radation rate of original PVP and ozonized PVP. In the case of the ozonized PVP, a steep drop of TOC was observed in the first two days of incubation. However, the subsequent rate of TOC drop was the same as that of original PVP. The initial TOC drop in PVP ozonized for 4 h was larger than that ozonized for 2 h, and the former was 200 ppm and the latter about 100 ppm. The fragments biodegraded in such initial incubation are found to be mainly ozonization products of molecular weight less than 100 from the variation of gel filtration pattern shown in Figure 3B. The biodegradability of ozonization products of molecular weight larger than 100 was the same as that of the original, even when the molecular weight was only a few hundred. On the other hand, the effluent peak corresponding to the molecular weight less than 100 still remained in the pattern of the 13th day. This phenomenon indicates that it is difficult to biodegrade some of the ozonization products of low molecular weight. The ozonization mechanism of PVP cannot be elucidated a t present. Accordingly, the nature of the low molecular weight compound produced by ozonization is still obscure. Polyacrylamide. The biodegradation rate and the variation of the gel filtration pattern relating to PAA are shown in Figure 4. The PAA was undoubtedly deteriorated by ozone, and the molecular weight of 280000 was lowered to average 340 a s t h e result of 4 h ozonization as can be seen in Table I and Figure 4B. However, the biodegradation rate of the ozonized PAA was about the same as that of original PAA, and the biodegradability of PAA was hardly affected by ozonization. Also, as can be seen from the gel filtration pattern, even the ozonization products of molecular weight less than 100 were scarcely biodegraded during 8 days incubation. These results suggest that PAA's resistance to biodegradation results from not only the high molecular weight but also the molecular structure containing amide group.
Sodium Polyacrylate. As shown in Figure 5A, the biodegradation rate of the ozonized PANa was larger than that of the original, and the biodegradability of PANa was improved by ozonization. On the other hand, from the variation of gel filtration pattern in Figure 5B, it can be seen that the PANa of molecular weight 1000 to 100 produced by ozonization disappeared by biodegradation during 34 days of incubation and that low molecular weight portions predominantly remained without being biodegraded. These results indicate that lowering the molecular weight of PANa by ozonization contributes toward an improvement in biodegradability, but some of the low molecular weight compounds produced at the same time are hard to biodegrade.
Literature Cited (1) Pitter, P., Water Res., 10,231 (1976). (2) Patterson, S. J., Scott, C. C., Tucker, K.B.F., J . A m . Oil Chem. SOC.,47,37 (1970). (3) Rossall, B., Int. Biodeterior. Bull.,, 10,95 (1974). (4) Richard, T., Kaplan, A. M., Appl. Microbiol., 16,900 (1968). (5) Booth, G . H., Cooper, A. W., Robb, J. A., J . Appl. Bacteriol., 31, 305 (1968). (6) Suzuki, T., Ichihara, Y., Yamada, M., Tonomura, K., Agric. Biol. Chem., 37,747 (1973). (7) Fincher, E. L., Payne, W. J., Appl. Microbiol., 10, 542 (1962). (8) Haines, J. R., Alexander, M., ibid., 29,621 (1975). (9) Ogata, K., Kawai, F., Fukaya, M., Tarii, Y., J . Ferment. Technol., 53,757 (1975). (10) . . Jones. P. H.. Prasad. D.. Hesins. M.. Morean. M. H.. Guillet. J. E., Enuiron. Sci. Technol.,' 8,919 (1974). (11) Spencer, L. R., Heskins, M., Guillet, J . E., Proc. of3rd Int. Biodegradation Symp., USA, p 753, 1975. (12) Suzuki, J., J . A p p l . Polym. Sci., 20,93 (1976). (13) Cazes, J., J . Chem. Educ., 43, A567 (1966). (14) Suzuki, J., Nakagawa, H., Ito, H., J . Appl. Polym. Sci., 20,2791 (1976).
Received for review September 6, 1977. Accepted May 15, 1978
Feasibility Study of Condensation Flue Gas Cleaning (CFGC) System John C. Cooper', Richard M. Ostermeier", and Russell J. Donnelly Department of Physics, University of Oregon, Eugene, Ore. 97403 ~
The feasibility of control of large stationary source (nonparticulate) emissions by condensation is studied. Measurements of condensation rates and calculations of the heat load characteristics for a variety of coal-air mixtures are made. Based on these results and certain assumptions concerning particulates, ice removal, and latent heat recovery, a system design and an order of magnitude cost estimate are made for a 700-MWe coal-burning power plant. The technique can control emissions of S02. The relatively higher vapor pressures of NO2, sulfates, and heavy metal vapors suggest that these pollutants may also be contained. It is estimated that the CFGC system will cost between $180 and 275/kWe (1976 dollars) and require 5-8% auxiliary power depending on plant performance and coal composition. These costs may be reduced by optimization or process changes. H
Is the removal of SO2 from coal-fired power plant flue gas by cryogenic condensation economically feasible? This question was answered in the negative in an earlier study (1) in which a final condensation stage at LN2 temperatures was assumed. Our preliminary calculations indicated condensation of SO2 could be accomplished a t considerably higher temperatures and therefore lower cost. In addition, the potential for simultaneous removal of a number of other pollutants warranted a more detailed study of the condensation technique. This report describes a feasibility study of the CFGC system for control of SO2 emissions from a 700-MWe coalburning power plant. The study included an experimental determination of the condensation rates of SO2 and C 0 2 for various simulated flue gas mixtures under a variety of flow conditions; heat load calculations for different coal compositions and excess air ratios; and a preliminary system design and cost estimate based on the condensation data and heat load calculations ( 2 ) . Condensation Experiments
Present address, Manufacturing Processes Laboratory, Ford Motor Co., 24500 Glendale Avenue, Detroit, Mich. 48239. 0013-936X/78/0912-1183$01.00/0
The absence of condensation data in the literature for flue gas mixtures in a flowing nonequilibrium system necessitated
@ 1978 American Chemical Society
Volume 12, Number 10, October 1978
1183
SENSOR
Ll
TEMPER ATU R E CONTROLLER
COMPUTER
CHROMATOGRAPH
reduced in steps from room temperature. Final temperature was usually such that the outlet concentration of SO2 or COz was well below the level demanded by Federal emission limits for SO2. Several condenser configurations and flow rates were tested. In general, the condensers incorporated two or three lengths of stainless steel tubing of decreasing diameters. Larger inlet sections provided the volume necessary for the larger amount of condensate collected near the inlet. Smaller tubes more efficiently collected the remaining condensable fractions of the gas mixture. Gas flow rates and the pressure drop across the condensers were constant. After an extended period of time, pressure drop across the condenser would increase, indicating incipient plugging. The data shown in Figures 2 and 3 were all collected before any measureable increase in pressure drop. Figure 2 shows results obtained for SO2 in N2 at typical flue gas concentrations. The dashed line is an extrapolation of published SO2 vapor pressures for higher temperatures ( 3 ) , assuming ideal fluid behavior. The solid line is a least-squares fit of the form log P = a bT-l c T - ~to the measured values. The measured partial pressure of SO2 decreases more rapidly with temperature than the extrapolation (an advantage in the CFGC system), and the curvature (Le., c # 0 ) of the line indicates a departure from ideal fluid behavior which may arise from the large electric dipole moment of S02. This fit reproduced all the data taken for a variety of mixtures in various condenser configurations. Flow rates were also varied by a factor of 80,and the results showed no measurable change in condensation efficiency. At the lowest flow rate the Reynolds number in the smallest condenser section was 124; therefore, flow was probably laminar ( 4 ) .The data show more scatter at higher flow rates, but again there is no significant change in SO2 partial pressure. With the sharp changes in diameter near the inlet, and a Reynolds number of 10 400, the flow should have been turbulent at the highest flow rate. When C02 was added to the gas mixture, its condensation did not significantly change the SO2 partial pressure in the effluent. This is a departure from ideal fluid behavior in an equilibrium svstem, where Raoult's law would imply that the
I Figure 1. Diagram of condensation test apparatus
experimental determination of the condensation rate for S02. The condensation of CO2 was also measured since in most actual flue gas mixtures, satisfaction of Federal New Source Performance Standards (NSPS) for SO2 requires concomitant condensation and removal of C02. Comparison of our measurements for SO2 and C02 with known equilibrium vapor pressures and extrapolations of that data to lower temperatures allawed us to estimate the effect of the CFGC system on other condensable pollutants from their equilibrium data. In the condensation experiments, simulated flue gas mixtures using N2, C02, and SO2 were passed through a condenser unit located inside a temperature-controllable refrigerated box. The concentration vs. temperature of C02 and SO2 in the effluent gas was determined using gas chromatography. It was assumed that the addition of 0 2 would produce no extra effect beyond that of N2 on the condensation of SO2 and COZ. It was assumed here and throughout the study that the untreated flue gas would be essentially free of particulates, that any remaining particulates would not adversely affect the CFGC system operation, and that SO2 removal aiong with the condensation of water vapor would not be sufficient to approach performance standards. These assumptions should be tested early in any subsequent development program. The refrigeration system consisted of a Styrofoam box, temperature controller, and LN2 supply. The box was fitted with stainless steel tubing inlets and outlets. An internal fan maintained circulation and improved temperature uniformity and heat transfer. The box was cooled by LN2 vapor admitted by a temperature-controlled solenoid valve. The controller senses temperature using a type K P thermocouple (Au:Au 7% Fe) which can be placed at an appropriate point for temperature control to within,fl "C. A block diagram of the test system is shown in Figure 1with the gas mixing apparatus on the left and the condenser unit under test in the refrigeration system on the right. Temperatures were measured at two points on the condenser surface, one of which was used for temperature control. The composition of the effluent gas was measured using a HewlettPackard 7624A gas chromatograph (GC) equipped with a flame photometric detector with 393-nm filter for SO2, and a thermal conductivity detector for COP.A 6-m Teflon column packed with 12%polyphenyl ether and 0.5% H3P04 on 40/60 mesh Chromasorb T was used for sulfur analysis. A 1-m stainless steel column with 80 mesh Carbosieve-B was used for C02 separation. An H P 3352 data system converted the GC data to effluent concentration. Prepared external standards (Scott Research Labs) were used for C02 calibration. SO2 calibration was accomplished using permeation tubes. For a typical test the GC was calibrated, and the flows were adjusted and allowed to stabilize. Concentrations were measured periodically as the temperature of the condenser was
+
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5 -
+
1184
Environmental Science & Technology
I P K ) 195
180
185
175
180
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Figure 2. Condensation of sulfur dioxide in nitrogen
Sold line: least-squaresfit to data from three separate tests, representedby three different shapes. Dashed line: extrapolation of published data for higher temperatures. T: temperature of condensing surface
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Figure 3. Condensation of carbon dioxide in nitrogen Solid line: least-squares fit to data from three separate tests represented by different shapes. Dashed line: published equilibrium vapor pressure. T: temperature of condensing surface
partial pressure of SO2 in the gas mixture should be reduced in proportion to the mole fraction of SO2 in the condensate. If this occurred, the SO2 partial pressure would be reduced by about an order of magnitude at the lower pressures. There are probably two reasons the reduction is not observed in this system. The ideal fluid analysis assumes the attraction between all molecules in the condensate is identical; however, SO2 has a large dipole moment and COz has none. Therefore, the attraction between COz and SO2 molecules is considerably less than that between two SO2 molecules. Furthermore, in a flowing system the SO2 and COz may condense largely in different locations, so the mole fraction of SO2 in the condensed mixture can be much larger than the -10% implied by the condensation rates of SO2 and COz. The combination of these effects is apparently such that COz condensation does not contribute significantly to control system performance. On the basis of these results the fit shown in Figure 2 was selected as the reference SO2 partial pressure curve on which the CFGC system design was based. Figure 3 shows measured partial pressure of COZ in the condenser effluent under conditions similar to the SO2 tests of Figure 2. The solid line in Figure 3 is a least-squares fit to the data using the form log P = a bT-l, and the dashed line is the published equilibrium vapor pressure ( 3 ) .COZ follows the straight line behavior characteristic of an ideal fluid, but the measured partial pressures are higher than the equilibrium values over the temperature range of the tests. This was expected since the system does not allow the condensation process to reach equilibrium. The solid line in Figure 3 was selected as the reference COz data for the system design.
cooling and partial condensation are then calculated using published specific heats and latent heats. Condensation rates as a function of temperature are based on published data for water and on the design reference data of Figures 2 and 3 for SO2 and COz. The temperature necessary to meet the NSPS of 1.2 lb of SO2 per million BTU ( 5 ) is calculated from the calorific value and condensation data. The program tabulates flue gas composition, type and quantity of condensate, and the heat rates at various temperatures, and plots the heat rates and energy required to reheat the cleaned flue gas as a function of temperature. Flue gas composition, dew points and other critical temperatures, and the heat load were calculated for various coal compositions (6) and for excess air ratios from 10 to 40%. High-volatile C bituminous coal burned with 40% excess air was chosen for the CFGC system design. This fuel is representative of a fairly high sulfur coal (3.8%sulfur content), and when burned with 40% excess air the overall heat load it places on the control system is among the highest. Thus, this fuel/air combination places stringent demands on the control system and should result in a conservative design and cost estimate. A set of heat load curves for this reference case is shown in Figure 4. The upper set of curves indicates heat loads for the cooling and condensation process. The lower set shows the heat rate required to reheat the cold, clean flue gas. The curves are calculated for plant heat rates of 8.5 and 10 million BTU/h which, if used to generate one megawatt of electrical power, correspond to thermal efficiencies of 40.1% and 34.1%, respectively. Though modern coal-fired power plants typically operate near the higher efficiency, the CFGC system design assumed a heat rate of 10 MBTU/h for 1MWe output to ensure a conservative design. For comparison an anthracite coal burned with 10% excess air would result in a heat load of 75% of the design case. If used in a plant with a heat rate of 8.5 X
A
,Q
+
Heat Loads Steam coals used in the United States vary widely in composition and combustion properties. A computer program was written to assess the effect of these variations and to select a representative case for the CFGC system design and cost analysis. The program calculates the rates of the combustion products, based on the fuel's ultimate analysis and calorific value and the amount of excess air supplied. Heat loads for
1
-200
-100
I
0 100 200 3 0 FLUE GAS TEMPERATURE DEG. F
-
Figure 4. Control system heat load for high volatile C bituminous coal burned with 40% excess air and two plant heat rates Upper pair of curves: cooling and condensation; lower pair: reheat of remaining gas mixture. Curves for heat rate of 10 million BTU/h used fdr this system analysis. Those for 8.5 million BTU/h represent less stringent "average" case
Volume 12, Number 10, October 1978 1185
Figure 5. Summary of process flow diagram. Dashed lines: heat flow
lo6 BTU/MW-h, the control system heat load per unit of electrical output would be only 64% of the design case. S y s t e m D e s i g n a n d Cost A n a l y s i s
To estimate costs and auxiliary power requirements for a condensation flue gas cleaning system, a conceptual design of a CFGC system to process flue gas from a 700-MWe coalfired power plant was developed ( 2 ) .This design is based on the condensation data shown in Figures 2 and 3 and on the high volatile C bituminous coal composition burned with 40% excess air. The system is shown schematically in Figure 5. Flue gas leaves the precipitator at about 300 O F and enters the CFGC system. A fan drives the gas through a series of five heat exchangers (E-1 through E-5) where it is cooled to 42 O F . Since the condensed watyr (dew point of 106 O F ) will be corrosive, Teflon bundles are used for the heat exchange surfaces and the ducts are rubber coated. Further cooling to -134 O F (the SO2 dew point) occurs in a series of three double-embossedplate heat exchangers, the first two (E-6 and E-7) of 316L stainless steel and the third (E-8) of 3l/2% nickel steel. It is assumed that the solid condensate that collects on these plates can be removed by flexing the plates. It is also assumed (as partially corroborated by our condensation measurements) that icing does not adversely affect heat transfer. The solid condensate is removed in an ethanol slurry. (Ethanol was selected as a slurry carrier because of its low freezing point and viscosity. It can also absorb a large fraction of SO2 gas at low temperatures. How effective ethanol will be in the throttling process for COz and SO2 latent heat recovery remains an open question. There also is a potential safety hazard in using it in an environment where some oxygen is present.) Final cooling and condensation of the SO2 and COz occur in E-9. This exchanger is a set of rotating discs partially submerged in a pool of ethanol at -161 O F . Heat is transferred to the surface of the discs from the flue gas. Since the dew point of COz is -152 O F , COz and SO2 condense on the disc surface. Heat is rejected to the ethanol as the discs through the pool. It is assumed that the COz and SO2 condensate on the discs goes into solution with the ethanol as the discs pass through the pool. If necessary, scrapers can be used to aid in condensate removal. Heat is rejected to the cold effluent gas from E-1 through E-11, and from E-4, E-6, and E-8 through E-10. Heat from E-2 is rejected to atmosphere using a cooling tower. To recover the latent heat of vaporization of COz from E-9, a continuous stream of solution from the ethanol pool of exchanger E-9 is throttled to a vacuum so that the vaporizing temperature of the COz and SO2 is controlled to -165 O F . This stream is passed through a coil submerged in the ethanol pool. The 1186
Environmental Science & Technology
ethanol rejects heat to the coil, vaporizing the COz and SO2 inside the coil to maintain the pool temperature. Cooling that cannot be accomplished by direct heat transfer within the system or to the atmosphere is obtained using two evaporative-type refrigeration systems. The high-level refrigeration system has three pressure levels of propylene corresponding to evaporator temperatures of 62,32, and -10 O F . The low-level system has three stages: propylene, ethylene, and methane. The final methane stage provides an evaporator temperature of -165 O F . With this refrigeration system the total auxiliary power requirement for the CFGC system is estimated to be 8%of plant output. This could be reduced to -6.5% if a more efficient alternative low-level system using refrigerants R-22 and R-503 were employed (proposed by York Division of Borg-Warner). The cost analysis for the 700-MWe CFGC system, as summarized in Table I, is for a complete SO2 removal installation including flue gas ducts, heat exchangers, refrigeration plants, and other hardware. To provide for unforeseen costs, there is a contingency of 30% of the total costs. Research and development funds, which are not considered in the estimate, would be required before the first system could be built. Allowance for funds during construction at 8% per year compounded from center-of-gravity of expenditures to commercial operation and allowance of 7% to cover owners' costs are included. Three estimates representing the costs of the identical facility if completed in April 1972,1976, and 1980 are shown in Table I. These feasibility estimates do not reflect the detailed nature of an actual construction estimate. Table 1. Cost Estimate Summary cryogenic SO2 removal system for 700-MWe coal-fired power plant cost summary: 700-MW plant hardware (ducts,heat exchangers, refrigeration plants, spares, etc.) other (engineering, 30% contingency) inflation, funds start-up (escalation(2.5 yr), construction funds, other client costs, initial facilities and funds) cost 4/1/80 completion 4/1/76 completion 4/1/72 completion auxiliary power 6 . 5 4 % of plant output
$1000
$/kW
133500
191
57 500
82
89 200
127
200200 194000 137000
400 277 196
Table II. Summary of CFGC System Effects on Some Pollutants
so2
NO
NOz HzS04
Hg Se Br, CI
Cd Pb Zn
As, Cu,
Ga,Mo, Sb, Se, AI, Ba, Ca, Ce, Co,
minor compounds present as vapors formed from S in coal, which varies from 0.2 to 8% of coal by weight. CFGC system design point is reduction of emissions to 1.2 lb/1O6 BTU. Emissions vary approximately a factor of 2 for each 10 O F change in lowest temperature typically 90% of NO, emissions. Varies with coal N and combustion conditions. Will not b e condensed but can be oxidized to NOn by 02,and faster by 03, CIO, etc. typically 10% of NO,. Vapor pressure -0.4 X atm at -154 O F . Thus, expect about 99% removal of NOp vapor pressure not available at -154 O F , but very low. Boils at 338 O C (98.3%).H2S04removed with H20. High collection efficiency expected trace elements present as vapors (
