WO2018078065A1

WO2018078065A1 - Process for removing sulfur dioxide from a gas stream

Info

Publication number: WO2018078065A1
Application number: PCT/EP2017/077542
Authority: WO
Inventors: Michel Ouimet; Christopher Willis
Original assignee: Shell Internationale Research Maatschappij B.V.; Cansolv Technologies Inc
Priority date: 2016-10-27
Filing date: 2017-10-27
Publication date: 2018-05-03

Abstract

The invention relates to a process for removing SO₂ from gas by contacting it with an aqueous lean absorbing medium in a primary absorption zone. The absorbing medium comprises an amine and 1 to 1.2 eq/amine mole of HSS, and has a pH of less than 6. The absorbing medium is regenerated. HSS is removed from a part of the regenerated absorbing medium. Diluted HSS lean regenerated absorbing medium is used in a second absorption zone to absorb SO₂ from off-gas leaving the first absorption zone. The diluted regenerated absorbing medium comprises an amine and 0.05 to 0.6 eq/amine mole of HSS, and has a pH between 6.5 and 8. The off-gas leaving the second absorption zone comprises a low amount of SO₂ which may be less than 5 ppmv SO₂.

Description

PROCESS FOR REMOVING SULFUR DIOXIDE FROM A GAS STREAM

Field of the invention

The present invention relates to a process for removing sulfur dioxide ( SO2 ) from a feed gas stream. The present invention especially relates to a process suitable to selectively capture sulfur dioxide ( SO2 ) from a feed gas stream, more especially to remove SO2 from a gas stream while not at the same time removing CO2 from the gas stream.

Background to the invention

It is known that SO2 is more soluble in water than many other components of feed gas streams. For example, measured at 1.013 bar 0°C, the solubility of SO2 in water is 228 g/L whereas the solubility of carbon dioxide and hydrogen sulfide in water is 3.369 g/L and 7.100 g/L, respectively.

The solubility of SO2 in many other pure solvents has also been widely studied. See, for example, Fogg and Gerrard, 1991 (Solubility of Gases in Liquids, John Wiley and Sons, Chichester, U.K.) for a summary of the

literature solubility data of SO2 .

Regenerable absorbents can be used to remove SO2 from feed gas streams. Typically, a lean aqueous medium comprising the absorbent is exposed to a SO2 containing feed gas stream, and then SO2 is absorbed by the medium producing a SO2 lean gas stream and a spent absorbing medium. Removal (recovery) of the absorbed S02 from the spent absorbing medium to regenerate the aqueous medium and to provide gaseous SO2 is typically effected by gaseous stripping using steam generated in situ. Amine-based absorbents can be used for SO2 removal. See, for example, US5019361 which discloses the use of an aqueous absorbing medium containing a water-soluble half salt of a diamine. US7214358 discloses the use of an aqueous absorbing medium containing a water-soluble half salt of a diamine and an elevated level of heat stable salts (HSS) . Physical solvents can also be used as SO2 absorbents .

Commercially available steam-regenerable S02 capture technologies include those that rely on chemical solvents or physical solvents, such as Cansolv DSTM (amine-based absorbent-containing chemical solvent), LabsorbTM

(inorganic absorbent-containing chemical solvent),

ClausMasterTM (non-aqueous physical solvent), and Sea water process (chemical solvent) .

Use of a combination of solvents has also been disclosed. Indian Patent Application No. 2381/DEL/2006 describes a process for the removal of SO2 using a solvent blend comprising chemical and physical solvents. US20130039829 describes a process for the capture of sulfur dioxide from a gaseous stream utilizing a

regenerable diamine absorbent comprising a diamine and a weak organic acid, such as formic acid.

In some processes S02 is removed from gas in an absorption zone, whereby S02 lean gas leaves the

absorption zone and rich solvent is withdrawn and sent to regeneration zone. Regenerated solvent is recycled to the absorption zone. Depending on the solvent used and the conditions in the absorption zone, the gas leaving the absorption zone still has a higher sulfur dioxide level than desired.

One regularly used method is to further treat the gas leaving the absorption zone with a strong alkaline, for example caustic soda in a polisher unit downstream of the S02 absorption zone. A disadvantage of this procedure is the need for the extra chemical, namely the strong alkaline. Another disadvantage is that it results in a waste stream containing strong alkaline. A further disadvantage is the risk of contamination of the amine with alkali metals or alkali earth metals.

US5262139 describes a process in which two absorption zones are used. In a primary absorption zone sulfur dioxide comprising gas is treated with a diamine of which a first amine group is in salt form associated with sulfite anions, and a second amine group is in free base form. The sulfur dioxide lean gas leaving the primary absorption zone is passed to a secondary absorption zone. In one process, the sulfur dioxide lean gas is contacted in the secondary absorption zone with a diamine with both amine groups in free base form. A disadvantage of this process, as mentioned in US5262139, is the volatility of the diamine with both amine groups in free base form, which increases the risk of amine emission. A solution proposed in US5262139 is to use in the secondary

absorption zone a diamine of which the first amine is in salt form associated with carbonate anions, and a second amine group in free base form. A drawback of this is that it requires contacting the sulfur dioxide lean gas leaving the primary absorption zone with a gas comprising carbon dioxide in a carbonation zone before passing it to the secondary absorption zone. This has several

disadvantages such as the requirement to use a further chemical in the process, the requirement of the extra process step of carbonation, the introduction of the risk of contamination with carbon dioxide of the solvent stream used in the primary absorption zone, and the requirement to handle extra chemicals in exit streams.

There is a need for a process with which sulfur dioxide (SO2) can be removed from a feed gas stream, and which process has a relatively low sulfur dioxide emission in the off-gas from the absorption zone, but without the disadvantages associated with a treatment with caustic soda, and without the disadvantages of a carbonation step between a primary and a secondary absorption step.

Summary of the invention

The invention relates to a process for removing sulfur dioxide from a feed gas stream, which process comprises :

(i) contacting the feed gas stream with an aqueous lean absorbing medium in a primary absorption zone to absorb sulfur dioxide and to form a sulfur dioxide lean treated gas stream and a spent absorbing medium;

wherein the aqueous lean absorbing medium comprises:

(a) a chemical solvent comprising a regenerable

absorbent which is an amine preferably a mono amine, a diamine, a polyamine, or a mixture thereof, most preferably a diamine;

(b) in the range of between 1 to 1.2 equivalent/amine mole heat stable salts;

wherein the pH of the lean absorbing medium is 6 or less, preferably 5.6 or less, more preferably in the range of from 4.5 to 5.6, even more preferably in the range of from 5.2 to 5.6; and

(ii) stripping, preferably steam stripping, absorbed sulfur dioxide from at least a part of the spent

absorbing medium obtained in step (i) in a regeneration zone to produce a regenerated aqueous absorbing medium and sulfur dioxide; and

(iii) recycling a part of the regenerated aqueous absorbing medium obtained in step (ii) to step (i) ; and (iv) removing heat stable salts from a second part of the regenerated aqueous absorbing medium obtained in step

(ii), preferably by means of an ion exchange resin, electrodialysis, crystallization, or thermal reclamation;

(v) diluting at least a part of the regenerated aqueous absorbing medium having a reduced heat stable salt content as obtained in step (iv) with water;

(vi) contacting diluted absorbing medium as obtained in step (v) with at least a part of the sulfur dioxide lean treated gas stream obtained in step (i) in a secondary absorption zone to absorb sulfur dioxide and to form a further treated lean gas stream and a spent or partly spent absorbing medium,

wherein the diluted absorbing medium comprises:

(a) the chemical solvent comprising a regenerable

absorbent;

(b) in the range of between 0.05 to 0.6

equivalent/amine mole heat stable salts;

wherein the pH of the diluted absorbing medium is in the range of from 6.5 to 8.0, preferably in the range of from 6.7 to 7.1; and

(vii) recycling at least a portion of the spent or partly spent absorbing medium obtained in step (iv) and/or at least a portion of the spent or partly spent absorbing medium obtained in step (vi) to step (i) .

The process of the present invention is suitable to remove sulfur dioxide (SO2) from a feed gas stream while having a relatively low sulfur dioxide emission, and at the same time avoiding the disadvantages associated with a treatment with caustic soda, and avoiding the

disadvantages of a carbonation step between a primary and a secondary absorption step.

The process of the present invention is less complex as compared to caustic treatment of absorption off-gas, and as compared to a process with a carbonation step between a primary and a secondary absorption step. It does not require an extra chemical. And it does not result in extra waste streams. It is safe. And it does not have the risk of contaminating the absorbing medium used in the primary absorption zone.

The process of the present invention is highly advantageous as it results in very low sulfur dioxide emissions. The off-gas leaving the secondary absorption zone comprises a very low amount of S02 which may even be less than 5 ppmv S02. Another advantage is that there is hardly any entrainment of diamine or polyamine in the off-gas leaving the secondary absorption zone.

Figures

Figure 1 shows a schematic diagram of a preferred embodiment of a line-up for a process according to the invention .

Figure 2 shows data of a test according to the invention. It shows an aggregated plot of pH and S02 emissions from the second absorption zone.

Detailed description of the invention

(i) contacting the feed gas stream with an aqueous lean absorbing medium in a primary absorption zone to absorb sulfur dioxide and to form a sulfur dioxide lean treated gas stream and a spent absorbing medium; wherein the aqueous lean absorbing medium comprises:

(a) a chemical solvent comprising a regenerable

(b) in the range of between 1 to 1.2 equivalent/amine mole heat stable salts;

(iii) recycling a part of the regenerated aqueous absorbing medium obtained in step (ii) to step (i) ; and

(iv) removing heat stable salts from a second part of the regenerated aqueous absorbing medium obtained in step

wherein the diluted absorbing medium comprises: (a) the chemical solvent comprising a regenerable absorbent ;

(b) in the range of between 0.05 to 0.6

equivalent/amine mole heat stable salts;

The invention relates to a process for removing sulfur dioxide from a feed gas stream. The feed gas stream used in step (i) comprises S02 and may comprise C02. The process steps are preferably performed in the order in which they are presented. Preferably the absorbing medium is present in a single liquid phase during step (i) . Preferably the absorbing medium is present in a single liquid phase during step (ii) .

Preferably the absorbing medium is present in a single liquid phase during step (vi) .

Step (i)

In step (i) a feed gas stream comprising sulfur dioxide is contacted with an aqueous lean absorbing medium in a primary absorption zone. Sulfur dioxide is absorbed. A sulfur dioxide lean treated gas steam is formed. And a spent absorbing medium is formed.

The aqueous lean absorbing medium comprises:

(a) a chemical solvent comprising a regenerable

absorbent which is an amine preferably a mono amine, a diamine, a polyamine, or a mixture thereof, most preferably a diamine; (b) in the range of between 1 to 1.2 equivalent/amine mole of heat stable salts.

The feed gas stream comprises sulfur dioxide. Sulfur dioxide is commonly present in effluent streams from a variety of commercial sources. Examples are stack gases from coal fired power plants, from industrial boilers, from smelting, and from metallurgical roasting

operations, and tail gas streams from Claus sulfur plants, from refineries and from chemical plants.

A sulfur dioxide comprising gas, for example an effluent stream of a commercial source, may be treated before use in step (i) of the present invention.

For example, the gas may be cooled, for example by quenching, or it may be subcooled. Additionally or alternatively the gas may be de-dusted. Additionally or alternatively the gas may be de-acidified. In one embodiment the gas is (sub) cooled and de-dusted, and optionally de-acidified before use in step (i) of the present invention.

Optionally sulfur dioxide is removed from a sulfur dioxide comprising gas before use in step (i) . In most cases, however, it is not necessary to remove sulfur dioxide from an effluent stream of a commercial source as the process of the present invention is suitable for treating gas streams having a high amount of sulfur dioxide .

The sulfur dioxide concentration in the feed gas stream used in step (i) may vary. Preferably the sulfur dioxide concentration in the feed gas stream used in step (i) is in the range of between 800 ppmv and

45 volume percent, more preferably in the range of between 800 ppmv and 11 volume percent. The feed gas stream used in step (i) may comprise C02. With the process of the present invention SO2 is removed from a gas stream while, at the same time, not or hardly removing CO2 from the gas stream. With the process of the invention a pure S02 stream can be obtained that can be used for sulfuric acid make, or for use in a sulfur reduction unit in a Claus application. When stripping sulfur dioxide from the spent absorbing medium in step (ii) , sulfur dioxide is obtained. The obtained sulfur dioxide is pure. The obtained sulfur dioxide does not comprise or hardly comprises contaminants such as C02. The obtained sulfur dioxide is water saturated. The obtained sulfur dioxide preferably comprises about 99wt% S02, calculated on dry product stream. If desired, water may be removed from the sulfur dioxide, e.g. by means of distillation .

The pH of the lean absorbing medium is 6 or less, preferably 5.6 or less, more preferably in the range of from 4.5 to 5.6, even more preferably in the range of from 5.2 to 5.6.

The contact of the absorbing medium with the SO2 containing gas stream may be effected within the

temperature range from the freezing point of the

absorbent up to 75°C, or from 10°C to 60°C, or from 10°C to 50°C.

The pressure in the primary absorption zone may be in the range of between 1.0 and 2 bara.

Preferably the aqueous lean absorbing medium used in step (i) comprises in the range of from 10 to 35 wt% amine, more preferably 13 to 25 wt% amine.

Preferably the aqueous lean absorbing medium used in step (i) comprises in the range of between 25wt% and 85wt% water. The aqueous lean absorbing medium comprises a chemical solvent and heat stable salts.

The chemical solvent comprises a regenerable

absorbent which is an amine preferably a mono amine, a diamine, a polyamine, or a mixture thereof, most

preferably a diamine.

The amount of heat stable salts in the aqueous lean absorbing medium may be in the range of between 0.9 to 1.3 equivalent/amine mole. Preferably the amount of heat stable salts in the aqueous lean absorbing medium is in the range of between 1 to 1.2 equivalent/amine mole. In other words, per mole amine, the aqueous lean absorbing medium may comprise in the range of between 0.9 to 1.3 mole equivalent HSS, and preferably, per mole amine, the aqueous lean absorbing medium comprises in the range of between 1 to 1.2 mole equivalent HSS. The heat stable salt may be a salt of a monoprotic, diprotic or

polyprotic acid.

Step (ii)

In step (ii) absorbed sulfur dioxide from at least a part of the spent absorbing medium obtained in step (i) is stripped, preferably steam stripped, in a regeneration zone. A regenerated aqueous absorbing medium is produced. Sulfur dioxide is stripped off. Preferably gaseous sulfur dioxide is obtained.

Preferably step (ii) is performed in a reboiler, more preferably in a kettle reboiler, forced circulation reboiler, fired reboiler, falling film reboiler, direct steam reboiler, or thermosyphon, more preferably in a thermosyphon .

The reboiler may be heated by hot oil, electricity or steam, preferably steam. Alternatively, direct steam addition can be utilized. The temperature in the regeneration zone may be in the range of between 100 and 150 °C.

The pressure in the regeneration zone may be in the range of between 1.0 and 4.8 bara, preferably between 1.0 and 3 bara.

Preferably at least 97 vol%, preferably at least 99 vol%, more preferably at least 99.9 vol% of the spent absorbing medium formed in step (i) is stripped,

preferably steam stripped, in step (ii) .

The regenerated aqueous absorbing medium obtained in step (ii) is withdrawn from the regeneration zone and split in at least two streams. One stream of regenerated aqueous absorbing medium is recycled to the primary absorption zone where it is used to absorb sulfur dioxide from gas entering the primary absorption zone; this is step (iii) . A second stream of regenerated aqueous absorbing medium is used in a second absorption zone to remove sulfur dioxide from S02 lean gas stream which leaves the primary absorption zone; this is step (vi) . The second stream of absorbing medium is diluted with water before and/or in the second absorption zone (this is step (v) . In other words, step (v) may be performed before and/or during step (vi) .

Step (iii)

In step (iii) a part of the regenerated aqueous absorbing medium obtained in step (ii) is recycled to step (i) . It is recycled to the first absorption zone where it is used to absorb sulfur dioxide from the feed gas stream. Additionally or alternatively fresh aqueous absorbing medium may be added to the primary absorption zone .

Step (iv) In step (iv) heat stable salts are removed from a second part of the regenerated aqueous absorbing medium obtained in step (ii) .

Heat stable salts are commonly formed in sulfur dioxide absorption processes during both the absorption and regeneration steps as by-product. The presence of HSS reduces the absorption capacity of the absorbing medium for sulfur dioxide. A limited amount of HSS is

acceptable. One way of controlling the amount of HSS in the absorbing medium is a treatment to remove HSS from regenerated absorbing medium. As a result, more amine groups are in free base form.

Typically, only a slip stream of the regenerated absorbing medium needs to be treated for heat stable salt removal or heat stable anion removal. In one embodiment HSS is removed from a small fraction, preferably less than 10 percent, preferably less than 5 percent, more preferably less than 2 percent of the total amount of regenerated absorbent. The often is sufficient to achieve a substantial increase in absorption capacity for sulfur dioxide .

HSS are preferably removed by means of an ion exchange resin, electrodialysis , crystallization, and/or thermal reclamation.

After removing almost all or a part of the HSS more amine groups are in free base form. Preferably in the range of from 40% to 97%, more preferably of from 50% to 97%, even more preferably from 75% to 97% of the amine groups in the regenerated aqueous absorbing medium, which has a reduced heat stable salt content, as obtained in step (iv) is in free base form.

Step (v) In step (v) at least a part of the regenerated aqueous absorbing medium having a reduced heat stable salt content as obtained in step (iv) is diluted with water .

Step (vi)

In step (vi) diluted absorbing medium as obtained in step (v) is contacted with at least a part of the sulfur dioxide lean treated gas stream obtained in step (i) in a secondary absorption zone. Sulfur dioxide is absorbed. A further treated S02 lean gas stream and a spent or partly spent absorbing medium are formed. The diluted absorbing medium comprises:

(a) the chemical solvent comprising a regenerable

absorbent; this is the chemical solvent as defined in the description of step (i);

(b) in the range of between 0.05 to 0.6

equivalent/amine mole of heat stable salts.

The pH of the diluted absorbing medium is in the range of from 6.5 to 8.0, preferably in the range of from 6.7 to 7.1. Water may be added and removed during step (vi) .

The primary and secondary absorption zones may be in the same absorber vessel or in separate absorber vessels.

As mentioned above, the sulfur dioxide concentration in the feed gas stream used in step (i) preferably is in the range of between 800 ppmv and 45 volume percent, more preferably in the range of between 800 ppmv and 11 volume percent. Step (vi) is especially advantageous when the sulfur dioxide lean treated gas stream obtained in step (i) has a sulfur dioxide concentration in the range of between 35 and 250 ppmv, preferably 50 to 250 ppmv. The off-gas leaving the secondary absorption zone comprises a very low amount of S02 which may even be less than 5 ppmv S02.

temperature range from the freezing point of the

absorbent up to 75°C, or from 10°C to 60°C, or from 10°C to 50°C.

The pressure in the secondary absorption zone may be in the range of between 1.0 and 2 bara .

As mentioned above, preferably the aqueous lean absorbing medium used in step (i) comprises in the range of from 10 to 35 wt% amine, more preferably 13 to 25 wt% amine. Preferably the diluted absorbing medium used in step (vi) comprises in the range of from 0.5 to 9.5 wt% amine .

As mentioned above, preferably the aqueous lean absorbing medium used in step (i) comprises in the range of between 25wt% and 85wt% water. Preferably the diluted absorbing medium used in step (vi) comprises in the range of between 40wt% and 99wt% water.

The off-gas leaving the secondary absorption zone comprises a very low amount of S02 which may even be less than 5 ppmv S02. Another advantage of a process according to the present invention is that there is hardly any entrainment of diamine or polyamine in the off-gas leaving the secondary absorption zone.

During step (v) a further treated S02 lean gas stream and a spent or partly spent absorbing medium are formed. The S02 lean gas stream leaving the primary absorption zone comprises a relatively small amount of S02. And large part of the amines of the absorbing medium is in free base form. The spent absorbing medium formed during step (vi) in the second absorption zone thus may be only partly spent. Partly spent absorbing medium can be passed from the second to the first absorption zone, where it can absorb more sulfur dioxide.

Step (vii)

In step (vii) at least a portion of the spent or partly spent absorbing medium obtained in step (iv) and/or at least a portion of the spent or partly spent absorbing medium obtained in step (vi) is reclycled to step (i) .

The level of HSS in the absorbing medium used in step (i) may be controlled by addition of HSS lean absorbing medium as obtained in step (iv) and/or in step (vi) .

Additionally or alternatively at least a portion of spent or partly spent absorbing medium obtained in step (vi) is regenerated in the regeneration zone.

Absorbing medium

Preferably the regenerable absorbent is a diamine or polyamine which in half salt form has a pK_a value for the free nitrogen atom of 3.0 to 5.5, preferably 3.5 to 4.7, at a temperature of 20 °C in an aqueous medium.

More preferably the regenerable absorbent is a diamine or polyamine with a pKa value of the first amine group, of from about 7.0 to 9.0, preferably 7.5 to 8.5, and a pKa value of the second amine group is from about 3.0 to 5.5, preferably 3.5 to 4.7, at a temperature of 20 °C in an aqueous medium.

Preferably the regenerable absorbent is a diamine represented by the formula:

R² R>

N— R, \ N wherein R¹ is an alkylene of two or three carbon atoms a a straight chain or as a branched chain, R², R³, R⁴, and R⁵ may be the same or different and can be hydrogen, alkyl, hydroxyalkyl, aralkyl, aryl, or alkaryl, and any of R², R³, R⁴, and R⁵ may form cyclic structures.

More preferably the regenerable absorbent is a tertiary amine represented by the formula:

wherein R¹ is an alkylene of two or three carbon atoms as a straight chain or as a branched chain, and R², R³, R⁴, and R⁵ can be alkyl, hydroxyalkyl, aralkyl, aryl, or alkaryl, and any of R², R³, R⁴, and R⁵ may form cyclic structures .

Even more preferably the regenerable absorbent is piperazine, hydroxyethyl piperazine, bis-hydroxyethyl piperazine, hydroxyethylethylenediamine (HEED) , bis- hydroxyethylethylenediamine (bis-HEED) ,

1, 4-diazabicyclo [2.2.2] octane (DABCO) , 2- [2- aminoethyl] pyridine,

2-aminomethylpyridine, 3-amino 5-methylpyrazole, 3- aminopyrazole ,

3-methylpyrazole, Ν,Ν,Ν' ,Ν' -tetraethyldiethylenetriamine, Ν,Ν,Ν' ,Ν' -tetramethyldiethylenetriamine, 2-piperazinone

1, 4-bis [ 2-hydroxyethyl ] ,

or a combination thereof.

Most preferably the regenerable absorbent is

piperazine, hydroxyethyl piperazine, bis-hydroxyethyl piperazine, hydroxyethylethylenediamine (HEED) , bis- hydroxyethylethylenediamine (bis-HEED) , or a combination thereof .

Acid

Preferably the lean absorbing medium used in step (i) of the process of the present invention additionally comprises an organic acid and/or an inorganic acid, preferably an inorganic acid, more preferably one or more acids chosen from the group of nitric acid (HNO3) , hydrochloric acid (HC1) , sulfuric acid (H2SO4) and sulfurous acid (H2SO3) , even more preferably sulfuric acid (H2SO4) and/or sulfurous acid (H2SO3) .

Physical solvent

Preferably the lean absorbing medium used in step (i) of the process of the present invention additionally comprises a physical solvent. The physical solvent preferably has a vapour pressure less than 0.1 mmHg at 20°C with a boiling point equal to or higher than 240°C, the physical solvent more preferably is a polyol, a polycarbonate, an N-formyl morpholine, or a combination thereof.

More preferably the physical solvent is

polyethyleneglycol dimethylether (PEGDME) ,

tetraethyleneglycol dimethylether (TetraEGDME) ,

tetraethylene glycol (TetraEG) , triethyleneglycol monomethylether (TriEGMME) , or a combination thereof, preferably polyethyleneglycol dimethylether (PEGDME) .

Even more preferably the physical solvent is

polyethyleneglycol dimethylether (PEGDME) , and

wherein the regenerable absorbent is

4- [hydroxyethyl] piperazine (Hep), or

1, 4-bis [hydroxyethyl] piperazine (DiHep) , or

3-aminopyrazole, or a mixture of 4- [hydroxyethyl ] piperazine (Hep) and

1, 4-bis [hydroxyethyl] piperazine (DiHep) .

Sulfur dioxide recovery

In some embodiments, the processes as described herein further comprise a step of recovering the gaseous sulfur dioxide.

With the process of the invention a pure S02 stream can be obtained that can be used for sulfuric acid make, or for use in a sulfur reduction unit in a Claus application. The pure S02 stream is not or hardly contaminated with C02 or mercaptans which would

contaminate sulfuric acid, or which would contaminate a Claus unit .

S02 removal

In general, a suitable indicator for an appropriate choice of absorbent for use in the capture of a given gaseous acid gas contaminant (such as SO2) in a feed gas is the difference in the pK_a values between the acid gas in water and the absorbent .

The pK_a of an acid is defined as the negative logarithm to the base 10 of the equilibrium constant K_a for the ionization of the acid HA (e.g., H2SO3) , where H is hydrogen and A is a radical capable of being an anion

(1)

K_a = [H⁺] [A-] / [HA] (2) pKa = -loglO K_a (3)

For a basic absorbent B, the pK_a is for the

ionization reaction of the conjugate protonated acid of B, the species BH⁺: BH⁺ ^_ B + H⁺ (4 )

The reaction involved in the absorption of the acid gas contaminant HA by the basic absorbent B can be shown as follows :

HA + B—► BH⁺ + A- (5)

Reaction (5) is reversible:

BH⁺ + A^"—► HA + B (6)

When SO2 is dissolved in water, following reaction (1), bisulphite ions (HS03^~) and protons are formed. The proton may be ionically associated with the absorbent (for example, when an amine-based absorbent is used, the proton may be ionically associated with the sorbing nitrogen of the absorbent). The absorbed S02/desorbed SO2 equilibrium is illustrated in the above reaction (6) . Absorbed SO2 can be "stripped" from the spent absorbing medium as gaseous SO2 , for example and without

limitation, by the application of steam. In this

stripping process, desorbed S02 is released from the spent absorbing medium. "Stripping" is used herein to broadly encompass removal of absorbed SO2 from the spent absorbing medium, and should be understood as also, more specifically, encompassing releasing desorbed S02 from the spent absorbing medium.

Heat Stable Salts (HSS)

HSS may accumulate in the medium due to, for example, sulfite/bisulfite oxidation or disproportionation, or due to the absorption of acid mist from the feed gas. These salts are too stable to decompose under normal steam conditions for stripping SO2 from spent absorbing medium. Examples of such heat stable salts are those salts that are formed from strong acids such as sulfuric acid, nitric acid, or hydrochloric acid. If allowed to

accumulate, these heat stable salts would eventually completely neutralize the SO2 absorption capacity of the absorbent. Therefore, management of HSS in the solution may be an important part of the SO2 removal process to maintain performance over time.

The amount of HSS formed may be affected by the absorbent used and/or the concentration of the absorbent. The amount of HSS for an absorbing medium may be

controlled by using conventional means, such as an ion exchange resin, eletrodialysis unit or crystallization.

Amine purification units (APU) that are currently used industrially utilize weak anionic resins capable of some selectivity between sulfate (a strong conjugated base) and weaker conjugated bases in the absorbing medium. The performance of such weak base resins varies depending on the concentration of sulfate in solution. These resins do not always perform well if there is a low concentration of HSS.

Ways to control the level of HSS for an organic acid/physical solvent mixture may also include ion exchange with cyclo [ 8 ] pyrrole as the functional groups or by crystallization of alkaline sulfate salts (e.g.

Na2SC>4) , where the cation can be sodium or potassium, most often sodium. Another way of controlling the level of HSS in the organic acid/physical solvent mixture is precipitation of Ettringite (Ca₆Al₂ (S0₄) 2 (OH) 12 · 26H₂0) .

In the alternative, HSS could also be removed by ion pairing. Without being limited by theory, it is believed that a low HSS amount in the absorbing medium, in accordance with some embodiments of the invention, may reduce the efficiency of the exchange of HSS with a standard anionic weak base resin. In some embodiments, it may therefore be desirable to remove HSS by ion pairing, which may permit a higher rate of removal of HSS even when the amount of salts in solution is low. Ion pairing may be achieved, for example, by using a dual function resin having different ionic functional groups (such as a combination of phenol and quaternary amine functional groups) or by liquid-liquid extraction.

Without being limited to theory, it is believed that a strong base quaternary amine functional group

insensitive to suppressed salt concentrations will attract opposite charged anions regardless of their type. During regeneration, the phenolic functional group which is the active exchange site in the above described dual function resin, becomes negatively charged at a pH greater than 10.5, and repels the like charged anions. Summary

The present invention relates to a process for removing sulfur dioxide from a feed gas stream, which process comprises:

wherein the aqueous lean absorbing medium comprises:

(a) a chemical solvent comprising a regenerable

absorbent which is an amine preferably a mono amine, a diamine, a polyamine, or a mixture thereof, most preferably a diamine; (b) in the range of between 1 to 1.2 equivalent/amine mole heat stable salts;

wherein the diluted absorbing medium comprises:

(a) the chemical solvent comprising a regenerable

absorbent ;

(b) in the range of between 0.05 to 0.6

equivalent/amine mole heat stable salts; wherein the pH of the diluted absorbing medium is in the range of from 6.5 to 8.0, preferably in the range of from 6.7 to 7.1; and

The feed gas stream used in step (i) comprises S02 and may comprise C02.

Preferably the absorbing medium is present in a single liquid phase during steps (i) (ii) and (vi) .

Additionally or alternatively, the sulfur dioxide concentration in the feed gas stream is in the range of between 800 ppmv and 45 volume percent, preferably in the range of between 800 ppmv and 11 volume percent.

Additionally or alternatively, the sulfur dioxide lean treated gas stream obtained in step (i) has a sulfur dioxide concentration in the range of between 35 and 250 ppmv, preferably 50 to 250 ppmv.

Additionally or alternatively, the aqueous lean absorbing medium used in step (i) comprises in the range of from 10 to 35 wt% amine, preferably 13 to 25 wt% amine, and the diluted absorbing medium used in step (vi) comprises in the range of from 0.5 to 9.5 wt% amine.

Additionally or alternatively, step (ii) is performed in a reboiler, preferably in a kettle reboiler, forced circulation reboiler, fired reboiler, falling film reboiler, direct steam reboiler, or thermosyphon, more preferably in a thermosyphon.

Additionally or alternatively, at least 97 vol%, preferably at least 99 vol%, more preferably at least 99.9 vol% of the spent absorbing medium formed in step (i) is stripped, preferably steam stripped, in step (ii) . Additionally or alternatively, the regenerable absorbent is a diamine or polyamine which in half salt form has a pK_a value for the free nitrogen atom of 3.0 to 5.5, preferably 3.5 to 4.7, at a temperature of 20 °C in an aqueous medium.

Additionally or alternatively, the regenerable absorbent is a diamine or polyamine with a pKa value of the first amine group, of from about 7.0 to 9.0,

preferably 7.5 to 8.5, and a pKa value of the second amine group is from about 3.0 to 5.5, preferably 3.5 to

4.7, at a temperature of 20 °C in an aqueous medium.

Additionally or alternatively, in the range of from 40% to 97%, preferably of from 50% to 97%, more

preferably from 75% to 97% of the amine groups in the regenerated aqueous absorbing medium as obtained in step

(iv) is in free base form.

Additionally or alternatively, the regenerable absorbent is a diamine represented by the formula:

wherein R¹ is an alkylene of two or three carbon atoms as a straight chain or as a branched chain, R², R³, R⁴, and R⁵ may be the same or different and can be hydrogen, alkyl, hydroxyalkyl, aralkyl, aryl, or alkaryl, and any of R², R³, R⁴, and R⁵ may form cyclic structures.

Additionally or alternatively, the regenerable absorbent is a tertiary amine represented by the formula:

Additionally or alternatively, the regenerable absorbent is piperazine, hydroxyethyl piperazine, bis- hydroxyethyl piperazine, hydroxyethylethylenediamine (HEED) , bis-hydroxyethylethylenediamine (bis-HEED) , 1, 4-diazabicyclo [2.2.2] octane (DABCO) , 2- [2- aminoethyl] pyridine,

2-aminomethylpyridine, 3-amino 5-methylpyrazole, 3- aminopyrazole ,

3-methylpyrazole, Ν,Ν,Ν' ,Ν' -tetraethyldiethylenetriamine, Ν,Ν,Ν' ,Ν' -tetramethyldiethylenetriamine, 2-piperazinone 1, 4-bis [ 2-hydroxyethyl ] ,

or a combination thereof.

Additionally or alternatively, the lean absorbing medium additionally comprises an organic acid and/or an inorganic acid, preferably an inorganic acid, more preferably one or more acids chosen from the group of nitric acid (HNO3) , hydrochloric acid (HC1) , sulfuric acid (H2SO4) and sulfurous acid (H2SO3) , even more preferably sulfuric acid (H2SO4) and/or sulfurous acid (H2SO3) .

Additionally or alternatively, the lean absorbing medium additionally comprises a physical solvent, the physical solvent preferably having a vapour pressure less than 0.1 mmHg at 20°C with a boiling point equal to or higher than 240°C, the physical solvent more preferably being a polyol, a polycarbonate, an N-formyl morpholine, or a combination thereof. Additionally or alternatively, the physical solvent is polyethyleneglycol dimethylether (PEGDME),

tetraethyleneglycol dimethylether (TetraEGDME) ,

Additionally or alternatively, the physical solvent is polyethyleneglycol dimethylether (PEGDME), and wherein the regenerable absorbent is

4- [hydroxyethyl] piperazine (Hep), or

1, 4-bis [hydroxyethyl] piperazine (DiHep) , or

3-aminopyrazole, or

a mixture of 4- [hydroxyethyl ] piperazine (Hep) and

1, 4-bis [hydroxyethyl] piperazine (DiHep) .

Figure 1

The present invention will be further elucidated with reference to a drawing. Figure 1 shows a schematic diagram of a preferred embodiment of a line-up for a process according to the invention.

A sulfur dioxide comprising feed gas stream (1) is treated in an absorption zone (2) . The sulfur dioxide concentration in the feed gas stream (i) preferably is in the range of between 800 ppmv and 45 volume percent, preferably in the range of between 800 ppmv and 11 volume percent. The feed gas stream (1) is contacted with an aqueous lean absorbing medium in absorption zone (2) .

S02 rich absorbing medium (3) is regenerated in a regeneration zone (4) . Use may be made of an optional reboiler (5) .

An S02 comprising stream is heated and sent to a reflux accumulator (6) . An S02 product stream (7) is obtained at the top of the reflux accumulator (6) . This product stream (7) preferably comprises about 99wt% S02, calculated on dry product stream.

Optionally heat exchange takes place between S02 rich absorbing medium (3) and regenerated aqueous absorbing medium (8) . Optionally the regenerated aqueous absorbing medium (8) is heated additionally or alternatively by other means .

A part of the regenerated aqueous absorbing

medium (8) is directly recycled to the absorption zone (2) via line (9) . A second part of the regenerated aqueous absorbing medium (8) is sent to an amine

purification unit (APU) (11) via line (10) .

Heat stable salts (HSS) are removed from the

regenerated aqueous absorbing medium in APU (11) . HSS lean absorbing medium may be sent to the absorption zone

(2) via line (12) .

HSS lean absorbing medium obtained in the APU (11) is diluted with water. This may be performed at any suitable point before or during its use in secondary absorption zone (15), preferably before its use in secondary absorption zone (15) . HSS lean absorbing medium may, for example, be diluted in optional tank (13) to which water may be added (not shown) .

Optionally HSS lean absorbing medium is sent to an equalization zone or buffer zone.

Optional tank (13) may serve as equalization zone and may additionally or alternatively be the place at which the HSS lean absorbing medium obtained in the APU (11) is diluted with water.

Diluted HSS lean absorbing medium is contacted with sulfur dioxide lean treated gas (14) in a secondary absorption zone (15) . Preferably, sulfur dioxide lean treated gas (14) contains in the range of between 35 and 250 ppmv S02, more preferably in the range of between 50 and 250 ppmv.

Spent or partly spent absorbing medium may be sent to the primary absorption zone (2) via line (17) .

Alternatively it may be sent to regeneration zone (4); not shown.

Further treated gas (16) leaves from the top of the secondary absorption zone (15) . The further treated gas (16) may contain less than 5 ppmv S02.

EXAMPLES

The invention will now be illustrated by the

following examples .

A test was performed using a pilot unit. The pilot unit was equipped with a primary and a secondary

absorption zone and a regeneration zone. The process performed using the pilot unit was a process according to the invention.

The pilot unit was also equipped with several gas and liquid sampling points. The sampling points were used to take accurate measurements of the S02 concentration in the gas, and to take measurements of the HSS

concentration in the liquid samples.

Diluted regenerated aqueous absorbing medium was used in the second regeneration zone. At least a part of the diluted absorbing medium was circulated over this zone.

The circulation rate in this loop varied from 1.2 to 6 L/min. This equates to a wetting range of the sulfur dioxide lean treated gas stream obtained in step (i) of 2.3 to 11.5 m3/m2 per hour.

All tests which were conducted at the same

temperature and wetting rate. The S02 concentration in the sulfur dioxide lean treated gas stream leaving the first absorption zone (which was treated in the secondary absorption zone) was varied between 35 ppmv to 250 ppmv, calculated on dry basis .

The test conditions are summarized in Table 1.

Table 1: Range of test conditions

Figure 2 shows an aggregated plot of pH and S02 emissions from the second absorption zone as determined in the tests.

Correlation data were determined; the correlation between 2 variables as defined by:

Cmrel T,7) =

where * and >' are averages

The grouped linear correlation factor is -0.8. This indicates that the pH of the absorbing medium has a strong effect on S02 concentration leaving the second absorption zone.

The observed trend shows a negative variance between pH and outlet S02 concentration indicating that emissions decrease with increasing pH. The observed relationship between pH and emissions may be explained by the

chemistry of absorption. A higher pH signifies a free hydronium leaner environment. Under these conditions S02 solubility is promoted. The solubility enhancement of the pH appears to wear off as the pH increases above approximately 6.9-7. Beyond this point, further improvement in chemical enhancement no longer has effect, and S02 gas side diffusivity (i.e. increasing gas side resistance) in conjunction with mass transfer mechanics become the predominately limiting factors.

These tests demonstrate that fugitive emissions from the second absorption zone can be controlled to

concentrations below 5 ppmv on a dry basis.

Claims

C L A I M S

1. A process for removing sulfur dioxide from a feed gas stream, which process comprises:

wherein the aqueous lean absorbing medium comprises:

(a) a chemical solvent comprising a regenerable

(b) in the range of between 1 to 1.2 equivalent/amine mole heat stable salts;

(ii), preferably by means of an ion exchange resin, electrodialysis, crystallization, or thermal reclamation; (v) diluting at least a part of the regenerated aqueous absorbing medium having a reduced heat stable salt content as obtained in step (iv) with water;

wherein the diluted absorbing medium comprises:

(a) the chemical solvent comprising a regenerable

absorbent ;

(b) in the range of between 0.05 to 0.6

equivalent/amine mole heat stable salts;

2. The process according to claim 1, wherein the sulfur dioxide concentration in the feed gas stream is in the range of between 800 ppmv and 45 volume percent,

preferably in the range of between 800 ppmv and 11 volume percent .

3. The process according to claim 1 or 2, wherein the aqueous lean absorbing medium used in step (i) comprises in the range of from 10 to 35 wt% amine, preferably 13 to 25 wt% amine, and the diluted absorbing medium used in step (vi) comprises in the range of from 0.5 to 9.5 wt% amine .

4. The process according to any one of the above claims, wherein the regenerable absorbent is a diamine or polyamine with a pKa value of the first amine group, of from about 7.0 to 9.0, preferably 7.5 to 8.5, and a pKa value of the second amine group is from about 3.0 to 5.5, preferably 3.5 to 4.7, at a temperature of 20 °C in an aqueous medium.

5. The process according to any one of the above claims, wherein the regenerable absorbent is a diamine

represented by the formula:

wherein R¹ is an alkylene of two or three carbon atoms a a straight chain or as a branched chain, R², R³, R⁴, and R⁵ may be the same or different and can be hydrogen, alkyl, hydroxyalkyl, aralkyl, aryl, or alkaryl, and any of R², R³, R⁴, and R⁵ may form cyclic structures.

6. The process according to any one of the above claims, wherein the regenerable absorbent is a tertiary amine represented by the formula:

7. The process according to any one of the above claims, wherein the regenerable absorbent is piperazine,

hydroxyethyl piperazine, bis-hydroxyethyl piperazine, hydroxyethylethylenediamine (HEED), bis- hydroxyethylethylenediamine (bis-HEED) ,

1, 4-diazabicyclo [2.2.2] octane (DABCO) , 2- [2- aminoethyl] pyridine,

2-aminomethylpyridine, 3-amino 5-methylpyrazole, 3- aminopyrazole ,

1, 4-bis [ 2-hydroxyethyl ] ,

or a combination thereof.

8. The process according to any one of the above claims, wherein the lean absorbing medium additionally comprises an organic acid and/or an inorganic acid, preferably an inorganic acid, more preferably one or more acids chosen from the group of nitric acid (HNO3) , hydrochloric acid (HC1) , sulfuric acid (H2SO4) and sulfurous acid (H2SO3) , even more preferably sulfuric acid (H2SO4) and/or

sulfurous acid (H2SO3) .

9. The method according to any one of the above claims, wherein the lean absorbing medium additionally comprises a physical solvent, the physical solvent preferably having a vapour pressure less than 0.1 mmHg at 20°C with a boiling point equal to or higher than 240°C, the physical solvent more preferably being a polyol, a polycarbonate, an N-formyl morpholine, or a combination thereof .

10. The process according to claim 9, wherein the physical solvent is polyethyleneglycol dimethylether (PEGDME) , and

wherein the regenerable absorbent is

4- [hydroxyethyl] piperazine (Hep), or

1, 4-bis [hydroxyethyl] piperazine (DiHep) , or

3-aminopyrazole, or

a mixture of 4- [hydroxyethyl ] piperazine (Hep) and 1, 4-bis [hydroxyethyl] piperazine (DiHep) .