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Synergistic combustion of coal with natural gas
6. pp En
477
4X4.
+ .oO 0360-5442184 S3.W 4‘ 1984 Pcrgamon Press Ltd.
1984
SYNERGISTIC COMBUSTION OF COAL WITH NATURAL GAS Department
ALEX E. S. GREEN and KRISHNA M. PAMIDIMUKKALA of Mechanical Engineering, University of Florida, Gainesville, Fl 32611, U.S.A. (Received
16 September
1983)
Abstract-Using an improved coal-devolatilization model and a simple char-burnout model, we explore possible synergisms in the simultaneous combustion of coal and natural gas. After describing our own work briefly in the context of the conversion of oil boilers to coal burning, we consider the direct use of pulverized coal or of coal-water slurries with gas augmentation, and the two-stage use of pulverized coal or coal-water slurries with gas augmentation. In the first case, we identify advantageous interactions in coming which speeds up char-burnout. In the second case, the primary role of the first stage is the “methanogasification” of coal analogous to, and possibly more effective than, the hydrogasification of coal. In both cases, simultaneous coal-gas combustion appears to be synergistic.
1. BACKGROUND
Work has been underway at the University of Florida since 1980 on the combustion of coal with natural gas augmentation. This work was initiated in the context of discussions of oil backout in Florida’ and a mundane cost problem.* As a result of experimental, theoretical and economic studies since then3-” we are convinced that there are advantageous synergisms in coal-gas combustion which warrant careful study. The purpose of this paper is to outline possible synergisms, particularly as they follow from our modeling studies of the kinetics of coal devolatilization and char-burnout. We confine our discussions to physical synergisms attendant to cofiring of coal and gas in single or two-stage combustion arrangements. Thus, our work should be distinguished in which coal is burned in some boilers and gas in from the “select bubble” use concepP3 other boilers within a multiple boiler plant. This select use bubble concept yields environment and economic benefits but does not involve physical synergisms in the combustion process itself. Our work has consisted of (1) A search of prior literature on coal-gas combustion which revealed very few entries and none related to the same objectives,3 (2) construction of a simple ring type gas-coal burner and firing in a small firebrick kiln in all fuel proportions,4 (3) construction and firing of a laboratory scale premixed laminar gas flame burner with a fluidized bed system for adding pulverized coal and with good spectroscopic diagnostic equipment,‘-’ (4) construction and firing of a vertical vortex combustor at the 1,OOO,OOO Btu/hr level using all fuel proportions, I4 (5) development and application of kinetic code capable of handling 80 simultaneous reactions, ‘JO(6) construction and firing of a small vortex coal-gas combustor at the 100,000 Btu/hr level,15 (7) adoption of the large vortex combustor to coal-water slurry/gas firing using a borrowed Moyno pump and an improvised atomizer,16 (8) adaption of the small vortex combustor to coal-water slurry/gas firing.”
COAL-GAS
COMBUSTOR
MODELING
The facilities listed under items (2) (4) and (6~(8) have served primarily for preliminary demonstrations of concept feasibility and are not yet well instrumented for detailed input and output analysis. The laminar flame system (item 3) is instrumented with flow-measuring instruments and spectroscopic sensors. Using this system, we found that pulverized coal additives (- 30 mg/min) to a methane flame leads to substantial changes in CH and C2 emissions at various heights in the gas-coal flames and lesser changes in OH and CO emissions. The magnitude of these emissions depend upon the stoichiometry of the methane-air flame. These variations can qualitatively be explained with a model of coal-gas 477
478
A. E. S. GREENand K. M. PAMIDMUKKALA
combustor which treats the coal devolatilization process quite realistically in terms of recent physical concepts. Experimental work at MIT” show that increased devolatilization can be achieved by passing the pulverized particles through a high temperature zone, which promotes rapid and more complete devolatilization. Figure 1 illustrates this feature of the work of the MIT combustion laboratory. The solid curves represent the dry ash free devolatile weight percentage according to the six parameter model of Kobayashi et af.‘* The dashed curves represent a somewhat simpler three parameter model, which we are now using.” In our model, coal under the influence of high temperature first forms an intermediate (tar) state with a reaction rate k,(T). This then decomposes with a reaction rate k,(r) into volatiles with branching ratio a(T) and char with the branching ratio [ 1 - r(T)]. Currently, we are using k, = k, = 1.65 exp ( T/9O6)2 s-i
(1)
a(T) = exp - (1045/T).
(2)
and
A more detailed model of the kinetics of the devolatilization and char burnout is illustrated in Fig. 2. Here, we also provide for an arbitrary ash weight fraction (b), and for the fact that the carbon/hydrogen ratio of the volatiles (CH,, HZ, CO, and C,) tends to increase with temperature, and for the attack of O,, CO, and Hz0 on the char. While our devolatilization model approaches the state of the art, our char-burnout model is admittedly simplistic. We use an average particle size rather than a size distribution. We also do not consider the influence of the additional free radicals which are present when burning coal with gas augmentation. These reactive species would also be expected to speed up the char-burnout. These simplifications are not of overriding importance in comparisons between the combustion of coal, coal-gas, coal-water and coal-water/gas which are the primary objectives of this work. With the help of our devolatilization and char-burnout model we have used our kinetic code to solve a set of 64 simultaneous reactions for a realistic temperature-time history. The r(t) function which we use is simplification of one used to
Bituminous cool 0 2lOOK a1940
0
1740
q l5iO _
-
-
Residence time (mS)
Fig. 1. Dry, ash-free weightloss vs residence time at various temperatures. The points represent the MIT data. The solid curves represent the Kobayashi (2 reactions;6 parameters) modeLls The dashed curves represent Eqs. (I) and (2).
Synergistic combustion of coal with natural gas
479
Cool C,HbOc
4 I
kz
f
2co
2co
co+
Hz
Fig. 2. Coal devolatilization and char burnout models used in kinetic simulation and rate parameters. k, = 1.65 exp (T/9O6)2 s-‘, k, =k,, k,=2.72 x lOOexp(-1500/T), k,=5.44x 103T k,= 1.69 x lO?fexp(-21060/T), k6= 1.69 x l@Texp -21060/T), OL= exp (-8057/T), exp (- 1045/T), B = 0.1, a, = 0.37 - O.OST, u2 = 0.35, a3 = 0.16 - 0.05 4 , a, = 0.12 + 0.1 F, f = T/1000, &I,= 1.
provide very good analytic fits to temperature given by
measured in our laboratory
T(f) = Toev P(v’ - ~2-1W~~ + expW~J
flames.lg It is
(3)
where To is a characteristic temperature, t, and t, are characteristic times and y is a characteristic dimensionless constant. We have also used this equation in simulations of our vortex combustor and in simulations of boiler flames. Figure 3(a) gives a set of what are believed to be not unrealistic temperature-time histories for coal particles in boiler flames fired with coal (C), coal-gas (C/G), coal-water (CW) and coal-water/gas (CW/G). Figures 4(a and b) illustrate the concentrations histories of the major and minor species which follow from our detailed kinetic simulation of the reactions in a coal-gas flame. Figure 3(b) shows the comparative char production and burnout histories in the four cases. The somewhat increased temperature and the more rapid rise times are major reasons for the faster burnout time of the coal-gas mix with respect to the coal case and the coal-water/gas mix with respect to the coal-water case. Recent work on flash pyrolysis of coal in reactive and non-reactive gaseous environments20*2’ show that total carbon conversion is higher in the presence of reactive gases (Hz, CH,, CO) than in the presence of non-reactive gases (He, N,, Ar). Indeed the ethylene and higher hydrocarbon production by flash pyrolysis of New Mexico subbituminous coal is distinctly higher with CH, than any of the other reactive or non-reactive species. Apparently at high temperatures CH, facilitates the depolymerization of coal. These results taken together with our laboratory flame studies and our kinetic simulations favor the concept of synergistic coal-gas combustion. 3. DIRECT
FIRING
SYSTEMS
Flame stabilization is a synergistic feature of practical coal-gas burning systems as observed at the James River Power Plant in Springfield Missouri.” Their boilers were retrofitted from gas to coal burning but to overcome some initial problems in the design of the coal systems and characteristics of their coal, they burned the two fuels simultaneously for a period. In coal combustion, gas assist is particularly useful at low load levels when coal flames are notoriously unstable. A ring type burner or a variety of other coal-gas
/ 1
A. E. S. GREENand K. M.
480
I-
PAMIDIMUKKALA
c/G~~~~~
Cand cw’F’ / / /
/-
5 I: 20 l3-l
I-
cw; /-
Reaction
time,
set
Fig. 3. (A) Time temperature histories used in simulations. The parameters T,(“K) and t,(ms) for Eq. (3) are (G), 2000 and 2; (C/G), 1900 and IO; (C), and (CW/G), 1800 and 25; (CW), 1700 and 50. In all cases y = 0.5 and f2 = 5000 ms. (B) Char concentrations vs time.
(b)
(a)
Reoctlon
time,
Fig. 4. Species concentrations
set
Reoctlon time, set
vs time for a coal-gas system; (A), stable species; (B), intermediate species.
Synergisticcombustion of coal with natural gas
481
configurations should provide insurance against flameout. Ability to accommodate a variety of coals by adjustment of the gas proportion is also a useful feature. It is generally recognized that the radiation from oil flames exceeds that of coal flames which greatly exceeds that of natural gas flames.23 However, a coal-gas flame may emit radiation comparable to an oil flame because of the higher temperatures of the coal particles. The quantification of such non-linear relationships should be pursued since radiation is important for heat transfer in oil boilers.24 NO, suppression in coal-gas flames would largely by a matter of taking advantage of the increased flexibility in blended fuel combustion to achieve fuel rich conditions in the initial burning zone. By methane staging, we may enhance the low NO, properties of burners which utilize air staging. 25 Sulfur dioxide reduction by coal-gas burning is accomplished in a benign (non-synergistic) way simply by the fraction of the energy provided by natural gas which is sulfur free. A synergism in the form of the global reaction CH, + 2S02-+C02 + 2H20 + SZ
(4)
is well documented in sulfur-extraction technology,26 however the application of this reaction in a practical combustor is a matter of speculation. The problem of coal ash in the conversion of an oil boiler to coal is recognized to be a formidable one27*28but is no longer regarded as insurmountable. Several conversions of oil designed boilers to dual coal/oil capability have already been carried out29*30or subjected to preliminary architect-engineering analyses31932and the technology should soon be fairly well established. In oil to coal conversion the cost to provide for gas combustion should be small compared to the benefits in pollutant reduction and boiler derating reduction. The beneficiation of coal to reduce ash weight is an aitemative approach to ash problems and considerable progress has been made which should simplify and reduce the capital cost of coal conversion 33-35albeit with an increase in the cost of fuel. Here, the use of gas to minimize derating might be expected to have a proportionally greater pay-off. Ash formation is sufficiently complicated that almost anything can happen, depending upon coal rank, temperature history and other variables. Slag on the Springfield boiler tubes was frequently cleared by boosting the proportion of gas in the flame to achieve the slag melting point. 36To what extent we can generally program the physical transformation of ash3’ to be helpful in minimizing ash problems in oil to coal-gas conversions is an important matter for further research. Large scale programs are underway3B41 on the use of coal-oil and coal-water slurries (CWS) to replace oil. Here, a driving consideration is the ability to transport the slurry fuel by pipe directly to the burners. To directly retrofit the boiler to bum powdered coal would require the installation near the boiler of pulverizers, blowers, hoppers and other massive components of typical coal systems and many oil boilers do not have space for this. The economical advantages of coal-oil slurries are questionable, since even with high coal loading, about 6O-70% of the slurry’s energy derives from its oil. However, coal-water slurries with 60-70x by weight of coal have been successfully combusted42A and here all of the useful energy derives from coal. In this case, the water might be viewed as a negative fuel since it must be evaporated before coal combustion can proceed. However, the heat of vaporization ( N 10 kcal/mole) imposes only small penalty (m 3%) and some beneficial effects attendant the high water vapor content in the burning zone have been reported. These effects possibly are associated with the OH radicals produced by the small fractional dissociation of water in the flame and more probably as suggested by our kinetic modeling by the higher concentrations of H,O available for oxidation of the char. The high viscosity of heavily coal loaded CWs’s poses a pumping problem should there be a large distance between the source preparation facilities and the burners. Here, a possible synergism could be exploited in combined methane-CWS burning if methanating the slurry were to reduce the viscosity.” Then the reduced pumping energy would combine with the advantages of the greater calorific value of the coal-water-gas combination. Unfortunately our measurements with a Brookfield viscometer in an open beaker on the effects of gas bubbles in the coal-water slurries we have prepared led to increased viscosity
482
A. E. S.
GREEN and K.
M. PAMIDIMUKKALA
readings.48 However, three phase (gas, liquid, and solid) how under pressurized conditions is an undeveloped science. In a thorium oxide-water-steam slurry flowing under high pressure a reduction of viscosity was observed. 49Thus the possibility of viscosity reduction in coal-water-methane flow warrants further research.
4. 2 STAGE COMBUSTION One of the major obstacles to the direct retrofitting of an oil boiler to coal burning is the high cost of the modifications required to accomodate the ash. A promising type of oil boiler retrofit which might minimize these modifications would be to use a first stage coal-natural gas system whose primary function is to de-ash the coal and extract a hot combustible gas for afterburning in the original boiler (see Ref. 6, p. 135). One might ask. “Why not just use a coal gasifier? Why add gas ?” Some answers are (1) the much higher Btu content of natural gas than producer gas, (2) CH4 adds free radicals which speed up the combustion kinetics, (3) flash “methanolysis”20~2’ appears to increase the volatile production by converting coal polymers to combustible hydrocarbons. While flash hydropyrolysis has received much attention, Soboth in direct experiments and in connection with hydrogasification research, we have found only a few references to flash methanolysis and none to what might be called “methanogasitication”. In methanogasification the methane serves as fuel to provide the high temperatures for rapid pyrolysis, supplies the hydrogen to promote the free radical attack on the coal polymers” and also facilitates char gasification via CO2 and Hz0 attack and probably attack by the increased concentrations of free radicals. Since methane and higher hydrocarbons are products of coal methanogasification it may be possible to reduce the external gas needs to proportions which are economically advantageous for any reasonable set of fuel prices. At off-peak times some of the methanogasifiers might be used to produce valuable chemicals or liquid fuels. There is a possibility of introducing lime or other additives with the pulverized coal in the first stage combustor to capture sulfur with the ash and recent work on limestone sorbant injection into low NO, multistage burners” would find natural application to such an effort. If one could build a first stage system to de-ash and de-sulfurize the fuel while after-burning the fuel rich hot gases in the boiler itself with gas augmentation in both stages to achieve the desired flame temperatures, the capital costs of retrofitting an oil boiler would be substantially reduced. Thus factory made methanogasification systems couid be the major component of the retrofitting project. The pulverizers and other fuel preparation and storage facilities can be at a convenient distance from the retrofitted oil boiler which alleviates the space requirement near the boiler. Only the methanogasifiers need be in close proximity to the boilers although how close is a matter of the technology of high temperature piping. The technology of hydrogasification systems which have the general nature of a methanogasification system is highly developed52-58 and much of this technology should be adaptable to the purposes here. Whereas methane is a relatively abundant naturally available feedstock, hydrogen must first be produced in an industrial process from a basic feedstock. Investing some industrial oxygen in the methanogasification step may also be useful since this would help reach higher temperatures faster without increasing NO production from air. Going to higher than atmospheric pressure should also be helpful in obtaining a higher synthetic fuel output with increased calorific content which should reduce the natural gas augmentation needed in the boiler itself. The use of a first stage methanogasifier fed by a beneficiated coal-water slurry might yield extra de-ashing and de-sulfurizing synergisms and reduce the requirements and costs of either approaches to the ash problem. The water in the slurry may also serve as a useful supplementary source of hydrogen for the methanogasifier. 5. DISCUSSION
AND CONCLUSIONS
Our primary thesis, which is consistent with the results of our combustion modeling, is that synergisms occur in simultaneous coal-gas combustion which should help in oil displacement without exacerbating pollution problems. Recent analyses”~” on the “select-
Synergistic combustion of coal with natural gas
483
bubble” use of gas with coal, show cases which are economically favorable with respect to continuation with oil or conversion to coal and installation of wet scrubbers. In the synergistic use of coal and gas some credits must be assigned for the reduced loss of derating and the inherently greater flexibility available in dual or multiple fuel systems with cofiring capability in coping with potential fuel shortages. These are left out of economic analysis of the select-bubble use of coal and gas. Thus we might reasonably expect additional economically favorable cases in synergistic use of gas and coal. We have concentrated our attention on coal-gas combustion in retrofitting oil boilers for the purpose of oil backout. Some of the potential synergisms we have discussed could also be useful with new boilers and furnaces. In cases where natural gas is not available, other high grade gaseous fuels such as propane and butane which can more easily be shipped and stored in liquid form might be utilized instead. While the hydrogen/carbon ratios would be somewhat lower, they are still much higher than those of coal. Clearly there is a need for improved knowledge of gas assisted gasification and two and three phase combustion and it would appear that the time has come to initiate experimental and theoretical research to meet these needs. Ac~kno~~/ed~emPn/s-This work was supported in part by University of Florida Engineering College and Gatorade Trust Funds and in lesser parts by the Middle Ultraviolet Associates and the Dragon Fire and Clay Company. We thank Ramesh R. Meyreddy for his help with the kinetic calculations.
REFERENCES 1. Coal Burning Issues (Edited by A. E. S. Green). University Presses of Florida, Gainesville, Florida (1980). 2. B. A. S. Green, Discussions with A. E. S. Green on the use of coal for firing pottery kilns to reduce firing costs. unpublished (1980). 3. A. E. S. Green and J. R. Jones, “Gas/Coal Burning Interactions”, an addendum to Impact of Increased Coal Use in Florida, a report issued by ICAAS, University of Florida, Gainesville, FL (March 1981). 4. A. E. S. Green and B. A. S. Green, “Development of Gas-Coal Combustor”, unpublished (1981). 5. J. J. Horvath. Spectroscopic Investigations on Methane-Air Flames Containing Coal Dust. Ph.D. Thesis, Department of Chemistry, University of Florida, Gainesville, Florida (1983). 6. An Alternative to Oil: Burning Coal with Gus (Edited by A. E. S. Green), with contributions by J. R. Jones, M. J. Ellerbrock, J. M. Schwartz, S. J. Kuntz, and B. Zeiler. University Presses of Florida, University of Florida, Gainesville, Florida (1981). I. A. E. S. Green and K. M. Pamidimukkala, “Kinetic Simulation of the Combustion of Gas/Coal and Coal/Water Mixtures”, Proc. 1st Int. Conf. on Combined Combustion of Coal and Gas, Cleveland, Ohio (1982). 8. D. B. Vaidya. J. J. Horvath, and A. E. S. Green, Appl. Optics 21, 3357 (1982). 9. J. J. Horvath, K. M. Pamidimukkala, W. B. Person, and A. E. S. Green, “Spectroscopic Observations of Methane-Pulverized Coal Flames”, presented at the Western States Section Symposium/The Combustion Institute, JPL, CA (1983) JQSRT 31, 189 (1984). 10. A. E. S. Green and K. M. Pamidimukkala, “Oil Backout and Acid Rain” in Acid Deposition; Causes and Eficrs (Edited by A. E. S. Green and W. H. Smith), p. 130. Government Institutes Inc., Rockville, MD (1983). 11. B. Schlesinger. “Natural Gas is Gaining Growing Approval as an Air Pollution Control Device”, Proc. 1st Inr. Cor~f. on Combined Combustion of Coal and Gas, Cleveland, Ohio (1982). I?. P. L. Wilkinson, “Select Gas Use: Economics and Regulatory Impediments”, in Ref. 7. 13. “Evaluation of the Environmental and Other Benefits of Select Gas Use”, Final Report prepared for Gas Research Institute and American Gas Association by Environmental Research and Technology, Inc.. Washington, D.C., Private communication (1983). 14. A. E. S. Green, B. A. S. Green, B. Zeiler, J. Samuels, K. M. Pamidimukkala, and K. Zawoy, “Development and Firing of Vortex Combustor for Burning Coal/Gas Mixtures”, University of Florida, Gainesville, Florida. unpublished (1981). 15. C. Winefordner, “Gas/Coal Combustion in a Small Vortex Combustor”, directed individual study (DIS) paper in Department of Mechanical Engineering, University of Florida, Gainesville, FL (May 1983). 16. K. Zawoy, “Coal-Water/Gas Slurry Combustor”, DIS Project, M.E. Dept., University of Florida, Gainesville. FL (July 1983). 17. T. Larkin. “Laboratory Scale Coal/Water Slurry Combustor”, Florida Foundation for Future Scientists DIS Project. University of Florida, Gainesville, FL (Aug. 1983). 18. H. Kobayashi. J. B. Howard, and A. F. Sarofim, “Coal Devolatilization at High Temperatures”, 16rh Symp. (IHI.) on Combustion, p. 411. Combustion Institute, Pittsburg, PA (1977). 19. K. M. Pamidimukkala, R. R. Meyreddy, and A. E. S. Green, “Kinetic Simulations of Spectroscopic Observations of Laboratory Gas/Coal Flames”, presented at the Eastern Stares Section Symp./The Combustion Institute, Technical Meeting, Providence, RI (Nov. 1983). 20. M. S. Sundaram. M. Steinberg. and P. T. Fallon. “Flash Pyrolysis of Coal in Reactive and Non-Reactive Gaseous Environments”, 186th ACS National Meeting, Division of Fuel Chemistry, Washingon, D.C. (1983). 21. M. Steinberg. P. T. Fallon. and M. S. Sundaram, “Flash Pyrolysis of Biomass with Reactive and Non-reactive Gases”. Summ0r.r Rep., Process Sciences Division, Department of Energy and Environment, Brookhaven National Laboratory, Upton, NY (1983).
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22. R. J. Drummond,
“Combustion
of Fuel Burning at James River Plant” Proc. 1st Int. Conf on Combined
Combustion of Coal and Gas, Cleveland, OH (1982).
23. J. M. Beer, “Radiation from Flames in Furnaces”, in Combustion Technology: Some Modern Decelopments (Edited by H. B. Palmer and J. M. Beer). Academic Press, New York (1974). 24. E. J. Kimel, “Conversion of Oil Designed Boilers to Dual Coal-Natural Gas Firing”. Proc. 1st Int. Conf on Combined Combustion of Coal and Gas, Cleveland, OH (1982). 25. I. Glassman, Combustion. Academic Press, New York (1977). 26. W. D. Hunter. Jr.. J. C. Fedoruk. A. W. Michener. and J. E. Harris. “The Allied Chemical Sulfur Dioxide Reduction Process for Metallurgical Emissions”, ‘in Adtrances in Chemistry Series 139 (Edited by J. B. Pfeiffer). ACS, Washington, DC. (1975). 21. W. T. Reid, “Coal Ash: Its Effects on Combustion Systems”, in Chemistry of Coal Utilization (Edited by M. A. Elliott). Wiley, New York (1981). 28. S. Ehrlich, S. Drenker, and R. Manfred, “Coal Use in Boilers Designed for Oil and Gas Firing”, American Power Corp., Chicago, IL (April 1980). 29. J. B. Kirkwood, Commissioner’s Comer, Energy Commission News, Western Australia (March 1979). 30. Staff Report, The Energy Daily 11(81), 2 (28 April 1983). 31. E. Kimel and R. Kurtzrock, “Comparison of Coal Conversion Alternatives”, hoc. 5th Int. Symp. on Coal Siurry Combustion and Technology, U.S. Department of Energy, Pittsburg Energy Technology Center, Pittsburg, PA (April 1983). 32. Office of Fuels Programs, “Conversion of Florida Electric Power-Plants from Oil to Coal Burning”. Economic Regulatory Administration, U.S. Department of Energy, Washington, D.C. (April 1983). 33. D. R. Keller, Jr., “Coal Slurries with Less than One Weight Percent Ash”, p. 250, in Ref. 3 I. 34. N. Berkowitz, An Introduction to Coal Technology. Academic Press, New York (1979). 35. S. P. N. Singh and G. R. Peterson, “Advances in Coal Beneficiation”, in Coal Processing Technology, Vol. V, p. 24. Chemical Engineering Progress, Technical Manual by AICE, New York (1979). 36. R. J. Drummond, James River Power Plant, Springfield, MO, Private communication with A.E.S. Green (Aug. 1983). 37. M. D. Horton, “Fast Pyrolysis” in Pulverized-coal Combustion and Garifcation (Edited by L. D. Smoot and D. T. Pratt), Chap. 8. Plenum Press, New York (1979). 38. G. T. Hawkins, “Liquid Coal Slurry Program”, p. 3 in Ref. 31. 39. G. A. Maier, R. E. Barrett, B. W. Rising, and R. D. Giammar, “Coal Slurry Fuels: Moving Toward Commercial Utilization”, p. 873, in Ref. 31. 40. C. B. Foster, “The U.S. Coal-Water Mixture Combustion Program”, Proc. 4th Int. Symp. on Coal Slurry Combustion, U.S. Department of Energy, Pittsburg Energy Technology Center, Pittsburg, PA (1982). 41. S. W. Chun et al,, Proc. 5th Int. Symp. on Coal Slurry Combustion and Technology, U.S. Department of Energy, Pittsburg Energy Technology Center, Pittsburg, PA (April 1983). 42. G. J. Germane, L. D. Smoot, S. P. Diehl, K. H. Richardson, and D. C. Rawlins, “Coal-Water Mixture Laboratory Combustion Studies”, p. 973, in Ref. 31. 43. G. DeMichele, M. Graziadio, S. Ligasacchi, and G. Salvi, “Large Scale CWS Firing Tests at S. Barbara Power Station”, p. 1053, in Ref. 31. 44. H. Whaley, D. M. Rankin, R. P. Nicholson, and I. D. Covill, “The Development of Coal-Water Technology for Utility Boilers in Eastern Canada”, p. 809, in Ref. 31. 45. E. T. McHale, R. S. Scheffee, and N. P. Rossmeissl, Combustion and Flame 45, 121 (1982). 46. R. Payne, S. L. Chen, W. Richter, and J. Wilbom, “A Procedure for the Evaluation of the Combustion Performance of Coal-Water Slurries”, Proc. 5th Int. Symp. on Coal Slurry Combustion and Technology, U.S. Department of Energy, Pittsburg Energy Technology Center, Pittsburg, PA (April 1983). 47. S. Ehrlich, EPRI, Palo Alto, CA 94303, Personal communication with A. E. S. Green (14 April 1983). 48. A. E. S. Green and K. Zawoy, “Preliminary Experimental Results on Viscosity Measurements of CWS with Air Bubbles”, unpublished (July 1983). 49. E. A. Farber, “Bubble and Slug Flow in Circulating Gas, Liquid and Solid Mixtures”, Rept. IV under subcontract 996, Oak Ridge National Laboratory, Reactor Experimental Engineering Division, Oak Ridge, TN (1956). 50. J. B. Howard, Fundamentals of Coal Pyrolysis and Hydropyrolysis, in Chemistry of Coal Utilization (Edited by M. A. Elliott), p. 665. Wiley, New York (1981). 51. P. L. Case, M. P. Heap, R. Payne, and D. W. Pershing, “LIMB Testing: The Use of Dry Sorbents to Reduce Sulfur Oxide Emissions from Pulverized-Coal Flames Under Low-NO, Conditions”, Proc. EPA/EPRI Joint Symp. on Stationary Combustion ofNO% Control, Dallas, TX (NOV. 1982). 52. D. 1. Miller and H. H. Lee, Synthetic Fuels From Coal, in Coal Burning Issues (Edited by A. E. S. Green), Chap. 6. University Presses of Florida, Gainesville, FL (1980). in Coal Utilization Technology, 53. G. V. McGurl, “Small Gasihers in Industry”, Symposium Papers-Aduances p. 11I. Institute of Gas Technology, Louisville, KY (May 1979). 54. D. F. Spencer, M. J. Gluckman, and S. B. Alpert, Science 215, 1571 (1982). 55. P. B. Probert, “Gasification System”, p. 243, in Ref. 35. 56. I. H. Smith and G. J. Werner, Coal Conversion Technology. Noyes Data Corporation, Park Ridge, NJ (1976). 51. W. G. Schlinger, “Coal Gasification Development and Commercialization of the Texaco Coal Gasification Process”. n. 119. 6th AnnuaI Int. Conf. on Coal Gasification Liqutfaction and Conversion to Electricity, Pittsburg, PA (1979). 58 Coal Gasificntion (Edited by L. G. Massey), Advances in Chemistry Series 131. ACS, Washington, D.C. (1974).
477
4X4.
+ .oO 0360-5442184 S3.W 4‘ 1984 Pcrgamon Press Ltd.
1984
SYNERGISTIC COMBUSTION OF COAL WITH NATURAL GAS Department
ALEX E. S. GREEN and KRISHNA M. PAMIDIMUKKALA of Mechanical Engineering, University of Florida, Gainesville, Fl 32611, U.S.A. (Received
16 September
1983)
Abstract-Using an improved coal-devolatilization model and a simple char-burnout model, we explore possible synergisms in the simultaneous combustion of coal and natural gas. After describing our own work briefly in the context of the conversion of oil boilers to coal burning, we consider the direct use of pulverized coal or of coal-water slurries with gas augmentation, and the two-stage use of pulverized coal or coal-water slurries with gas augmentation. In the first case, we identify advantageous interactions in coming which speeds up char-burnout. In the second case, the primary role of the first stage is the “methanogasification” of coal analogous to, and possibly more effective than, the hydrogasification of coal. In both cases, simultaneous coal-gas combustion appears to be synergistic.
1. BACKGROUND
Work has been underway at the University of Florida since 1980 on the combustion of coal with natural gas augmentation. This work was initiated in the context of discussions of oil backout in Florida’ and a mundane cost problem.* As a result of experimental, theoretical and economic studies since then3-” we are convinced that there are advantageous synergisms in coal-gas combustion which warrant careful study. The purpose of this paper is to outline possible synergisms, particularly as they follow from our modeling studies of the kinetics of coal devolatilization and char-burnout. We confine our discussions to physical synergisms attendant to cofiring of coal and gas in single or two-stage combustion arrangements. Thus, our work should be distinguished in which coal is burned in some boilers and gas in from the “select bubble” use concepP3 other boilers within a multiple boiler plant. This select use bubble concept yields environment and economic benefits but does not involve physical synergisms in the combustion process itself. Our work has consisted of (1) A search of prior literature on coal-gas combustion which revealed very few entries and none related to the same objectives,3 (2) construction of a simple ring type gas-coal burner and firing in a small firebrick kiln in all fuel proportions,4 (3) construction and firing of a laboratory scale premixed laminar gas flame burner with a fluidized bed system for adding pulverized coal and with good spectroscopic diagnostic equipment,‘-’ (4) construction and firing of a vertical vortex combustor at the 1,OOO,OOO Btu/hr level using all fuel proportions, I4 (5) development and application of kinetic code capable of handling 80 simultaneous reactions, ‘JO(6) construction and firing of a small vortex coal-gas combustor at the 100,000 Btu/hr level,15 (7) adoption of the large vortex combustor to coal-water slurry/gas firing using a borrowed Moyno pump and an improvised atomizer,16 (8) adaption of the small vortex combustor to coal-water slurry/gas firing.”
COAL-GAS
COMBUSTOR
MODELING
The facilities listed under items (2) (4) and (6~(8) have served primarily for preliminary demonstrations of concept feasibility and are not yet well instrumented for detailed input and output analysis. The laminar flame system (item 3) is instrumented with flow-measuring instruments and spectroscopic sensors. Using this system, we found that pulverized coal additives (- 30 mg/min) to a methane flame leads to substantial changes in CH and C2 emissions at various heights in the gas-coal flames and lesser changes in OH and CO emissions. The magnitude of these emissions depend upon the stoichiometry of the methane-air flame. These variations can qualitatively be explained with a model of coal-gas 477
478
A. E. S. GREENand K. M. PAMIDMUKKALA
combustor which treats the coal devolatilization process quite realistically in terms of recent physical concepts. Experimental work at MIT” show that increased devolatilization can be achieved by passing the pulverized particles through a high temperature zone, which promotes rapid and more complete devolatilization. Figure 1 illustrates this feature of the work of the MIT combustion laboratory. The solid curves represent the dry ash free devolatile weight percentage according to the six parameter model of Kobayashi et af.‘* The dashed curves represent a somewhat simpler three parameter model, which we are now using.” In our model, coal under the influence of high temperature first forms an intermediate (tar) state with a reaction rate k,(T). This then decomposes with a reaction rate k,(r) into volatiles with branching ratio a(T) and char with the branching ratio [ 1 - r(T)]. Currently, we are using k, = k, = 1.65 exp ( T/9O6)2 s-i
(1)
a(T) = exp - (1045/T).
(2)
and
A more detailed model of the kinetics of the devolatilization and char burnout is illustrated in Fig. 2. Here, we also provide for an arbitrary ash weight fraction (b), and for the fact that the carbon/hydrogen ratio of the volatiles (CH,, HZ, CO, and C,) tends to increase with temperature, and for the attack of O,, CO, and Hz0 on the char. While our devolatilization model approaches the state of the art, our char-burnout model is admittedly simplistic. We use an average particle size rather than a size distribution. We also do not consider the influence of the additional free radicals which are present when burning coal with gas augmentation. These reactive species would also be expected to speed up the char-burnout. These simplifications are not of overriding importance in comparisons between the combustion of coal, coal-gas, coal-water and coal-water/gas which are the primary objectives of this work. With the help of our devolatilization and char-burnout model we have used our kinetic code to solve a set of 64 simultaneous reactions for a realistic temperature-time history. The r(t) function which we use is simplification of one used to
Bituminous cool 0 2lOOK a1940
0
1740
q l5iO _
-
-
Residence time (mS)
Fig. 1. Dry, ash-free weightloss vs residence time at various temperatures. The points represent the MIT data. The solid curves represent the Kobayashi (2 reactions;6 parameters) modeLls The dashed curves represent Eqs. (I) and (2).
Synergistic combustion of coal with natural gas
479
Cool C,HbOc
4 I
kz
f
2co
2co
co+
Hz
Fig. 2. Coal devolatilization and char burnout models used in kinetic simulation and rate parameters. k, = 1.65 exp (T/9O6)2 s-‘, k, =k,, k,=2.72 x lOOexp(-1500/T), k,=5.44x 103T k,= 1.69 x lO?fexp(-21060/T), k6= 1.69 x l@Texp -21060/T), OL= exp (-8057/T), exp (- 1045/T), B = 0.1, a, = 0.37 - O.OST, u2 = 0.35, a3 = 0.16 - 0.05 4 , a, = 0.12 + 0.1 F, f = T/1000, &I,= 1.
provide very good analytic fits to temperature given by
measured in our laboratory
T(f) = Toev P(v’ - ~2-1W~~ + expW~J
flames.lg It is
(3)
where To is a characteristic temperature, t, and t, are characteristic times and y is a characteristic dimensionless constant. We have also used this equation in simulations of our vortex combustor and in simulations of boiler flames. Figure 3(a) gives a set of what are believed to be not unrealistic temperature-time histories for coal particles in boiler flames fired with coal (C), coal-gas (C/G), coal-water (CW) and coal-water/gas (CW/G). Figures 4(a and b) illustrate the concentrations histories of the major and minor species which follow from our detailed kinetic simulation of the reactions in a coal-gas flame. Figure 3(b) shows the comparative char production and burnout histories in the four cases. The somewhat increased temperature and the more rapid rise times are major reasons for the faster burnout time of the coal-gas mix with respect to the coal case and the coal-water/gas mix with respect to the coal-water case. Recent work on flash pyrolysis of coal in reactive and non-reactive gaseous environments20*2’ show that total carbon conversion is higher in the presence of reactive gases (Hz, CH,, CO) than in the presence of non-reactive gases (He, N,, Ar). Indeed the ethylene and higher hydrocarbon production by flash pyrolysis of New Mexico subbituminous coal is distinctly higher with CH, than any of the other reactive or non-reactive species. Apparently at high temperatures CH, facilitates the depolymerization of coal. These results taken together with our laboratory flame studies and our kinetic simulations favor the concept of synergistic coal-gas combustion. 3. DIRECT
FIRING
SYSTEMS
Flame stabilization is a synergistic feature of practical coal-gas burning systems as observed at the James River Power Plant in Springfield Missouri.” Their boilers were retrofitted from gas to coal burning but to overcome some initial problems in the design of the coal systems and characteristics of their coal, they burned the two fuels simultaneously for a period. In coal combustion, gas assist is particularly useful at low load levels when coal flames are notoriously unstable. A ring type burner or a variety of other coal-gas
/ 1
A. E. S. GREENand K. M.
480
I-
PAMIDIMUKKALA
c/G~~~~~
Cand cw’F’ / / /
/-
5 I: 20 l3-l
I-
cw; /-
Reaction
time,
set
Fig. 3. (A) Time temperature histories used in simulations. The parameters T,(“K) and t,(ms) for Eq. (3) are (G), 2000 and 2; (C/G), 1900 and IO; (C), and (CW/G), 1800 and 25; (CW), 1700 and 50. In all cases y = 0.5 and f2 = 5000 ms. (B) Char concentrations vs time.
(b)
(a)
Reoctlon
time,
Fig. 4. Species concentrations
set
Reoctlon time, set
vs time for a coal-gas system; (A), stable species; (B), intermediate species.
Synergisticcombustion of coal with natural gas
481
configurations should provide insurance against flameout. Ability to accommodate a variety of coals by adjustment of the gas proportion is also a useful feature. It is generally recognized that the radiation from oil flames exceeds that of coal flames which greatly exceeds that of natural gas flames.23 However, a coal-gas flame may emit radiation comparable to an oil flame because of the higher temperatures of the coal particles. The quantification of such non-linear relationships should be pursued since radiation is important for heat transfer in oil boilers.24 NO, suppression in coal-gas flames would largely by a matter of taking advantage of the increased flexibility in blended fuel combustion to achieve fuel rich conditions in the initial burning zone. By methane staging, we may enhance the low NO, properties of burners which utilize air staging. 25 Sulfur dioxide reduction by coal-gas burning is accomplished in a benign (non-synergistic) way simply by the fraction of the energy provided by natural gas which is sulfur free. A synergism in the form of the global reaction CH, + 2S02-+C02 + 2H20 + SZ
(4)
is well documented in sulfur-extraction technology,26 however the application of this reaction in a practical combustor is a matter of speculation. The problem of coal ash in the conversion of an oil boiler to coal is recognized to be a formidable one27*28but is no longer regarded as insurmountable. Several conversions of oil designed boilers to dual coal/oil capability have already been carried out29*30or subjected to preliminary architect-engineering analyses31932and the technology should soon be fairly well established. In oil to coal conversion the cost to provide for gas combustion should be small compared to the benefits in pollutant reduction and boiler derating reduction. The beneficiation of coal to reduce ash weight is an aitemative approach to ash problems and considerable progress has been made which should simplify and reduce the capital cost of coal conversion 33-35albeit with an increase in the cost of fuel. Here, the use of gas to minimize derating might be expected to have a proportionally greater pay-off. Ash formation is sufficiently complicated that almost anything can happen, depending upon coal rank, temperature history and other variables. Slag on the Springfield boiler tubes was frequently cleared by boosting the proportion of gas in the flame to achieve the slag melting point. 36To what extent we can generally program the physical transformation of ash3’ to be helpful in minimizing ash problems in oil to coal-gas conversions is an important matter for further research. Large scale programs are underway3B41 on the use of coal-oil and coal-water slurries (CWS) to replace oil. Here, a driving consideration is the ability to transport the slurry fuel by pipe directly to the burners. To directly retrofit the boiler to bum powdered coal would require the installation near the boiler of pulverizers, blowers, hoppers and other massive components of typical coal systems and many oil boilers do not have space for this. The economical advantages of coal-oil slurries are questionable, since even with high coal loading, about 6O-70% of the slurry’s energy derives from its oil. However, coal-water slurries with 60-70x by weight of coal have been successfully combusted42A and here all of the useful energy derives from coal. In this case, the water might be viewed as a negative fuel since it must be evaporated before coal combustion can proceed. However, the heat of vaporization ( N 10 kcal/mole) imposes only small penalty (m 3%) and some beneficial effects attendant the high water vapor content in the burning zone have been reported. These effects possibly are associated with the OH radicals produced by the small fractional dissociation of water in the flame and more probably as suggested by our kinetic modeling by the higher concentrations of H,O available for oxidation of the char. The high viscosity of heavily coal loaded CWs’s poses a pumping problem should there be a large distance between the source preparation facilities and the burners. Here, a possible synergism could be exploited in combined methane-CWS burning if methanating the slurry were to reduce the viscosity.” Then the reduced pumping energy would combine with the advantages of the greater calorific value of the coal-water-gas combination. Unfortunately our measurements with a Brookfield viscometer in an open beaker on the effects of gas bubbles in the coal-water slurries we have prepared led to increased viscosity
482
A. E. S.
GREEN and K.
M. PAMIDIMUKKALA
readings.48 However, three phase (gas, liquid, and solid) how under pressurized conditions is an undeveloped science. In a thorium oxide-water-steam slurry flowing under high pressure a reduction of viscosity was observed. 49Thus the possibility of viscosity reduction in coal-water-methane flow warrants further research.
4. 2 STAGE COMBUSTION One of the major obstacles to the direct retrofitting of an oil boiler to coal burning is the high cost of the modifications required to accomodate the ash. A promising type of oil boiler retrofit which might minimize these modifications would be to use a first stage coal-natural gas system whose primary function is to de-ash the coal and extract a hot combustible gas for afterburning in the original boiler (see Ref. 6, p. 135). One might ask. “Why not just use a coal gasifier? Why add gas ?” Some answers are (1) the much higher Btu content of natural gas than producer gas, (2) CH4 adds free radicals which speed up the combustion kinetics, (3) flash “methanolysis”20~2’ appears to increase the volatile production by converting coal polymers to combustible hydrocarbons. While flash hydropyrolysis has received much attention, Soboth in direct experiments and in connection with hydrogasification research, we have found only a few references to flash methanolysis and none to what might be called “methanogasitication”. In methanogasification the methane serves as fuel to provide the high temperatures for rapid pyrolysis, supplies the hydrogen to promote the free radical attack on the coal polymers” and also facilitates char gasification via CO2 and Hz0 attack and probably attack by the increased concentrations of free radicals. Since methane and higher hydrocarbons are products of coal methanogasification it may be possible to reduce the external gas needs to proportions which are economically advantageous for any reasonable set of fuel prices. At off-peak times some of the methanogasifiers might be used to produce valuable chemicals or liquid fuels. There is a possibility of introducing lime or other additives with the pulverized coal in the first stage combustor to capture sulfur with the ash and recent work on limestone sorbant injection into low NO, multistage burners” would find natural application to such an effort. If one could build a first stage system to de-ash and de-sulfurize the fuel while after-burning the fuel rich hot gases in the boiler itself with gas augmentation in both stages to achieve the desired flame temperatures, the capital costs of retrofitting an oil boiler would be substantially reduced. Thus factory made methanogasification systems couid be the major component of the retrofitting project. The pulverizers and other fuel preparation and storage facilities can be at a convenient distance from the retrofitted oil boiler which alleviates the space requirement near the boiler. Only the methanogasifiers need be in close proximity to the boilers although how close is a matter of the technology of high temperature piping. The technology of hydrogasification systems which have the general nature of a methanogasification system is highly developed52-58 and much of this technology should be adaptable to the purposes here. Whereas methane is a relatively abundant naturally available feedstock, hydrogen must first be produced in an industrial process from a basic feedstock. Investing some industrial oxygen in the methanogasification step may also be useful since this would help reach higher temperatures faster without increasing NO production from air. Going to higher than atmospheric pressure should also be helpful in obtaining a higher synthetic fuel output with increased calorific content which should reduce the natural gas augmentation needed in the boiler itself. The use of a first stage methanogasifier fed by a beneficiated coal-water slurry might yield extra de-ashing and de-sulfurizing synergisms and reduce the requirements and costs of either approaches to the ash problem. The water in the slurry may also serve as a useful supplementary source of hydrogen for the methanogasifier. 5. DISCUSSION
AND CONCLUSIONS
Our primary thesis, which is consistent with the results of our combustion modeling, is that synergisms occur in simultaneous coal-gas combustion which should help in oil displacement without exacerbating pollution problems. Recent analyses”~” on the “select-
Synergistic combustion of coal with natural gas
483
bubble” use of gas with coal, show cases which are economically favorable with respect to continuation with oil or conversion to coal and installation of wet scrubbers. In the synergistic use of coal and gas some credits must be assigned for the reduced loss of derating and the inherently greater flexibility available in dual or multiple fuel systems with cofiring capability in coping with potential fuel shortages. These are left out of economic analysis of the select-bubble use of coal and gas. Thus we might reasonably expect additional economically favorable cases in synergistic use of gas and coal. We have concentrated our attention on coal-gas combustion in retrofitting oil boilers for the purpose of oil backout. Some of the potential synergisms we have discussed could also be useful with new boilers and furnaces. In cases where natural gas is not available, other high grade gaseous fuels such as propane and butane which can more easily be shipped and stored in liquid form might be utilized instead. While the hydrogen/carbon ratios would be somewhat lower, they are still much higher than those of coal. Clearly there is a need for improved knowledge of gas assisted gasification and two and three phase combustion and it would appear that the time has come to initiate experimental and theoretical research to meet these needs. Ac~kno~~/ed~emPn/s-This work was supported in part by University of Florida Engineering College and Gatorade Trust Funds and in lesser parts by the Middle Ultraviolet Associates and the Dragon Fire and Clay Company. We thank Ramesh R. Meyreddy for his help with the kinetic calculations.
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McGurl, “Small Gasihers in Industry”, Symposium Papers-Aduances p. 11I. Institute of Gas Technology, Louisville, KY (May 1979). 54. D. F. Spencer, M. J. Gluckman, and S. B. Alpert, Science 215, 1571 (1982). 55. P. B. Probert, “Gasification System”, p. 243, in Ref. 35. 56. I. H. Smith and G. J. Werner, Coal Conversion Technology. Noyes Data Corporation, Park Ridge, NJ (1976). 51. W. G. Schlinger, “Coal Gasification Development and Commercialization of the Texaco Coal Gasification Process”. n. 119. 6th AnnuaI Int. Conf. on Coal Gasification Liqutfaction and Conversion to Electricity, Pittsburg, PA (1979). 58 Coal Gasificntion (Edited by L. G. Massey), Advances in Chemistry Series 131. ACS, Washington, D.C. (1974).