Cascade acid gas removal process

The present invention relates to an improvement to a process for the removal of acid gases from a feed stream containing acid gases in which the feed gas is cooled and countercurrently contacted with a liquid absorbent in an absorber tower and the spent absorbent is regenerated by distillation wherein dissolved acid gases are stripped from the spent absorbent thereby producing a regenerated liquid absorbent and recycled to the absorber tower. The improvement, which is for the production of a product which is essentially free of sulfur containing compounds and has a reduced concentration of carbon dioxide, comprises the following steps: (a) compressing the acid gas-lean product gas to an elevated pressure and cooling the resultant compressed portion; (b) countercurrently contacting the elevated pressure, cooled, acid gas-lean product gas of step (a) and the regenerated liquid absorbent in a second absorber, thereby producing the product, which is essentially free of sulfur containing compounds and has a reduced concentration of carbon dioxide, at the top of the second absorber and a partially spent absorbent at the bottom of the second absorber, wherein said second absorber is operated at a higher pressure than the operating pressure of said absorber tower; (c) recovering the product, which is sulfur containing compounds and has a reduced concentration of carbon dioxide; and (d) using the partially spent absorbent to contact with the feed gas in the absorber tower.

TECHNICAL FIELD 
The present invention relates to a process for the selective removal of 
acid gases and other sulfur containing compounds from a feed stream using 
a physical solvent to absorb the acid gases. 
BACKGROUND OF THE INVENTION 
Numerous absorption processes using a physical solvent are known in the art 
for the selective removal of acid gases such as carbon dioxide, hydrogen 
sulfide and other sulfur containing compounds such as carbonyl sulfide 
from a feed stream containing such components. The process depicted in 
FIG. 1 is representative of these. The term "physical solvent" means an 
absorbent which absorbs the selected component from the feed gas stream by 
physical characteristics and not by means of a chemical reaction. The term 
"absorbent" as used herein and in the claims shall mean a physical 
solvent. For ease of description, the terms "acid gas" or "acid gases" as 
used herein and in the claims shall include in its meaning other sulfur 
containing compounds, in addition to the two classic acid gases, hydrogen 
sulfide and carbon dioxide. 
SUMMARY OF THE INVENTION 
The present invention relates to an improvement to a process for the 
removal of acid gases from a feed stream containing acid gases. In the 
process, the feed gas is cooled and countercurrently contacted with a 
liquid absorbent in an absorber tower thereby absorbing at least a portion 
of the acid gases into the liquid absorbent producing an acid gas-lean 
product gas at the top and spent absorbent at the bottom. The spent 
absorbent is regenerated by distillation wherein dissolved acid gases are 
stripped from the spent absorbent thereby producing a regenerated liquid 
absorbent. The regenerated liquid absorbent is recycled to the absorber 
tower. 
The improvement, which is for the production of a product which is 
essentially free of sulfur containing compounds and has a reduced 
concentration of carbon dioxide, comprises the following steps: (a) 
compressing at least a portion of the acid gas-lean product gas to an 
elevated pressure and cooling the resultant compressed portion; (b) 
countercurrently contacting the elevated pressure, cooled, acid gas-lean 
product gas portion of step (a) and the regenerated liquid absorbent in a 
second absorber, thereby producing the product, which is essentially free 
of sulfur containing compounds and has a reduced concentration of carbon 
dioxide, at the top of the second absorber and a partially spent absorbent 
at the bottom of the second absorber, wherein said second absorber is 
operated at a higher pressure than the operating pressure of said absorber 
tower; (c) recovering the product, which is essentially free of sulfur 
containing compounds and has a reduced concentration of carbon dioxide; 
and (d) using the partially spent absorbent to contact with the feed gas 
in the absorber tower. 
The process of the present invention can further comprise flashing the 
partially spent absorbent of step (b) to liberate dissolved carbon 
dioxide, and then phase separating the warmed, flashed partially spent 
absorbent to remove the liberated carbon dioxide, thereby leaving a 
low-carbon-dioxide-content, partially spent absorbent to be used in step 
(d). This embodiment can further comprise phase separating the partially 
spent absorbent prior to flashing to remove any acid gas-lean syngas 
entrained in the partially spent absorbent and recycling the removed, 
acid-gas lean syngas to the absorber tower.

DETAILED DESCRIPTION OF THE INVENTION 
The process of the present invention is best understood in light of the 
prior art. In a conventional coal gasifier combined cycle facility, 
synthesis gas (syngas) is produced by the gasification of coal using any 
of the known gasifier technologies. This syngas is then combusted and the 
combustion products expanded in a turbine for the production of electrical 
power. Unfortunately, with the use of most coals, i.e., those containing 
sulfur, this syngas cannot be fed directly to the turbine but must be 
cleaned to remove acid gases which cause air pollution. The typical way of 
removing these acid gases is with an absorption process which uses a 
selective physical solvent. 
A conventional process for removal of acid gas from a synthesis gas 
(syngas) stream produced by a coal gasifier using absorption is shown in 
FIG. 1. With reference to this FIG. 1, the syngas stream, line 10, is 
cooled in heat exchanger 12 against warming cleaned product gas. This 
cooled syngas is fed, via line 14, into the bottom of absorber tower 22 
wherein it is countercurrently contacted with absorbent descending the 
tower thus selectively removing acid gases, e.g., most of the hydrogen 
sulfide, about twenty percent (20%) of the carbon dioxide and about fifty 
percent (50%) of the carbonyl sulfide. 
The spent absorbent from absorber 22, is removed, via line 24, reduced in 
pressure (flashed), warmed in heat exchanger 32 against cooling 
regenerated absorbent and fed, via line 34, to phase separator 36. The 
liquid from separator 36 is further warmed in heat exchanger 42 against 
warming regenerated absorbent and fed, via line 44, to stripper 46 for the 
stripping of the acid gases from the absorbent, thereby regenerating the 
absorbent. 
The overhead from stripper 46 is removed, via line 48, cooled thereby 
partially condensing a portion of the overhead. This partially condensed 
is then phase separated in separator 50. This vapor overhead, line 58, and 
combined with the overhead from separator 36, line 38, into a process 
stream to be sent to a sulfur recovery unit, via line 60. 
The liquid from separator 50, line 52, is returned to the top of stripper 
46 as liquid reflux, via line 56. In order to prevent a build up of water 
in the absorbent, a small purge stream can be removed, via line 54, from 
this liquid stream, line 52. 
The regenerated absorbent is removed, via line 62, from the bottom of 
stripper 46. In order to provide vapor boilup to stripper 46, a portion of 
the regenerated absorbent, line 62, is removed, via line 64, and returned 
to the bottom of stripper 46. The remaining portion, line 66, is pumped to 
pressure with pump 68, cooled in heat exchangers 42 and 32 and then 
further pumped to pressure with pump 72. 
This pressurized regenerated absorbent, line 74, is admixed with the acid 
gas-lean syngas, line 26, from the top of absorber 22 to presaturate the 
absorbent with carbon dioxide to minimize the temperature increase 
associated with the carbon dioxide absorption. This combined stream, line 
80 is cooled and the phase separated in separator 82. The liquid from 
separator 82 is fed, via line 84, to the top of absorber 22 as the 
absorbent. 
The vapor overhead from separator 82 is removed, via line 86, warmed in 
heat exchanger 12 and removed as acid gas-lean syngas product, via line 
88. This acid gas-lean syngas product is environmentally suitable to be 
sent to the combustion turbines for the generation of electrical power. 
From two to five percent (2-5%) of the acid gas in a syngas is typically 
carbonyl sulfide with the balance being hydrogen sulfide and carbon 
dioxide. The absorbents used for selective desulfurization such as 
methanol, n-methyl pyrolydone and the alkyl ethers of polyethylene glycol 
have hydrogen sulfide solubilities about eight (8) times as high as carbon 
dioxide solubility. When absorbent flow is set to absorb essentially all 
the hydrogen sulfide, about twenty percent (20%) of the carbon dioxide is 
co-absorbed. The absorption of carbonyl sulfide, which has a solubility 
intermediate to hydrogen sulfide and carbon dioxide solubilities, is about 
fifty percent (50%). Therefore, about ninety seven to ninety nine percent 
(97-99%) of the total sulfur is therefore absorbed and about eighty 
percent (80%) of the carbon dioxide is retained in the syngas. If the 
absorbent flow is increased to absorb the remainder of the carbonyl 
sulfide, then excessive quantities of carbon dioxide are coabsorbed. It is 
advantageous to retain the carbon dioxide in the syngas so that when the 
pressurized syngas is fed to the turbine, power will be generated as a 
result of the extra flow of carbon dioxide through the turbine. 
Additionally, this retention of carbon dioxide in the syngas minimizes 
carbon dioxide dilution of sulfur containing acid gas stream to the sulfur 
recovery unit. 
Unfortunately, where a liquid fuels plant, such as a liquid phase methanol 
plant, or any other chemical process is incorporated into the coal 
gasifier combined cycle, the acid gas-lean syngas produced by the above 
described conventional absorption process is not suitable to be used as 
feed for such a liquid fuels plant. Typically, the level of sulfur present 
in the acid gas-lean syngas will poison most commercial methanol or other 
synthesis catalysts. Also, it may be desirable to reduce the levels of 
carbon dioxide for efficiency reasons. Therefore, an additional level of 
purification is required. The present invention is an improvement to the 
above described conventional process for this further purification. The 
improvement of the present invention is shown in FIG. 2. 
With reference to FIG. 2, streams and equipment which are similar to the 
process depicted in FIG. 1 are commonly numbered. The improvement of the 
present invention begins with the further processing of the acid gas-lean 
product stream, line 88. A portion (representing the quantity of syngas to 
be processed in the liquid fuels reactor) of the acid gas-lean syngas is 
removed, via line 100. (The remaining portion is sent to the turbines of 
the coal gasifier combined cycle, via line 90.) The portion, line 100, is 
compressed to the operating pressure of high pressure absorber 116 and 
aftercooled. This processing is accomplished in the process of FIG. 2 by 
the means of compressors 102 and 106 and heat exchangers 104 and 106. 
However, the number of compressors and heat exchangers used is immaterial. 
This high pressure, acid gas-lean syngas stream, line 110, is then cooled 
in heat exchanger 112 against warming, essentially sulfur containing 
compound-free syngas product and fed, via line 114 to high pressure 
absorber 116 wherein it is countercurrently contacted with absorbent to 
produce an essentially sulfur containing compound-free overhead at the 
top. The essentially sulfur containing compound-free overhead also has a 
greatly reduced concentration of carbon dioxide. 
The essentially sulfur containing compound-free overhead is removed, via 
line 176 and combined with the high pressure regenerated absorbent, line 
174. The high pressure regenerated absorbent is produced by pumping with 
pump 172, the regenerated absorbent, line 73. This combined stream, line 
178, is cooled and phase separated in separator 180. The liquid is fed, 
via line 182, to the top of high pressure absorber 116 as the absorbent. 
The vapor portion is warmed in heat exchanger 112 and removed as an 
essentially sulfur containing compound-free syngas product, via line 184. 
This essentially sulfur containing compound-free syngas is suitable for 
reacting in the presence of a catalyst to produce liquid fuels such as 
methanol or other chemicals. 
The absorbent at the bottom of high pressure absorber 116 is removed, via 
line 118 and phase separated in separator 120. The vapor overhead from 
separator 120 is removed via line 121 and recycled back to absorber 22. It 
would typically be combined with the syngas feed stream, line 10. 
The liquid from separator 120, line 122, is flashed and optionally warmed 
to liberate dissolved carbon dioxide and then phase separated in separator 
123. The overhead produced from the phase separation is removed, via line 
140 and can be recovered as carbon dioxide product. 
The liquid from separator 123, line 124, (the partially spent absorbent) is 
pumped to the operating pressure of absorber 22 with pump 126 and then fed 
to absorber 22, via line 128. 
The improvement of the present invention is usable with most any acid gas 
removal process which uses a liquid absorbent. 
In order to show the efficacy of the present invention, a computer 
simulation of the process schemes shown in FIGS. 1 and 2 have been run. 
For each simulation the flowrate of the absorbent was constant at 402 
gallons per minute at 10.degree. F.; the simulations were run using a 
mixture of dimethyl ethers of polyethylene glycol as the absorbent. Tables 
1 and 2 show some properties of the feed and product streams of the 
process of FIGS. 1 and 2, respectively. 
TABLE 1 
______________________________________ 
CO.sub.2 
Stream Name Flowrates: moles/hr 
Conc.: 
(Stream Number) 
Total H.sub.2 S COS mol % 
______________________________________ 
Syngas Feed 9914.2 29.51 0.77 24.1 
(10) 
Acid Gas-Lean Syngas 
9368 0.22 0.39 20.3 
(88) 
Acid Gases to SRU 
540 29.29 0.38 90.5 
(60) 
______________________________________ 
TABLE 2 
______________________________________ 
CO.sub.2 
Stream Name Flowrates: moles/hr Conc.: 
(Stream Number) 
Total H.sub.2 S 
COS % 
______________________________________ 
Syngas Feed 9914.2 29.51 0.77 24.1 
(10) 
Acid Gas-Lean Syngas 
5034 0.11 0.34 25.6 
(90) 
Acid Gas-Free Syngas 
4171 0.001 0.007 11.2 
(184) 
Acid Gas to SRU 
549 29.39 0.40 90.6 
(60) 
CO.sub.2 Removal Stream 
154 0.004 0.03 91.6 
(140) 
______________________________________ 
Table 3 lists the typical operating conditions for the absorbers of each 
process. 
TABLE 3 
______________________________________ 
FIG. 1 FIG. 2 
Absorber 22 
Absorber 22 Absorber 116 
______________________________________ 
Pressure: 460 460 1200 
psia 
Temperature: 
10 10 10 
.degree.F. 
______________________________________ 
With reference to the improved process of FIG. 2, we see that the absorbent 
has been used twice in series. At the same solvent flow and theoretical 
trays required in FIG. 1, the improved process of FIG. 2 produces a sulfur 
containing compound-free syngas with a reduced carbon dioxide content. 
Surprisingly, the sulfur-contaminated absorbent being fed to first 
absorber 22, line 128, of FIG. 2 achieves an increase in overall sulfur 
recovery as well as a desulfurized methanol reaction feed gas. The overall 
sulfur recovery increases from 98.0 for the process of FIG. 1 to 98.38% 
for the process of FIG. 2; although this may not appear to be significant, 
this increase corresponds to about a twenty percent (20%) reduction in 
emissions. The sulfur recovered in the second absorber 116 more than 
compensates for decreased percent sulfur recovery in the first absorber 22 
due to contaminated solvent because half of the sulfur in stream 88 is 
essentially recovered in absorber 116. 
Note, also, that FIG. 2 shows the combined gas/liquid streams, line 178, 
being cooled to accommodate the carbon dioxide absorption exotherm, this 
cooling could be provided any place in tower 116. 
While the improved process of FIG. 2 beneficially recovers a carbon dioxide 
byproduct, a preferred embodiment, FIG. 3, is shown for use when a carbon 
dioxide byproduct is not desired. The process of FIG. 3 uses the partially 
spent absorbent from second absorber 116, line 118, as a carbon dioxide 
preloaded absorbent for first absorber 22; thus, eliminating the 
requirement of the cooler and separator 82 as well as intermediate vessels 
120 and 123, pump 126 and the heater. To the extent that partially spent 
absorbent, line 118, is supersaturated with carbon dioxide, it will flash 
when fed into absorber 22 and beneficially refrigerate the absorbent. 
Key to understanding this invention is in recognizing that with physical 
solvent absorbents, absorbent flow required to remove a given component 
with a fixed number of absorber trays is proportional to the component 
solubility and the amount of gas treated; it is independent of the amount 
of the component to be absorbed. Required absorbent flow is inversely 
proportional to absorber pressure. Also because solubilities increase as 
temperature is decreased, physical solvent absorption processes often are 
operated at refrigerated temperatures to minimize solvent flow. 
In the embodiments of FIGS. 2 and 3, with 50% of the lean gas product 88 
treated in the high pressure absorber 116, the normal solvent flow of 402 
gallons per minute indicated when cooled to 10.degree. F. will absorb 51% 
of the carbon dioxide and with 7 or more theoretical trays will absorb 
essentially all the hydrogen sulfide and the carbonyl sulfide. The net 
carbonyl sulfide absorption occurs in the high pressure absorber 116, as 
can be seen from the above tables. 
It is important to note that at a given absorbent temperature, the fraction 
of the total feed that can be compressed and freed of sulfur containing 
compounds in high pressure absorber 116 without increasing the solvent 
flow will depend on the relative operating pressures of high pressure 
absorber 116 and hydrogen sulfide absorber 22. For example, at the 2.6 
pressure ratio shown above, the fraction corresponds to about fifty 
percent (50%). For a pressure ratio of one (1), the fraction percentage 
would drop to about twenty percent (20%). 
The present invention has been described with reference to two embodiments 
of the process of the present invention. These embodiments should not be 
viewed as a limitation on the scope of the present invention, the scope of 
which should be ascertained by the following claims.