Energy & Fuels 1991,5, 254-258
254
Table 11. Fraction Absorbed by Scrubbing System method SO2 NO NO2 cocurrent countercurrent NO oxidation enhanced NO soln Chiyoda
0.91 0.95 0.91 0.91
0.02 0.02 0.02 0.99
0.90
0.02
0.91 0.93 0.91 0.91 0.90
calculated for the different conditions for input into the program. In general, the fractions of the gases absorbed are quite similar. The exception is the fraction of NO absorbed by scrubbing liquor with an additive to enhance the solubility of NO. The effect of limestone on the scrubbing liquor chemistry was studied by comparing simulations done with and without Ca2+present. In terms of N20 and N-S compound production, there were few substantial differences between the simulations done with calcium and those done without calcium. This was a result of the dissolved S(1V) concentrations being similar in the two conditions. If FGD systems without limestone have higher S(1V) concentrations than their limestone-based counterparts, then more N-S compound production would be expected. In summary, the simulations of scrubbing liquor chemistry provide quantitative results of the effects of scrubber conditions on the production of nitrogen-containing products. The accuracy of the calculations is limited by current knowledge of the solution kinetics of the reactive species in scrubbing liquor and by the ability to model heterogeneous processee (such as dissolution and formation of solid particles) and free-radical processes. Without a kinetic model, it is very difficult to predict the quantities of N20 and N-S compounds that will be formed in scrubbing liquors. The results of our simulations indicate that lower temperatures minimize production of both N20 and nitrogen-ulfur compounds. Maintaining the scrubbing liquor above pH 5.5 will help minimize N S compound formation. Solution pH has little effect on N20 formation. Rapid oxidation of S(1V) to sulfate not only minimizes CaSOs formation but reduces the rates of the dissolved NO, with
S(1V) reactions that produce N-S compounds. At these conditions, the Chiyoda CT-121 process appears to be capable of reducing NO, conversion to N-S compounds. The Phosnox process should be capable of nearly eliminating N20 production. Systems which enhance NO solubility may have problems with N20 formation, although the metal chelate system used can exert strong influence on the solution chemistry. All of the metal chelate chemistry was not included in the simulation because it depends on the specific metal ion-chelate compounds combination used, and many of the reactions involved are not well understood. consequently, the only effects that were included in the model were the enhanced NO solubility and the additional reactivity of the dissolved NO. Some antioxidants have been proposed for use with metal chelate systems,which would further complicate the solution kinetics. This investigation indicates a number of areas in which additional research is needed. A better understanding of NO2 aqueous chemistry is needed, especially for the reactions involved with the conversion of N02(aq) to NO, and NO,. The S(1V) oxidation process is still poorly understood. A number of free radicals may be involved in the aqueous sulfur oxyanion chemistry and their role needs to be better defined. Further studies of N-S compound chemistry are needed. Trace metal ions, organic compounds, and other species influence the decomposition of S2072-and peroxymonosulfuric acid (Caro’s acid). The hydrolysis reactions of the N-S compounds may show similar dependence on trace species. Techniques for removing N-S compounds from solution, such as thermal decomposition, precipitation, or oxidation, need further study. Also, efficient techniques need to be developed for removing NO2- and NO3- from scrubbing liquor. Acknowledgment. This work was supported by the Assistant Secretary for Fossil Energy, Office of Coal Utilization Systems, US. Department of Energy, under Contract No. DE-AC03-76SF00098through the Pittsburgh Energy Technology Center, Pittsburgh, PA.
Prediction of SO2 Removal for Power Plants Using Duct Injection of Lime Slurry Peter Harriott,*i+John Ruether, and Fred Sudhoff’ Pittsburgh Energy Technology Center, US.Department of Energy, Pittsburgh, Pennsylvania 15236 Received November 14, 1990. Revised Manuscript Received January 18, 1991
In the duct injection process, lime slurry is sprayed into the flue gas to absorb S02, and the dry solids formed are collected in a precipitator or baghouse. A model is used to predict SO2 removals for a population of coal-fired boilers that currently have no SOz controls. For the majority of these units, the residence time available is greater than 0.5 s, and SO2 removals of 40-80% are predicted at a stoichiometric ratio of 1.8 if the maximum drop size is 70 pm.
Introduction More than half of SO2 emissions in the United States come from older coal-fired power plants that have no At Cornel1 University, Ithaca, NY. ‘Burns and Roe Services Corp., now at Morgantown Energy Technology Center, Morgantown, WV.
scrubbers or other devices for SO2 removal. Pending legislation may require at least 50% so2 reduction, but it would be difficult to retrofit many of these older p l a t s with large scrubbers of the type used for new plants. Duct injection of lime slurry is a promising method for achieving moderate so2 removal by Simply spraying lime SlurrY into the flue gas between the air preheater and the solids
0887-0624/91/2505-0254$02.50/00 1991 American Chemical Society
Energy & Fuels, Vol. 5, No. 2, 1991 255
Prediction of SO2 Removal
t
801
1
I
,
,
I
I
I
1
[ , 1 Coal.
*"
U
Figure 1. Induct lime slurry injection process flow diagram.
2or 0
collection equipment. The SO2is absorbed and neutralized in the short time that it takes for the drops to evaporate, and the nearly dry solids are collected with the fly ash in the existing electrostatic precipitator or baghouse. A flow diagram is shown in Figure 1. In the present paper, a simple model is used to estimate the extent of SO2removal that could be expected if lime slurry injection were to be retrofitted to a population of coal-fired utility boilers in the US. that currently have no SO2 controls. Simple Model for SO2 Removal Several studies of duct injection were recently carried out in pilot units using a slipstream of flue gas from an operating coal-fired utility boiler.'-* The extent of SOz removal depends on the approach to adiabatic saturation temperature of the flue gas and on parameters describing the reaction of lime and SOp. The results were correlated by using a simple model based on the fundamentals of mass and heat transfer to and within the drops plus some empirical f a ~ t o r s . ~The equation for fractional removal of SO2 is
ESO2= 1 - e-x
(1)
where
SR is the stoichiometric ratio = Ca(OH)2/S02(molar) T, is the adiabatic saturation temperature, O F . The factors A and B were obtained by fitting the data and depend on the type of lime and the SO2concentration in the gas. The values of A were 1.25 for calcitic lime and 0.78 for pressure-hydrated dolomitic lime, and the value of B was 2.0 for both l i e s . The reason for the lower SO2removal with dolomitic lime is not known, and calcitic limes are being used in most current work. There are limited data indicating lower percent SO2 removal for high initial SOz concentrations, a trend that is expected because of the smaller fraction of H2S03that dissociates in more con(1) Murphy, K. R.; Samuel, E. A.; Demian, A. Presented at the First Combined FGD and Dry SO2 Control Symposium, St. Louis, MO, Oct. 1988. (2) Murphy, K.R.; Samuel, E. A. Presented at the Fourth Annual Coal Preparation, Utilization, and Environmental Contractors Conference, Pittsburgh, PA, August 1988. (3) Drummond, C. J.;Babu, M. Presented at the Fourth Annual Coal Preparation, Utilization and Environmental Contractors Conference, Pittsburgh, PA, August 1988. (4) Pennline, H. W.; Tice, J. H.; Newman, J. T.; Abrams, J. Z.; Benz, A. D. JAPCA 1988,38,1334-1341. (5) Harriott, P. J . Air Waste Manage. Assoc. 1990, 40, 948-1003.
0.8
1.2
1.6
2.0
2.4
SR
Figure 2. Dependence of SO2removal on stoichiometricratio.
centrated solutions. For this study, a simple equation for B was used to allow for the concentration effect. B = O.OB(ppm SOz)0.5 (3) The value of B is 2.0 for 1600 ppm SOp. The predicted SO2removal for different values of SR, Th, and (Tmt- T,) for 1600 ppm SOz is shown in Figure 2. For given inlet conditions, the SO2 removal can be improved by increasing the stoichiometric ratio or by decreasing the approach to the saturation temperature. However, too close an approach will lead to incomplete drying and deposition of wet solids in the duct or the particulate collection device. Plants that have long ducts or low flue gas velocities to give 2-3 s residence time in the longest straight duct could operate with a close approach to saturation and achieve good SOzremoval with moderate excess of lime. Plants with less than 1 s residence time in a straight length of duct would have to use a larger approach to ensure dry solid at the exit and might not get 50% SOz removal even with a large excess of lime. Drying Times for S l u r r y Droplets A key part of the SOz removal prediction is estimating the permissible approach to saturation, which must be large enough to give nearly dry particles in the available residence time. The rate of drying depends mainly on the drop size and gas temperature, and numerical calculations were made for a range of conditions to establish a correlation for the drying time. The calculations are for a standard flue gas with 74% Nz, 4% 02,13.7% COz,0.3% SOz + NO,and 8% H20. The adiabatic saturation temperature for this gas is given by the equation T,,= 102 + O.OSTi,, OF (4)
A typical spray is assumed to have a surface-mean drop size of 30 pm and a maximum size of 70 pm. Commercial air-assisted nozzles being used in pilot tests are able to produce drops of this size at liquid flows of about 2 gal/ min. Plug flow of gas is assumed with a uniform distribution of drops, and the slip velocity of the drop is neglected. For drops 70 pm or smaller, extra heat transfer during the deceleration period is very small, and a Nusselt number is 2.0 is used for the entire evaporation process. The calculations are focused on the drying times for a 70-pm drop, since the largest drops in the distribution must form dry particles to avoid deposit formation. The drying time for a slurry droplet is less than that for a pure water drop, since there is less water to evaporate, and the area for heat transfer in the final stages is greater for a wet porous particle than for a shrinking water drop. The slurry is assumed to have 20% solids, and the final particles are
Harriott et al.
256 Energy & Fuels, Vol. 5, No. 2, 1991 Table I
TO",
MWe 125 JOPP~ 183 668 Gibson 81 Hutsonville J. M. Stuart 610 New Castle 105 station J. P.Pullian
I .4
\ \
I .2 I .o
D 0.0
-
L,
i
0.6 0.4
o.2
1 t*
0
20
40
60
T0ut-To.s.
80
100
120
,OF
Figure 3. Predicted drying time for slurry droplets. considered dry when the moisture content realizes 10%. The calculated drying times were correlated with the equation (5)
where
Fs = (dmax/70)2
(7)
and ATh is the log mean temperature difference between the spray and flue gas at the beginning and end of the straight length of duct. The factor F D allows for the effect of drop size distribution, which makes the largest drops evaporate more slowly than they would in a monodispersion. The very rapid evaporation of the smallest drops raises the humidity and lowers the driving force for evaporation of the large drops. This effect is most pronounced for a close approach to saturation, and the factor FD takes this into account in an approximate fashion. The factor Fs is used if the maximum drop size is greater than 70 pm. The predicted drying times for different inlet and approach temperatures are shown in Figure 3. Duct Survey and Fortran Program for Utility Boilers Data on duct dimensions, flue gas velocities, and gas temperatures are available for 316 utility boilers in a Duct Survey data base at PETC.6 The units surveyed have no SO2 controls and have emissions of 1.8 lb of S02/million Btu or greater. The units have capacities of at least 50 MWe and are less than 35 years old. These limits restrict the survey to boilers which are major sources of SO2 but are not so old as to make retrofitting for SOz controls unlikely. The units in the data base have a total capacity of 85400 MWe, which is 42% of the capacity of all uncontrolled utility boilers. However, these units had emissions of 7.9 million tons of SO2in 1985, which is about 60% of the total SO2emissions from all uncontrolled units. (6) Sarkus, T. A.; Henzel, D. S. 'DOE'S Duct Injection Survey"; Pittsburgh Energy Technology Center, US.Department of Energy, 1988.
t. s 0.40 0.50 0.66 0.73 1.00 1.98
DDm
1526 1337 1874 1927 1032 1006
Ti,, O F 350 320 320 300 286 256
-
T,, O F 108 84 51 46 29 20
Em., % 35 40 53 53 68 72
Most of the remaining SO2emissions are from boilers using low-sulfur coal (
