Controlling acid deposition: The role of FGD Flue gas desulfurization systems could play an important role at existing power plants if an acid rain control law is passed
Edward S. Rubm Mark A. Cushey Ronald J. Marniao Carv N. Blovd J&es E Sk"ea
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Carnegie-Mellon Universiry Pinsburah. Pa. 15213 If a national acid rain control statute is enacted, the use of 0ue gas desulfurization (FGD) systems to remove up to 90% of the sulfur dioxide (Sq)emissions from existing coal-f& electric power plants may increase significantly A broad range of technological, economic, and regulatory variables will &ect increased FGD use at existing power plants. A newly developed simulation model assesses the effects of these variables, especially as they pertain to coal-f& power plants in the midwestern United States, where annual SO2 emissions a~ the highest in the country (1, 2).
I
Increased FGD capacity In the past decade the use of FGD systems for air pollution control at coal-f& power plants in the United States has increased from less than four gigawatts (GW)(2% of capacity) a decade ago to approximately 50 GW (20% of c o a l - f d capacity) today. An additional 60 GW is planned or under construction (3). This dramatic change is attributable to two major factors: the passage of the Clean Air Act Amendments of 1970, and the subsequent promulgation of federal new source performance standards (NSPS)requiring control of S q emissions from all large boilers constructed after 1971. Coal-burning units constructed before 1971 (about 200 GW of capacity) have not yet been affected as significantly as new sou~ceshave. A number of FGD systems have been S60 Envimn. Sci. Technol., '&I.
20. NO.10,1888
retrofitted on older plants to comply with state implementation plan emission limitations. Nevertheless, most existing facilities either have been unaffected or have been able to comply with state and local requirements by conversion to lower sulfur fuels. This situation may change sharply if
new acid rain controls are enacted by Congress. Proposals introduced in recent years call for the reduction of SO2 emissions in the 3 1 eastern states by a total of 7.3-10.9 metric tons (t) annually below 1980 levels, to be achieved over the next decade. Total SOz emissions in that region east of and border-
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ing on the Mississippi River would have to be curtailed to as little as half of 1980 levels. In addition, existing coalfired power plants could be required to reduce overall emissions by 90% or more (4). Thus, the role played by FGD as a technology for abatement of sulfur dioxide could increase dramatically. This article examines the important technical, economic, and policy factors affecting the extent to which FGD systems may be required at existing coalf d power plants if new SO, emission reductions are mandated to control acid deposition. It discusses currently available sulfur removal technologies, as well as several that are still under development, and explores their potential uses and costs under a variety of circumstances. The analysis also accounts for many of the site-specific factors affecting control strategy selection, including the type, size, age, and efficiency of the boiler, characteristics of the fuel, and use of the plant.
Control technology options Sulfur dioxide can be reduced by switching to lower sulfur coal or by processes that remove sulfur from coal before, during, or after combustion (5). But the highest levels of SO2 removal are currently achieved by postcombustion FGD processes. Among competing FGD systems, wet chemical processes that use lime (CaO) or limestone (CaC03) as a reagent are by far the most prevalent and account for more than 80% of the systems now in use (3). A typical system achieves 90%sulfur removal and employs forced oxidation of reaction products to yield a solid waste consisting primarily of calcium sulfate (gypsum). qpically, this waste is mixed with dry fly ash, separately collected up stream of the FGD system, then disposed of in a landfii. If forced oxidation is not employed, larger amounts of calcium sulfite are present, requiring stabfiiing agents to fix the sludge and prevent leaching. In the United States “throwaway” processes of this type are more economical than regenerative systems that produce bypducts rather than waste. The quantity of solid waste generated may be two to five times greater than that produced without FGD, depending on the ash and sulfur content of the coal. The electrical and thermal energy needed to operate the FGD system also decrease the power plant’s net operating efficiency by 2 4 % (a). Analytical models of FGD system performance and cost derived from a detailed cost and design model are used in this study to account for a variety of site-specific factors (7,8).
In recent years, dry FGD systems that use l i e spray dryers for SO, removal and fabric fdter (baghouse) colleaors for particulate matter removal have emerged as the preferred option for many new coal-fired plants that use low-sulfur western coal (3). Although this technology has not yet been used commercially as a retrofit option for plants burning medium- or high-sulfur eastern coals, it is included in the CUIrent study as a potential alternative to wet FGD. Performance and cost models for a typical dry FGD system are based on a number of design studies for new plants using high-sulfur as well as low-sulfur coals (9). Such a system nominally operates at an SO, removal efficiency of 70%. with efficiencies of up to 90% achievable at higher stoichiometries (moles of calcium sorbent per mole of sulfur in the gas). Data from pilot plants and small-scale applications currently provide the principal basis for estimating the performance of FGD systems for coals with higher sulfur content and lower alkalinity than those normally used in current commercial applications. The removal of sulfur oxides by injection of limestone or other sorbents directly into the boiier is a third retrofit option receiving considerable attention in current research programs of EPA, the Electric Power Research Institute, and others. This technology, however, has yet to be demonstrated commercially (10). Known widely as LIMB (for liestone injection with multistage burners), this process allows sulfur to be captured in dry form as calcium sulfate, which is then collected along with fly ash. On the basis of recent studies (10, ] I ) , we assume that if it is successful, LIMB will achieve 50% sulfur re-
moval in retrofit applications and that the accompanying increases in fly ash resistivity and particulate loadings will require a new fabric fdter device for particulate control in lieu of an existing electrostatic precipitator. Physical coal cleaning is another currently available technology capable of removing some sulfur from coal before combustion (typically 10-30% for medium- and high-sulfur U.S. coals with significant pyrite content). Models for estimating the performance and cost of coal washing have been derived by processing more than 700 coals characterized by the US. Bureau of Mines (12) through a computer model of a coal preparation plant that uses coalspecific washability data for four increasingly complex model plants. From these data, multivariate regression models predicting washed-coal properties and cost as a function of sulfur removal level were developed for coals in 18 regions of the United States (13). The overall simulation model allows washed coals to compete with unwashed coals regardless of their sulfur content, so that coal cleaning may be used in conjunction with combustion or postcombustion desulfurization methods to minimize overall power generationcosts (I, 14).
Modeling framework The Utility Control Strategy Model used in this study provides a detailed method of analyzing technical, economic, regulatory, and environmental factors affecting the selection of a control strategy for SO, at new or existing coal-fired power plants over the next 10-15 years. Pollution control options are analyzed at the individual plant or unit level by means of newly developed models of the performance, cost, and
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.Constant 1984 dol!ars. cosfs are esllmated for I995 una charactenstiw are 614 MW (net), 9382 BtulkWh Bs5%capacny faclor, Isyear lifeurn remain1 coal pmpertlas ere 11.487 BNllb, 2 0% suilur. 19 7% ash WI ImIemotone system removes%% of me sunur ‘Lime ray dryer tm removes m% o t t k sulfur Furnace firnestonem p m n system rmwes 3% of me mnur a new fabric IIlter Colleclor with dry FOD or U B ’Assumes w d i a p a l of fly ash and FQD waste8 *Includes all fmd and vanme opraling and maintenancecosts except uldi1186 q o mnverl m m a r k unls multiply by
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An alternative to this approach is a least-cost emission reduction strategy for a state as a whole. By ranking alternative strategies for individual s o m s according to their cost-effectiveness of control (measured in dollars per ton of So, removed), one can develop a marginal cost of control curve for the entire set of plants in a state. Figure 1 shows an example of this approach. At the low end of the curve the least expensive strategies involve only coal switching and cleaning; the higher costs represent increasing amounts of scrubbing. For any specified level of total emissions reduction, the corresponding point on the marginal cost curve specifies the set of plant-specific abatement strategies that minimizes overall cost.
Regional analysis
selection of control technology (9).
Here, the model seeks the lowest cost option for each facility over its remaininventory containing current informa- ing life. Included are the delivered cost tion on gemratingunit size, type, per- of fuel, plus the additional capital and formance, age, fuel use, pollution con- operating costs of all feasible air pollutrol equipment, and environmental tion control and solid-waste-disposal regulations (I). system (9). The strategies under consideration are coal switching, coal blending, scrubbing, COmhiMtiOIIS of scrubbing and coal switching, and early retirement of units before the expiration of their e x p t e d lifetimes. (“Scrubbing” and “ F G D are used loosely here to include any retrofit control technology that removes sulfur during or after combustion.) Table 1 shows typical results of applying the performance and cost models of wet FGD, dry FGD, and LIMB to a single coal-fired facility. These figures are in agreement with other recent utility and government cost estimates for these technologies when expressed in the same monetary terms (IO. 11). In particular, it should be noted that the common use of “current dollars” for reporting pollution control costs gives numbers that are significantly higher than the “constant dollar” costs used throughout this article, from which the effects of inflation are removed. The unit level analysis is the building block for analyses of states and regions. The state level is important becaw this is where electric utility rates are determined and where air pollution emission standards for existing (pre-NSPS) power plants are set. Historically, S@ emission reductions have been achieved largely through the imposition of local or statewide emission caps a p pliable to each unit (expreskd as pounds of SO1 per million Btu). This is one of the cases modeled in this study.
This study also provides a detailed unit
062 Envimn. Sci. Technol., Vol. 20, NO.I O , 1986
Several recent studies have addressed the national effects of specific acid rain mitigation proposals (4, 15-19). The strong qualitative conclusion that emerges is that the most severe effects of proposed emission reductions would fall on the Midwest, where local highsulfur coals are extensively used for power generation. Quantitative results vary considerably, however, because of
differencesin assumptionsand methods of analysis. To arrive at a better nnderstanding of these effects, this article focuses on the eight states shown in Fig-
ure 2. These states have the conntry’s highest annual SO, emissions, making them the prime targets of acid rain control requirements. C o a l - f d power plants account for most So, emissions in the Midwest. In 1980, the total coal-fired capacity in these eight states was 116 GW (Isble 2), of which only 8.4% was equippxi with FGD. Average SO, emission rates ranged from two to four times the maximum valne permitted for new facilities. Total 1980 mass emissions in this region accounted for approximately 70% of all utility So, emissions in the 31 eastern states targeted for acid rain controls (4).
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The future role of FGD was analyzed through an extensive series of computer simulations (more than loo0 cases) in which 15 important variables were altered alone and in combination. The principal determinant of future FGD use at an existing facility will be the required level of emissions reduction. We examined S a reductions of 5096, 6596, and 80% of uncontrolled emissions from the 101GW of capacity not already equipped with FGD in 1980 and not scheduled to be retired before the assumed compliance year of 1995. Our scenarios approximate those required by recent congressional proposals d i n g for the reduction of SO, emissions in 31 states, amounting to 7.3 million, 9.1 million, and 10.9 million t/yr below 1980 levels withii the next decade. Certain midwestern states could be required to reduce their emissions by greater percentages nnder some of these schemes (4). One important potential constraint on coal use is a requirement to use only local coals-those produced within a state-as an alternative to the unconstrained situation in which any suitable U.S.coal may be considered. This potential requirement reflects the desire of many midwestern states to protea mining jobs in their local high-sulfur coal industries. A further restriction modeled in this study allows the use of only those varieties of coal currently bemg burned at each plant. Another critical issue not examined in previous studies concern the way in which conpsionally mandated state or regional emission reductions are allocated to individual sowcm. Three cases are considered. In the nominal case,reflecting current practice, allowable emissions from each unit are restricted to the more stringent of its current standard or a uniform statewide
emissions cap in pounds of SO, per million Btu (ng SO&. Because there are differences in plant characteristics the valne of this standard differs from state to state for each level of reduction considered. A second case involves the statewide least-cost solntion, which requires that appropriate mechanisms be available in each state to implement this type of strategy. This approach typically is assumed to involve intrastate trading, although a simple multitiered system of emission caps based on the cost-effectiveness of control also may closely a p proximate a least-cost solntion (I). A thii option allows the overall emission reduction for the eight-state region to be achieved from sources anywhere withii the region. A marginal cost-ofantrol curve is developed for the region as a whole in the same way in which this curve is developed for an individual state. This simulates cases in which efficient interstate trading of So, emission rights is assumed to be feasible, as permitted in some congressional proposals. For each of the above cases three possibilities regarding available So, control technology are modeled. First, only conventional wet FGD systems are assumed to be available in addition to coal switching, washing, and blending. Next, dry FGD systems are allowed to compete with wet FGD for retrofit applications. Finally, it is assumed that LIMB technology also becomes a commercial option for most boilers (wall-fired and tangentially fdunits) by 1995. For each of these cases the effect of performance and economic variables on the degree of the implementation of
technology and the costs of control have been examined. Several scenarios that consider price trends for coals of different sulfur content also have been analyzed. The nominal values of the impatant model variables are summarized in Table 3.
W FGD vs. coal switehing Figure 3 shows the resultsof 99 cases reflecting different emission reduction requirements, methods of implementation, and constraints on coal use. Figure 3a indicates the percentage of total eligible capacity in the eight-state region, choosing FGD when only conventional wet systems are available. For the least stringent requirements, Sq emissions are reduced primarily through coal switching, with some FGD. FGD capacity increases significantly as the emission reduction requirement becomes more stringent, although the absolute valne depends strongly on the constraint on coal choice and the method of allocating b tal emission reductions to individual sources.
In general, FGD retrofits are accompanied by a prefemnce for less expensive, higher sulfur coals to minimize overall cost. Coals that can be washed to remove moderate amonnts of sulfur (typically 10-1596) also are widely selected, especially in the local coal scenarios in which only in-state coals may be selected. Among the three implementation schemes, imposition of uniform caps on So, emissions results in the highest FGD retrofit capacity for a given level of emission reduction. In contrast, the leastast solutions employ full scrubbing of less capacity. The economic
Economic assumptionsfor base h l N lvalue
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Valueadded tax charges Investmenl tax credi rata
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4.5% 11.75% 100%
1.30 $14/tOn Wton 80 rnllWkWh 0.0 FGD expendlture schedule
Coal prlce escalation rates Vanspanation prlce esca!a
1.5/0.76/0.0/0.0
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benefit of this approach is seen in Figure 3b, which shows the average level i cost per ton of SO2 removed for plants retrofitting FGD. (Levelized costs account for all costs incurred over the remaining lifetime of each unit.) This ranges from $460h to $745/t of SO, removed across the set of cases shown. Note that these figures also reflect savings in fuel cost by plants' switching to less expensive coals in conjunction with FGD, hence, they are generally lower than costs that would be incurred if coal switching were not considered. Average FGD costs incurred through the use of only local coals are 9-24% higher than those that would be incurred if coal switching were permitted depending on the implementation plan. The state and regional least-cost strategies indicate FGD costs that are on average 20% lower than corresponding cases with uniform caps, except for the high (80%)reduction level where there is relatively little Uexibdity for cost minimization. The full effect of different implementation methods and coal use constraints is seen in Figures 3c and 3d, which show results for all plants in the region, including those that do not choose FGD. Statewide least-cost strategies 904 Enuiron. Sci. Technol.. Vol. 20, No. 10, I986
lead to overall pollution control costs that are 15-4056 lower than those brought about by corresponding unit caps; regional least-cost strategies reduce average control costs by an additional 3-10%. But the feasibility of implementing the regional approach appears much more limited than the statewide least-cost method (1). At present, total power generation costs in the Midwest are typically 3050 mills/kWh (a mill is one-tenth of a cent) (20). As a result, the added revenue requirements made necessary by SO, emissions control represent average increases of roughly 5-25 % in the total current cost of electricity production across all cases. Seen in this light, various effects are less pronounced when they are compared with total power production costs than with pollution control costs alone. (For instance, local coal constraints add roughly 25 % to the cost of electricity generation hut 9-24% to the cost of S O , control.) Cost increases for individual utilities could vary more widely. A rigorous analysis of future rate effects (prices) paid by consumers would require projection of all future generation costs (including nuclear, coal, oil, and gas) together with a financial analysis reflecting state and federal regulatory
policies, treatment of different customer classes, and other costs such as transmission and distrihution. Table 4 shows the sensitivity of p r e dicted FGD capacity to changes in technical, economic, and regulatory asumptions for scenarios involving leastast strategies. In the case of a 65% SO2 reduction, modest changes in FGD capacity relative to the base case (approximately 3 % of the total regional capacity) result from variations in the FGD retrofit cost premium, price escalation rates, operating and maintenance costs, electrostatic precipitator (ESP) upgrade cost, and unit capacity factors. A much more significant effect is seen for the 20year plant life extension scenario (Case 9), in which the useful lifetime of units greater than 100 MW is extended from 45 to 65 years. The combination of higher expected plant use and longer amortization periods causes roughly 10%more of the eligible capacity to choose FGD to meet the stricter reduction requirements. The effect is even more pronounced when the life extension program is combined with lower real interest rates, which make investment in capital equipment more attractive. The additional requirement to use only local coals (Case 24) results in the highest use of FGD in any
of the scenarios (an additional 20% of the eligible capacity). The coal price and availability assumptions against which future FGD capacity and costs are evaluated are clearly critical faclors in the analysis of scrub-or-switch decisions (21). This is especidy true for low to moderate emission reduction requirements and for plants using high-sulfur coals. Table 4 shows the results of several scenarios involving different coal supply and price assumptions. The base case reflects recently estimated price premiums for lower sulfur eastern coals (23,
together with 1980 estimates of minemouth coal prices and transportation costs (19, 23). Consistent with other' studies, the results show moderate to significant changes in total FGD capacity for the lower SO, reduction requirements, with less sensitivity at high abatement levels.
Dry FGD retrofits Table 5 shows what occurs when retrofit lime spray dryer FGD systems compete with wet FGD. In the base case, dry systems are selected for no more than 3% of the eligible capacity.
The major reason is the assumed need for a new fabric filter collector. Methods are available, however, for conditioning flue gases and upgrading existing electrostatic precipitators to handle higher particulate loadings and higher resistivity (lower sulfur) materials at costs substantially lower than those for a new baghouse (10,24). Although these methods have not yet been demonstrated commercially in conjunction with dry FGD systems, it is reasonable to expect this demonstm tion to occur by the early 1990s. In this case, dry systems become preferable to
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I wet FGD systems for 50% and 65% SOz reduction requirements and are still widely used to meet 80% reduction requirements. When lower particulate costs are combined with an improvement in reagent stoichiometry dry FGD is given a further advantage over wet systems. Overall, such scenarios suggest that technical advances in dry scrubber performance and ESP upgrades could make l i i spray dryer technology extremely competitive for retrofit applications in the eastern United States.
LIMB commercielizBtion Figure 4 shows the pamm of control technology selection when LIMB also becomes a commercially available retrofit option in the next decade. With uniform emission caps (Figure 4a), LIMB and wet FGD are the preferred retrofit technologies for the 50% and 65% statewide SO, reduction levels. Much of the wet FGD capacity again reflects situations in which only partial scrubbing is used to achieve the emission standard. For an 80%reduction in statewide SO, emissions, the capacity wing LIMB decreases and the more efficient dry FGD system comes into wider use. In all cases, more SO, removal techOw Envimn. Scl. Technol.. MI. 20, NO. 10, 1986
nology is employed when only local d s are used in each state. The major difference for the least-cost strategy (Figure 4b) is that dry FGD systems are no longer a strongly preferred option in any of the scenarios. The reason is that theii marginal cost of S@ removal t y p i d l y exceeds that of LIMB at low total abatement levels, as well as that of wet FGD at high abatement levels, for the base. case design and cost assumptions. Average costs of So, removal are shown in Figures 4c and 4d. FGD costs again rise with increasing abatement level and are even higher when only local coals are used. Statewide leastcost strategies result in lower FGD costs than corresponding strategies based on uniform standards. Figures 5a and 5b show the capacity and average costs for all plants retrofitting S a removal systems.To put these costs in perspective, Figures 5c and 5d show resnlts for all plants in the.region, including those that blend, switch coals, take no action, or are retired prematurely as part of an emission reduction strategy. The availabdity of multiple SOa removal options (at lower average cost) results in 5-20% more scrubbed capacity (Figure 5a) than that achieved with wet removal systems only (Figure 3a). Nevertheless, aver-
age So, removal costs for the region as a whole are not affected dramatically. Figures 5a and 5b also show that FGD capacity and cost can be significantly affected by policies formulated at the state level in response to federal requirements. At all three reduction levels illustrated, state-imposed emission allocation schemes and local coal restrictions together can force up to 25% more of the eligible power plant capacity to employ scrubbers relative to the unrestricted (least-cost) solution. Again, overall pollution control cost savings of 1 5 4 0 % are achievable through the statewide least-cost solutions relative to conventional emission caps. In the most restrictive cases, in which states employ uniform emission caps together with local coal constraints to achieve large SO, reductions, the average SO, removal cost for the region as a whole is actually higher than the total cost for plants in the region that retrofit FGD. This is because some plant managers find it more economical to retire the plant prematurely under these circumstances (that is, when the cost of pollution control exceeds the cost of purchasing the foregone power production). 'lhble 6 shows the results of a sensitivity analysis with three S@ removal
(80% reduction)
Constanl
options. The most important technical factor influencing the choice of an S@ control device is the method and cost of particulate control. A scenario in which payoffs from research and developmenf are combined with a major program of plant life extension plus a more favorable long-term outlook for real interest rates (Case 10) results in the strongest preference for FGD system. Although this is clearly an extreme case,it nevertheless suggests that technical advances in combination with other factors can have a significant effect on least-cost SQ removal strategies. Table 6 also shows the results of alternative coal price and choice constraints. For the local coal scenarios in which only washed and unwashed coals produced within each state are available for switching, more wet FGD and less dry FGD and LIMB are chosen. This choice is made necessary because higher removal efficiencies are needed with the higher sulfur coals produced in midwestern states. Use of the two dry removal systems decreases further for the most restrictive case in which only those varieties of coal currently in use at each plant continue to be used (with no additional coal washing). On the other hand, more dry removal technology is expected with lower coal and
transportation prices, which allows more washed and unwashed low- and medium-sulfur coals to be used. Costs will depend on rules Our analysis of the eight midwestern states likely to be most significantly af-
fected by SO2 emission reductions por+, posed to control acid deposition has shown that FGD retrofit capacity and SI& control costs will depend on emission reduction requirements, reduction implementation schemes, control technology options and performance variables, power plant operating characteristics, coal use constraints, and general economic factor?.. For S@ emission reductions of 50-80%, to be achieved by 1995, average S@ control costs for the region as a whole were found to be 525% of total current generating costs over the range of cases considered. In all cases, retrofit FGD systems play a major role in achieving these emission reductions. The way in which states allocate overall SQ emission reductions to individual sources has a significant effect on control technology selection, the cost of FGD, and the total FGD capacity required to achieve a particular level of reduction. Of the three options analyzed in this study, the statewide least-
cost approach is strongly suggested as the most promising option to pursue. Restricting the use of midwestern coal to current or local coals to protect the high-sulfur coal industry also leads to higher control costs and diminished flexibility for SO2 emissions reduction. If they also are faced with a policy of uniform statewide emission standards, as is the case in many parts of the country, some electric utility plants could be forced to be retired prematurely rather thaAbe retrofitted with expensive control te+ology. The ptential effect of plant life extension programs on the attractiveness of FGD technology is significant. Scenarios with 2Cbyear life extensions for units greater than 1M)MW show sizable increases in total FGD capacity together with decreases in the levelized cost of sulfur removal. The extension of commercial l i e spray dryer FGD systems to plants using medium- and high-sulfur coals also can markedly influence FGD retrofit capacity and costs, particularly for overall So, reductions in the range of 5 0 4 5 % . once so2 performance of plants using high-sulfur coals is demonstrated, the most critical factors affecting the viability of dry FGD will be the requirements for and costs of associEnvimn. Sci. Teehnol..\lol. 20, NO.10, 1986 %7
ated particulate control equipment. The ability to upgrade an existing electrostatic precipitator rather than retrofit a new baghouse collector will be essential to the widespread use of dry S q removal systems in wmpe.tition with conventional wet limestone systems. Of the three FGD options examined in this study, the availabdity of direct sorbent injection technology (L.IMB) achieving 50% sulfur removal in the boiler has the most significant effect on the future choice of SO2 control method. However, this conclusion is predicated on the ability to retrofit direct injection systems on most existing coal-fired units, which has yet to be demonstrated. For all FGD options, however, the increased use of coal cleaning for sulfur removal in conjunction with FGD systems often yields the most economical approach to sulfur dioxide emission reductions in the Midwest, particularly if only local coals are employed. The results of sensitivity analyses also affirm the findings of earlier stadies regarding the importance of such faaom as coal prices and overall S q abatement requirements on the extent and cost of FGD retrofits. Results for other regions of the country are expected to show similar sensitivities.
Some uncertainties A number of important caveats obviously must accompany this analysis.
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First, we recognize that some acid rain control proposals are. not adequately modeled here. For instance, a bill that mandam the use of FGD at specific facilities has different (more predictable) implications for the use of this technology. Schemes that place an absolute ceiling on total future sulfur emissions also would lead to different results. For regions that rely heavily on coal, this would more l i l y favor the heavier use of wet FGD systems with much less r e l i c e on other options, such as LIMB,which does not achieve high S q removal efficiencies. The long-term outlook for electrical energy demand and low-emission alternatives to conventional coal combustion technology (including nuclear power, fluidized-bed combustion, coal gasificationcombined cycle processes, and conventional natural gas) obviously take on increased importance if sulfur emissions are capped in perpetuity. In comparing conventional and advanced S a removal systems, we recognize that developing technolcgies, such as LIMB, often grow more costly and less attractive as they approach commercialization (25). We have tried to deal with this through sensitivity analyses based on current estimates of performance and m t , but such scenarios are inherently more speculative than those involving only currently available options. Certain noneconomic faaors. as well
as additional site-specific factors not considered in this analysis, also could affect FGD retrofit decisions and costs for particular power-generating plants or units. As information becomes available, analyses may be improved. The same applies to other analytical and data base refmements, including the evaluation of SO, control options in conjunction with power plant dispatching models; more detailed projections of fum electricity demand, including price elasticity effects; relative power generation costs; financial and tax treatment of utilities; coal price and availability assumptions; and long-term capacity planning. The ability to integrate and examine such considerations in detail will provide the next round of refmements and insights into the role of FGD in controlling acid deposition
Aelmowledgment The work described in this paper was supported by a grant from the Claude Worthington Benedum Foundation (Pittsburgh). Support from EPA in the development of the Advanced Utility Simulation Model project also contributed significantly to this effort. The authors acknowledge the assistance of W. Gooding, 1. Salmento, and H.Dowlatabadi in preparing the software and data bases used in this paper. We also are grateful to the many individuals whose advice, comments, and insight have contributed to these model developments over the past several years.
Before publication, this article was reviewed for suitability as an ES&T feature by James A. Fay, Massachusetts Institute of Technology, Cambridge, Mass. 02139; and Kurt Yeager, Electric Power Research Institute, Palo Alto, Calif. 94303.
References ( I ) Skea. J. F.; Rubin. E. S. Paper85-18.6. In Proceedings of the 1985 Annuol Meeting; Air Pollution Control Association: Pittsburgh, 1985. (2) Skea, 1. F. “Utility Control Strategy Model User’s Manual”; Center for Energy and Environmental Studies. Carnegie-MelIon University: Pittsburgh, 1984. (3) “Utility FGD Survey: April-September 1983.” Report CS-3369; Electric Power Research Institute: Palo Alto. Calif.. 1984. (4) “Acid Rain and Transkrted Air Pollutants: implications for Public Policy,” OTA0-204; Office of Technology Assessment: Washineton. D.C.. 1984. (5) T l e & Coal Use Technologies,’’ DOEIS0 0 3 6 Energy Research Advisory Board, Department of Energy: Washington. D.C.. 1985. Vals. I and II. ( 6 ) Rubin. E. S.; McMichael E C. J. Air Pol/ut. C O ~ ~ ~ O I A S S OiCm . . 2(11), 1099-105. (7) Molburg. J. C.; Rubin. E. S . J. Air Polluf. comroi ASSOC.1983,33(5), 523.30. (8) Anders. W. L.;Torstrick, R. L. “Computerized Shawnee LimelLimestone Scrubbing Model Users Manual.” TVAIOPIEDT-811 I S ; Tennessee Valley Authority: Muscle Shoals. Ala.. 1981. (9) Bloyd, C.N. et al. In “The Pollution Control Module.” final rewrt from the Univerw e < Reuarch Grmp on Energy. CwpcraIne Agreement CR808514. PPA Rcrerrch Trianelc Park. N C 19%. Chmtcr 5 (IO) L&hapelli. D. G . ; Kaplan,‘ N.; Chappell, J. Paper6H. I n Procecdingsofthc First Joinr Symposium on Dry SO, and Simultoneous S 4 - N O . Control Technologies; EPA: Research Triangle Park. N.C.. 1984. (11) Yaeger. K. E. In Proceedings ofthe 1985 American Power Conference; Illinois Institute of Technology: Chicago, 1985. (12) Cavallaro, J. A. et al. “Sulfur Reduction Potential of the Coals of the United States,” 818118; Bureau of Mines: Washington, D.C., 1976; computer tape data augmented to 1982. (13) Skea. J.F.; Rubin, E.S. P a p r 84-27.3. In Proceedings ofthr 1984 Annuol Meeting; Air Pollution Control Association: Pittsburgh, 1984. (14) Skea, J. E; Rubin, E. S. In “Coal Washing MethodoloKy,” final rewrt from the Universities R e k c h Group un Energy. Cooperative Agreement CR808514. EPA Research Trian.de Park. N C 1984. Appndlx
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r -.
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Coal Prices.” EPRl EA-3733; I C F Washington, D.C.. 1984. 123) Morrison. M. B. h f . J. Enernv ”, Svstems , 1983,3(2) 8 6 8 4 . (24) Grieco. G. J. In Proceedings of the 1984 Joinr Power Generotion Conference; American Society of Mechanical Engineers: New York. 1984. ( 2 5 ) Merrow. E. W.; Chapel, S. W.; Worthington. C. “A Review of Cost Estimlion in New Technologies: Implications far Energy Process Plants.” R-2481-DOE Rand Corporation: S a m Monica. Calif.. 1979.
Edward S. Rubin i s a professor in the departments of mchonicol engineering and engineering and public policy at CarnegieMellon Universiry ( C M U ) . H e is also direcfor of CMUi Cenfer for Energy and Environmenfal Sfudies. H e has a Ph.D. in mechanical engineering from Stanford University.
.d: Mar& A. Cushey (I.) i s on rnvironmenral planner with fhe Allegheny Counv Planning Department in Piffsbuqh. H e recently completed his m s f e r of engineering degree in civil engineering ai CMU. R o d J. Mamicio ( r ) recenfly joined Ebosco Services (Columbus, Ohio). Previously, he held fhe position of visiting scholar in the Center for Energy and Environmental Studies at CMU.
(15) Streets, D. 0.; Knudson. D.A,; Shannon, J. D. Environ. Sci. Technol. 1983. 17. 474-8SA. (16) “Evaluation of H.R.3400, the SikorskiWaxman Bill for Acid Rain Abatement.” report for Edison Electric Institute; Temple, Barker and Sloane: Lexington, Mass., 1983. (17) “‘Analysis of Alternative Emission Reduction Strategies: FourlEightITivelve Million Ton Reductions and TenITwelve State Reductions.’’ report for EPA; ICF Washington. D.C., 1984. (18) Fuldncr, A. H. In Proceedings of Cool Technology ‘84; Technical Presentations: Houston. 1984. (19) Morrison, M. B.; Rubin. E. S . J. AirPollur. Control Arroc. 1985,31(1 I),1137.48. (20) “Historical Plant Cost and Annual Production Expenses for Selected Electric Plants 1983.’’ DOE/EIA-0455(83); Department of Energy: Washington. D.C.. 1985. (21) “‘Agenda of Critical Issues: Coal Price and Availability.” EPRl EA-3750; Temple, Barker and Sloane: Lexington. Mass., 1984. (22) “Effects of Resource Depletion on Future
The most complete listing of college chemistry faculties in the U S . and Canada
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pages ...6 3 4 . 0 0 Cary N . Bloyd (i.) ; s a scientirr at the CMU Center Jhr Encwgy ond Environmenfal Sfudies. H e obfained his M.S. in mechanical engineering and his Ph.D. in engineering and public policyfrom CMU.
James E Skea fr) is a research fellow in the Science Policy Research Unit at the University of Sussex, England. H e obtained his Ph.D. in physicsfrom the University of Cambridge.
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