November 1950
INDUSTRIAL AND ENGINEERING CHEMISTRY
Graff,R. A., Oil Gas J., 47,99404 (Feb. 17, 1949). Haenisch, E., and Schroeder, M., J. SOC.C h . I d . . 3, 570-71 (1884).
Hartmann, M. L., IND.ENQ.CHEM.,41,2391-5 (1949). Hay, W. H., Chem. Inda., 65, 208-9, 294 (1949). Hewson, G. W., Pearce, 5. L., Pollitt, A., and Reee, R. L.,Soc. Chem. Ind. Proc., Chem. Eng. Group, 15, 67 (1933). Hill, G. R., and Thomas, M. D., Plant PhyebZ., 8, 223-45 (1933).
HiU, G: R., Thomas, M. D., and Abereold, J. N., M6niqj CW. J.,31, NO.4,21-5 (1945). Holmes, J. A., Franklin, E. C., and Gould, R. A., U. 5. Bur. Mines, Bull. 98 (1915). Johnstone, H. F., IND.ENQ.CEEM.,29, 1396 (1937). Johnstone, H. F., Read, H.J., and Blankmeyer, H.C., I W . , 30,101 (1938). (28) Johnstone, H. F., and Singh, A. D., Univ. Ill. Enp. Expt. Sta., Bull. 324 (1940). (29) Katri, Morris, IND.ENQ.CHEM.,41,2450-66 (1949). (30) Katz, Morris, et al., “Effect of Sulphur Dioxide on Vegetation,” Ottawa, National Research Council of Canada, 1939. (31) Lanander, N. E., U. 5. Patent 1,860,585 (May 31, 1932). (32) IW., 1,904,482 (April 18,1933). (33) IW., 1,904,483 (April 18,1933). (34) Ibid., 1,917,725 (July 11,1933). (35) Ibid., 1,962,602 (June 12,1934). (36) Ibid., 1,969,021 (Aug. 7,1934). (37) Lepsoe, R., IND.ENQ.CHEM.,32,910-18 (1940). (38) Lessing, R., J. SOC.Chm. I d . , 57,373-88 (1988). (39) McCabe, L. C., Mader, P. P., McMahon, H. E., and Hamming, w. J.. IND.ENO.CHEM,,41,2486-93 (1949). (40) McCabe, L. C., Rose, A. H., Hamming, W. J., and Vietu, F.H., Ibid., 41,2388-90 (1949). (41) McCallan, 8. E. A.. and Setterstrom. Carl, Contrib. Boyce Thompson Inst., 11,325-30 (1940). (42) McCarthy, F., private communication. (43) Mage, J., and Batta, G., Chimie et induutris, 27,961-75 (1932). (44)Neuberger, H., Mech. Eng.* 70,221 (1948).
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O’Gsra, P. J., IND.ENQ.CEEM.,14,744 (1922). Ontario Research Foundation, “Removal of Sulphur Gases from Smelter Fumes,” Toronto, King’s Printer, 1949. Pacifi C h . Met. I d . , 2, 24 (September 1938). Parker, A.. privata communication. Patty, F. A., “Industrial Hygiene and Toxicology,” Vol. 11, Chap. 18, New York,Interscience Publishers, 1949. Peareon, J. L., Nonhebel, G.,and Ulander, P. H. N., J. Inet. Fuel, 8, 119-52 (1935). Reed, R. M., Petroleum Processing,2, 907-12 (1947). Roberson, A. H., and Marks, G. W., U. 5. Bur. Mines, Rspl. Invest. 3415 (1938). Schrenk, H. H.,Heimann, Harry, Clayton, G. D., Gafafer, W. M., and Wexler. Harry, U. 5. Pub. Health Service, Pub, Health Bull. 306 (1949). btterstrom, Carl, Zimmerman, P. W., and Crocker, W., Con:&.Boyce T h p s u n Inat., 9,179-98 (1938). Snowball, A. F., Con. C h .Processlnds., 31, 1110-14 (1947). Sulphur Patents Limited, “Recovery of Sulphur from Smelter Oases,” Birmingham, England, xjrnoch Press, 1936. Swain, R. E.,C h m . & Msf. E w . , 24,463-5 (1921). Swain, R. E., IND.ENQ.CR~M., 41,2384-8 (1949). Swain, R. E., and Johnson, A. B., I W . , 28,42-7 (1936). Thomas, M. D., and Aberaold, J. N., IND. ENO.CHEM.,ANAL. ED.., 1. 14-15 11829). ~ , ~ ~ Thomas, M. D., Ivie, J, O., Abersold, J. N., and Hendrioks, R.H., Ibid., 15,287-90 (1943). Thomas, M. D., Ivie, J. O., and Fitt, T. C., Ibid., 18, 383-7 ~
.._._.,_
(1946).
Thomas, M. D., and Hill, G. R., Plant Physiol., 12, 309-83 (1937).
U. 8. Bur. Mines, “Minerals Yearbook, Sulfur and Pyrites,” PP. 1122-36,1947.
Weber, O., Oil GaaJ., 45,58 (March 8,1947). Wiedmsnn, H., and Roesner, G., MBtaEloea. Periodic Rev.,1936 (February): U. 5. Bur. Mines, Rep$. Inuest. 3339 (1937). R ~ C E I V EMaroh-27, D 1990. Report 43 from Defenoe Reaearoh Chemical Laboratories,Ottawa, Canada.
Removal of Hydrogen Sulfide from Industrial Gases ROBERT M. REEID AND NORMAN C. UPDEGRAFF’ Gas Processes Division, The Uirdier Corporation, Louisville. Ky.
Removal of hydrogen sulfide fiom natural and manufactured gases has become of great importance in recent years because of more rigid specificatione for pipe-line distribution, higher sulfur content in raw materials, and the depletion rate of mineral sulfur deposits. This paper reviews the various commercial processes used for this purpose. The only dry process in extensive use is the iron oxide process, largely used by utility companies for purification of city gas. The wet processes used fall in the nonregenerative processes, following classifications : including caustic soda, lime slurry, potassium permanganate, and bichromate-zinc sulfate : regenerative nonrecovery processes (the only process in commercial use in this classification is the Seaboard process); regenerative processes with recovery as hydrogen sulfide, including vacuum carbonate, Girbotol, phosphate, Alkazid, and phenolate; and regenerative processes with recovery as sulfur (the principal process used here is the Thylox process; the earlier Ferrox and nickel processes are now becoming obsolete). Various processes are selective in varying degrees for the removal of hydrogen sulfide in the presence of carbon dioxide. Potassium permanganate and bichromate-zinc sulfate processes may be wed for the removal of small quantities of hydrogen sulfide. Manufactured gas may be purified by the w e of iron oxide, Seaboard, vacuum carbonate, and Thylox procegsa, which
are highly seleotive. Natural and refinery gases may be treated with the Oirbotol procees using the tertiary amine, the phosphate process, or the A l W d Dik solution for semhlectiw removal of hydrogen sulfide.
T”
4’ removal of hydrogen sulfide from natural and manufaotured geses is not a new problem; the objectionable properties of this impurity are well known. Hydrogen sulfide not only has an objectionable odor, but also is highly poisonous, being almost as toxic aa the more notorious hydrogen cyanide and five to six times aa toxic as carbon monoxide. In addition, hydrogen sulfide is oorrosive to pipe lines, compressors, and combustion equipment. When burned it produces sulfur dioxide, which is also obnoxious and oorrosive. Lastly, its presence in synthesis gases may result in catalyst poisoning and product contrtmination. Although an old problem, the importance of hydrogen sulfide removal has increased considerably in recent years, owing to several factors. Probably the most significant of these is the increased usage of raw materials of higher sulfur content. These include natural gaa, crude oil, and coal, from which most of the industrial gams considered here are produced.
INDUSTRIAL AND ENGINEERING CHEMISTRY
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In addition to the removal of hydrogen sulfide, the problmi of its disposal must be considered. The common practice in the past has been either to vent the unwanted gas to the atmosphere or to burn it in a flare or under a boiler. Venting hydrogen sulfide directly is hazardous to human beings and livestock, while burning it produces sulfur dioxide which is harmful to vegetation and obnoxious, although not as t80xicas hydrogen sulfide. Recent legislation concerning atmospheric pollution also dictat,es that these gases be not released to the air in rertain localities.
1 z
Figure 1.
WET PROCESSES The so-called wet processes utilize a solution containing a reagent that combines with hydrogen sulfide chemically to remove it from the gas stream. These processes all employ some type of contactor, such as a tray or packed tower, in which the gas to be treated passes upward countercurrent to the liquid flow. As the basic differences in the processes lie in the disposition of the hydrogen sulfide-laden solution, the processes have been grouped by their similarity in this respect. NONREGENERATIVE PROCESSES
t
AIR BLOWER
Vol. 42, No. 11
SOLUTION PUMP
Flow Diagram of Seaboard Process
Finally, the depletion rate of our mineral sulfur deposits has imde the recovery of sulfur from various sources more attractive economically as well as desirable from a conservation viewpoint. Thus, a formerly wasted material resource is now becoming a valuable by-product of purifying operations. Although this paper i8 a review of the various chemical processes used for the removal of hydrogen sulfide from natural and manufactured gases, partirular emphasis is placed on processes that are readily adaptable to the ultimate recovery of hydrogen sulfide as elemental sulfur. There are two general classifications of purification processes used in the industry, the dry processes and the wet processes. Dry processes include the use of iron oxide (9, 17’) and activated carbon. The iron oxide process has been in almost universal use for many years for treating coal gas and carbureted water gas for city distribution. Activated carbon has not been used in this country on a commercial scale. These processes are well covered by Sands and Schmidt (83). In this paper the wet processes have been further divided into four groups: the nonregenerative procc~ssesin which the hydrogen sulfide reacts with some chemical reagent and the product is discarded; the regenerative processes in which the absorbing solution is recycled, but the hydrogen sulfide is necessarily discarded; the regenerative processes in which the hydrogen sulfide is recovered as a gas; and the regenerative processes in which the hydrogen sulfide is recovered as elemental sulfur. A brief discussion is also included on processes for the selective removal of hvdrogen sulfide in the presence of carbon dioxide.
The first group to be considered is the nonregenerative processes, in which the reagent employed reacts with hydrogen sulfide to remove it from the gas stream. The reaction product is discarded periodically and replaced with fresh solution. In general, these processes are not economical for large quantities of hydrogen sulfide, as the cost of replacing the reagent becomes excessive. They do have their use when the quantity of hydrogen sulfide is small and for cleaning up residual hydrogen sulfide after the bulk has been removed by some other process. The most commonly used process in this category employs a solution of caustic soda. Generally, a large quantity of solution is made up and the gas is allowed to bubble through it or the solution is recycled continuously over a contacting tower. When most of the sodium hydroxide has been converted to sodium sulfide, the spent solution is discarded and replaced with a fresh charge. In some installations hydrogen sulfide is removed from gases with caustic soda solution in two stages, the caustic soda in the first stage being converted to sodium hydrosulfide, which is then concentrated and sold. Some purification plants employ the lime slurry process in which a suspension of calcium hydroxide is used. Difficulties are experienced in this process with plugging of the equipment, however, and it is not used as extensively as the caustic soda process. Both of these reagents absorb carbon dioxide as well as hydrogen sulfide from the gas. Two other processes that fall in the nonregenerative classification may be used for removing smalI amounts of hydrogen sulfide from gases, but they do not remove carbon dioxide. One process, employing potassium permanganate solution, is widely used for purifying carbon dioxide gas before liquefaction and production of dry ice. As the quantities of hydrogen sulfide present are very small, the reagent cost is negligible. The other process utilizes a buffered solution of sodium bichromate and zinc sulfate (16). Although this process is somewhat more economical than potassium permanganate for hydrogen sulfide removal generally, it is not as effective as permanganate for removing some of the other impurities found in commercial carbon dioxide. REGENERATIVE PROCESSES
Because of the excessive replacement cost of the reagents used in the nonregenerative processes, and the problem of disposal of the products, it is desirable to use an absorbant which may be regenerated and recycled whenever appreciable quantities of hydrogen sulfide are involved. Several successful processes have been developed for this purpose, which accomplish regeneration by steam or air stripping. The one commercial process which employs air stripping does not permit recovery of the hydrogen sulfide, but several successful processes employing steam stripping recover and deliver hydrogen sulfide as a gas which may be converted to elemental sulfur or sulfuric acid. There is one process employii Ig air which produces precipitated sulfur directly. REGENERATIVE, NONRECOVERY PROCESS
The Seaboard process (9, 10, 81),developed by the Kopperj Company in 1920, falls in the classification of a regenerative process without. recovery of the hydrogen sulfide removed. It is
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INDUSTRIAL AND ENGINEERING CHEMISTRY
apparently the first liquid regenerative process to be used on an industrial scale and is in use today in a number of natural and manufactured gas plants and a t least one ammonia synthesis plant. This process employs ~ t i iaqueous solution containing 3.0 to 3.5% sodium carbonate whiah contacts the hydrogen sulfidebearing gas in a bubble tray or packed tower as shown in Figure 1. The solution removes hydrogen cyanide at the same time when this impurity is present. The products of the reaction between hydrogen sulfide and sodium carbonate are sodium bicarbonate and sodium hydroaulfide. This foul solution is pumped from the bottom of the scrubbing tower to a second tower where the solution is reactivated by blowing air through it, which reverses the above reaction. The released hydrogen sulfide passes out of the top of the tower with the air and is lost to the atmosphere. Some plants have utilized this exhaust air for combustion air in boilers, which not only takes advantage of the heat of combustion of the hydrogen sulfide, but also exhausts the sulfur as sulfur dioxide which is somewhat less obnoxious than hydrogen sulfide. One plant treating natural gas proposed use of this air for the partial combustion of another stream of hydrogen sulfide gas in a modified Claus sulfur recovery plant. This would have affected the recovery of hydrogen sulfide from the Seaboard process, but such a combination of plants is rarely found. The major advantages of the Seaboard process are the inexpensive reagent used and the small space required in comparison with iron oxide boxes. As the air blowing produces some thiosulfate (and thiocyanate), it is necessary to add fresh soda ash to the solution regularly and discard part of the solution, to maintain the proper concentration and composition. However, the low cost of sodium carbonate makes this relatively inexpensive. A t8ypicalSeaboard installation may be seen in Figure 2. The major disadvantage of the Seaboard process is the loss of hydrogen sulfide with accompanying atmospheric pollution. In addition, sodium carbonate is not an active absorbant and the removal of hydrogen sulfide from the treated gas is not complete. Because of these factors, several Seaboard plants have been converted to other more efficient processes. REGENERATIVE PROCESSES WITH RECOVERY AS HYDROGEN SULFIDE
All the previously mentioned processes have the common disadvantage that the hydrogen sulfide may not be economically recovered or disposed of in a practical manner. Various groups working on this problem both hcre and abroad developed processes in the early 1930’s which employed steam regeneration and delivered concentrated hydrogen sulfide gas from the solution reactivator. The f i s t was the Girbotol process, using aliphatic amines as absorbants for the hydrogen sulfide. The first patent on this process was issued to Bottoms ( 4 ) of The Girdler Corporation in 1930. In 1934 Rosenstein and Kramer (88)of the Shell Development Company obtained a patent on the use of potassium phosphate for this purpose. This process is known as the Shell phosphate process. Meanwhile in Germany, Baehr (%)and his colleagues were working with solutions containing alkali metal salts of amino acids such as glycine and alanine. Their process, known as the Alkazid process, was patented in this country in 1935. The phenolate process, which uses a solution of sodium phenolate, was patented by Shaw (SO) of the Koppers Company in 1930. More recently Koppers has developed the vacuum carbonate process (IS,is,SI), which is a modification of the Seaboard process described above and which is described first, so that it may be compared with the earlier process. The major differencesin these several processes are in the solutions used, as all employ the same basic flow scheme.
As may be seen from Figure 3, the hydrogen sulfide-bearing glty enters the base of the contacting tower or absorber and flows up
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COURTESY YOPPERS COMPANV
Figure 2. Seaboard Process Installation
through the tower countercurrent to the absorbing solution. The urified gas passes out a t the top of the tower. The hydrogen sulfi8ebearing solution, called variously rich solution, foul solution, or fat solution, asses out of the bottom of the absorber, may or may not pass ttrough heat exchangers as shown, and flows to the reactivator. The absorber and reactivator are either packed or bubble tray towers. In the reactivator the downflowmg solution is heated and stripped of h drogen suifide by ascending steam generated by boiling the soGtion in a reboiler a t the base of the tower. The heat for this reboiler is supplied by steam, hot oil, direct firing, or other means. In some processes live steam is introduced directly into the regenerator tower. The hydrogen sulfide and steam pass from the top of the tower into a condenser where the steam is condensed, removed from the gas, and returned to the system or discarded. The hydrogen sulfide is then available for further use. The solution at the base of the reactivator, which has been essentially stripped of hydrogen sulfide, is recycled through the heat exchanger, further cooled with water or air, and returned to the absorber, Vacuum Carbonate Process (9, IO,lI, id, Si). A major objection to the Seaboard process is the loss of hydrogen sulfide. The Koppers Company solved this problem by employing stesni stripping of the sodium carbonate solution instead of using air. The flow plan of this process is essentially the same as is shown in Figure 3. As the steam requirement is high when operation# are carried out a t atmospheric pressure, the Koppera engineer8 placed the reactivation tower under about 25 inches of mercury vacuum. This expedient not only reduces the amount of steam required, but permits the use of low pressure exhaust steam in the reboiler for reactivation. The reactivation is more complete in this process than in the Seaboard process and lower solution circulation rates are required for the removal of a given quantity of hydrogen sulfide. The absence of oxygen in the reactivator eliminates the build-up of thiosulfates (and thiocyanates) in the solution, except when oxygen is present in the gas being purified. This improved process, known as the vacuum carbonate process or the vacuum activation process, is in use in two plants for removing hydrogen sulfide from coke oven gas, one located at Kearny, N. J., and the other at Pittsburgh (Neville Island), Pa. Both plants are used in conjunction with units to manufacture
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INDUSTRIAL AND ENGINEERING CHEMISTRY
sulfuric acid from the recovered hydrogen sulfide. The combined hydrogen sulfide-removal capacities of these two plants amounts to 27,000 pounds per day. Hydrogen cyanide is also removed in these plants and may be recovered separately as sodium cyanide or anhydrous hydrogen cyanide.
Vol. 42, No. 11
from the amine solutions during regeneration enables them to remove hydrogen sulfide completely from gases, inasmuch as the purified gas contacts the regenerated solution which has essentially no vapor pressure of hydrogen sulfide. The Girbotol process in its various modifications gives consistent gas purification to
PURIFIED
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Figure 3. Basic Flow Diagram Girbotol Process (3, 4,22, 93, 95, 34), The Girbotol process, developed originally by The Girdler Corporation in 1930, has become the process most widely used at the present time for the removal of hydrogen sulfide from natural and refinery gases; thcrc are many more installations in these fields than all the other processes combined. The amines used commercially for hydrogen aulfide removal are mono-, di-, and triethanolamine. Triethanolamine was the first to be employed, because it was the first to become available in commercial quantities. It has been largely replitced by the more reactive monoethanolamine for purification of natural gas, escept in special cases where selective hydrogen sulfide removal is required. Diethanolamine is being widely employed for the removal of hydrogen sulfide from refinery gases, as it has been found to be inert toward carbonyl sulfide, which ie usually present in refinery gases, and which will react with monoetlianolt~mine to form diethanolurea, a stable compound not readily dissociated by heat. The ethanolamines are generally utilized in aqueous solution, although other solvents have been employed for special purposes. The use of amines for hydrogen sulfide removal in a regenerative process is based upon the fact that a t low temperatures the amines, like ammonia, form salts with hydrogen sulfide which dissociate readily on heating. During regeneration, the volatile hydrogen sulfide separates from the relatively nonvolatile amine. Steam generated by boiling the amine solution is commonly employed to strip the hydrogen sulfide from it and regenerate it for further hydrogen sulfide absorption. A comparatively small amount of steam is required to strip hydrogen sulfide completely from amine solutions (to a residual hydrogen sulfide content of a few grains per gallon). The complete removal of hydrogen sulfide
a degree comparable with the dry iron oside box process and the nonregenerative caustic sods, process-namely, to a negative lead acetate test. The high degree of purification obtainable with amine solutions, ttogether with the relatively low steam requirement for regeneration, has been responsible for their widespread adoption for hydrogen sulfide removal. A disadvantage of the Girbotol process has been the relatively high cost of the ethanolamines as compared with other absorbants, necessitating special precautions to avoid mechanical losses and vaporization and neutralization or oxidation losses The many impurities present in manufactured gases-tars, cyanogen, and oxygen-have discouraged the commercial use of amine solutions for purifying such gases, although pilot plant operations have indicated that suitable pretreatment of the gases may overcome these difficulties. Considerablc difficulties have been encountered in certain installations using amines for removing hydrogen sulfide from gases due to the corrosion encountered in the steel equipment. Although steel equipment has been generally suitable for this service, in a number of instances, particularly with gases containing considerable percentages of carbon dioxide as well its hydrogen sulfide, severe corrosion has been encountered, ncoessitating the use of corrosion-rcsistant materials. A large number of improvements in the use of amines for gaa purification have been made since 1930 and some of these are in commercial use a t present. A patent issued to Hutchinson (fa)in 1939 cover8 the use of certain combinations of amines and polyhydric alcohols such aa diethylene glycol to remove hydrogen sulfide and water vapor simultaneously from gases. Hutchinson’s combinations and other combinations have been found effective
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I N D U S T R I A L A N D E N G I N E E R I N G CHEMISTRY
for purifying natural gas for pipe-line transmission, a t the same time dehydrating it sufficiently to avoid difficulties due to hydro-
of the residual hydro en sulfide from the gaa stream. Both solution streams flow to &e base of the absorber.
carbon hydrates in the transmission lines, Solutions using monoethanolamine and diethylene glycol are employed by The Fluor Corporation in its glycol-amine process. However, becauae ethanolamines are equal in hygroscopicity to diethylene glycol, a similar result may be obtained with solutions containing ethanolamines alone, or ethanolamines with &or proportions of glycol8 and other materials. Another improvement in general commercial use, based upon a patent issued to Reed (84)in 1946, covers the use. of superatmospheric pressure (15 to 70 pounds per square inch gage) for the regeneration of monoethanolamine solutions. It was found that the regeneration of monoethanolamine solutions containing both hydrogen sulfide and carbon dioxide (or carbon dioxide alone) is more complete a t the temperatures (280' to 300' F.) obtainable under increased pressures than a t atmospheric preesure (Z20' F.). The increased dissociation of monoethsnolamhe carbonate at the higher temperatures more than offsets the lowered efficiency of the stripping steam. A number of plants purifying gases containing both hydrogcn sulfide and carbon dioxide are operating u n d a the conditions disclosed in this patent. In order to obtain more efficient use of stripping steam, the basic flow scheme haR been modified in two Girbotol plants to the "split flow" shown in Figure 4.
This split flow differa from the two-stage absorption and regeneration scheme of Shoeld (31)applied to the phenolate proceea, for in that procesa all the tich solution entored the top of the rertctivator, or else the two stages were kept entirely Beparate except for common w e of the stripping steam. Amine solutions, particularly aqueous diethanolsmine solutions, are also in general use for the removal of hydrogen sulfide from liquid hydrocarbons. An installation of the Girbotol process for purifying natural gas in connection with a natural gasoline plant is sl~ownin Figure 5. Phosphate Process (7,19, .W, $8). The Shell phosphate process uses the same general flow scheme aa the other regenerative proce8888, but employs a solution of tripot3ssium phosphate. For maximum efficiency in hydrogen sulfide removal from gan streams a aplit solution flow scheme aa shown in Figure 6 is recommended. This is different in some respects from the Girbotol, split-flow schemc. As may be seen in Figure 6, the sour gss enters tho bottom of thtr contacting tower and psssea upward countercurrent to the solution flow. The semilean solution is introduced into the middle of the column so that it may pick up the bulk of the hydrogen sulfide. The h a 1 clean-up of the as is accomplished in the top half of the column by contact with t a n solution which is more completely
--e
AESORBL R
Figure 4.
REACTIVATOR
REBOILLR
Flow Diagram of Split-Flow Girbotol Process
A portion of the rich solution from the absorber flows to the top of the reactivator, passing psrt-way down it in countercurrent flow to stripping stearn (generated b boilin solution in the reboiler), and then flows back through t e a t ex&angers and coolers to a mid-point of the absorber. This semilean solution can absorb much hydrogen sulfide, but contains enough as it enters the absorber $0 that it, cannot remove all the hydrogen sulfide from the gae. The bel:mce of the rich solution from the absorber flows to the mid-point of the reactivator, down to the base of the tower, and through the rehoiler, being complete1 stripped of hydrogen sulfide. This lean solution flows througi heat exchangers and coolers to the top of the absorber, and dects complete removal
stripped of hydrogen sulfide than the somilemi solution. Theoretically, the hydro en sulfide content of this lean solution is the same aa the semiyean solution b the time it reaches the tray where the latter is introduced. &he combined solutions are pumped through a heat exchanger to the top of the regeneration column, where the hydrogen sulfide is stripped with steam. Approximately half-way down the tower the total solution is diverted b a catch tray into a reconcentrator which acts UB a p ' i m a y retoiler. his partially reactivated solution is the semiean 80 ution referred to above. Part of this solution is directed back through the heat exchanger and a solution cooler, from which i t ia pumped back to the center of the sbnorber column.
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INDUSTRIAL AND ENGINEERING CHEMISTRY
Vol. 42, No. 11 The balance of this solution is returned to the regenerator for further stripping, passes through the reboiler, and after being cooled is pumped back to the top of the absorber as lean solution. The overhead gas from the regenerator passes through a condenser where the water vapor is removed and returned to the system. The hydrogen sulfide gm from the regenerator is available in concentrated form for further processing, such as the production of sulfur or sulfuric acid,
Figure 5.
Girbotol Process Installation
figure 6. flow Diagram of Split-FlowPhosphate Process
The main disadvantage of the phosphate process is that it requires somewhat more steam for reactivation than the Girbotol procesfi. Offsetting this somewhat is the lower volatility of the absorbant, which results in a lower solution make-up and permits the use of live steam for stripping in place of the reboiler if so desired. Another advantage of this process is that some selectivity for absorbing hydrogen sulfide in the presence of carbon dioxide may be obtained by proper design. This is discussed below. As in the case of Girbotol, the phosphate process is also used for treating liquid hydrocarbons. Alkazid Process (I, 2, 33). The Alkazid process, which was developed a n d used i n
November 1950
INDUSTRIAL A N D ENGINEERING CHEMISTRY
I
PURIFIED OAS
ACTIVATED SOLUTION
ICsLpnRATDR
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’\\PRODUCT SULFUR
S LUTION
RETURN COMPRESSEO *---
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2215
have almost all been converted to the newer Thylox process (6, 9-11, 16), which is more economical and produces a larger yield of precipitated sulfur. The Thylox process differs from the original Ferrox and nickel processes in that it uses an essentially neutral solution of a sodium thioarsenate instead of an alkaline soda ash solution as the absorbant for hydrogen sulfide. Because of this difference in alkalinity, the amount of sodium thiosulfate produced by the undesired side reaction is greatly reduced. A flow diagram of the Thylox system ie shown in Figure 7.
The gas to be treated enters the base of the absorber, passes upward countercurrent to the Thylox solution, and leaves at the top ABSORBER SOLUTION SOLUTION THIONILER of the tower. The foul solution is pumped PUMP HEATER through a solution heater to the base of the Figure 7. Flow Diagram of Thylox Procees aerating tower or “thionizer” which differs in several respects from reactivators described previously, in that the tower is completely flooded, the solution flow is upward, and it is surGermany, employs a flow diagram similar to the processes premounted by a sulfur se arator. This vessel may be over 100 viously described. The three absorbants employed are varied feet high and in some pgnts two or more such towers are used according to the usage. These aredesignated as Alkazid solutions, in series. Compressed air introduced a t the base of the tower M, Dik, and S. bubbles up through the solution. The presence of arsenic compounds catalyzes the oxidation of the absorbed hydroM is sodium alanine, which is a primary amine and is used for gen sulfide to sulfur which is carried u by the air and rises to the the removal of h drogen sulfide or carbon dioxide or both from top surface as a sulfur-bearing froth. %he solution level is held a gas streams. Dic originally was the potassium salt of diethyllittle below a dam in the sulfur separator, and the sulfur-bearing glycine, but the potassium salt of dimethylglycine was substifroth overflows into a slurry tank from which it is fed to a contuted, as it was more readily available. This solution is used for tinuous filter. The reactivated solution returns to the absorber. the selective removal of hydrogen sulfidein the presence of carbon dioxide or when small uantities of carbon disulfide or hydrogen The sulfur formed in this process is in the form of a paste concyanide are present. Saution S was developed for the purification sisting of approximately 50% finely divided sulfur and 50% water of coke oven gas and is reported to be a solution of sodium plus small quantities of impurities such as arsenic and other phenolate. soluble salts. Because of these impurities, the market for this The Alkazid process has not been used in this country, as those form of sulfur is limited to agricultural fungicides and the like, developed here for the same purposes have been satisfactory. unless it is further purified by distillation. In one plant the sulfur One of the major problems connected with this process has been is melted in an autoclave and run on to a water-cooled steel concorrosion from the amino acid solutions. Nevertheless, the procAIR INLET
ess was used extensively before the war in Germany when about 1,O00,OOO cubic feet per day of hydrogen sulfide were being removed and about 30,000metrir tons of sulfur were being recovered from this annually. Phenolate Process (6, 90). The phenolate process, developed by the Koppers Company, used a solution of sodium phenolate in a flow acheme similar to the others. Several operating difficulties were encountered in the few plants that were erected and the majority of them were converted to other processes. REGENERATIVE PROCESSES WITH RECOVERY AS SULFUR
Processeshave been discussed above which are not economically adaptable to the recovery of sulfur or in which hydrogen sulfide is recovered as such in concentrated form. For economic as well as antipollution reasons, a process which in itself oxidizes hydrogen sulfide to elemental sulfur would seem desirable. Considerable work has been done in this country and Germany, with the result that several workable processes have been developed. The original processes used in this country to recover precipitated sulfur are known as the Ferrox (9, 16) and the nickel (8, 9, 18) processes. In both processes the hydrogen sulfide is washed out of the gas with a dilute soda ash solution, after which the solution is oxidized by aeration in the presence of a catalyst. Oxidation converts the dissolved hydrogen sulfide chiefly to precipihted sulfur, but partially to sodium thiosulfate, and the solution is thereby regenerated so that it can again be used to scrub hydrogen sulfide from the gas. It is essential that some oxidation catalyst be present in the solution, for which purpose iron oxide or other iron compound is used in the Ferrox process, and some nickel compound, usually nickel sulfate, is used in the nickel procem. The original installationa of the Ferrox and nickel processes
OWRTE8Y KWPLOI) OOMPANV
Figure 8. Thylox Process Installation
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INDUSTRIAL AND ENGINEERING CHEMISTRY
veyer belt wliere it is solidified for convenience in handling. Others cast it in briquets for furthcr handling. If dried carefully to avoid melting, a fine free-flowingpowdered sulfur can be produced Any hydrogen cyanide prcsent in the original gas stream is convwted to sodium thiocyanate, a material that as yet hits found but limited usefulness The major disadvantages of the Thylox process are incomplete hydrogen sulfide removal, high solution replacement, and poor quality sulfur. In general, these plants have been designed for only 90 to 96% removal of hydrogcn sulfide, although it is claimed that lead acetate purity may be attained with more rigorous design. About 10 to 15% of the sulfur absorbed forms thiosulfate which builds up 111 the solution and conwmes soda ash. Thus part of the solution must be withdrawn fiom the plant continuously and either discarded or treated to recover the arsenic. Camprtred with thiosulfate formation of 30 to 40% for the Ferros and nickel pr.ocrsses, the solution replacement is less serious in the Thylox process. The impurities in the sulkur have been discumcd above The Thylox process is in successful use in at least ten eommercirtl installatioire in this country with a combirrcd capacity of 88,OOO pounds per (lay of hydrogen sulfide. A typical Thylou installation is slion n in Figure 8. Other processcs similar to the Thylox process have been used in Europe, in which ammoniacal suspensions are used instead of thioaraenate salts. In these processes, such as the Cluud process (D), a closed aerating systeni is uged to recover the ammonia vapor that would otherwise be lobt to the system. This is claimed to bo more economical, owing to the lower equivalent weight of ammonia. For economic reasons also, the European installations geriernlly distill the product sulfur and market it as the pure material.
SELECTIVE PROCESSESFOR REMOVAL OF HYDROGEN SULFIDE IN PRESENCE OF CARBON DIOXIDE As most of the processes for removing hydrogen sulfide from industrial gases are based on the acidic nature of hydrogen sulfide, it is understandable that carbon dioside, another acidic gas, will bo removed as well. In some cases this is desirable, but in general it would be more economical not to remove the carbon diouide. In the f i s t place, carbon dioxide is not objectionablc in most gascq as far ah toxicity and corrosion are concerned. Secondly, the investment and operating costs of a treating plant will be higher rf the solution circulation rate must be increased to take care of the carbon dioxide removed with the hydrogen sulfide. Finally, in city distribution system using manufactuwd gas, the heat value and specific gravity of the gas may be changed by the removal of carbon dioxide. To avoid this uneconomical removal of carbon dioxide, it is frequently desirabic to use a process that will remove hydrogen sulfide selectively. The choice of such a process will depend largely on the type of gas to be treated, particularly with reEWCt to the other impurities and constituents present. Two processes are used for the fbal purification of carbon dioxide gases prior to liquefaction and dry ice production. The treating agents used are potassium permanganate and bichromate-zinc sulfate. Both are nonregenerative solutione which are discarded when spent. These are highly selective processes, but are economical only for removing very small quantities of hydrogen sulfide. In the manufactured gas ficld, carbon dioxide is &?enerally present in coke oven gas, water gas, and producer gas to a greater extent than hydrogen sulfide. The processes used for purification of these gases are iron oside boxes, Seaboard, vacuum carbonate, and Thylox. These generally are selective and are well adapted for the purpose. Iron odde boxes do not pick up carbon dioxide. Although sodium carbonate solutions are used in the dry ice industry for carbon dioxide absorption, the selectivity in the case of the Seaboard and vacuum carbonate processes is largely a matter of hydrogen sulfide’s greater solubility in water and correspondingly
Vol. 42, No. 11
faster reaction rate as compared to carbon dioxide. The contact time is too brief in these installations to permit the absorption of any appreciable amount of carbon dioxide. The thioarsenate eolution in the Thylox process is essentially neutral and does not react with carbon dioxide. The processes generally used for purifying natural and refinery gases can be made selective to some extent by proper choice of solution and contact time. In general, this selectivity is due to a faster rate of reaction or solution of hydrogen sulfide as against carbon dioxide. In the Girbotol process selertivity is accomplished by the use of a tertiary amine, such as triethanolamine, which reacts more readily with hydrogen sulfide. Bottoms ( 3 )has shown that carbon dioxide cannot react directly with the tertiary amine, but must be absorbed in water first as carbonic acid. Hydrogen sulfide therefore reacts more rapidly, as it will combine directly. Hydrogen sulfide cannot be completely removed without the absorption of some carbon dioyide in the gcneral case. However, the majoritv of the carbon dioxide will remain in the treated gas. The phosphate process also attains selectivity to a ccrthiii extent, owing to a faster reaction rate with hydrogen sulfide. Frolov ( 7 ) has poindd out that if an acid gas containing equal amounta of hydrogen sulfide and carbon dioxide is passed over a phosphate solution, very little hydrogen sulfide will be absorbed when equilibrium is reached, as carbonic acid is the stronger acid of the two. However, because of the relatively short period of contact time encountered in commercial operation, hydrogen sulfidc is preferentially absorbed, and gases containing a 10 to 15 to 1 ratio of carbon dioxide to hydrogen sulfide may be treated economically for hydrogen sulfide removal. At a 10 to 1 ratio of carbon dioxide to hydrogen sulfide, for example, the hydrogen sulfide concentration in the recovered acid gas will be about 35% Thus, this process will not remove hydrogen sulfide to the exclusion of carbon dioxide, but is preferential to a certain estent, The Alkazid Dik solution ( 1 ) was developed for the selective removal of hydrogen sulfide in the presence of carbon dioxide Bachr has shown that this selectivity is due to a faster rate of ahsorption of hydrogen sulfide than carbon dioxide. The selectivity in this case is also due to a tertiary amine group Thus certain processes may be used for removing hydrogen sulfide completely in the presence of carbon dioside, whereas others will preferentially absorb hydrogen sulfide, leaving the bulk of the carbon dioxide in the treated gas. The importance of this selectivity varies considerably with the application and is closely tied in with the economics involved. It is conceivable that in some instances more savings would result in total removal of both hvdrogen sulfide and carbon dioxide than in hydrogen sulfide removal alone. In general, however, if carbon dioxide removal is not desired it is feasible to employ a preferential procwr for hydrogen sulfide removal.
ACKNOWLEDGMENT The authors would like to acknowledge the assistance given by H. A. Gollmar of the Koppers Company and B. A. Frolov of the Shell Development Company in supplying information for this papcr
LITERATURE CITED (1) Baehr, Hans, Proc. Am. Petroleum Inst., 8th Mid-YeUr Meeting. Sect. I I I , 19,37 (1938). ( 2 ) Baehr, Hans, U. S. Patent 1,990,217 (1935). (3) Bottoms, R. R., “Organic Amines, Girbotol Process,” pp. 181015, “The Science of Petroleum,” by Dunstan, Nash, Tizard, and Brooks, London, Oxford University Press, 1938. (4) Bottoms, R. R., U. S. Patent 1,783,901 (1930), reissued as Re. 18,958 (1933). ( 5 ) Carviin, G. M., Proc. Am, Petroleum Inst., 8th Mid-Yeur Meat ing, Sect. I I I , 19,23 (1938). (6) Farquhar, N. G . , Chem. & Met. Eng., 51, No. 7, 94 (1944). (7) Frolov, B. A., prlvate communication. (8) Gluud, W., U. S. Patent 1,597,964 (1926).
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INDUSTRIAL AND ENGINEERING CHEMISTRY
(9) Gollmar, H. A., Chap. 25 of “Chemistry of Coal Utilization,” New York, edited by H. H. Lowry, John Wiley & Sons, 1946. (10) Gollmar, H. A., private communication. (11) G o b a r , H. A., U. 8. Patent 1,719,762 (1929). (12) Ibid.. 2,379,076 (1945). (13) Zbid., 2,464,804 (1945). (14) Hutchinson, A. J. L., Ibid.. 2,177,068 (1939). (16) Jacobson, D. L., Zbid., 1,719,180 (1929). (16) Mann, M. D., Jr., and Lebo, R. B., Ibid., 1,525,140 (Feb. 3, 1926). (17) Marshall, J. R.. Uas World (Coking Seotion), 129, 106 (1948). (18) Morgan, R. A., et al., U. 6.Patent 1,732,905 (1929). (19) Mullen, J. M., Refiner Natural Gasoline Mfr., 18, No. 4, 159 (1939). (20) Powell, A. R., IND. ENQ.CHEM.,31,789-95 (1939). (21) Powell, A. R., U. 9.Patent 2,242,323 (1941). (22) Reed, R.M., Oil d Qas J . , 44, 219-26 (1946).
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(23) Reed, R. M., Petroleum Processing, 2, 907 (1947). (24) Reed, R. M., U. 8.Patent 2,399,142 (1945). (25) Read, R. M., and Wood, W. R., Trans. Am. Inst. Chem. Engrs., 37,363 (1941). (26) Reitmeier, R. E., U. 8. Patent 2,405,672 (Aug. 13, 1946). (27) Rombaugh, T. W., Proc. Am. Petroleum Inst.. 8th Mid-Year Meeting, Sect. IZI, 19, 47 (1938). (28) Rosenatein, L., and Kramer, G. A., U. 8.Patent 1,945,163 11934). (29) Sanda, A. E.,and Sohmidt, L. D., IND. ENG.CHEM.,42, 2277 (1950). (30) Shaw, J. A., U. S.Patent 2,098,124 (1936). (31) Shoeld, Mark, Ibid., 1,971,798 (1934). (32) Spew, F. W . , Jr., Proc. Am. Qae Aasoc., 1921, 282-364. (33) Technicel Oil Mimion Film, Reel 132. (34) Wood, W. R., and Storrs, B. D., Proc. Am. PefroleumInat., 8th Mid-Year Meeting, Sect. IZZ, 19,34-6 (1938). R B ~ c ~ Msroh v~~D 27, 1950.
RECOVERY OF SULFUR FROM SYNTHESIS GAS A. E. SANDS AND L. D.SCHMIDT U. 8. Bureau of Mines, Synthesis Gar, Production Branch, Morgantown, W. Va.
The United States Bureau of Mines at ita Morgentown, W. Va., station, in cooperation with West Virginia University, is conducting reaearch and development work on a laboratory and pilot plant Male on the problem of producing synthesis gae directly from raw coal by a continuous, low cost process. An essential part of this work is the atudy of the gam purification neceaary to meet the rigorous .tandads (23)required to render the gas suitable for the synthesis of liquid fuels by the Fischer-Tropsch process.
Although the purification of synthesi. gas may result in the removal of several different impurities, the complete removal of sulfur is generally considered to be the most important problem. While this involves removal of both organic sulfur and hydrogen sulfide, this paper ie largely devoted to discussion of the removal of hydrogen sulfide, with special reference to sulfur recovery. For a more extensive review of sulfur compounds in gas and their removal, refer to the excellent work of Gollmar (221.
T
supplying thw importpnt commodity, when natural reserves become exhausted, is of the highest importance. The recovery of sulfur from manufactured gas in any plant is not entirely a matter of economics. Several plants have found it necessary to reduce the amount of air pollution which results from purification procesaes that vent hydrogen sulfide to the a t m o s phere. These plants have turned to sulfur recovery as a means of disposal of hydrogen sulfide.
HE recovery of sulfur from synthesis gas made from coal is a matter of interest not only to the large synthetic liquid fuel plants of the future but to present and future plants that are built to produce ammonia, alcohols, and other chemicals from coal through the medium of synthesis gas. This paper discusaaa the factors that differentiate synthesis gas purification from other gas purification practice. The relation between sulfur content of the coal used for synthesis gas production and the cost of synthesis gas purification is explored through cost estimates for gas purification and sulfur recovery. These estimates, which are not to be considered accurate and final, were p r e p d as a baeis for discueaion and for future revised cost estimates of a more aaourate nature. It is believed that the recovery of sulfur in connection with the purification of synthesis gas will yield important credits to the cost of gas purification. Cost estimatw indicate that the cost of removing sulfur doea not increase in proportion to the concentration of sulfur in the gre. On the other hand, the net credits resulting from sulfur r e m e r y do increase in proportion to the sulfur content. If this relationship between gas purification costs and sulfur credits is validated by further experimental work, it would mean that the use of higher sulfur coals for synthesis gas production; rather than being objectionable, would be dasirable. Growing concern has been expressed with respect to the extent of the nation’s sulfur reserves. At the current rate of consumption the amount of natural sulfur known to exist in the United States would last for only 30 years (19). I n 1947, production of sulfur amounted to 4,441,214 long tons (18). Because sulfur is so essnntial to the national welfare, in peace or in WW, a means of
PROCESSES FOR HYDROGEN SULFIDE REMOVAL AND SULF’UR RECOVERY Processes for the removal of hydrogen sulfide from gas may be classified as “wet” and “dry” processes and may be further described according to their ability to permit sulfur recovery in one form or another. The wet processes-wherein hydrogen sulfide is removed by scrubbing-are described in another paper in this symposium (88). The principal dry processes are the dry box (iron oxide) process and the activated carbon catalytic proceea. Both these processes offer possibility of sulfur recovery. DRY BOX (IRON OXIDD
Hydrated iron oxide, coated on shavings and supported on trays in rectangular boxes, is used in most small plants that manufacture gas for city use-that is, for distribution by public utilities. This proceaa is also used in large plants for ‘ h a 1 clean-up of the last 10 to 25 grains of hydrogen sulfide per 100 cubic feet of gas following such liquid purification processes aa the Seaboard (N), Thylox, or vacuum carbonate proceeaes. It is geserally lesa expensive to remove these remain-
