LANTS elective Absor tion of Hydrogen ulfide from Synthesis H. W.
Wainwright, G. C. Egleson, Synthesis G a s Branch, Bureau
C. M. Brock, J.
Fisher, AND A. E. Sands
of M i n e s , M o r g a n f o w n , W. V a .
T
HE Bureau of Mines, a t its Morgantown, W, Ira., atation,
working in cooperation with West Virginia University, is conducting research and development work on the production of synthesis gas from raw coal for subsequent conversion to liquid fuels (14-16). As the most active catalysts employed in this process are sulfur-sensitive, the purificd synthesis gas must have an extremely low sulfur content. 1 concentration of 0.1 grain of total sulfur per 100 standard cubic feet of purified synthesis gas has been established as the maximum economical limit (13). The Morgantown station has constructed a pilot plant on the campus of West Virginia University to study the removal of hydrogen sulfide, organic sulfur compounds, and carbon dioxide from synthesis gas made directly from coal. The first report on operation of the purification pilot plant was published as a Bureau of Mines report ( 1 9 ) and dealt with the removal of hydrogen sulfide and carbon dioxide by means of aqueous solutions of di- and triethanolamine. The selective absorption of hydrogen sulfide by triethanolamine was reported in that paper. This report, the second of a series on operation of the purification pilot plant, deals with selective absorption of hydrogen sulfide from synthesis gas by tripotassium phosphate and potassium N-dimethyl glycine.
Sulfur Recovery Should Be Feature of Gas-Purification Systems The gas-purification research and development program a t Morgantown always contemplated the necessity of including the recovery of sulfur as a feature of the gas-puiification system in any large Fischer-Tropsch plant ( 1 1 ) . At the time the purification pilot plant was put into operation, most of the sulfur-recovery systems in this country were based on the Claus process and were designed to operate with feed gas containing large amounts of hydrogen sulfide, generally more than 30% ( 2 , 21). The concentration of hydrogen sulfide in the feed gas has a maiked effect on the economy of these sulfur-recovery plants ( 1 , 4, 6 , 11). When the raw gas produced contains a high carbon dioxidehydllogen sulfide ratio, selective absorption processes are of importance so that the acid gas (carbon dioxide and hydrogen sulfide)recovered from the reactivator of the gas-purification plant will have the highest possible hydrogen sulfide content. Owing to this need for selectivity, pilot plant data had to be obtained on the selective properties of such absorbents as triethanolamine, tripotassium phosphate, and potassium N-dimethyl glycine. The literature states that recent advancements in the art of sulfur recovery now make it possible to recover sulfur from acidgas streams low in hydrogen sulfide (8). In the Fischer-Tropsch synthesis, where all the hydrogen sulfide and the bulk of the
carbon dioxide must be removed (S), this new development in sulfur recovery is of utmost importance, as it permits substantially complete removal of both acid-gas constituents simultaneously. However, the need for selective absorption will continue to be of importance to companies possessing sulfur-recovery systems designed to operate on acid-gas mixtures rirh in hydrogen sulfide. .ilso, in processes where the carbon dioxide need not he removed from the raw gas, hydrogen sulfide alone may be renioved a t a lower cost. All purification studies made in the pilot plant were carried out a t 300 pounds per square inch gage, the approximate pressure contemplated for the Fischer-Tropsch synthesis. Most of the pilot plant runs were made using inert gas obtained by burning natural gas. Hydrogen sulfide and additional carbon dioxide, if necessary, were added to the inert gas to give the desired concentrationf. synthesis gas was used, when available.
Equipment for H2S Removal Follows Design of Single Solution Flow System
A description of the pilot plant equipment has been given in an earlier publication ( 1 9 ) . The only major change has been replacement of the wet-type gasholder with a waterless holder. A view of the holder is given in Figure 1. Use of the waterless holder facilitated operation, inasmuch as little 0 1 no hydrogen sulfide was removed from the gaq stream by the holder. Therefore, it was possible to feed gas to the pilot plant with a constant hydrogen sulfide concentration 1% ith little attention given to the hydrogen sulfide addition apparatus. With a webtype holder fornieily used, appreciable variations in the hydrogen sulfide concentration in the gas resulted owing to absorption of small amounts of hydrogen sulfide by the water in the w h o l d c r and reaction of the hydrogen sulfide mith the wet iron surfaces. The equipment used for removing hydrogen sulfide follows the ronventional deqign for a single solution flow system. Figure 2 gives a view of the pilot plant n ith the absorber and reactivator a t the extreme right. The equipment t o the left is used for iemoving organic sulfur compoundP The absorber consists of a 21-foot length of 10-inch steel pipe and is equipped with a pressure-relief valve and a liquid-level controller. A liquid separator has been installed in the outlet gas line a t the top of the absorber for removing small amounts of entrained solution. The absorber is packed with 15 feet of 1-inch porcelain Raschig rings. The reactivator consists of a 17-foot length of IO-inch steel pipe connected directly to the reboiler by a flange. The reboiler is 10 feet in length and I6 inches in diameter. The reactivator is packed with 15 feet of 1-inch porcelain Raschig rings. The steam used for reactivation ie controlled by a pressure controller
1378
June 1953
INDUSTRIAL AND ENGINEERING CHEMISTRY
1379
the low vapor pressure of hydrogen sulfide over phosphate solutions at elevated temperatures (6). I n commercial gas purification, tripotassium phosphate has been used to treat gases containing little or no carbon dioxide. Today, owing to the great interest developed in recent years in sulfur recovery resulting from sulfur shortage (20) and concern over air pollution, tripotassium phosphate, because of its selective properties, is being used for treating gases containing both hydrogen sulfide and carbon dioxide. However, there are few published data on the performance of this purifying agent when used with gases containing carbon dioxide and hydrogen sulfide in ratios as high as 44:l. Large quantities of tripotassium phosphate are used for commercial gas purification by the Shell Development Co. in several plants built in the United States and abroad.
Ten Test Runs Evaluated Tripotassium Phosphate Solutions
a
The phosphate solution initially prepared for pilot plant investigation contained 43.7% tripotassium phosphate by weight. This was prepared by dissolving a weighed amount of potassium hydroxide in the required amount of steam condensate. The heat of solution was removed by a water-cooled coil in the mixing tank, The necessary quantity of 75% solution of phosphoric acid was then added. Air agitation was used for stirring. An electrometric titration on the solution as prepared showed 2.06 moles of POa" HPOa; 0.06 mole of COS", and 6.12 moles of K + per kg. of solution. Table I gives the data from ten pilot-plant runs. Runs 1, 2, and 3 were made using a solution with an initial concentration of 43.7% tripotassium phosphate. During runs 1 and 2, crystals of potassium bicarbonate were observed in the foul solution. It was necessary to discontinue run 3 because of the plugging of the Rasohig rings in the absorber. It was evident that in the pilot plant it was impracticable to treat a gas having such a high partial pressure of carbon dioxide and a high carbon dioxide-hydrogen sulfide ratio with a 43.7% phosphate solution having a concentration of 2.06 moles of PO1' per kg. The carbon dioxide content of the foul solution was so high that precipitation of the bicarbonate resulted. Subsequent runs were made with a 32 to
+
Figure 1.
Dry Gasholder, 1000 Cubic Feet
and measured either by a rotameter or by weighing the condensate. The pressure in the reboiler and reactivator is controlled by an air-operated valve in the acid-gas line a t the top of the column. The solution and gas flow are typical of many liquid purification systems using the single solution flow. A detailed description of the solution and gas flow for the Morgantown pilot plant has been published (19).
Tripotassium Phosphate Seemed a Promising Scrubbing M e d i u m The use of tripotassium phosphate as scrubbing medium has long been advocated for removing hydrogen sulfide from gases and liquid hydrocarbons. The absorption of hydrogen sulfide may be represented essentially by the reaction
KaPOa
+ H2S --+ IGHPOa + KHS
It has been reported that, inasmuch as tripotassium phosphate is immiscible with liquid hydrocarbons, this process is especially attractive for removing hydrogen sulfide from such compounds. It also offers certain advantages in the field of gas purification because of the nonvolatile nature of tripotassium phosphate solutions. It is particularly useful in removing hydrogen sulfide from gases up to temperatures of 200" F. because of
Figure
2. Gas Purification Pilot Plant
INDUSTRIAL AND ENGINEERING CHEMISTRY
1380
Vol. 45, No. 6
Table I. Results of Pilot Plant Runs with Tripotassium Phosphate Run
No.
Type Gas
la lb
Inert Inert Inert,
IC
2 3a 3b 4 5a 5b 5c 6 ia 76 83
8b Sa 96 9c
1Oa 105 1oc 1Od 1Oe a b
Inert Inert Inert Inert Inert Inert Inert Inert Syn. Syn. Inert Inert Inert Inert Inert Syn. Syn. Syn. Syn. Syn.
L/Ga,Gal. H18 in Gas Gas Rate, Soln./1000 Soln Rate Std. Std. cu.F t . Grains/100 Std. d u . Ft.b Gal.'/Min.' Cu. Ft./Hour Raw Gas In out 0.85 0.85 0.85 1.00 1.00 1.40 1.40 0.85 1.40 0.90 1.40 1.10 1 10 1.25 1.25 0.88 1.17 1.39 0.59 0.53 0.51 0.50 0.62
2340 1660 1380 1580 2450 8870 3780 2220 2460 2420 3650 3300 3500 2300 2560 3000 3000 3000 3000 3000 3000 3000 3020
21.8 30.7 37.0 38.0 24.5 21.7 22.2 23.0 34.1 22.3 23.0 20.1 18.8 32.3 29.3 17.5 23.4 27.8 11.8 10.6 10.2 10.0 12.3
400 400 400 400 460 400 400 400 400
400 400 290 290 400 400 205 400 650 190 190 190 190 400
COZin Gas, % out In 12.4 11.3 12.4 10.5 12.4 10.2 12.4 10.4 12.4 9.9 12.4 10.3 12.4 10.0 12.4 10.7 12.4 9.5 12.4 10.1 13.4 11.2 12.5 10.5 12.5 10.6 23 0 18.5 18.7 14.7 13.7 11.8 13.7 11.3 13.7 10.7
90 50 30 25 25 25 20 230 80 25 25 10 20 30 25 25 25 25 15 20 25 30 25
6.3 6.3 6 6 .. 33 6.5
5.2 5.4
::; 6.4
HzS in rlcid Gas, % Calod. Actual 27.0 ... 20.0 ... 18.8
20.1 17.1 19.5 18.2 12.2 13.4 18.5 18.2 16.6 18.2 9.3 10.9 11.7 18.6 22.1
18.6 22.2 21.5 22.6 33.7
HzS in L~~~ soln,, Grains/Gal 300
...
... ...
25.1
230
...
65
21.3 22.1
18.8 16.7
70 75 20 20 65 65 65
7.8
65 3I
...
1'6,'0
...
...
11.7 18.6 23.4 16.8 18.8
... ...
35.8
53 70 8d !35
... ...
110
160
Liquid-gas ratio. Standard gas volumes refer t o 60' F., 30 inches of Hg, dry.
35% solution, and the difficulties resulting from precipitation were eliminated. Runs 1 and 2 were made with only a 2-foot depth of Raschig rings in the absorber. Cqmparison of these runs with subsequent ones in which a 15-foot depth of Raschig rings was used shows that considerably higher liquid-gas ratios were required with the lower packing height. Data from these runs also shox the effect of hydrogen sulfide removal efficiency on the acid-gas composition. Generally, reactivation was cariied out with a reboiler pressure of about 3 pounds per square inch gage. Operation under these conditions resulted in an actual steam for reactivation of approximately 1.0 pound per gallon of circulating solution. Allo~iing lor heat losses, the average steam consumption was about 0.87 pound per gallon of solution. On larger scale operation, the steam consumption would probably be lower. For the most economical operation, it would probably be advantageous to use the split solution flow, a method of operation to which the phosphate process lends itself very well ( I O ) . I n an attempt to reduce steam consumption, runs 5a and XI were made in which the reboiler was operated a t a pressure of only 5 inches of mercury absolute. Under these conditions the potassium bicarbonate formed in the absorber was not regenerated, and much higher solution rates were required to attain good hydrogen sulfide removal, even though the reduced pressure operation lowered the hydrogen sulfide content of the lean solution to 20 grains per gallon. The selectivity was not improved by such operation. During the latter part of run 10e, the steam rate was increased 20%. This change reduced the hydrogen sulfide content of the lean solution from 160 to 140 grains per gallon. Under our operating conditions the effect of this reduction in hydrogen sulfide content on scrubbing rates was only slight, considering the significant increase in steam consumption. During the operation of the pilot plant, it was noted that, for a given reactivation steam rate, an increase in the carbon dioxide content of the foul solution had a marked effect on lowering the hydrogen sulfide content of the lean solution. The following data show this springing effect of the carbon dioxide. Although in run 10e the hydrogen sulfide content of the foul solution is somewhat higher than that in run l a , the hydrogen
Table II. Springing Effect of Carbon Dioxide in Reactivation COn Content of Foul Soln., Std. Cu. Ft /
R u n No. 10e
la 9, 10d
Gal. 0.94 0 53 1.21 0.84
51s
Content of S o h , Grains/Gal. Foul Lean 465 160 442 300 310 85 270 110
sulfide content of the lean aolution is lower owing to the larger amount of carbon dioxide in the foul solution. A comparison of runs 9c and 10d also shows this effect. It i s also interesting to note the reasons for the differences in the carbon dioxide content of the foul solution for the above runs. While the operating conditions of runs 1Oe and l a differ in niany respects, the significant variation, resulting in the effect, noted, is in the packing depths, which are 15 and 2 feet, respectively. In the second comparison between runs 9c and 10d, the large difference betwem the carbon dioxide concentrations in the feed gas accounts primarily for the higher carbon dioxide content of the foul solution in the former run.
Morgantown Synthesis Gas Was Treated in Two Runs For runs 7 and 10 synthesis gas produced in a hIorgalltown gasifier was treated. Analyses of the raw synthesis gas used in these runs are given in Table 111. Of particular interest in these runs was the study of the effect of the organic sulfur compounds in the raw gas on the tripotasPium phosphate solution. The types of organic sulfur compounds present in the gas were not definitely known, but over 90% was believed to be present as carbon oxysulfide. The remainder was believed to be carbon disulfide. n'either thiophene nor mercaptan sulfur was present. The organic sulfur content of the gas was determined immediately before and after the absorber, using the platinum-spiral method for analysis ( l a ) . Table 1V gives the results of these determinations. In general, a small amount of the organic sulfur was removed from the raw synthesis gas under the specific operating conditions. However, control tests on the lean solution showed no
I
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
lune 1953 Table 111.
co2
Composition of Synthesis Gas
02 Unsatd. hydrocarbons
Ha
co
CHI Nz
I
1381
Composition, % Run 7 Run 10 13.0 6 6 0.4 0.3 0.7 0.6 28.0 31.7 50.5 56.3 3.4 1.1 3.4 4.0
build-up of nonregenerative sulfur compounds. One possible explanation of this could be that a part of the carbon oxysulfide was hydrolyzed to hydrogen sulfide and removed as potassium bisulfide.
Preliminary Estimates Indicate Complete Removal of H2S Not Economical
GALLONS OF 3 5 % K3P04 SOLUTION PER lo00 Std.CF OF RAW GAS
Figure 4.
Effect of Phosphate Scrubbing Rates on Removal of Carbon Dioxide
i
The data in Table I were correlated and are presented in the following series of diagrams. The data are presented as typical results of the Morgantown pilot plant. Preliminary cost estimates showed that complete removal of hydrogen sulfide by liquid scrubbing is not economical. Pilot plant operations indicated that, in the range of hydrogen sulfide and carbon dioxide concentrations studied, excessive scrubbing rates and steam consumption were required to reduce the hydrogen sulfide content t o less than 10 grains per 100 standard cubic feet. The optimum concentration of residual hydrogen sulfide in the gas leaving the
S 4 O IH,S
IN RAW G A S = W O R A l N S PERYT) SldC.E1
absorber was found to be 25 grains per 100 standard cubic feet. This was indicated by an economic balance made between the removal of the residual hydrogen sulfide by liquid scrubbing and dry box purification. However, in commercial operation, split solution flow would undoubtedly improve purification and reduce steam costs. Figure 3 shows the effect of carbon dioxide in the raw feed gas on the scrubbing rates required t o give the desired hydrogen sulfide content of 25 grains per 100 standard cubic feet. Figure 4 shows the effect of phosphate scrubbing rates on reduction of the carbon dioxide content of the gas. The data used in both these diagrams are from operations in which the absorber was filled with 15 feet of Raschig rings. It may be that, under test conditions, the carbon dioxide removal was excessive, resulting thereby in high scrubbing rates to attain the desired hydrogen sulfide removal. Data from Table I show that the reduced contact time due t o the lower height of Raschig rings improved selectivity, but excessive scrubbing rates were required to effect hydrogen sulfide removal. Investigation of a series of feedsolution inlets would be desirable to determine the optimum solution inlet position. Figure 5 shows the effect of phosphate scrubbing rates on the residual hydrogen sulfide in the gas leaving the absorber. The 100,
I
I
I
1
I
Figure 3. Effect of Carbon Dioxide Content of Raw Gas on Scrubbing Rate Requirements
Table IV.
Removal of Organic Sulfur by Tripotassium Phosphate
Grains S/100 Std. Cu. Ft. Organic S Gas Removal, %a Run No. Before absorber After absorber 7 50.0 46.6 8.6 61.1 61.1 2.1 48.5 46.6 6.0 51.5 45.9 12.8 55.3 46.5 17.7 52.9 53.2 1.7 10 61.2 60.0 2.5 27.6 28.3 -0.14 25.4 25.6 0.04 17.7 18.0 -0.06 Owing to 8 volume reduction involved, 5gures refer t o total weight of organio sulfur removed from raw gas. Q
M z IN PAW GAS I3 %
4OQ GR4NS FER 100 SldC + 6W G R A M PER 100 SldC
GALLONS OF S1d.C.E
U,P04
SOLUTION PER 1000
OF RAW QAS
Figure 5. Effect of Phosphate Scrubbing Rates on Residual Hydrogen Sulfide in Treated Gas
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
1382
curves refer to raw gas containing about 13% of carbon dioxide and varying amounts of hydrogen sulfide. The data indicate a trend toward higher solution rates when the hydrogen sulfide in the purified gas decreases below 25 grains per 100 standard cubic feet. As previously stated, in most of the pilot plant runs the stripping steam waF held constant in relation to the solution rate, but not independently constant. Experience of Shell Development Co. ( 7 ) indicated that the shape of the curves in Figure 5-i.e., improvement in removal with increasing liquid-gas ratio-should be attributed to the increased steam consumption per unit of raw gas or per unit of hydrogen sulfide removed. It has been established for tripotassium phosphate that, for a given set of operating conditions, as the solution rate is varied, the extent of hydrogen sulfide removal passes through a maximum. This may be explained as follows: As the solution rate ip increased above the optimum value, a greater portion of the steam input t o the reactivator i,s consumed as sensible heat in bringing the foul solution to the boiling point. In addition, the scrubbing solution becomes continually less saturated with hydrogen sulfide, hence the stripping job requires more steam per unit of hydrogen sulfide. If, on the other hand, the solution rate is reduced beyond the optimum, the hydrogen sulfide content of the purified gas increases rapidly owing to the inability of the solution to absorb any additional quantity of hydrogen sulfide after equilibrium is reached.
3
i.05 $0 4 X
z
2 .03 0
w n
g02 (I
:m: *w
1
2
2 .01 I O G%:H,S
20
30
40
50
R A T I O I N RAW G A S . S t d . C.F. /Sld,C.F.
Figure 6. Correlation of COrHsS Ratios in Raw Gas with H?SRemoved by Phosphate Scrubbing Solution
Figure 6 shows the relationship between the carbon dioxidehydrogen sulfide ratio in the feed gas and the amount of hydrogen sulfide removed by the circulating phosphate solution. Figure 7 gives the interrelation between the acid-gas composition and carbon dioxide-hydrogen sulfide ratios in the feed garanging from 14 to 44. The curve refers to a feed gas containing 13'% carbon dioxide. The range in the ratios of 14 to 44 was obtained by changing the hydrogen sulfide content only. Limited data indicate that similar curves drax n €or gas containing 21 and 6.5y0 carbon dioxide would show a 25% decrease and a 25% increase, respectively, in the hydr ogen sulfide concentration in the acid gas.
Potassium %Dimethyl Glycine Has
High Carrying Capacity for H2S The use of potassium S-dimethyl glycine as a basic absorbent in gas purification was developed in Germany before World War I1 and was used extensively in that country during the war.
10
I5 C 4 i C 4 . S RATIO
IN
m
Vol. 45, No. 6
30
4 0 5 0
R4W GAS, Sld.G:F./Std.W.
Figure 7. Correlation of COYH~SRatios in Raw Gas with Composition of A c i d Gas from Reactivation of Foul Phosphate Scrubbing Solution
The absorbent solution is made by combining a strong inorganic base with a weak organic nonvolatile amino acid. Two other similar amino acid and inorganic base combinations have also been used in Germany as absorbents in gas purifiration-potassium N-methylalanin and an amino acid salt of unknown composition. The former has been employed for the removal of both hydrogen sulfide and carbon dioxide, and the latter purportedly was used for a similar simultaneous removal of these impurities from gases containing tar vapors, hydrogen cyanide, dust, and other contaminants. However, the potassium A$7-dimethyl glycine absorbent (known as Alkazid in Germany) has been marketed most widely for the selective removal of hydrogen sulfide from various industrial gases, chiefly because it permitted the subsequent recovery of sulfur in a Claus kiln. Large scale operation of purifying equipment using glycine salt as absorbent is similar to those employing ethanolamines and tripotassium phosphate. No plants have been elected in thk country, but the process is used throughout Europe. Vapor-pressure studies made in Morgantown on a potassium .V-dimethyI glycine sample supplied by the Rohm & Haas Co. of Philadelphia indicated that the compound had an extremely high carrying capacity for hydrogen sulfide. The results of the vapor-pressure studies made are compiled in Table V. Owing to the possible process advantages accruing from such high carrying power, Rohm & Haas supplied the bureau with sufficient solution to carry on pilot plant investigations. The pilot plant runs were made with particular attention to the selective properties of this absorbent.
Table V. Absorptive Capacity of Potassium N-Dimethyl Glycine for Hydrogen Sulfide a t 80" F. and Atmospheric Pressure (20% in Solution, Std.
Cu. Ft./Gal. 1.3 1.3 1.3 1.3 2.2 2.2 2.2 2.2
HzS in Solution GrainsiGal, 260
HzS i n Gas Phase Grains/100 Cu. Ft.' 40
7.50 1000
230 390
500 750 1000
220 430 865
500 250
iin 7..r,
INDUSTRIAL AND ENGINEERING CHEMISTRY
June 1953
For preparing the potassium .V-dimethyl glycine solution, dimethylamine, formaldehyde, and hydrogen cyanide are used according to the following reactions (9):
F
H I
+ HCT -+ H-k-CzN
H-C=O H
H-(!kK
I
OH H
CHa
+ CH3-T-HI
--+ H-d-C=\7 I
OH
+ H20
N
CH! H
fide and carbon dioxide. The foaming, hoa-ever, ceased after a short period of operation. This tendency to foam a t the start appears to be characteristic of glycine salt absorbents (18). In general, the following operating conditions were used in the pilot plant runs made: Absorber pressure, lb./sq. inch gage Reactivator presosure, Ib./sq. inch gage Reboiler temp., F. Lean solution to cooler, O F. Lean solution to absorber, O F. F. Foul solution to heat exchang:r, Foul solution to oreactivator, F. Acid-gas temp., F.
I
+ KOH + H20 +’ H-
6
b-C-0-0-K
+ NH3
I
N CH!
0 5
‘CN3
!i
5
g2
H2S IN PURIFIED GAS 825 QRAINS PER IOOSltlOF GO2 IN LEAN SOWTION 0.7-1.1 Std.OF./&U.WI
12 Cot
IN
14 RAW G A S ,
16 PERCENT
18
$ 6
The solution, as charged in the pilot plant, contained 6.9 ‘grams of iron per gallon. Duridg the early runs, the iron content increased, indicating some attack on the equipment. Consequently, for these early runs the hydrogen sulfide-removal figures were not reliable, since much of the hydrogen sulfide was being removed as iron sulfide. However, after several runs the iron precipitated out of the solution as sulfide, and the solution showed a negligible iron content. There was some evidence of foaming during the initial operation particularly when treating gases containing both hydrogen sul-
IO
E 4
r 3
2.60 19.26 0.01 29.2 1.1380
Scrubbing Rates, Gas Flow, and Types of S in Raw Gas Determine Amount of Organic S Removed
8
s B
The absorbent solution, as received from Rohm & Haas, had the following oomposition: Total nitrogen, yo Sulfated ash, yo KH3 nitrogen, % Solids, 70 Specific gravity
300 3-4 222-225 149 95 106 164 160-180
‘CH3
H
H-6-C-N
1383
20
Figure 8. Effect of Carbon Dioxide in Raw Gas on Scrubbing Rates with Potassium N-Dimethyl Glycine Absorbent
I 8 12 16 20 24 28 GALLONS OF ABSORBENT SOLUTION PER 1000 Std C F RAW GAS
Figure 9. Effect of Scrubbing Rates on Removal of Carbon Dioxide with Potassium N-Dimethyl Glycine Absorbent
From the pilot plant data, a general correlation can be made between the carbon dioxide in the lean solution, steam used for reactivation and circulating solution rates. The data indicate that, with a gas containing 10 to 14% carbon dioxide and hydrogen sulfide in the gas reduced to about 25 grains per 100 standard cubic feet, a lean solution containing about 1.3 standard cubic feet of carbon dioxide per gallon of solution is near optimum for the conditions studied. Figure 8 shows the effect of carbon dioxide in the raw gas on the scrubbing rates. The effect of scrubbing rates on the reduction of the carbon dioxide in the gas is shown in Figure 9. Figures 10 and 11 show the relation between the carbon dioxide-hydrogen sulfide ratio in the feed gas and the amount of hydrogen sulfide removed and the acid-gas composition, respectively. German information indicates that the glycine-salt solution is not generally used in packed columns because of the excessive contact time. The possibility of atomizing the solution had been investigated, but it was almost impossible to obtain nozzles with large enough capacities. Some German plants used disintegrators rather than columns ( l 7 ) , which, it is claimed, resulted in a marked improvement in the selectivity. Two runs were made using synthesis gas produced in a Morgantown atmospheric pressure gasifier. Data from these runs indicated that the operating results obtained when using inert gas would equally apply to synthesis gas. Analyses of the raw synthesis gas used in these runs are given in Table VI. During these runs a study was made of the removal of the organic sulfur compounds from the gas by the glycine salt solution. The results are given in Table VII. Complete data are presented to show the wide variations in the degree of removal of these sulfur compounds. As with the phosphate solution, no exact explanation can be given for these variations, but it is believed that scrubbing rates, gas flow, and types of organic sulfur
1384
INDUSTRIAL A N D ENGINEERING CHEMISTRY Table VI.
Vol. 45, No. 6
Composition of Synthesis Gas Purified in Pilot Plant Run 6 8
Table VII.
6a Ga 6a 6a Gb 6b 6b 6b 6b
4 0 5 0 C%: H2S RfiTIO IN R A W GAS,Std.C.f./Std.M
20
30
Effect of C O d G Ratios in Raw Gas on HIS Removed by Potassium N-Dimethyl Glycine Absorbent Figure I O .
in the raw gas are among the variables that determine the amount
of organic sulfur removed b y the absorbents. Owing to the scale of operation and the particular operating conditions used in the pilot plant, care should be taken in extending these data to large size commercial plants, which may be of different design and operate under different conditions. The data presented in this paper were obtained b y the use of a packed absorber and reactivator; bubble-cap columns might give different results.
a
Run 7
Removal of Organic Sulfur by Glycine Salt Absorbent Organic Sulfur Organic Sulfur
Run S o . 6a IO
Composition. $' $ Run 6b
into Absorber, Grains/100 Std. Cu. Ft. 20.8 17.6 14.4 13.7 11.4 19.8 15.2 17.1
Out of Absorber Grains/100 Std. Cu. Ft. 21.9 17.4
17.7 13.4 10.7 10.1 10. 9 14.2
11.1 11.0 10 7 14 4 14.1 16.8 17.1 12.7 11.3 11.1 12.2 10.1
Organic Sulfur Removal, %" 3.4 9.1 27.8 24.8
12.3 31.3 12.6
i o
8.5 10.4 0.0 -3.9 -5.5 11.3
Owing t o a volume reduction involved, figures refer t o the total weight of
organic sulfur removed from the raw gas.
their experience in gas purification. Thanks are due, also, to E. H. Riddle, of Rohm & Haas Co., who supplied the glycine absorbent used in the pilot plant investigations and t o General American Transportation Corp., which supplied the dry gasholder. Literature Cited Blohm, C. L., Oil Gas J., 50, No. 51,89-93 (1952). Cooper, C. W., and Waddle, H., Gas, 21, No. 7,31-3 (1946). Kastens, M. L., Hirst, L. L., and Dressler, R. G., IND.CNG. CHEM.,44,450-66 (1952).
Kohl, A. L.,and Fox, E. D., Oil Gas J , 50, No. 42, 154-9 (1952).
LaCroix, H. N., and Coulthurst, L. J., Refiner Xatural Gasoline Mjr., 18, 90-4 (1939). Parker, J. L., Petroleum Processing, 7, No. 3, 338-9 (1952). Randlett, H. E., Shell Development Co., private communication (1952). 0
I
I
I
I
I
l
l
L..
IO
20 30 40 C V H 2 S RATIO IN RAW GAS, Std.C.F./Sld.C.F.
50
Figure 11. Effect of COI-HzS Ratios in Raw Gas on Composition of A c i d Gas Obtained in Reactivation of Potassium N-Dimethyl Glycine Absorbent
Resin, F. L., Oil Gas J . , 50, Xo. 4, 59 (1951). Roberts, F. H., Combined Intelligence Objectives Sub-Committee, Target No. 22/lf (1945). Rosebaugh, T. W., Proc. Am. Petroleum Inst., 19M, Sect. 111, pp. 47-52 (1938).
Sands, A. E., and Schmidt, L. D., IND.ENG.CHEM.,42,2277-87 (1950).
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However, there is such a limited amount of published information on actual operation of plants in which hydrogen sulfide is removed selectively that the authors believe the results reported herein may prove t o be of value and interest. Acknowledgment
The authors wish t o express their appreciation t o the members of the Synthesis Gas Branch, especially those of the Gas Treating and Testing Section, whose cooperation was most helpful. Thanks are due to H. E. Randlett and his associates of Shell Development Co., who contributed valuable information from
Sebastian, J. J. S., Ibid., 44, 1175-84 (1952). Strimbeck, G. R., Cordiner, J. B., Taylor, H. G., Plants, K. D , and Schmidt, L. D., U. S. Bur. Mines, R e p t . Invest. (in preparation). Strimbeck, G. R., Holden, J. H., Rockenback, L. P., Cordincr. J. B., and Schmidt, L. D., I b i d . , 4733 (1950). Technical Oil Mission (obtainable from Library of Congress, Washington, D. C.), Item 22a, Reel 132. I b i d . , Item 5a, Reel 132. Wainwright, H. W., Egleson, G. C., Brock, C. M., Fisher, ,J., and Sands, A. E., U. S.Bur. Mines, Rept. Invest. 4891 (1952). Weber, G., Oil Gas J., 50, No. 36,61-4 (1952). Zurcher, P., Petroleum Processing, 7 , No. 3, 333-8 (1952) RECEIVED for review March 14, 1963.
ACCEPTEDApril 10, 1953.
