NOVEL PROCESS FOR REGENERATIVE SULFUR DIOXIDE REMOVAL FROM GASES
FIELD OF INVENTION
The present invention relates to development of a novel process for removing sulfur dioxide from gas streams. The process relates to removing sulfur dioxide from gas streams using a novel solvent blend of chemical and physical solvents, and sulfite oxidation inhibitors. The present process further discloses sulfur dioxide absorption as well as regeneration. PRIOR ART AND BACKGROUND OF INVENTION
Petroleum refineries, thermal power-plants, suifide smelters, and other SO2 emitting industries world-wide are under increasing regulatory pressure to reduce their sulfur emissions. Regenerative liquid phase absorption technologies are being increasingly used for SOi removal and recovery. Various regenerative SO? removal technologies have been developed using organic and inorganic solvents for SCb absorption. However, due to several drawbacks of regenerative technologies, non-regenerative lime/limestone/caustic scrubbing methods have been the predominant methods for SC>2 removal in thermal power-plants and petroleum refineries.
Recent developments in technology have resulted in regenerative SOj removal methods becoming viable for applications involving fuel gases generated from high sulfur fuels, and in general for fuel gases with high 862 concentration. The economic viability of regenerative processes is critically dependent on factors such as solvent cost, solvent SOi holding capacity, method of solvent regeneration, and regeneration heat duties. The different types of solvents that are being used can be broadly categorized as [i] Chemical Solvents-fa] inorganic and [b] organic, and [ii] Physical Solvents. Chemical Solvents:
Inorganic Salts: Sodium salts of sulfite, phosphate, and carbonate are used as buffering agents in regenerative SO-, removal processes. The Well man-Lord process for SOa removal uses a sulfite buffer. The salts of phosphate and carbonate have for long been used by microbiologist to maintain culture media near neutral pH. Carbonate has been used as the buffering media in a recently developed biological SO2 removal process (Branes, L.L et al, 1991, Trans 1 Chem £, 69A: 184-187), "Non-
regenerative seawater scrubbing processes use the alkalinity of carbonate in seawater to neutralize SCh The buffering capacity of seawater is over 2 orders of magnitude lower than that of phosphate/sulfite based processes implying much larger flow of scrubbing solution for the same 862 removal load. Recently, processes using the phosphate buffer for regeneration 862 removal have also been developed (Eagleson S.T. et al, 2001, Presentation at Petwtech-2001, New Delhi, India). Solvent regeneration for inorganic solvents requires evaporation of the rich solution, and is typically very energy intensive for single stage evaporation.
Organic solvents: The use of weak bases for regenerative SC>2 absorption has been known for many decades (Danckwerts P.V., 1970, Gas Liquid Reactions, McGraw-Hill). Diamine compounds known to have basicity in the optimal range allowing effective SO2 absorption and solvent regeneration include the ethylene diamine, alkyl and alkanol substituted ethylene diamine, piperazine, alkyl and alkanol substituted piperazine. Mono-amines that are weak bases include heterocyclic amines such as pyridine and piperdine, aromatic amines such as aniline and alkyl substituted aniline, quinoline. Several of these amines have been referred to in earlier patents.
In US Patent 4,080,423 [1978] Smith et al. claims a method for absorbing gaseous component in an aqueous liquid where the gaseous component is sulfur dioxide. The aqueous liquid comprises a weakly dissociating compound selected from the group of aniline, hydroxylamine, piperazine, piperdine, among others.
In US Patent 5,019,361 [1991] L E Hakka claims a cyclic process for removal of SO2 with the absorbing medium containing a water-soluble half salt of a diamine. The patent lists several diamines like N-N'-N'-[trimethyl], N-[2-hydroxyethyl] ethylene diamine and N-N-N'-N'-tetra methyl ethlene diamine and piperazine.
These solvents are stripped of 862 and regenerated by raising the temperature of the SO2 -loaded solutions. Basicity of the organic bases decreases when the temperature is raised from 40°C to 100°C, while those of the inorganic bases increase marginally. Diamine buffers are therefore easier to regenerate by increasing the solvent temperature. Thus, while the high basicity of phosphate and sulfite inorganic buffers makes them good buffering agents for SO2 absorption, they are hard to regenerate; the regeneration requires evaporation heat input which represents a major operating expense for regenerative SC^-loaded solutions. The specific steam consumption of aqueous buffered solvents also depends on the solvent buffer
concentration. The specific steam consumption decreases with increasing buffer strength and is limited by the operable buffer strength of the solvent.
Solvent losses in gas streams leaving the process is a concern with low-boiling organic solvents. Diamine solvents are employed with the first amine function present as a salt [that is, in ionic form]. Thus, volatilization losses are negligible. Oxygen and SC>2 present in the absorber feed gases oxidize bisulfite and sulfite ions to sulfate, resulting in accumulation of heat stable sulfate salts.
Carbon dioxide is present in significant quantities in most sulfur dioxide containing fuel gases. Dissolution of CO2 has to be kept to a minimum, to reduce contamination of regenerated SOigas and minimize regeneration heat duties. Solvents with low basicity allow high CO2 slippage. Physical Solvents:
Some polar organic solvents, due to their Lewis base properties, have high affinity for SC>2, which is a Lewis acid. Sulfolane, poly glycol ethers, dimethyl aniline, etc, are known as effective physical solvents for SC>2 removal from sour gases. Solubility of SC>2 in sulfolane, dimethyl aniline, quinoline, and various poly glycol ethers has been reported (Sciamanna, S.F. & Lynn, S, 1988, Ind. Eng. Chem. Res., 27: 492-499). The SO2 holding capacity is reported to be the highest for di-methyl aniline, followed by quinoline, the poly-glycol ethers, and lowest for sulfolane. For each of these solvents SC>2 holding capacity increases with SO2 partial pressure and decreases with temperature. The efficiency of SC>2 removal for processes using these physical solvents increases when the SO2 pressure in the gas increases. In general, physical solvents have low heats of absorption/regeneration compared to chemical solvents. Processes using physical solvents typically require greater number of contacting stages than chemical solvents implying larger equipment sizes.
A commercial reference for the use of di-methyl aniline for regenerative SC>2 removal was made in the late 1970's [Kohl & Nielsen], but no recent application was reported. Di-methyl aniline and quinoline are known to be toxic in nature. A process using a mixture of poly-glycol ethers for regenerative SO2 removal has been reported in US Patent 4,795,620 [1989].
Thus both chemical (inorganic or organic) and physical solvents have drawbacks. The regeneration for inorganic solvents requires evaporation of the rich solution which is very energy intensive for single stage evaporation. Whereas, physical solvents require greater number of contacting stages than chemical solvents
implying larger equipment sizes. The present invention uses a novel solvent blend of chemical and physical solvents, with added sulfite oxidation retardants as SOj absorbent. This allows selection of a solvent blend that can be varied and optimized depending on the feed gas composition and pressure. OBJECTS OF THE INVENTION
Primary object of the present invention is to provide a novel process for removing sulfur dioxide from gas streams.
Another object of the present invention is to use a solvent blend of chemical and physical solvents and sulfite oxidation inhibitors for removing sulfur dioxide from gas streams using a novel solvent blend.
Yet another objective of the present invention is to use sulfite oxidation inhibitors along with the solvent blend which reduce formation of heat stable salts and increase solvent life
Still another object of the present invention is to absorb sulfur dioxide in the solvent blend at low temperatures.
Another object of the present invention is to provide a process for removing sulfur dioxide gas streams produced by various processes such as utility boilers, refinery fluid catalytic cracking (FCC) units, Claus sulfur recovery units (SRU) and sulfide smelters. SUMMARY OF THE INVENTION
The present invention describes a novel process for sulfur dioxide removal from a gas stream comprising the steps of (a) absorption of said gas stream with a solvent blend; and (b) removing sulfur dioxide from said solvent blend in a regenerator.
In another embodiment of the present invention the gas stream contains upto 20 volume % of sulfur dioxide.
In yet another embodiment of the present invention" the solvent blend comprises chemical solvents and physical solvents.
In still another embodiment of the present invention the solvent blend further consists of sulfite oxidation inhibitors.
In another embodiment of the present invention the chemical solvents are diamines selected from a group comprising l-(2-hydroxyethyl) piperazine, l-(2-aminoethyl) piperazine, piperazine, and l-(2-methyl) piperazine and combinations thereof.
In still another embodiment of the present invention the physical solvents are selected from a group comprising quinoline, tri-ethylene glycol, di-methyl ether, tetra-ethylene glycol, sulfolane and combinations thereof.
In yet another embodiment of the present invention the sulfite oxidation inhibitors are selected from a group comprising ethylene diamines, tetra acetate (EDTA), ascorbic acid, N-N-Diethylhydroxyl amine (DEHA), di-phenyl carbazone, hydroquinone and combinations thereof.
In another embodiment of the present invention the concentration of chemical solvents in the solvent blend is in the range of 5 to 35 weight %, the concentration of physical solvents in the solvent blend is in the range of 0 to 20 weight % and the concentration of sulfite oxidation inhibitors is in the range of 100-2000 mg/liter.
In yet another embodiment of the present invention the absorption is performed at temperature ranging from 10°C to 65°C and an absolute pressure of 1 atmosphere or higher.
In still another embodiment of the present invention the regenerator is an amine regenerator comprising a reboiler, a stripping column and a condenser wherein the reboiler is maintained at a temperature from 102°C to about 120°C, at an absolute pressure of 1.05 to 2.0 atmosphere and the condenser is maintained at a temperature in therangeof35°Cto55°C.
In another embodiment of the present invention the first nitrogen of the diamines is reacted with an acid preferably sulfuric acid.
In still another embodiment of the present invention for operation demanding low regeneration energy the preferred chemical solvent is l-(2-hydroxyethyl) piperazine at concentration in the range of 5-10 wt % in water and for operation demanding low treated gas SO2 concentrations, the preferred chemical solvent is a mixture of l-(2-hydroxyethyl) piperazine and piperazine at total amine concentrations in the range of 5-35 wt % in water.
BRIEF DESCRIPTION OF THE ACCOMPANYING DRAWINGS Figure 1: Flow diagram of regenerative SCh removal process. Figure 2: VLB curves for physical and chemical solvents at absorber conditions. DESCRIPTION OF THE INVENTION
The present invention proposes a process for regenerative SO2 removal from various fuel gases. The process takes as input gases with SC>2 concentration varying
from 2000 ppmv to 20 vol%, and produces a treated gas stream with less than 500 ppmv SO2 and a concentrated SO2gas stream with over 90 mole% SC>2.
The process comprises a SC>2 absorber column, a solvent regenerator column with associated bottom reboiler and overhead condenser, and associated heat exchangers, pumps and storage tanks. Figure-1 gives a schematic flow diagram for the said process.
The unit configuration is essentially identical to that of typical petroleum refinery gas sweetening unit. It comprises of an 862 absorber column where preconditioned (cooled to less than 65°C and essentially particle free) SO2 containing fuel gas [1] is scrubbed with cooled lean amine absorbent [3] by counter-current contact. The gas leaving the absorber [2] has SC>2 content below 500 ppmv. Units can be designed to achieve treated gas 862 levels below 100 ppmv. The absorber can employ packing or tray contacting devices. For large volume, low SC>2 concentration fuel gases spray tower contactors can also be used. The SC>2 rich solvent leaving the absorber [4] is heated in a cross-exchanger and fed to a SCh regenerator column. The regenerator column is essentially a distillation column with a bottom reboiler and an overhead condenser. The regenerator column can use packing or trays as contacting internals. The amine leaving the bottom of the 862 regenerator [5] enters the reboiler, where heat is applied in a steam or electrically-heated bottoms reboiler to strip SC>2 from the SO2 rich solvent. 862 and water vapors from the reboiler [6] are returned to the regenerator and serve as the stripping agent. The 862 rich overhead vapors [7] are passed through a water-cooled condenser and sent to a reflux drum where condensed water vapors are separated from the concentrated SC>2 vapor. The exit gases from the reflux drum contains water saturated SC>2 gas, typically over 90 mole% 862. This gas is processed in a downstream sulfur recovery plant, acid plant, 862 liquefaction plant. A portion of the condensed water [8] is refluxed to the top of the regenerator column. Another portion of the condensed water [9] is mixed with lean amine leaving the reboiler [10]. This partial bypass of the cooled condensate improves the thermal efficiency of the process. Typically the regenerative 862 process requires very high total reflux ratios and high reboiler energy input. The combined streams [9] and [10] constitute the regenerated lean amine which is recycled to the SC>2 absorber after cooling in the amine heat exchanger and amine cooler. The above description covers the major process equipments of the said process.
The regenerative SO2 removal process uses an aqueous absorbent, which is a blend of chemical and physical solvents, and sulfite oxidation inhibitors. The process can also include solvent particulate and chemical filters, including a heat stable salt removal unit. These are externally supplied items based on existing technologies. Process Chemistry
SO2 is an acidic gas whose pKa for dissociation to bisulfite in water 25°C is 1.88. Thus all bases with pKa greater than 5 are good absorbents for this gas. Strong bases such as caustic soda, alkylamines, alkanolanines, etc. serve as effective absorption agents for 862, but are not regenerable thermally. Thus, they cannot be effectively used in regenerative 862 -removal process.
Thermodynamic evaluation indicates that bases with basicity intermediate to the following two aqueous phase dissociation reaction of SO2 are optimal for regenerative applications.
R, : S02 +H2OC=^> H+ + HSCV pKa = 1 .88 @ 25°C
R2: HSO3fe> H+ + SO3 2" pKa = 7.69 @ 25°C
On this basis, bases with pKa of about [7.69+1. 88]/2 = 4.8 have optimal properties for regenerative applications. The basicity of the second nitrogen of several diamines have basicity lying in the range from 2 to 7, and more preferably in the range 4-6. Based on this criterion several diamines are selected in the present invention for evaluation as effective solvents for the regenerative SO2 removal process.
The diamines solvents used in the present process have 2 nitrogen atoms. The first nitrogen is a strong base and is neutralized by addition of an acid, usually sulfuric acid.
R3: HN-R,-R2-NH + H2SO4 = HN-RrR2-NH2+ -HSCV
This reaction is practically irreversible. The second nitrogen has lower basicity and is used for regenerative SO2 capture.
R4: HN-R,-R2-NH + *H2SCV + SO2 + H2O = -HO4S-+ H2N-R,-R2-NH2+
This reaction is reversible. At absorber temperature of 40-600°C the reaction proceeds to the right, while at regenerator temperatures of 100-1200°C it proceeds to the left. The solvents have pH in the range 3.5 to 6.5. This is low compared to the pH of alkanol amine solutions for H2S and CO2 removal of 8.0 to 10.0. The co-absorption of CC>2 can also occur via the reaction:
R5: HN-R,-R2-NH2+ 'HSO4'+ CO2 + H2O = HO4S-+H2N-R|-R2-NH2+ 'HCO3"
However, the solvent is selected of suitably low basicity of second nitrogen to minimize CO2 absorption. The preferred chemical solvents identified for the present process are in general heterocyclic diamines with second dissociation constant (pKa 2) in the range of 4-6. The general structure of these diamines is
(Figure Remove)
(Figure Remove)
represents piperazine, [C2H4NH]2.
More specifically the selected heterocyclic amines are l-[2-hydroxyethyl] piperazine, ]-[2-aminoethyl] piperazine, piperazine, and bis-[hydroxyethyl] piperazine.
The physical solvents used are polar organic chemicals, which act as Lewis bases and absorb SO2 effectively at high SO2 partial pressures thereby allowing high solvent capacities for high concentration SO2 gases. They also allow solvent regeneration with lower heat input.
The combination of chemical and physical solvents allows extending the range of process conditions that is handled in terms of feed gas SO2 concentration and solvent loading. Physical solvent equilibrium SO2 holding capacity increases with increasing feed gas SO2 partial pressure. This is in contrast to chemical solvents which have a maximum equilibrium SO2 capacity for a given amine strength. This is illustrated in the SO2 VLB curves in physical and chemical solvents in Figure-2. This aspect of physical solvents gives added flexibility of operation where feed gas SO2
concentrations fluctuate over time. For operation with a suitable blend of chemical and physical solvents large fluctuations in SC>2 concentration can be handled without resorting to significant change in solvent flow rates as the solvent capacity increases with increased feed gas SC>2 concentration. Thus, the blend of chemical and physical solvents works by combing the superior SO2 holding capacity of physical solvents at high SC>2 pressures, and the superior power of chemical solvents to ensure low treated gas 862 concentrations
The preferred physical solvents for the present process are quinoline, tri-ethylene glycol di-methyl ether, tetra-ethylene glycol di-methyl ether, and sulfolane.
The chemical solvents lead to interfacial mass-transfer rate enhancement leading to faster loading of both the chemical as well as the physical solvent. This in turn leads to smaller contactor sizes for achieving a given amine SC>2 loading in the presence of physical solvents, which otherwise typically require larger contactor size.
The presence of oxygen in the feed gas can result in oxidation of sulfite to sulfate in the aqueous solutions. This leads to formation of heat stable salts and reduced solvent capacity for SO2 capture, since the reaction is not reversible at regeneration conditions.
R5: -H04S'+H2N-RI-R2-NH2+ -HSO3' + 0.5 O2 = -HO4S'+H2N-R,-R2-NH2+ «HS(V
The formation of heat stable salts is reduced by additions of sulfite oxidation retardants. The sulfite oxidation retardants used in the present invention are ethylene diamine tetra acetate [EDTA}, ascorbic acid, N-N-diethyl hydroxyl amine [DEHA], di-phenyl carbazone, hydroquinone, and mixtures thereof. However, HSS formation cannot be completely eliminated and a small periodic bleed and make-up of solvent is required.
The present invention is illustrated and supported by the following examples. These are merely representative examples and optimization details and are not intended to restrict the scope of the present invention in any way. Example-1
Several diamines are tested for regenerative SO2 removal. The parameters evaluated are net cyclic capacity and ease of regeneration. The feed gas used is 1% SC>2 in N2. Absorption is done at atmospheric pressure and 40°C. Regeneration is done at atmospheric pressure, which corresponds to a boiling temperature of 102°C.
Regeneration apparatus includes an overhead condenser maintained at 40°C for condensation of water vapors. Table-1 shows a summary of the results. The net cyclic SC>2 holding capacity (defined as the difference of the loading achieved after absorption and the loading achieved after regeneration) is highest for l-(2-hydroxyethyl) piperazine (HEP) followed by that of piperazine. The regeneration time is also lowest for these tow diamines indicating ease of regeneration. Thus these data indicate piperazine and l-(2-hydroxyethyl) piperazine (HEP) are superior solvents for regenerative 862 removal. Table-l: Net cyclic capacity and regenerability comparison of some diamines.

(Table Remove)
Example-2
Sulfide smelter off gas treating is one of the areas where the present process can be used for producing concentration SO2 gas for feed to sulfuric acid plants. Batch smelting processes operate in cycles and lead to production of fuel gases of varying flow rates and SC>2 concentration. Typically fuel gas SC>2 concentration can vary between 2-12 mole %, while the overall gas flow rate varies about 10-20%. For treating fuel gas with such a large fluctuation of SC^ concentration, the present process employing a blend of chemical and physical solvents allows the SC>2 removal unit to operate with minimal fluctuation in amine circulation rates. This results from the increased 862 holding capacity of the solvent at high SCK partial pressures due to the presence of physical solvents. The composition of the amine absorbents chemical and physical solvent constituents is selected based on process parameters such as feed gas SO2 concentration range, cycle times, treated gas SCh specification, etc. The reduced fluctuation in circulation rates allows use of smaller absorber and regenerator columns, and associated holding tanks for rich and lean amines. This leads to ignificant reduction in high MOC specification equipment costs.
Example -3
The optimal process operating conditions are identified with respect to regeneration energy equipment. Table-2 shows the effect of variation of reboiler pressure and temperature on specific steam consumption (SSC, Kg steam/Kg SO2 released) for a solvent comprising 10 wt% piperazine and 10 wt% sulfolane. These results are obtained based on process simulation with models developed for the present process. Table-2: Effect of reboiler pressure on solvent regeneration

(Table Remove)
*Lean solution loading = 0.01 mole fraction
Use of increased regeneration pressure upto 2.0 bara allows significant reduction in steam consumption and reflux ratio. It also allows production of higher purity SC>2 gas. The main advantages of the present invention are:
1. A blend of chemical and physical solvents facilitates handling of large
fluctuations in SC>2 concentration without resorting to changes in solvent
flow rates because the solvent capacity increases with increased feed gas
S(>j concentration.
2. The use of chemical solvents leads to interfacia! mass-transfer rate
enhancement leading to faster loading of both the chemical as well as the
physical solvent.
3. the present invention uses small contactor sizes for achieving a given
amine SOj loading in the presence of physical solvents, which otherwise
typically require large contactor size.
4. Use of pressures and temperatures significantly higher than atmospheric
boiling is possible without significantly increased amine degradation for
the specific amine blends developed in the present process.

We claim
1. A process for sulfur dioxide removal from a gas stream comprising the steps
of (a) absorption of said gas stream with a solvent blend comprising chemical
solvents and physical solvents; and (b) removing sulfur dioxide from said
solvent blend in a regenerator.
2. The process as claimed in claim 1 wherein said gas stream contains upto 20
volume % of sulfur dioxide.
3. The process as claimed in claim 1 wherein said solvent blend further consists
of sulfite oxidation inhibitors.
4. The process as claimed in claim 1 wherein said chemical solvents are
diamines selected from a group comprising 1 -(2-hydroxyethyl) piperazine, 1-
(2-aminoethyl) piperazine, piperazine, and l-(2-methyl) piperazine and
combinations thereof.
5. The process as claimed in claim 4 wherein the concentration of said chemical
solvents in the solvent blend is in the range of 5 to 35 weight %.
6. The process as claimed in claim 1 wherein said physical solvents are selected
from a group comprising quinoline, tri-ethylene glycol, di-methyl ether, tetra-
ethylene glycol, sulfolane and combinations thereof.
7. The process as claimed in claim 6 wherein the concentration of said physical
solvents in the solvent blend is in the range of 0 to 20 weight %.
8. The process as claimed in claim 3 wherein said sulfite oxidation inhibitors are
selected from a group comprising ethylene diamines, tetra acetate (EDTA),
ascorbic acid, N-N-Diethylhydroxyl amine (DEHA), di-phenyl carbazone,
hydroquinone and combinations thereof.
9. The process as claimed in claim 8 wherein the concentration of said sulfite
oxidation inhibitors is in the range of 100-2000 mg/liter.
10. The process as claimed in claim 1 wherein said absorption is performed at
temperature ranging from 10°C to 65°C and an absolute pressure of 1
atmosphere or higher.
11. The process as claimed in claim 1 wherein said regenerator is an amine
regenerator comprising a reboiler, a stripping column and a condenser.
12. The process as claimed in claim 11 wherein said reboiler is maintained at a
temperature from 102°C to about 120°C, at an absolute pressure of 1.05 to 2.0
atmosphere.

13. The process as claimed in claim 11 wherein said condenser is maintained at a
temperature in the range of 35°C to 55°C.
14. The process as claimed in claim 4 wherein the first nitrogen of said diamines
is reacted with an acid preferably sulfuric acid.
15. The process as claimed in claim 4 wherein for operation demanding low
regeneration energy the preferred chemical solvent is l-(2-hydroxyethyl)
piperazine at concentration in the range of 5-10 wt % in water.
16. The process as claimed in claim 4 wherein for operation demanding low
treated gas SC>2 concentrations, the preferred chemical solvent is a mixture of
l-(2-hydroxyethyl) piperazine and piperazine at total amine concentrations in
the range of 5-35 wt % in water.
17. A process for removing sulfur dioxide from a gas stream substantially as
hereinbefore described and with reference to the foregoing examples.