manpower requirements for erecting the process plant. It is expressed in terms of $/MMBtu/D. The capital requirements for FGD processes are about $4OO/MMBtu/D, while the capital requirements for clean fuel process range from $1300 to 8200/MMBtu/D. The lowest estimate for the clean fuels is low-Btu gas, which is still 3.2 times more expensive than the lime/limestone FGD processes. As pointed out earlier, the low-Btu gas estimate appears to be too low due to optimistic estimates in early stages of development or improper cost escalation. From the capital investment point of view, FGD processes are clearly preferred over the clean fuel processes. This is especially important for the future when the demand for capital will greatly increase, particularly in the field of energy production. Thermal ejiciency. The thermal efficiency of the lime/limestone FGD process is 93%, and that for clean fuel processes is between 60 and 79%. This loss in thermal efficiency would be particularly crucial in areas of the world where coal is in short supply. Again, from the points of view of thermal efficiency and energy conservation, FGD processes are preferred over the clean fuel processes. Utility requirements. Among the utility requirements, water is the most crucial, particularly since the plants for conversion of coal to clean fuel need to be located near the mine mouth. The processes for converting coal to clean fuels use enough water to cause concern regarding its availability, particularly in the arid western states.’ ‘*I6 Relative costs The cost of FGD is likely to be always lower than the cost of converting coal to clean fuels. Glazer et aI.” have studied the cost of controlling emissions from clean fuel processes and expressed the cost of pollution control in terms of the percentage of the overall clean fuel cost. These percentages are 15-30%, 15-50%, and 6-28% for high-Btu gas, low-Btu gas, and liquid fuels, respectively. According to the average product costs, the corresponding emission controlling costs would be $1.052.10/MMBtu, %0&l-1.45/MMBtu, and $0.371.73/MMBtu, respectively. Such costs are in the same range of the FGD cost of $0.75l.OO/MMBtu. That is, the cost component for emissions control in clean fuel conversion processes is comparable to the total FGD cost. This is understandable because FGD is a pollution control step in fuel combustion and the pollution control steps in the fuel conversion processes could be equally or more costly than the FGD due to their increased complexity. It is tempting to conclude that under normal conditions fuel conversion processes will always be more expensive than FGD. The cost of clean fuel is typically between 4 and 6 times as expensive as coal in terms
Meeting emission standards with high-sulfur coals
1329
of heating value. This ratio has stood the test of time, including times of high inflation and of rapid technological development. The clean fuel/coal price ratio of 4-6 is reasonable enough to make the conversion process viable. Historical data show that the crude oil/coal price ratio has been around 3 since the turn of the century. As a result, coal conversion processes have never been economical until now. On the other hand, it is difficult to conceive how the FGD cost could increase from the estimated ratio of 1.75 to equal or exceed 4-6. In other words, it seems unlikely that the cost of FGD can equal or exceed the cost of coal conversion to synfuels. Choice of the control strategy Our literature survey indicates that FGD is the preferred strategy for SO, emission control in fuel power plants using high-sulfur coals. It involves lower incremental control costs, is less taxing on resources and capital requirements, is higher in thermal efficiency, and has lower utility requirements. Use of FGD scrubbing processes also leads to nearly complete control of particulate emissions and a substantial reduction in NO, emissions. While not competitive for fueling a conventional power plant, clean fuels can be employed advantageously in other systems. For instance, clean gas can be used in a combined-cycle system to improve thermal efficiency and reduce capital requirement. The economics of various gasification and combined-cycle systems have been investigated by Beckman et al.” Such schemes impro ve the economics of the clean fuel approach significantly but still remain noncompetitive with FGD. The Coolwater Gasification Combined-Cycle Power Generation project by Southern California Edison and EPRI has demonstrated its technical feasibility, but the early indication is that the power cost is 10% or so higher than the conventional coal-fired steam plant with FGD. The decision by Virginia Electric to proceed with 400-MWe utility gasification combined-cycle power plants may be based on sitespecific economics. Clean fuels could become attractive when they are used as turbine fuels in peak shaving and when the low capital cost of the turbine (vs a conventional steam power plant) is taken into account. Retrofit installation to existing power plants Retrofit installation of FGD systems in existing plants requires higher capital costs than in new plants. An FGD system for a new plant can be incorporated into the overall design of the plant, while a retrofit installation requires that the system be adapted to the rigid configurations of the existing plant. Thus, the cost of retrofitting is rather site specific. Burchard has quantitatively rated the difficulty of retrofitting various plants (Table 3) and expressed this in terms of a difficulty factor that can be used as a multiplier to the retrofit scrubber cost.lg The scale ranges from 1.0 for a new plant to 1.5 for a difficult retrofit case. That is to say, the more difficult to retrofit case can cost 50% more than a corresponding new plant. About 20% of the electrical capacity surveyed by Burchard had no space for scrubbers (thus making retrofitting impossible) or was rated above a difficulty factor of 1.5. Clean fuels from coal may find a pplication in such plants. The remainder was about uniformly distributed between 1.125 and 1.5. These results are consistent with those of DeVitt et al.” For existing plants with retrofit difficulty factors up to 1.5, which represent about 80% of the installed coal-fired electrical capacity in the United States, FGD remains the less costly alternative to SO, emission control, compared to clean fuel alternatives. The clean fuel processes are about an order of magnitude more expensive than FGD, so that a 50% increase in retrofitting costs will not affect the attractiveness of FGD. The difficulty of retrofit is strongly related to the age and size of boilers (Table 3). As would be expected, newer and larger units are easier to retrofit than older and smaller units. Besides the increased cost of retrofitting, the cost of FGD also depends on the life of the power plant itself, for the life of the newly retrofitted scrubbing unit will have a life equal to the remaining life of the power plant. Consequently, it probably will not be worthwhile to retrofit power plants substantially older than 15 yr.
T. Y. YAN and C. S. YAN
1330
Table 3. Average retrofit difficulty factors” as a function of plant size and age” Dificultyfactor, by unit age (yrs) Unit size (MW) o-99 loo-199 200-499 500+
o-9
10-19 -
1.33 1.26
20+ 1.51
1.34 1.29
“These factors are for application to direct scrubber cost.
Conversion of existing power plants from high-sulfur coal to clean fuels also requires certain modifications. The cost of such conversions, which has been studied by Schreiber et a1.21, also makes FGD more attractive relative to the clean fuel processes. Status and development of FGD
FGD systems are generally considered by the regulators to be the most effective method for controlling SO, emissions from power plants. The growth of FGD systems in terms of equivalent scrubbed capacity has been studied by DeVitt et al.” From the first installation in 1968, the capacity of FGD approached 20,000 MW equivalent in 1980, and is projected to exceed 70,OOOMW by 1988. The revised SO, New Source Performance Standards (NSPS), promulgated by the EPA in June 1979, require new coal-fired units to have some type of continuous control device. These regulations are stringent enough to require the use of FGD systems in nearly every case. Approximately 6% of total coal-fired power-generating capacity is now controlled by FGD; this is expected to increase to about 25% by 1988. The operating FGD units are mainly wet, calcium-based systems producing a sludge by-product that must be disposed of in an environmentally sound manner. They account for 90% of the total capacity. 22 The utility industry’s preference for limestone processes is expected to continue in the foreseeable future, primarily due to process economics, e.g. the incremental costs are 60 and $1.73/MMBtu for limestone and Welman-Lord processes, respectively. Since the first commercial application of FGD in 1968, the process of developing and improving the technology continues. The early calcium-based FGD systems were plagued with fouling and plugging of scrubbing hardware. In recent years, the process has been sufficiently improved to attain an acceptable reliability. On-stream factors exceeding 90% are now common. For example, factors of 94-96% and 90% are reported for the Colstrip Unit No. 1 of the Montana Power Company and the La Cygne Unit No. 1 of the Kansas City Power and Light, respectively. Building on experience gained in the operation of the first generating systems, suppliers and designers are providing better design configurations and construction materials. Further improvements in reliability and reductions in costs can be expected. Some promising second-generation calcium-based FGD systems are being developed. Among the most promising are: the lime-slurry spray-drier/fabric filter process and the Chiyoda Thoroughbred 121 process. The first process uses a slurry of hydrated lime Ca(OH),, calcium sulfite, and fly ash to sorb SO2 from the flue gas by contact with atomized droplets of the alkali slurry. This process appears to be most attractive for lowsulfur coal. Initial estimates show that the cost could potentially be as little as half that of lime/limestone slurry process. I5 The study at Argonne National Laboratory using a 20MW boiler also showed that the lime-based spray-drier scrub system is economical and reliable, and can be used for retrofitting the existing boilers.31 SO2 absorption, sulfite/bisulfite oxidation, and precipitation of calcium sulfate and gypsum are accomplished in a single reaction vessel. Virtually all of the sulfur is removed as an easily dewatered gypsum slurry that reduces waste disposal problems and improves reliability.
Meeting emission standards with high-sulfur coals INDUSTRIAL
1331
USE
Coal for industrial use is about 20% of use in the United States, or a quarter of that for power plant use. However, coal use in industry is expected to become more important in the future, for economic and political reasons. When coal is used, the replaced oil and gas can be used for transportation fuel. Depending on the process requirements, coal can be used as fuel in industry in two ways: direct combustion and conversion to clean fuel before combustion. For example, direct combustion can be used in boilers for generation of steam and electricity. More than 80% of coal in industrial use is for these purposes. On the other hand, direct coal combustion is difficult or impossible for process heating, manufacture and processing of ceramics and glass, and fabrication of steel, aluminum, and other metals.23 Direct combustion of coal, wherever applicable, is generally more economical than coal conversion to clean fuel for sulfur emission control. Direct combustion Unlike the large power plants where FGD can be economically used to control sulfur emissions, industrial furnaces and boilers for steam and power generation are generally too small to equip with FGD profitably, except in large industrial complexes. The real alternative for direct coal combustion in smaller furances and boilers is fluidized-bed combustion. The principles of operation, status of application, and economics of fluidizedbed combustion have been reported. 24-27 The SO, from coal combustion is trapped by the alkaline ash or added limestone or dolomite without being emitted to exhaust air. In such a scheme, the fluidized-bed combustor doubles as a high-temperature scrubber, thus eliminating the costly wet FDG and waste disposal, i.e. sulfur control during the combustion. For optimum reaction between sulfur and lime, the bed should be operated at about 1550 “F. At a calcium-to-sulfur mole ratio of 2, more than 80% of SO, can be trapped. At such temperatures, NO, emissions are also greatly reduced. The emission of other trace elements such as arsenic, antimony, and mercury can be lower than those from conventional furnaces and boilers. In addition to the advantages from the environmental point of view, fluidized-bed combustion is also economical. All kinds of coal, regardless of sulfur, ash, and heat content, and ash fusion temperatures, can be effectively combusted in fluidized beds.24 At the Great Lakes Naval Training Center, high-sulfur Illinois coal was used in a program jointly sponsored by Combustion Engineering and the DOE. In Wilkes-Barre, Pennsylvania, the DOE has successfully used a fluidized bed to fire anthracite crum, a by-product of mining. This flexibility is of utmost importance in boiler design for it allows the development of standard design boilers and combustion systems to a degree not possible before. Fluidized beds also permit the use of low-grade coal, even at low loads, without the need for expensive support fuels to ensure stable ignition. Because of the low-temperature operation, the corrosion of tubes by sodium, vanadium, and metal depositions is reduced as is the need for soot blowing. The turn-down ratio is high and the response time is short. The high heat-transfer coefficient between the boiling bed and heater tube leads to a greatly reduced surface-area requirement. These advantages lead to improved economics for fluidized-bed combustion. The economics of fluidized-bed combustion have been studied, particularly in comparison with conventional units with scrubbers. ’ 7 The results by Thurlow shown in Table 4 indicate that fluidized-bed combustion is more economical than the conventional boiler with scrubber, notwithstanding the fact that the scrubber is not economical to fit for small units. The same study showed that the fluidized bed is economically better than a conventional boiler without scrubber (Table 4). A similar optimistic comparison was made by Bagnulo et ~1.~~These estimates were made in the early 197Os, however, and may be somewhat optimistic. For instance, the cost of controlling particulate emission could have been underestimated. Nonetheless, it is believed that fluidized-bed combustion is economically viable and competitive with conventional boilers with scrubbers for SO, control.
T. Y. YAN and C. S. YAN
1332
Table 4. Comparative costs of fluidiied-bed boilers2’ Savings OWT Conventional Boiler (%) Operating cost Capital cost
Source
Atmospheric fluidized-bed Exxon study 100,000 # steaqhr 400,000 # steam/hr Westinghouse 1971 study British Columbia Hydro study ECAS study” Pressurized fluidized-bed Westinghouse 1971 British Columbia Hydro study” ECAS studyb
With scrubber
Without scrubber
With scrubber
Without scrubber
20 29 13-16
-5
15 18 10-13
-1
6 13-16
1 8-11
27
14
13
0
21 26
12-16 14
23
17
21 40 18
10-14 12
10
“Coal at %15/tori bCoal at S21.6iton
Besides improving the atmospheric units, research and development is continuing on pressurized fluidized-bed combustion to improve combustion efficiency to increase heatrelease rates, reduce coal-feed points, and couple with gas turbines for combined-cycle operation. There are many fluidized-bed combustion units in demonstration and commercial use. A market of 1400 units in the United States by the year 2000 has been predicted.2* There are thousands of fluidized-bed combustors of various sizes currently in use in China. These facts underscore the technical and economic viability of fluidized-bed combustion. Indirect
combustion
Coal can be converted to clean industrial fuels for indirect combustion to control SO, emissions and to serve furnaces and processes where direct combustion is impractical. The demand in this type of operation represents less than 20% of total coal used in the industrial sector, which, in turn, is only 20% of the total consumption in the country. However, this application can become more important as oil and gas reserves are depleted. The technology and economics of industrial gas from coal have been reviewed by Ferretti.2g Coal can be converted to the following fuel gases: (1) A low-Btu gas of about 150 Btu/SCF produced from an air-blown gasifier; (2) an intermediate-Btu gas of around 300Btu/SCF produced from an oxygen-blown gasifier; and (3) natural gas of about lOOOBtu, or an SNG derived from coal in an oxygen-blown gasifier and upgraded in heat value by employing additional steps, such as CO shift and methanation. The characteristics of these fuel gases are shown in Table 5. With low-Btu gas, the boilers have to be derated significantly because the flame temperature is lower and gas volume is larger than obtained when burning high-Btu or natural gas. On the other hand, the medium-Btu gas will not be detrimental to boiler performance. Thus, for existing furnaces at least, medium-Btu gas is preferred over low-Btu gas. It should be noted that the air-to-fuel ratios vary greatly between the different fuel gases; thus, a substitution of one gas for another will require mechanical changes in the burner system. As shown in Table 3, the clean fuel gases are expensive, and the cost of gases increases Table 5. Characteristics of fuel gases”
Type of gas Low-Btu gas Intermediate-Btu gas High-Btu gas *15% excess air
Heat value (SCF/Btu)
Flame temp. (“F)
Gas volume Fuel Air
(SCF/MBtu) Flue Gas
153 298
2853 3767
7043 3584
9860 8900
15,790 11,260
970
3279
1145
12,340
13,480
Meeting emission standards with high-sulfur coals
1333
in the order of low-Btu < medium-Btu < high-Btu, with the average cost of $2.90, $6.65, and $6.98/MMBtu, respectively. Ferretti calculated the cost of medium-Btu gas at $3.76 and $4.24/MMBtu, depending on economic assumptions. If these 1975 prices were to be escalated at 8%/yr to 1981, the costs will be $5.97 and $6.72/MMBtu, respectively. Thus, there appear to be opportunities to improve the gasification process to reduce the cost of gas production. Because of the extra processing steps required, the production cost of highBtu gas will always be higher than that of medium-Btu gas. Since high-Btu gas is more costly, the medium-gas will be preferred, particularly for local uses. Coal gasification is a capital-intensive process and will never be cheap. Thus, if it is at all technically feasible, coal should be combusted directly in an environmentally acceptable manner by use of available means rather than converting to clean fuel first. Size economy is an important factor in gas production cost. The gas cost decreases rapidly as the size of the operational unit is increased; it levels off at about 50-60 x 10’ Btu/day. The sharp rise in the cost of gas produced for the smaller plants results from a spare unit being provided in each case to ensure adequate availability. In addition, the off-site costs per unit of gas produced for the smaller plants is much higher than for the larger plants. Thus, it is desirable to consolidate several small units and to establish a large central gasification unit to supply industries within a radius of 3-l mile.
DOMESTIC
AND COMMERCIAL
USE
The domestic and commercial uses of energy are mostly for space heating. On-site cleaning processes such as FGD are not suitable for SO, emission control for these uses. Conversion of coals to clean fuels appears to be the only reasonable solution. There are two approaches to produce clean fuels from coal for domestic and commercial uses: gasification and compounding with additives Gasijication Coal can be gasified and cleaned in a community energy center for delivery to local users. The technical feasibility of this approach is apparent. In fact, in the late 192Os,there were more than 11,000 gasifiers in the United States to convert about 15 MM tons of coal per year into low-Btu gas for both industrial and domestic requirements.30 Typical lowBtu gas contains 20-25% of CO, which is toxic. Special provisions are required to ensure safety in the use of this gas. The cost of producing low-Btu gas at $2.90/MMBtu is considerably lower than for medium- and high-Btu gases. Pate1 et al. estimated the cost of low-Btu gas from the Institute of Gas Technology (IGT) process at $2.01/MMBtu in 1975 dollars.30 Upon escalation at 8% per year to 1981, this cost becomes $3.19/MMBtu. Thus, from a production cost point of view, low-Btu gas is preferred over medium- and high-Btu gases. It is particularly important to note that the capital investment of $13OO/MMBtu/D for low-Btu gas is only about a quarter of that for medium- and high-Btu gases. This is an important consideration for the future when capital resources are scarce. Compounded fuel High-sulfur coals can be compounded with additives such as lime, limestone, and dolomite that react with SO, during combustion to abate sulfur emissions.6 Other additives such as manganese nodules and iron oxides can be added to improve the combustion and ash properties of the product fuel. The product fuel can be in powder or briquette form.
Without question, the use of such fuels is much less convenient than the combustion of gas or oil when it comes to handling and controlling. However, the revival of wood stoves in recent years suggests that domestic coal stokers could be acceptable to the consumer if the price of fuel is lower than gas or oil and the effect on the environment is minimal. Improvements in coal stokers and an improved furnace design would further improve the
1334
T. Y. YAN and C. S. YAN
viability of this approach. Further research and development in the production of compounded clean fuels from coal appears justified because it is a less expensive alternative to SO, emission control than gasification. CONCLUSIONS
The technical and economical viabilities and thus the strategies of SO, control depend on how the coal is used. Based on the published data, it was concluded that for large power plants, FGD is favored over conversion of coal to clean fuels before combustion. The advantages of FGD are lower total and capital investment costs, higher thermal efficiency, and lower utility requirements. FGD will remain economically preferred even with possible improvements in coal conversion technology. The process reliability has reached an acceptable level, and about 80% of existing plants can be retrofitted with FGD. For industrial use, direct combustion of coal in fluidized beds is preferred. Fluidized bed combustion is economically viable and has reached commercial status. For applications requiring fluid fuels, gasification of coal to medium-Btu gas is preferred. Gasification is expensive but could be made more economical by taking advantage of the scale of economy through use of an energy center. For domestic and commercial use, coal can be gasified to low-Btu gas or compounded with additives to produce clean solid fuels. REFERENCES 1. T. A. Siddiqi, A. Rev. Energy 9, 81 (1984). 2. D. R. Mosher, U. D. Marwig and J. A. Phinney, “Basic Features of the CO2 Acceptor Process”, American Chemical Society, Washington, DC., Preprints Dio. Fuel Chem. 15(3), 40 (1971). 3. C. E. Fink, “CO, Acceptor Process Pilot Plant-1975”, Proceedings of the 7th Synthetic Pipeline Gas Symposium, p. 5, Chicago, Ill. (1975). 4. P. S. Lowell, “A Theoretical Description of the Limestone Injection-Wet Scrubbing Process”, National Technical Information Series PB-193029, Springfield, Va. (1970). 5. R. H. Essenhigh, “Coal Combustion in Coal Conversion Technology”, edited by C. Y. Wen and E. S. Lee, pp. 171-312, Addison-Wesley, Reading, Mass. (1979). 6. T. Y. Yan, “Solid Fuel for Use In Small Furnaces”, U.S. Patent 4,210,423, assigned to Mobil Oil Corporation (1980). 7. G. G. McGlamery and R. L. Torstrick, Fuel Gas Desulfurization Symposium (sponsored by U.S. Environmental Protection Agency), Atlanta, Ga. (1974). 8. S. G. Bloom, H. S. Rosenberg, D. W. Hissong and J. H. Oxley, “Analysis of Variations of Costs in FGD Systems”, Battelle Columbus Laboratories, final report prepared for Electric Power Research Institute, EPRI FP-909, Palo Alto, Calif. (1978). 9. U.S. Statistical Abstract, p. 573 (1982-83). 10. Chinese Annual Statistical Abstract, National Statistics Bureau, Chinese Statistics Publishing Company, p. 250 (1983). 11. T. Y. Yan, Energy 9, 265 (1984). 12. G. A. Mills and C. W. Knudsen, “Comparative Economics of Synthetic Hydrocarbon Sources”, Proceedings of the World Petroleum Congress, Bucharest, Vol. 3, p. 329 (1979). 13. R. L. Dickenson, “Synthetic Fuels: A Perspective on Commercialization”, American Chemical Society, Washington, D.C., Preprints Div. Fuel Chem. 22(7), 1 (1977). 14. H. M. Siegel and T. Kalina, Mech. Engng 95, 23 (1973). 15. W. Dunlop, “Economic and Design Factors for Flue-Gas Desulfurization Technology”, Electric Power Research Institute report CS1428, Palo Alto, Calif. (1980). 16. J. Harte and M. El-Grassier, Science 199, 623 (1978). 17. F. Glazer, A. Hershaft and R. Shaw, “Emission from Processes Producing Clean Fuels”, National Technical Information Series PB-245671, Springfield, Va. (1974). 18. R. Beckman, W. Hsu and J. Joiner, “Economics of Coal Gasification (An Update)“, Fluor Engineering and Constructors, urenared for Electric Power Research Institute. EPRI AP-1725. Palo Alto. Calif. 0981). 19. J. K. Burchard, “Some General Economic Considerations’ of Flue-Gas Scrubbing for Utilities”, ‘paper presented at the Electrical World Conference on Sulfur in Utility Fuels, Chicago, Ill. (1972). 20. T. W. DeVitt, B. A. Laseke and N. Kaplan, Chem. Engng Prog. 76, 45 (1980). 21. R. J. Schreiber, A. W. Davis, J. M. Delacy, Y. H. Chang and H. N. Lockwood, “Boiler Modification Cost Survey for Sulfur Oxides Control by Fuel Substitution”, National Technical Information Series PB-239455, Springfield, Va. (1974). 22. M. Smith, M. Melia and T. Koger, “EPA Utility FGD Survey: April-June 1979”, EPA-60017-79-002e, U.S. Government Printing Office, Washington, D.C. (1979). 23. R. H. Essenhigh, Chemtech 11, 351 (1981). 24. E. C. McKenzie, Chem. Engng 85, 116 (1978).
Meeting emission standards with high-sulfur coals
1335
25. A. H. Bagnulo, J. W. Bishop, S. Ehrlich and E. B. Robinson, “Development of Coal-Fired Fluidized-Bed Boilers”, Final Report vol. 1, Office of Coal Research and Development report No. 36, Contract no. 14-010001-478, prepared by Pope, Evans & Robbins, Division of Perathon, Inc. (1970). 26. W. C. Patternson and R. Griffin, “Fluidized-Bed Technology: Coming to a Boil”, Inform, 25 Broad St., New York. 27. G. G. Thurlow, Proc. Inst. Me&. Engrs 192, 145 (1978). 28. “Industry Takes to Burning Coal in Fluidized Beds”, Ckem. Week, p. 24 16 Sept. 1981). 29. E. J. Ferretti, “Technology and Economics of Industrial Fuel Gas from Coal”, in Synthetic Fuels Processing, Comparntioe Economics A. H. Pelofsky, ed., pp. 375-95. Marcel Dekker, New York (1977). 30. J. G. Patel, K. B. Burnham and J. W. Loeding, “The IGT Low-BTU Gas Process-Design and Economics”, in Synthetic Fuels Processing, Comparatioe Economics A. H. Pelofsky, ed., pp. 193-214, Marcel Dekker, New York (1977). 31. P. S. Farber, “Dry-scrubbing at Argonne’s 20-MW boiler”, DE84013457, Argonne National Laboratory, Ill., Department of Energy, Washington, D.C. (1984).