I n d . E n g . C h e m . Res. 1989,28, 27-33
maximum sorbent utilization efficiency. These pilot test results indicate that SOz capture by entrained hydrated lime particles occurs by two different mechanisms: a gas/solid reaction mechanism for particles which do not interact with droplets; a gas/solid/droplet reaction mechanism for particles interacting with water droplets. Accordingly, the sorbent injection process performance may be improved by enhancing either of these two reaction mechanisms. The lime properties may be improved to enhance the sorbent’s intrinsic activity for the gas/solid reaction mechanism. The humidifier may be designed to provide increased particle-droplet interactions to promote the wet reaction. Registry No. SOz, 7446-09-5.
Literature Cited Babu, M.; Forsythe, R. C.; Runyon, C. V.; Kanary, D. A.; Pennline, H. W.; Sarkus, T.; Thompson, J. L. “Results of 1.0 MMBtu/Hour Testing and Plans for a 5 MW Pilot HALT Program for SOz Control”. Proceedings of the Third Annual Pittsburgh Coal Conference, Pittsburgh, PA, Sept 1986. Forsythe, R. C.; Kaiser, R. A. “Hydrate Addition at Low Temperature: SOzRemoval in Conjunction with a Baghouse”. Proceedings
27
of the Second Annual Pittsburgh Coal Conference, Pittsburgh, PA, Sept 1985. Klingspor, J. “Kinetic and Engineering Aspects on the Wet-Dry FGD Process”. Licenciate Thesis, Lund Institute of Technology, Lund, Sweden, 1983. Statnick, R. M.; Burke, F. P.; Koch, B. J.; McCoy, D. C.; Yoon, H. “Status of Flue Gas Sorbent Injection Technologies”. Proceedings of the Fourth Annual Pittsburgh Coal Conference, Pittsburgh, PA, Sept 1987. Yoon, H.; Stouffer, M. R.; Rosenhoover, W. A.; Statnick, R. M. “Laboratory and Field Development of Coolside SO2Abatement Technology”. Proceedings of the Second Annual Pittsburgh Coal Conference, Pittsburgh, PA, Sept 1985a. Yoon, H.; Ring, P. A.; Burke, F. P. “Coolside SOzAbatement Technology: 1 MW Field Tests”. Proceedings of the Coal Technology ’85 Conference, Pittsburgh, PA, Nov 1985b. Yoon, H.; Theodore, F. W.; Burke, F. P.; Koch, B. J.; Corder, W. C. “Low Capital Cost, Retrofit SOz Control Technologies for High Surfur Coal Applications”. Proceedings of the 79th Annual Meeting of the Air Pollution Control Association, Minneapolis, MN, June 1986. Yoon, H.; Stouffer, M. R.; Rosenhoover, W. A.; Withum, J. A.; Burke, F. P. “Pilot Process Variable Study of Coolside Desulfurization“. Enuiron. Prog. 1988, 7, 2, 104-111.
Received for review March 4, 1988 Revised manuscript received August 31, 1988 Accepted September 16, 1988
Evolution of Hydrogen Sulfide in a Fluidized Bed Coal Gasification Reactor Robert P. Ma, Richard M. Felder,* and James K. Ferrell Department of Chemical Engineering, North Carolina State University, Raleigh, North Carolina 27695
T h e rates of evolution of hydrogen sulfide have been measured for the steam/oxygen gasification of a devolatilized Western Kentucky bituminous coal, a New Mexico subbituminous coal, and a Texas lignite in a pilot-scale fluidized bed reactor, and a phenomenological model has been formulated t o correlate the results. T h e model assumes instantaneous devolatilization and partial combustion of the coal followed by rate-limited gasification of the char in a single well-mixed stage and includes kinetic correlations for the water gas shift reaction and char hydrodesulfurization. Estimated char reactivities agree well with results obtained in other studies, and the model predictions are generally satisfactory, especially considering the relative simplicity of the model. T h e results indicate that sulfur present in the coal as pyrite, mercaptans, aliphatic sulfides, and disulfides is converted completely, while sulfur in aryl sulfides and thiophenes is only partially converted. A substantial fraction of the sulfur converted during gasification is released in pyrolysis-50-70% for the subbituminous coal and 35-45% for the lignite. An Environmental Protection Agency sponsored study of the potential environmental impact of coal gasification operations has been under way since 1978 at North Carolina State University. Several coal feedstocks have been gasified with steam and oxygen in a small (15-cm i.d.1 pilot-scale fluidized bed reactor operated by the faculty, students, and staff of the NCSU Department of Chemical Engineering (Felder et al., 1980; Ferrell et al., 1980). Results have been reported on the compositions of synthesis gas and waste streams from the gasifier (Ferrell et al., 1980, 1982a,b), and dynamic and steady-state models have been developed to correlate the observed rates of production of the principal product gas species with the operating conditions of the gasifier (Ma et al., 1988; Purdy et al., 1981,1984; Rhinehart et al., 1987a,b). Other studies have dealt with rates of evolution of nitrogen gases (Farzam et al., 1985) and of volatile trace elements (Rudisill,
* To whom correspondence should be addressed.
1984). This paper reports on experimental and modeling studies of the evolution of hydrogen sulfide, the most prevalent sulfur-containing species in the synthesis gas. Coal generally contains iron pyrite (FeS2)and various divalent organic sulfurs, including, in descending order of thermal stability, thiophenes, aryl sulfides, cyclic sulfides, aliphatic sulfides, and aryl and aliphatic thiols (Attar, 1978). In a reducing atmosphere above about 500 “C, iron pyrite reacts with hydrogen to form hydrogen sulfide (Thompson and Tilling, 1924). All the organic sulfur species present in coal can also react with hydrogen to form hydrogen sulfide, with the reactivity of a species varying inversely with its thermal stability (Attar, 1978). Coal decomposition and secondary gasification reactions also lead to the formation of other sulfur gas species including carbonyl sulfide (COS), carbon disulfide, and various thiophenes and mercaptans. Studies of coal desulfurization chemistry have been reported by Zielke et al. (1954), Maa et al. (1975), Robinson (1976), Haldipur and Wheelock
0888-588518912628-0027$01.50/0 0 1989 American Chemical Society
28 Ind. Eng. Chem. Res., Vol. 28, No. 1, 1989
(1977), Huang and Pulsifer (1977), Attar (1978, 19791, Torrest and VanMeurs (1980), and Yeboah et al. (1982), and kinetic studies of H2S evolution have been performed for coal pyrolysis (Solomon, 1977; Lester et al., 1982;Attar and Messenger, 1983) and coal hydrogasification (Vestal et al., 1969, 1970,b, 1972; Vestal and Johnston, 1970; Yergey et al., 1974). Being able to predict rates of formation of sulfur gases in coal gasifiers would clearly be useful, both to optimize gasifier operating conditions and to design downstream gas cleaning systems. The work to be reported here is a step toward the development of such a capability.
Experimental Section Facilities and Procedures. The pilot plant consists of a fluidized bed gasifier, a raw gas cleaning system (a cyclone followed by a venturi scrubber and several filters), and an acid gas removal system (packed absorption and stripping towers and several flash tanks in series). The gasifier is a 15-cm-i.d. Schedule 40, 316 stainless steel pipe enclosed in several layers of Fiberfrax bulk ceramic insulation and housed in a 61-cm-i.d. Schedule 80 carbon steel pipe. Gases are fed to the reactor through three feed nozzles spaced triangularly near the bottom of the reaction chamber. The height of the reactor (from the gas feed nozzles to the top) is roughly 4 m; the bed itself typically has a height of 1 m. Coal is fed at the top of the gasifier, and char is removed a t the bottom by a nitrogen-purged screw conveyor. The temperature profile in the bed is monitored by six thermocouples housed in a central thermowell in the reactor. The thermocouple located 25 cm above the feed nozzles is used for reactor temperature control, with the oxygen feed rate being adjusted to maintain the selected temperature. The bed level is monitored with a nuclear level gauge and controlled by adjusting the char removal screw rotation rate. Hot reactor effluent gas is continuously sampled from a centerline point in the effluent pipeline downstream of the cyclone. The tars and solids in the sampled gas are trapped in a steel wool filter, condensable and water-soluble species are removed in a cold water quench, and the gas is reduced in pressure and either vented or drawn into 1-L coated stainless steel or glass bombs. The solids and tars are separated by a methylene chloride extraction. The composition of the reactor make-gas can be reconstructed from the flow rates and compositions of the samples. Gas chromatography is used to determine concentrations of fixed gases (Hz,CH4, CO, COz, and NJ, sulfur gases (H2S, COS, CSz, thiophenes, and mercaptans), and light aliphatic and aromatic hydrocarbons. Proximate, ultimate, and sieve analyses are routinely performed on the solid feed and effluent streams. Purdy (1983) gives details about process control and gasifier operation and describes gasifier effluent sampling and analysis methodology, and additional procedural details are provided by Rudisill (1984), Zand (1984), Lee (1985), and Rhinehart (1985). A detailed description of the pilot-plant data acquisition system is given by Willis (1981). Since 1979 a devolatilized Western Kentucky bituminous coal (Purdy et al., 1981), a New Mexico subbituminous coal (Purdy et al., 1984), and a Texas lignite (Rhinehart et al., 198713) have been gasified. Typical proximate and ultimate analyses of the feedstocks are shown in Table I. The average bed temperature varied from 1017 K for the Texas lignite to 1281 K for the Western Kentucky char, the span for steam-to-carbon feed ratio was 0.68 for the Kentucky char to 2.27 for the Texas lignite, and the per-
Table I. Analyses of Coal Feedstocks KY char NM subbit. coal proximate, w t 70 35.2 fixed carbon 86.0 31.7 2.4 vol. matter 10.5 moisture 0.9 22.6 10.7 ash ultimate, wt '7~ 83.8 52.5 carbon 4.8 hydrogen 0.6 18.1 2.2 oxygen 1.2 nitrogen 0.1 2.6 0.8 sulfur 22.6 ash 10.7
T X lignite 23.1 29.1 24.3 23.5 39.2 4.2 32.1 0.5 0.5 23.5
Table 11. Proximate Analyses of a New Mexico Subbituminous Coal and a Texas Lignite (Weight Percent) NM subbit. coal T X lignite fixed carbon 42.33 37.09 vol. matter 34.26 37.63 moisture 1.16 1.11 22.25 24.17 ash Table 111. Distribution of Organic Sulfur by Species NM subbit. T X lignite, org. S group coal, g S / g coal E! S / n coal mercaptans 4.53 x 10-4 8.86 X lo-' 5.37 x 10-4 aliphatic sulfides 9.0 x 10-5 2.72 x 10-4 2.61 x 10-4 disulfides 6.46 x 10-4 1.322 X aryl sulfides 4.49 x 10-4 simple thiophenes 2.88 x 10-4 3.534 X 1.322 X complex thiophenes 9.187 X 7.166 X total
centage carbon conversion varied from 16.2 for the Kentucky char t~ 94.0 for the New Mexico subbituminous coal. In most of the runs, the system pressure was maintained at 765 kPa (100 psig), and in a few runs the pressure was as low as 550 kPa. The average feed particle diameter and density were 0.2-0.6 mm and 1.4-1.8 g/cm3, respectively, and the comparable figures for particles in the fluidized bed were 0.05-0.4 mm and 1.8-2.6 g/cm3. Complete experimental results are given by Purdy (1983) and Rhinehart (1985). Distribution of Sulfur in Coal. The content and forms of sulfur in the three gasifier feedstocks have been measured or estimated. Total sulfur content was determined with a Fisher Model 470 sulfur analyzer. Pyritic sulfur content in the New Mexico subbituminous coal is given by Agreda et al. (1979), and the quantity of pyritic sulfur in the Texas lignite is estimated to be one-third of the total sulfur by weight (Attar and Dupuis, 1979). The organic sulfur distribution was determined by Coal Gas Inc. (115M Umstead Industrial Park, Raleigh, NC) using a nonisothermal technique similar to the one devised by Juntgen and Van Heek (1968). Samples of New Mexico subbituminous coal and Texas lignite were prepared for the organic sulfur distribution measurement by mixing feed coal samples from the four runs that had the best sulfur mass balance closures. The combined samples were extracted with 1:l HC1 and dried in a vacuum oven. Proximate analyses of the samples are given in Table 11. Table I11 lists the species distributions of organic sulfur in the subbituminous coal and the lignite. For the devolatilized Western Kentucky bituminous coal, all organic sulfur functional groups are assumed to be thiophenic (Attar and Messenger, 1983).
Modeling A simple three-stage fluidized bed model has been used to correlate gasifier data. The model, which was originally
Ind. Eng. Chem. Res., Vol. 28, No. 1, 1989 29 Table IV. Distribution of Organic Sulfur by Functional Groups functional KY char, NM subbit. TX lignite, S g/g s coal, g/g S g/g s pyrite 0.047 0.425 0.333 org. I, I1 0.004 0.089 0.235 org. I11 0.949 0.486 0.432
developed by Purdy et al. (1981,1984) and extended by Rhinehart et al. (1987a,b), presumes instantaneous coal devolatilization at the top of the reactor (freeboard region), instantaneous carbon combustion at the bottom of the reactor, and steam-carbon gasification and water gas shift in a single perfectly mixed isothermal stage. In the current study, the hydrogen sulfide evolution scheme of Yergey et al. (1974) has been added to the third-stage model. Back-reactions involving H2S and partially desulfurized coal are neglected since the amount of H2S produced in the reactor is relatively small. A summary of the principal model features is given below. Additional details are provided by Ma et al. (1988) and Ma (1988). Hydrodesulfurization Kinetics. Vestal et al. (1969, 1970,b, 1972), Vestal and Johnston (1970), and Yergey et al. (1974) described the release of hydrogen sulfide from coal in terms of five hypothetical groups of origin: pyrite, sulfide, organic I, organic 11, and organic 111. Organics I and I1 correspond to sulfur loosely bound to the organic matrix, and organic I11 corresponds to tightly bound sulfur. The specific species contained in these groups were not identified. However, the analytical technique used in the present study is similar to the one employed by Yergey et al. (1974), so that the results may be used to identify the species in the groups labeled by Yergey et al. according to the release sequence of H2S. Mercaptans, aliphatic sulfides, and disulfides are assigned to organics I and I1 since they release H2S before the release of pyritic sulfur, while aryl sulfides and thiophenes release sulfur after the release of pyritic sulfur and so are assigned to organic 111. Table IV lists the sulfur distributions by functional groups in the gasifier feedstocks. A coal hydrodesulfurization process is represented by (Aj-S)solid + HZ (AjIsolid + HzS
-
The rate of this reaction is -d[A,-S]/dt
= (d[HzS]/dt)j = kjPH,[A,-SIn~
where [A,-S) is the concentration of solid reactant sites of type j ( j = 1-5) and nj is the order of reaction with respect to this pseudospecies. The rate constant kj can be written in the Arrhenius form
();:
kj = koj exp - Yergey et al. (1974) give values of the frequency factors, activation energies, and reaction orders with respect to the solid species. Devolatilization. Coal drying and devolatilization occur in the freeboard region. Devolatilization yields were calculated from pilot-plant data (Rhinehart, 1985; Rhinehart et al., 1987b) and fitted with the equation Mi/Md,f = Ai + BiT where Mi (kg/h) is the devolatilization yield of species i, Mdaf (kg/h) is the dry ash free coal feed rate, and T (K) is the devolatilization temperature. Tables V and VI list values of Aiand Bifor the New Mexico subbituminous coal and the Texas lignite, respectively.
Table V. Devolatilization Yield Correlations for New Mexico Subbituminous Coal
suecies
co HZ CH, COZ H2S
cos tar
Mi(kg/h)/Mdkg/h) = Ai + BiT(K) A; B; -0.625 6.52 X 10”’ -4.93 x 10-2 5.02 x 10-5 -0.325 3.43 x 10-4 -9.95 x 10-2 1.43 X lo4 -2.28 x 10-2 2.29 x 10-5 -2.79 x 10-3 3.16 X lo* 0.1175 0.0
Table VI. Devolatilization Yield Correlations for Texas Lignite
co HZ
CH, COZ H2S
cos tar
-0.356 -3.54 x -1.94 X 0.107 -2.34 X -1.93 x -0.35
3.93 x 4.06 x 7.31 x 0.0 2.33 x 1.96 X 5.00 X
10-2 lo-’ lo-’ 10-3
10-4 10-5 10-5 10-5 10” 10“‘
Organics I and I1 sulfurs are released to the gas phase and hydrogenated during pyrolysis: organic I + organic I1 + Hz H2S After this process is complete, pyrite releases sulfur, still during pyrolysis of the coal: FeS, + H, FeS + H2S The amount of pyrite reduced depends on the peak pyrolysis temperature and the residence time of coal particles in the freeboard region. Combustion. Oxygen is consumed completely in the combustion stage according to the hypothetical stoichiometric equation: C + a02 2(1-a)CO + (2a-l)CO, where a is an adjustable parameter whose value specifies the split of carbon combustion products between carbon monoxide and carbon dioxide: a = 0.5 indicates formation of only CO, and a = 1.0 signifies that only C02 is formed. Gasification. The Johnson kinetic scheme (Johnson, 1981) is used to describe the steam-carbon gasification process: C + HzO CO Hz C + 2Hz CH4 C + 0.5H2 + O.5HzO 0.5CO + 0.5CH4 The “char reactivity coefficient”,a parameter that accounts for differences in intrinsic reactivities of different chars, is the only adjustable model parameter associated with the gasification step. (For a full presentation of the model equations, see Ma (1988).) A rate expression given by Wen and Tseng (1979) is used for the water gas shift reaction CO + HzO + C02 + Hz with the rate constant being the third adjustable parameter of the model. Instantaneous water gas shift reaction equilibrium may be assumed as an alternative to the inclusion of shift reaction kinetics. All pyrite remaining after the devolatilization stage is reduced to ferrous sulfide and H2Sin the gasification stage. The ferrous sulfide and organic I11 sulfur subsequently react with hydrogen to release H2S. FeS, + H, FeS + H2S
-
-
-
--
-
-
+
30 Ind. Eng. Chem. Res., Vol. 28, No. 1, 1989
- -
FeS + Hz Fe + HzS organic I11 + H2 HzS The rates of hydrogasification of pyrite, ferrous sulfite, and organic I11 sulfur are described by the Yergey-Vestal kinetics (Yergey et al., 1974). The HzS-COS shift reaction COS HzO H2S + C02
Table VII. Estimated Model Parameters reactivitv coal type a char shift W. KY char 0.902 0.284 8.7 X lo4 NM subbit. coal 0.981 3.44 equilibrium TX lignite 0.500 15.4 equilibrium
+
is assumed to attain equilibrium instantaneously in the gas phase, with the equilibrium constant being given as a function of temperature by In (K,) = A , + B,/T The coefficients A, and B, have been determined by linear regression of data given by Kohl and Riesenfeld (1979). For temperatures below 900 "C, A , = -1.1315 and B, = 4273.5, and for temperatures above 900 "C, A , = -10.29 and B, = 15018. Implementation of the Model. The devolatilization of the feed coal is first simulated by using the empirical correlations given above. The residual char from this step is then oxidized instantaneously assuming complete consumption of oxygen in the feed, and the molar flow rates of carbon and oxygen are reduced by the appropriate amounts from their feed values. The calculation of the effluent composition from the gasification stage is performed iteratively. Mole fractions of CO, H2, CH4, COz, and HzO and fractional conversions of base carbon, ferrous sulfide, and organic I11 sulfur are assumed, the mass balance equations for the gasification stage are solved to obtain a new set of effluent composition variables and fractional conversions, and the newly calculated values are used to generate the starting point for the next iteration by modified successive substitution with convergence accelerated by the dominant eigenvalue method (Orbach and Crowe, 1971). Convergence is achieved when the differences between assumed and calculated values are all less than 0.1%. The model program was written in FORTRAN and executed on a VAX 11/750 computer. The bed calculation usually converged within 40 iterations, and the computing time was less than 30 CPU seconds per run. Parameter Estimation. In its current form, the fluidized bed model has three adjustable parameters: the combustion product distribution parameter, a; the char reactivity; and the rate constant for the water gas shift reaction. For gasification of the New Mexico subbituminous coal and the Texas lignite, shift reaction equilibrium was assumed based on the evidence of pilot-plant data obtained by using an in-bed sampler (Rhinehart, 1985). The adjustable parameters were evaluated by using a pattern search technique (Beightler, 1979) to minimize a function of the sums of squared deviations between predicted and measured values of gasifier performance variables. The variables used for this purpose were the dry effluent gas flow rate, the fractional carbon conversion, and the mole fraction of CO, Hz, and C 0 2 in the effluent gas. Details of the simulation and parameter estimation algorithms are given by Purdy et al. (1981).
Results Model Parameters. Table VI1 lists the estimated parameter values for the three feedstocks. The values of a indicate that COz is the principal combustion product for the Kentucky char and the New Mexico subbituminous coal char, while CO is the principal product of lignite char combustion. Both COz and CO have been found to be the
a
5
0
I u-
tK 0
0 K
n
% r
Ba a
0.0
4.0
8.0
12.0
16.0
EXPT'L b S PROD. RATE, MOUHR
Figure 1. Predicted versus measured H,S production rate (Western Kentucky char).
principal combustion product in other studies-COz by Ross et al. (1981), LaNauze and Jung (1982), and Smith (1982), and CO by Ayling and Smith (1972), Roberts and Smith (1973), and Macke and Bulik (1984). Char reactivities are seen to increase with decreasing feedstock rank, with that for the Kentucky bituminous char being lowest and that for the Texas lignite being highest. The results are consistent with results reported by Johnson (1984), whose value of 0.3 for a low volatile bituminous coal char is remarkably close to the 0.28 value obtained for the Kentucky bituminous char in this study and whose value of 10 for a North Dakota lignite compares well with the Texas lignite reactivity of 15.4. The water gas shift reaction reactivity for Kentucky char-8.7 X lO*-is 5 orders of magnitude lower than the value typically obtained in catalytic shift reactors. Wen and Tseng (1979) used a shift reactivity value of 1.7 X lo4 in modeling the gasification of a bituminous coal by the Synthane process. Gasifier Data Correlations. The model with the parameter values listed in Table VI1 was used to simulate all gasification runs with acceptable mass balance closures. The criteria for acceptability were overall and carbon elemental mass balance closures between 92% and 108% and hydrogen and oxygen elemental mass balance closures between 90% and 110%. Figure 1 is a plot of predicted versus measured HzS production rates for the Kentucky char. The two dotted lines bracketing the 45-deg line represent *20% deviations of model predictions from measured values. Most of the predicted H,S production rates fall within this range, indicating that the Yergey-Vestal kinetics provide a reasonable basis for estimating hydrogen sulfide evolution from the NCSU coal gasifier. Similar plots for gasification of the New Mexico subbituminous coal and the Texas lignite are shown in Figures 2 and 3, respectively. Again, most of the predictions deviate by no more than 20% from the measured values.
Ind. Eng. Chem. Res., Vol. 28, No. 1, 1989 31 6.0
/
6.0
/
/
/
U /
4.0
/
/
/'
2
4.0
J c a a d
/
e
8n
:
2.0
2.0
9a n
0.0 0.0
I
2.0
I
4.0
0.0 0.0
6.0
2.0
EXPT'L H2.S PROD. RATE, MOLlHR
Figure 2. Predicted versus measured H2S production rate (New Mexico subbituminous coal).
4.0
6.0
EXPT'L HpS PROD. RATE, MOL/HR
Figure 3. Predicted versus measured H2Sproduction rate (Texas lignite).
Table VIII. Mean Percentage Deviations of Predicted H2S Evolution Rates from Measured Values coal type evolution kinetics equal conversn W. KY char -8.0 -24.0 NM subbit. coal 0.2 16.0 TX lignite 9.5 17.0
x
t
e
80-
*
e
x
e
In the absence of a reliable kinetic correlation, it would be logical to assume that sulfur conversion equals carbon conversion. For purposes of comparison, the well-mixed bed model with this assumption incorporated was used to simulate the gasification runs. Table VI11 compares the mean percentage deviations of the measured H2S evolution rates from values predicted based on (1)sulfur evolution kinetics and (2) the equal conversion assumption. The kinetic model both provides a firmer theoretical basis and substantially improves the prediction. Origins of Evolved Sulfur. The modeling results indicate that 50-70% of the sulfur released in the gasification of New Mexico subbituminous coal is released in pyrolysis, with 55-95% of the pyrite in the coal being reduced to ferrous sulfide in this stage. In contrast, 3545% of the sulfur converted in the gasification of Texas lignite comes from pyrolysis, with 20-40% of the pyrite being reduced to sulfide in this stage. The model also predicts that, in the gasification of subbituminous coal and lignite, organics I and I1 sulfurs are completely released as hydrogen sulfide. Moreover, all pyrite not converted in the pyrolysis stage is reduced in the fluidized bed to ferrous sulfide, which is subsequently hydrogasified to iron and hydrogen sulfide. The complete conversion of pyrite is in agreement with the experimental results of Vestal et al. (1969). Only part of the organic I11 sulfurs are hydrogasified. Analyses of the gasifier effluent performed with gas chromatography and flame photometric detection indicated that H2S was by far the predominant sulfur gas, followed by COS and trace amounts of thiophenes, mercaptans, and CS2. The model indicates that more than 99% of the COS produced (5-10% of the H2S produced) originates in pyrolysis. The model correlations for COS production at best provided order-of-magnitude estimates of the measured values. Figure 4 is a plot of measured sulfur conversion as a function of average bed temperature. Although the scatter
* 60
*
x
-
x
"e.
>
sz uj
40 x Q
20
-
X
D
KYCHAR NMSUB. TXLIG.
750
650
950
1050
AVG. BED TEMP., OC
Figure 4. Sulfur conversion as a function of average bed temperature.
is considerable, it appears that sulfur conversion increases with increasing bed temperature for all feedstocks. Since the model predicts complete conversion of organics I and I1 sulfurs and pyrite, the temperature dependency can be taken to be that of the hydrogasification rate of organic I11 sulfur.
Acknowledgment This work was supported by the United States Environmental Protection Agency under Cooperative Agreement CR-809317.
Nomenclature a = stoichiometric parameter that specifies the split of carbon combustion products between CO and COz
32 Ind. Eng. Chem. Res., Vol. 28, No. 1, 1989
Ei = activation energy of reaction j , J/mol k j = rate constant of reaction j koj = frequency factor of the reaction rate constant k , K, = equilibrium constant for hydrolysis of carbonyl sulfide Mdaf= dry ash free coal feed rate, kg/h Mi = devolatilization yield of component i, kg/h nj = reaction order with respect to solid sulfur species j PH2= hydrogen partial pressure, atm R = gas constant, 8.314 J/(mol.K) t = time, s T = temperature, K [A,-SI = number of solid reactant sites of type j , mol [H2SIj= H2S generated from process j , mol Registry NO.H a , 7783-06-4; CO, 630-08-0; Hz,1333-74-0; CHI, 74-82-8; COP, 124-38-9; COS, 463-58-1.
Literature Cited Agreda, V. H.; Felder, R. M.; Ferrell, J. K. Devolatilization Kinetics and Elemental Release in the Pyrolysis of Pulverized Coal. EPA-600/7-79-241, 1979; EPA, Washington, DC. Attar, A. Chemistry, Thermodynamics and Kinetics of Reactions of Sulfur in Coal-gas Reactions: A Review. Fuel 1978, 57(4), 201-212. Attar, A. Sulfur Reactions in Coal Pyrolysis and Hydrogenation, In Coal Processing Technology. Vol. IV, CEP Technical Manual, 1979; pp 26-34. Attar, A.; Dupuis, F. Data on the Distribution of Organic Sulfur Functional Groups in Coal. Prepr. Am. Chem. SOC.,Diu. Fuel Chem. 1979, 24(1), 166-177. Attar, A.; Messenger, L. R. The Desulfurization of Organic Sulfur and the Transformations of Organic Sulfur Functional Groups in Coal Pyrolysis. Chem. Eng. Commun. 1983, 20, 53-62. Ayling, A. B.; Smith, I. W. Measured Temperatures of Burning Pulverized-Fuel Particles. Combust. Flame 1972, 18(2), 173-184. Beightler, C. S.Foundations of Optimization, 2nd ed.; Prentice-Hall: Englewood Cliffs, NJ, 1979. Farzam, A. Z.; Felder, R. M.; Ferrell, J. K. Analysis of Nitrogenous Compounds in the Effluent Streams from a Fluidized Bed Coal Gasification Reactor. Fuel Process. Technol. 1985,10, 249-259. Felder, R. M.; Kelly, R. M.; Ferrell, J. K.; Rousseau, R. W. How Clean Gas Is Made from Coal. Enuiron. Sci. Technol. 1980, 14, 658. Ferrell, J. K.; Felder, R. M.; Rousseau, R. W.; Ganesan, S.; Kelly, R. M.; McCue, J. C.; Purdy, M. J. Coal Gasification/Gas Cleanup Test Facility. 11. Environmental Assessment of Operation with Devolatilized Bituminous Coal and Chilled Methanol. EPA Project Summary Report EPA-600/7-82-023, 1982a; EPA, Washington, DC. Ferrell, J. K.; Felder, R. M.; Rousseau, R. W.; Kelly, R. M.; Purdy, M. J.; Ganesan, S. Coal Gasification/Gas Cleanup Test Facility. 111. Environmental Assessment of Operation with New Mexico Subbituminous Coal and Chilled Methanol. EPA Project Summary Report EPA600/S7-82-054, 1982b; EPA, Washington, DC. Ferrell, J. K.; Felder, R. M.; Rousseau, R. W.; McCue, J. C.; Kelly, R. M.; Willis, W. Coal Gasification/Gas Cleanup Test Facility. I. Description and Operation. EPA Project Summary Report EPA600/7-80-046a, 1980; EPA, Washington, DC. Haldipur, G. B.; Wheelock, T . D. Desulfurization in a Fluid-Bed Reactor. Coal Desulfurization; ACS Symposium Series 64; American Chemical Society: Washington, DC, 1977; pp 305-319. Huang, E. T. K.; Pulsifer, A. H. Coal Desulfurization during Gaseous Treatment. Coal Desulfurization; ACS Symposium Series 64; American Chemical Society: Washington, DC, 1977; pp 290-304. Johnson, J. L. Chemistry of Coal Utilization; Elliott, M. A., Ed.; Wiley: New York, 1981; 2nd Suppl. Vol., Chapter 23. Johnson, J. L. Coal Gasification; ACS Advances in Chemistry Series 131; American Chemical Society: Washington, DC, 1984; pp 145-178. Juntgen, H.; van Heek, K. H. Gas Release from Coal as a Function of the Rate of Heating. Fuel 1968, 47, 103. Kohl, A.; Riesenfeld, F. Gas Purification, 3rd ed.; Gulf Publishing Company: Houston, 1979. LaNauze, R. D.; Jung, K. The Kinetics of Combustion of Petroleum Coke Particles in a Fluidized-Bed Combustor. Nineteenth Eymposium (International) on Combustion, The Combustion Institute, Pittsburgh, PA, 1982; pp 1087-1092. Lee, M. K. A. Phenolic and Polynuclear Aromatic Hydrocarbon Compounds in Aqueous and Tar Emissions from a Coal Gasifi-
cation Pilot Plant. M.S. Thesis, North Carolina State University, Raleigh, 1985. Lester, T. W.; Polavarapu, P.; Merklin, J. F. Formation and Destruction of H2S in the Short Residence Time Pyrolysis of Pulverized Coal and Model Compounds. Fuel 1982,61(6), 493-498. Ma, R. P. Modeling a Fluidized-Bed Coal Gasification Reactor. Ph.D. Dissertation, North Carolina State University, Raleigh, 1988. Ma, R. P.; Felder, R. M.; Ferrell, J. K. Modeling a Pilot-Scale Fluidized Bed Coal Gasification Reactor. Fuel Process. Technol. 1988, in press. Maa, P. S.;Lewis, C. R.; Hamrin, C. E., Jr. Sulphur Transformation and Removal for Western Kentucky Coals. Fuel 1975, 54(1), 62-69. Macke, A.; Bulik, C. Direct Measurement of Char-Particle Temperatures in Fluidized-Bed Combustors. Twentieth Symposium (International) on Combustion, The Combustion Institute, Pittsburgh, PA, 1984; pp 1223-1230. Orbach, 0.;Crowe, C. M. Convergence Promotion in the Simulation of Chemical Processes with Recycle-the Dominant Eigenvalue Method. Can. J. Chem. Eng. 1971,49, 509-513. Purdy, M. J. Operation and Modeling of a Pilot-Scale Fluidized Bed Coal Gasifier. Ph.D. Dissertation, North Carolina State University, Raleigh, 1983. Purdy, M. J.; Felder, R. M.; Ferrell, J. K. Coal Gasification in a Pilot-Scale Fluidized Bed Reactor. 2. Gasification of a New Mexico Subbituminous Coal. Ind. Eng. Chem. Process Des. Deu. 1981, 20(4), 675-682. Purdy, M. J.; Felder, R. M.; Ferrell, J. K. Coal Gasification in a Pilot-Scale Fluidized Bed Reactor. 1. Gasification of a Devolatiliied Bituminous Coal. Ind. Eng. Chem. Process Des. Deu. 1984, 23(2), 287-294. Rhinehart, R. R. Dynamic Modeling and Control of a Pressurized Fluidized Bed Coal Gasification Reactor. Ph.D. Dissertation, North Carolina State University, Raleigh, 1985. Rhinehart, R. R.; Felder, R. M.; Ferrell, J. K. Dynamic Modeling of a Pilot-Scale Fluidized Bed Coal Gasification Reactor. Ind. Eng. Chem. Res. 1987a, 26(4), 738-745. Rhinehart, R. R.; Felder, R. M.; Ferrell, J. K. Coal Gasification in a Pilot-Scale Fluidized Bed Reactor. 3. Gasification of a Texas Lignite. Ind. Eng. Chem. Res. 198713, 26(10), 2048-2057. Roberts, 0. C.; Smith, I. W. Measured and Calculated Burning Histories of Large Carbon Spheres in Oxygen. Combust. Flame 1973, 21(1), 123-127. Robinson, L. Hydrodesulphurization of Char. Fuel 1976, 55(3), 193-201. Ross, I. B.; Patel, M. S.; Davidson, J. F. The Temperature of Burning Carbon Particles in Fluidized Beds. Trans. Inst. Chem. Eng. 1981, 59(2), 83-88. Rudisill, T. S.Sampling and Analysis of Trace Elements in Effluent Streams from a Coal Gasification Pilot Plant. M.S. Thesis, North Carolina State University, Raleigh, 1984. Smith, I. W. The Combustion Rates of Coal Chars: A Review. Nineteenth Symposium (International) on Combustion, The Combustion Institute, Pittsburg, PA, 1982; pp 1057. Solomon, P. R. The Evolution of Pollutants during the Rapid Devolatilization of Coal. NSF/RA-770422, NTIS PB 278496/AS, 1977. Thompson, F. C.; Tilling, N. The Desulfurization of Iron Pyrites. J . SOC.Ind. Trans. 1924, 43(9), 37T-46T. Torrest, R. S.; VanMeurs, P. Laboratory Studies of the Rapid Pyrolysis and Desulphurization of a Texas Lignite. Fuel 1980,59(7), 458-464. Vestal, M. L.; Johnston, W. H. Chemistry and Kinetics of the Hydrodesulfurization of Coal. Prepr. Am. Chem. SOC.,Diu. Fuel Chem. 1970, 14, 1-11. Vestal, M. L.; Day, A. G., 111; Snyderman, J. S.; Fergusson, G. J.; Lampe, F. W. Sulfur Behavior and Sequestering of Sulfur Compounds During Coal Carbonization, Gasification, and Combustion. NTIS P B 211481, 1972. Vestal, M. L.; Day, A. G., 111; Snyderman, J. S.; Fergusson, G. J.; Lampe, F. W.; Essenhigh, R. H.; Johnston, W. H. Kinetic Studies on the Pyrolysis, Desulfurization, and Gasification of Coals with Emphasis on the Non-Isothermal Kinetic Method. NTIS P B 185882, 1970. Vestal, M. L.; Day, A. G., 111; Snyderman, J. S.; Fergusson, G. J.; Lampe, F. W.; Essenhigh, R. H.; Johnston, W. H. Report SRIC 70-14, 1969; Scientific Research Instruments Corporation, Baltimore, MD.
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33
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Received f o r review February 2, 1988 Reuised manuscript receiued September 30, 1988 Accepted October 17, 1988
A Kinetic Model for Leaching Process in Preparation of Raney Nickel Cata1y st Vasant R. Choudhary,* Sudhakar K. Chaudhari, and Ashok N. Gokarn Chemical Engineering Division, National Chemical Laboratory, Pune 41 1 008, India
Kinetics of leaching of aluminum from Raney Ni-A1 (50 wt 9% Ni) alloy with aqueous sodium hydroxide has been studied in an agitated reactor a t a constant alkali concentration in the temperature range 283-343 K using alloy particles of different sizes. The kinetic data could be fitted well t o a rate model, log [ x / ( l - x ) ] = a log (tb) (where x is the fractional leaching; t is the reaction time; and a and fl are the rate parameters). The activation energy for the leaching process has been found t o be 56.6 k J mol-'. h e y nickel is an important hydrogenation catalyst and has been extensively employed both in the industry and laboratory for the hydrogenation of organic compounds. It is mostly prepared by leaching out aluminum from Raney Ni-A1 alloy with aqueous alkali (Freifelder, 1971). The leaching of aluminum from Raney Ni-A1 alloy with aqueous alkali occurs according to the reaction (Mozingo, 1941)
A1 + 3NaOH
-
Na3A103 + Y2H21
(1)
The kinetics of the above process can be followed either by measuring the amount of hydrogen evolved or by determining the amount of aluminum leached out in the course of the reaction. However, in the former method, kinetic analysis is made difficult because of the fact that an appreciable fraction of the hydrogen formed in the leaching process is retained on the solid product(s) due to chemisorption and physical adsorption (Choudhary and Chaudhari, 1983). The kinetics of hydrogen evolution in the leaching of Raney Ni-A1 alloy with alkali has been reported by Choudhary and Chaudhari, (1983) recently. However, no information is available on the kinetics of removal of aluminum from the Raney alloy. Therefore, the present investigation was undertaken with the objective to study the kinetics of leaching of aluminum from the Raney alloy under the conditions employed in the preparation of Raney Ni catalyst and to develop a kinetic model for the leaching process.
Experimental Section Raney Ni-A1 alloy was obtained from Fison, Philadelphia, PA. The chemical composition and physical properties of the alloy are given in Table I. Laboratory reagent grade (BDH) sodium hydroxide was used in the leaching studies. Leaching of aluminum from the alloy with aqueous alkali was carried out in a stirred glass reactor (100 mm in di-
* To whom correspondence should be addressed. 0888-5885/S9/2628-0033$01.50 JO
Table I. Properties of Raney Alloy and Raney Ni Obtained in t h e Leaching Ranev Ni-A1 allov Ranev Ni chemical composition Ni, wt % 50.0 96.0 50.0 4.0 (as AlzO3) Al, wt % ' solid-phase density, g cm-3 4.10 8.10 particle density, g 3.99 3.32 0.027 0.59 porosity pore vol, cm3 g-' 0.007 0.178
ameter and 200 mm in height) provided with a water jacket for maintaining the reaction temperature, a flat six-blade disk turbine stirrer (50 mm in diameter, each blade having a width of 1 2 mm and height of 11 mm), a thermometer for bubbling hydrogen before the reaction, and a glass stopper at the top for introduction the alloy in the reactor. A known volume (900 cm3) of aqueous alkali solution of required concentration was charged into the reactor, and the water from the constant-temperature bath (set a t the desired temperature) was circulated through the reactor jacket and stirring started. After the required temperature was attained, the alkali solution was flushed with hydrogen to remove the dissolved air and to saturate the solution with hydrogen. A known quantity (about 2.0 g) of the Raney alloy was then added to the reactor by removing the stopper. After addition of the alloy, the stopper was replaced. The samples of the reaction mixture were pipeted out a t regular intervals of time and filtered in a Gooch crucible (No. 4), and the filtrate diluted to a known volume and analyzed for aluminum by the EDTA titration method. The change in the volume of the reaction mixture after removing the samples for analysis was very small (less than 5 vol %). The aluminum dissolution rate data were collected under the following experimental conditions: particle size of alloy concn of NaOH temp stirring speed
0 1989 American Chemical Society
45,90, 180 bm 6.25 m m ~ l - c m - ~ 283-343 K 1500 rpm
