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Air Quality and Stationary Source Emission Control CHAPTER 9 EFFECTS OF IMPROVED FUEL UTILIZATION ON DEMAND FOR FUELS FOR ELECTRICITY (Chapter 9 was written by Elias Gyftopoulos and Thomas Widmer under the general supervision of the committee, which reviewed the work at several stages and suggested modifications that have been incorporated. While every committee member has not necessarily read and agreed to every detailed statement contained within, the committee believes that the material is of sufficient merit and relevance to be included in this report.) INTRODUCTION This chapter estimates the potential reduction of fuel for electricity in 1985 resulting from improved utilization of fuel in industrial, residential, and commercial end-uses. Because a fraction of the fuel used for electricity is coal, improved fuel utilization is a method complementary to other available methods for reducing sulfuric oxides and sulfates discharged into the atomosphere by electric powerplants. The chapter also evaluates the potential effect on fuel-demand for electricity resulting from some alternate methods of space heating.
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Air Quality and Stationary Source Emission Control PATTERNS OF FUEL SUPPLY AND DEMAND This section presents statistical data for the U.S. patterns of fuel supply and demand (SRI 1972) in 1968 and projections for these patterns for 1985 (Dupree and West 1972). Although many projections have been made for 1985, for the purposes of this report, we will consider only the projections of the U.S. Department of the Interior (Dupree and West 1972). In 1968, the amount of fuel consumed in the U.S. was about 57 quads (1 quad=1015 Btu) exclusive of about 3 quads used as feedstock materials. It was distributed among the fuel sources approximately as follows: Petroleum products 43.5% Coal 23.0% Natural Gas 32.0% Nuclear and hydrostatic head 1.5% 100% It was consumed in the major sectors of the economy in the amounts shown in the first and second columns of Table 9–1, namely 41 percent in the industrial sector, 34 percent in the residential and commercial sector, and 25 percent in the transportation sector. Some of the fuel was consumed in the form of electricity (columns 3 and 4, Table 9–1) which was primarily (92 percent) from utilities and to a lesser degree (8 percent) generated as by-product of industrial processes. The fuels used in electricity generation were 53.5 percent coal and 46.5 percent others. The principal end-uses of fuels in industry in 1968 can be classified in the four major catagories shown at the bottom of Figure 9–1 among which the fuels are distributed as follows:
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Air Quality and Stationary Source Emission Control TABLE 9–1 Fuel Consumption by Sector in 1968 Sector All fuels Electricity 1012 kwh 1015 Btu Percentage % Generated by Utilities Total Industrial 23.0 41 0.6 0.72 Residential and commercial 19.5 34 0.73 0.73 Transportation 14.5 25 NIL NIL Total 57.0 100 1.33 1.45
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Air Quality and Stationary Source Emission Control FIGURE 9–1: Sources and End-uses of Fuel by U.S. Industry in 1968.
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Air Quality and Stationary Source Emission Control Direct combustion heating 29.0% Process steam 44.7% Direct electric heating 1.3% Motors, lighting and electrolysis 25.0% 100% The principal end-uses of fuels in the residential and commercial sector are shown in Table 9–2. We see from the data in Figure 9–1 and Table 9–2 that process steam raising, space and process heating, and refrigeration and air conditioning in 1968 represented the major end-uses of fuels in sectors other than transportation. These processes consumed over 50 percent of the coal in 1968 as illustrated by the data in Table 9–3. Several projections have been made about the fuel demand in 1985. For the purposes of this report, the projections of the U.S. Department of the Interior have been used (Dupree and West 1972). The projected demand in the major sectors is shown in the first column of Table 9–4 exclusive of fuels for feedstock materials. It will be distributed among the principal fuel sources approximately as follows: Petroleum product 42% Coal 28% Natural Gas 25% Others 5% 100% Some of the anticipated fuel demand will be supplied by utilities in the form of electricity as whown in the third column of Table 9–4. Comparing the data in Tables 9–4 and 9–1 we see that in 1985 the demand for all fuels is projected to be about two times as large, and for electricity about three times as large as those in 1968. The demand for fuels for electricity generation is projected to be as shown in Table 9–5. We see from this table that 37 percent of electricity will be generated from coal in
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Air Quality and Stationary Source Emission Control TABLE 9–2 Major End-Uses of Residential and Commercial Fuel in 1968 (excluding feedstock) FUEL End-use Percentage of sector fuel % Electricity 1015 Btu(1) Petroleum and gas for direct firing 1015 Btu Coal for direct firing 1015 Btu Total 1015 Btu Heating Space 56 0.48 9.84 0.57 10.89 Water 13 0.9 1.55 NIL 2.45 Refrigeration and air conditioning 16 3.0 0.1 NIL 3.1 Total 85 4.38 11.49 0.57 16.44 (1) 1 kw-hr of electricity=10,000 Btu fuel in power plant.
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Air Quality and Stationary Source Emission Control TABLE 9–3 Selected End-Uses of Coal in 1968(1) End-use 106 tons Percentage of coal consumption % Industrial Process steam 87 18.5 Heating 51 11 Residential and Commercial Heating 49(2) 10.5 Refrigeration and air-conditioning 56(3) 12 Total 243 52 (1) Total consumption 13.1 quads or 470×106 tons at 28×106 Btu/ton. (2) Weighted average of direct coal usage and electricity produced by using 53.5% of fuels in the form of coal. (3) Based on 53.5% of electricity produced from coal.
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Air Quality and Stationary Source Emission Control TABLE 9–4 USDI Projected Fuel Demand by Sector in 1985 Sector All fuels Electricity generated by utilities 1015 Btu Percentage 1012 kw-hr Percentage Industrial 41.9 38.5 1.86 45 Residential and commercial 39.7 36.5 2.23 54 Transportation 27.2 25.0 0.04 1 Total 108.8 100 4.13 100
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Air Quality and Stationary Source Emission Control TABLE 9–5 USDI Projection of Demand of Fuels for Electricity Generation in 1985(2) Fuel Electricity 1012 kw-hr Percentage of total electricity % Coal 1.53 37 Hydrostatic head and geothermal 0.25 6 Petroleum and gas 1.07 26 Nuclear 1.28 31 Total 4.13 100
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Air Quality and Stationary Source Emission Control 1985 whereas 53.5 percent of electricity was generated from coal in 1968. POTENTIAL FOR IMPROVED EFFECTIVENESS Industrial Sector As discussed in a report to the Energy Policy Project of the Ford Foundation (Gyftopoulos et al. 1974) many opportunities exist for the application of existing technology to the enormous fuel flow in industrial heating processes so as to yield large fuel savings. For example, the bulk of industrial fuel (about 45 percent in 1968) is consumed in raising process steam. Wherever process steam is required in reasonable amounts, an opportunity exists to produce electricity at small cost in fuel consumed. For example, if process steam at 200 psi or 382 F is generated by burning a hydrocarbon fuel, (CH2) n, over 60 percent of the available useful work of the fuel is lost. Much of this loss may be prevented by burning fuel in a gas turbine and using the turbine exhaust to generate steam (Figure 9–2a), by generating steam at a pressure higher than 200 psi and expanding the steam in a steam turbine to 200 psi at which pressure it is exhausted to process (Figure 9–2b), or by a combination of these two (Figure 9–2c). Figure 9–3 compares a combined system (Figure with the more widely used present practice of spearate generation of steam and electricity.) Typical results of the electricity generated by the various topping systems are summarized in Table 9–6. The electricity produced, if considered as a by-product of the process heat, should be charged with the fuel consumption over and above that required when process steam is produced directly without the intervening
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Air Quality and Stationary Source Emission Control FIGURE 9–2: Combined Process Steam Raising and Electricity Generation Options for Process Steam at 200 psi and 106 BTU/hr.
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Air Quality and Stationary Source Emission Control from coal gasifications; assuming a gasification and distribution efficiency of 0.62, demand would be modified as follows: EVALUATION OF CAPITAL COST FACTORS Costs Related to Improved Effectiveness The evaluation of the relative benefits of various fuel saving methods necessitates consideration of both capital requirements and fuel pricing practices. From an aggregate capital availability point of view, it is important to compare the capital for supplying additional fuel with that for saving an equal amount of fuel through improved effectiveness measures. Some estimates for capital required to supply various forms of energy are listed in Table 9–8. All figures are normalized to the equivalent of one barrel of oil per day. For an industrial installation needing 1 megawatt of electricity, if this electricity were to be provided by a coal-fired powerplant, with a load factor of 0.7, the capital required would be: Coal-fired powerplant (AGA 1974) $ 456,000 Distribution 180,000a Coal supply (28 barrels of oil per day equivalent annual average) 48,000 Total $ 684,000 (a Note: Capital investment in distribution system for industrial customers assumed to be $13,000 per 1760 kw-hr of electricity per day which is energetically equivalent to 1 barrel of oil per day; comparable figure used for residential customers in Table 9–8 is $20,500.)
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Air Quality and Stationary Source Emission Control TABLE 9–8 Approximate Capital Costs for Supplying the Fuel Equivalent of One Barrel of Oil Per Day (6×106 Btu/day) in Various Forms 1. GAS FROM COAL GASIFICATION Coal production (Eastern deep mine) $ 2,800 (a) Gasification plant (AGA 1974) 10,000 Transmission and distribution system 7,400 (b) $20,200 (a) At 0.62 plant and distribution efficiency (b) Assumes $1.35 per million Btu ($8.10 per barrel of oil equivalent) as the average cost of transmission and distribution to residential customers in the Eastern United States. Fifty percent of this figure is assumed to derive from capital charges computed at 20 percent annually, namely 2. OIL FROM NEW DOMESTIC SOURCE Production (off-shore) (7) $5,000–$8,000 (c)(d) Refining 1,000 Transportation and distribution 3,000 (e) $9,000–$12,000 (c) Includes bonuses paid on leases (d) Estimates for shale oil, synthetic crude from coal, or tertiary recovered oil vary from $10,000 to $20,000 per barrel per day. (e) For Alaskan oil, the pipe line alone costs $5,000 per barrel per day. 3. ELECTRICITY FROM COAL-FIRED POWERPLANT Coal production (Eastern deep mine) $ 5,500 (f) Electric plant (AGA 1974) 36,500 (g) Transmission and distribution system 20,500 (h) $62,500 (f) Electricity generated at 0.34 plant and distribution efficiency. (g) Estimate based on average capital cost $456/Kw for new coal-fired generating plants greater than 1,300 Mw capacity that could be on-stream by 1981, and load factor 1.0. (h) Assumes 1.28¢ per kw-hr as average cost of distribution to residential customers, with 50 percent of this figure attributed to capital costs, as in note (b) above.
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Air Quality and Stationary Source Emission Control On the other hand, suppose that the industrial installation has a potential application for a 1.0 megawatt bottoming-cycle engine generator to recover waste heat from a large continuous metal processing furnace with an annual utilization factor of 0.7. At $400 per kw, the capital required would be $400,000 and the fuel consumed would be zero. To this may be added $62,000 for 50 percent emergency supply diesel generators and, therefore, the capital investment would be $462,000. From these results we see that the investment for incremental electricity from a coal-fired powerplant would require about 48 percent more than that for the on-site bottoming-cycle system. For an oil-fired powerplant, the advantage of the bottoming cycle is even greater. On the other hand, whether the advantage of the fuel-saving over the increased fuel supply method will be evident to the industrial firm depends on fuel pricing policies. If the price of fuel reflects the true cost of new fuel supplies then the bottoming cycle is advantageous. If the price of fuel is based on averages over old and new sources then the bottoming cycle and, therefore, the advantage of the fuel-saving method may not be as decisive as the preceding capital requirement estimates indicate. To illustrate this point, we shall assume 2.5 cents per kw-hr as being representative of the price paid by an industrial customer for electricity. By assuming a ten-year sum-of-year- digit depreciated life time for the bottoming cycle generator, a 0.3 cent per kw-hr operating and maintenance cost and a 70 percent duty cycle, we obtain the following
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Air Quality and Stationary Source Emission Control break-even capital costs for on-site power generation with bottoming cycle system: Required after tax (52%) return on investment Break-even capital cost for bottoming cycle system 12% 546 $/kw 15% 469 $/kw We see that the bottoming cycle capital requirement of 462$/kw is comparable with the break-even cost determined from the price of electricity of about 2.5 cents per kw-hr. It follows that for the assumed price of electricity, the user most likely will decide to buy electricity rather than install a bottoming-cycle system. The reason for such a decision is, of course, that the assumed price of electricity does not reflect the true cost of new supplies. Costs of Fuel Shifting for Space Heating The demand for fuel for residential and commercial space heating could be shifted from oil and natural gas to either electricity generated from coal or to alternate sources such gas produced from coal. Table 9–9 lists estimates of capital requirements for three alternate methods of space heating, electric resistance, electric heat pump, and gas from coal, all of which use coal as the primary fuel. The calulations are based on residential heating units requiring 150×106 Btu per year, or 0.07 equivalent barrels of oil per day. We see from this table that electric heat pumps offer the lowest total fuel consumption of the three cases. Gas from coal gasification on the other hand, affords a significant saving in capital investment over either form of electrical space heating. It should be noted that the investment advantage for the gas from coal
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Air Quality and Stationary Source Emission Control TABLE 9–9 Capital Investment of Alternate Home Heating Methods Using Coal as Primary Fuel Home heating method Electric resistance Electric heat pump Gas from coal gasification Plant efficiency: 0.34 0.34 0.62 Home furnace yield: 1.0 1.8 0.7 Barrel per day equivalent coal consumed per equivalent barrel of oil per day of heat supplied to home 2.94 1.63 2.30 Capital investment per equivalent barrel of oil per day of heat supplied to home Supply planta $ 96,100 $ 53,400 $ 44,400 Home heating plantb 7,200 28,600 14,300 Total $ 103,300 $ 81,000 $ 58,700 a Load factor for all plants 0.65. b Based on home heating unit costs of $500, $2,000 add $1,000 per home from baseboard resistance, heat pump, and gas-combustion furnaces, respectively.
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Air Quality and Stationary Source Emission Control gasification approach will be increased even further when adjustment is made for the high percentage of existing gas home-furnaces which would have to be replaced if either electric heating concept were adopted. SUMMARY OF DEMAND MODIFICATION ALTERNATIVES The limiting incremental values of effects of demand modifications established in the preceding sections can be allocated to coal. The results are summarized in Tables 9–10 and 9–11 in million tons of coal per year on the basis of 1 ton of coal =24×106 Btu. Only a fraction of these effects can be achieved, however, by 1985 partly because some industrial plants may be too small in size to justify a modification, partly because of fuel-pricing policies that do not make changes attractive, and partly because of institutional constraints. For example, a plant may need process steam in amounts which do not justify economically the installation of a topping system, or the price of electricity may be low enough so that the investment for an on-site system cannot be recovered in sufficiently short time. Finally, there may be state or local utility regulations which prohibit the sale of surplus electricity by an industrial plant to a utility. EFFECTIVENESS OF FUEL UTILIZATION IN A PROCESS In attempting to evaluate the opportunity for fuel saving in a particular process, we need to know the minimum fuel requirement for the process so that we can compare it with the fuel consumed under current practice and obtain a measure of the effectiveness of that practice. The minimum fuel requirement can be evaluated by means of the thermodynamic concept of
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Air Quality and Stationary Source Emission Control TABLE 9–10 Maximum Potential Shift in Coal Requirements Resulting from Selected Improvements in Electrical Effectiveness at Point of Use. (1 quad=24×106 tons of coal) Demand modification Maximum incremental coal consumption (tons/year from 1985 baseline USDI forecast) On-site generation of by-product electricity in industrial processes −333×106 Re-optimization of Aluminum electrolysis process to lower current density(1) −10×106 Improved performance residential & commercial refrigeration air conditioning equipment −75×106 Relamping of commercial & public buildings to FEA lighting standard −54×106 (1) Aluminum electrolysis, which accounts for about 7.5% of industrial electricity, is shown as an example of improved industrial process effectiveness. In order to determine potential savings for improvements in other electrical-intensive processes, it will be necessary to perform a detailed study of each individual industry.
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Air Quality and Stationary Source Emission Control TABLE 9–11 Maximum Potential Shift in Coal Requirements Resulting from Shifting All Residential and Commercial Space to Methods Based on Coal as Primary Source Demand modification Maximum incremental coal consumptiona (tons/year from 1985 baseline USDI forecast) Shift all space heating to electric resistance +1640×106 Shift all space heating to electric heat pumps +896×106 Shift all space heating to gas from coal gasification + ×106 a The corresponding reduction in oil and natural gas consumption is about 9 million barrels of oil equivalent.
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Air Quality and Stationary Source Emission Control available useful work. Readers unfamiliar with the foundations of thermodynamics and the concept of available useful work might consult the article on “Principles of Thermodynamics” in the 1974 Edition of the Encyclopedia Britannica In a report prepared for the Energy Policy Project of the Ford Foundation (Gyftopoulos et al. 1974) the concept of available useful work was used to evaluate the effectiveness of fuel utilization in five energy-intensive industries. Table 9–12 lists the industries, outputs, specific fuel consumptions, and total fuel consumed in 1968. In addition, the table lists the minimum specific fuel requirements, and minimum total fuel requirements for these industries. It is seen from these data that the average fuel effectiveness for the five industries under consideration is 1.17 ×1015/9.2×1015=13 percent. The average fuel effectiveness of 13 percent should not be confused with the efficiency value of 70 percent or higher reported in the literature. The latter figure represents the average fraction of the heating value of the fuels that are used in industrial processes. The large margins that exist between current practives and minimum theoretical requirements indicate the potential which is available for major long-term reductions in fuel consumption through basic process modifications.
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Air Quality and Stationary Source Emission Control TABLE 9–12 1968 Product Output and Fuel Consumption for Selected U.S. Industries Industry Industry Output (tons/yr) Specific Fuel Consumption (Btu/ton) Total Fuel Consumption (Btu/yr) Percentage of Industrial Sector Fuel Theoretical Minimum Specific Fuel Consumption Based Upon Thermodynamic Availability Analysis (Btu/ton) Minimum Total Fuel Requirement (Btu yr.) Iron and Steel 131×106 26.5×106 3.47×1015 15.2 6.0×106 0.79×1015 Petroleum Refining 590×106 4.4×106 2.6×1015 11.4 0.4×106 0.24×1015 Paper and Paperboard 50×106 39×106 1.95×1015 5.4 bGreater than −0.2×106 smaller than +0.1×106 0.00 Primary Aluminum 3.25×106 190×106 0.62×1015 2.8 25.2×106 0.08×1015 Cement 72×106 7.9×106 0.57×1015 2.5 0.8×106 0.06×1015 TOTAL 9.2×1015 38% - 1.17×1015 a Includes heating value of waste products (bark and spent pulp liquor). b Negative value means that no fuel is required.
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Air Quality and Stationary Source Emission Control LITERATURE CITED American Gas Association (1974) Gas Supply Review, Gas Supply Committee. Volume 3, Number 2, November. Dupree, W.G., Jr. and J.A.West (1972) U.S. energy through the year 2000, U.S. Department of the Interior. Federal Energy Administration, Lighting and thermal operations, energy management action program for commercial, public, industrial buildings—Guidelines. U.S. Government Printing Office, Washington D.C. Gyftopoulos, E.P., L.J.Lazaridis, and T.F.Widmer (1974) Potential fuel effectiveness in industry, Ballinger Publishing Company, Cambridge, Massachusetts, Report to the Energy Policy Project of the Ford Foundation, November. Morgan, D.T. and J.P.Davis (1974) High efficiency decentralized electrical power generation utilizing diesel engines coupled with organic working fluid rankine-cycle engines operating on diesel reject heat. Prepared for the National Science Foundation, Washington, D.C. NSF Grant No. GI-40774, November. SRI (1972) Patterns of energy consumption in the United States, U.S. Government Printing Office, Stock Number 4106–0034, Washington, D.C.
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