CN107580522A - Process for removal of aromatics from acid gas-lean feedstock for sulfur recovery - Google Patents

Abstract

The invention relates to a catalyst composition comprising less than 20 mol.% H₂A process for removing aromatics from a lean S gas, the process comprising: a) mixing the acid-depleted gas stream (1) with H in a first absorption zone (2)₂S-selective liquid absorbent solution (29) to produce spent H₂S stream (3) and enriched H₂S absorbent solution (4), b) introducing the absorbent solution (4) into a non-thermal stripping zone (8) where it is contacted with a stripping gas stream (7) to obtain spent C₄ ⁺Absorbent solution (9) of aliphatic and aromatic hydrocarbons and enriched aromatic hydrocarbons and C₄ ⁺A stripping gas stream (10) of aliphatic hydrocarbons, c) the stripping gas stream (10) obtained in step b) is brought into a second absorption zone (12) with H₂S-selective liquid absorbent solution (28) to obtain depleted H₂Stripping gas stream (13) of S and enriched H₂S absorbent solution (14), d) introducing the absorbent solution (9) obtained in step b) into a desorption zone (16), wherein H is introduced₂The S-selective liquid absorbent solution (17) is recovered and produces a lean acid gas.

Description

Process for removal of aromatics from acid gas-lean feedstock for sulfur recovery

technical field

The present invention relates to the removal of aromatics (BTX) such as benzene, toluene, ethylbenzene, and xylenes from acid-lean gases containing _CO2 and less than ₂₀ mol.% H2S prior to sulfur recovery, and those having 4 carbon atoms or more carbon atoms (C ₄ ⁺ ) aliphatic hydrocarbons.

Background technique

As trapped from naturally occurring deposits, natural gas consists primarily of light aliphatic hydrocarbons such as methane, propane, butane, pentane, and their isomers. Certain contaminants are naturally present in this gas and must be removed before the purified gas can be delivered for private use or commercial settings. These pollutants include aliphatic hydrocarbons with 4 carbon atoms or more (C ₄ ⁺ ), and aromatic hydrocarbons such as benzene, toluene, ethylbenzene, and xylenes collectively known as "BTX," but more importantly Acid components such as hydrogen sulfide (H ₂ S) and carbon dioxide (CO ₂ ).

The presence of hydrogen sulfide in industrial gases causes serious environmental problems and is detrimental to plant structures requiring ongoing maintenance. Therefore, removal of _H2S from gas streams is strictly required, especially in natural gas plants.

_The removal and treatment of H2S in natural gas is usually achieved by contacting natural gas containing _H2S with a liquid amine solvent at natural gas pressure, usually 40-100 bar (considered "high pressure"), thus making H2S ₂ S is absorbed by the amine solvent. Due to the high pressure maintained during the absorption of H2S, carbon _dioxide ( _CO2 ), aromatics and _C4 ⁺ aliphatic hydrocarbons are simultaneously absorbed by the amine solvent. This results in "sweet" or purified natural gas that meets environmental standards and recovers amines that contain most of the contaminants ( _CO2 , H2S, aromatics and _{C4 +} aliphatics ⁾ . The contaminated amine solvent is then sent to the regeneration zone where it is recovered under high temperature (typically about 130°C) and low pressure conditions (typically about 2-3 barA). Acid gases comprising _CO2 , H2S, aromatics and _{C4 +} aliphatic hydrocarbons are also obtained ^.

The presence of H2S in _acid gases obtained after natural gas purification remains problematic, so sulfur recovery units (SRUs) are installed to convert toxic sulfur _compounds , such as H2S, into harmless elemental sulfur.

A common method for desulphurization of H2S containing gas streams is the Claus process, which operates through _two main process steps. The first process step is carried out in a furnace in which hydrogen sulfide is converted to elemental sulfur and sulfur dioxide at a temperature of about 1100-1400° C. by combusting about one third of the hydrogen sulfide in the gas stream. The sulfur dioxide thus obtained reacts with hydrogen sulfide in the furnace to form elemental sulfur via a Claus reaction. Therefore, in the first step of the Claus process, about 60-70% of the H2S in the feed gas is converted and most of the aromatics ^{and C4+} _{aliphatics are} removed.

For higher sulfur recovery, at least one catalytic step proceeds following the Claus reaction according to Equation 1:

The Claus process is well suited for acid gas feeds containing greater _than 55 mol.% H2S, where the first combustion step, operating at temperatures above 1200°C, can proceed sufficiently to convert 60-70% of the _H2S and Simultaneously destroys aromatics and _C4 ⁺ aliphatics. However, using the Claus process to recover sulfur from acid gas feeds containing less _than 55 mol.% H2S is more complicated: the first combustion step cannot be performed at a sufficiently high temperature, or the combustion reaction is cooled by the presence of To a large amount of CO ₂ below 1100 ° C, the first combustion step cannot be carried out at all, or when the content of CO ₂ exceeds 85%, the combustion reaction is even inhibited. This allows aromatics and _C4 ⁺ aliphatics to avoid combustion in the first thermal step of the Claus process and to be unreacted in the catalytic step. However, these aromatic and _C4 ⁺ aliphatic hydrocarbons are detrimental to the installed unit as they deactivate the catalysts that operate in the catalytic step of the Claus process. This results in poor sulfur recovery and frequent catalyst replacement.

Several methods have been investigated to remove aromatics and _C4 ⁺ aliphatic hydrocarbons from acid gas-depleted feeds containing less _than 55 mol.% H2S, making them suitable for use in sulfur plants. For example, the Acid Gas Enrichment (AGE) process, in which acid-depleted gas (typically at about 130°C and 2- obtained in the regeneration zone operated at 3 barA). Due to the "low pressure" in AGE operations, the solvent preferentially absorbs H2S rather _{than CO2} , and the levels of aromatics and _C4 ⁺ aliphatics are much lower. After solvent regeneration ^{, an acid gas enriched in H2S and depleted in CO2, aromatics and C4+} _{aliphatic hydrocarbons is} obtained. The AGE process is usually chosen when it can increase the H2S content in the _acid gas to more than 55 vol.%, allowing the resulting acid gas to be conventionally processed by Claus, by processing in a Claus furnace at a temperature above 1100 °C, Aromatics and _C4 ⁺ aliphatics are thereby removed prior to the Claus catalyzed step. For example, patent application EP2402068 discloses the treatment of acid gases with two absorption steps. In this process, the H2S _- enriched solvent obtained from the first absorption zone is sent to the desorption zone, where heat is supplied to desorb the H2S and facilitate the formation of the _{H2S -} enriched gas. _A portion of this H2S _- enriched gas is then sent to another H2S absorption zone for further enrichment. However, AGE is not satisfactory when the initial concentration of H2S in the _acid gas is too low (typically less than 20.mol.%) to reach a concentration higher than 55 mol.% after enrichment.

Another solution for the removal of aromatics and _C4 ⁺ aliphatics is the gas stripping process, typically fuel gas stripping, of the amine-rich solvent obtained from a "high pressure" sour natural gas absorber prior to its regeneration. The fuel gas stream will remove aromatics and _C4 ⁺ aliphatics from the acid-lean gas, so an amine solvent depleted of aromatics and _C4 ⁺ aliphatics can be obtained. Fuel gases containing aromatics and _C4 ⁺ aliphatic hydrocarbons will be used as combustibles in incinerators or utility boilers where the pollutants will be destroyed. However, in this gas stripping method, the removal of aromatics and _C4 ⁺ aliphatics from rich amines varies with the stripping fuel gas flow rate: the higher the fuel gas flow rate, the more is removed. However, the fuel gas is used in the unit as feed to the incinerator and/or utility boiler, and its flow rate is therefore still limited by the requirements of the incinerator or utility boiler. In order to properly remove aromatics and _C4 ⁺ aliphatics, it is necessary to use extremely large quantities of fuel gas much higher than that required to run incinerators and/or utility boilers. Consequently, this would result in a high waste of fuel gas, especially when the amine-rich solvent obtained from a "high pressure" sour natural gas absorber has a high content of aromatics and aliphatics. In this case, fuel gas stripping will not provide a satisfactory solution to the problem of removing aromatics and _C4 ⁺ aliphatic hydrocarbons from acid-lean gas prior to sulfur recovery.

Another option considered in industry is the absorption of aromatics and _C4 ⁺ aliphatic hydrocarbons from acid gases in regenerable activated carbon beds or molecular sieves. Although technically feasible, these methods are still expensive due to the necessary regeneration cycles of the carbon beds, and the difficulty of stabilizing the products from these regeneration zones due to the presence of contaminants such as _H2S .

Therefore, when AGE cannot achieve sufficient H2S enrichment, there is still a need for an efficient removal of such as benzene, toluene, ethylbenzene and xylene from acid _- lean gas containing less than ₂₀ mol.% H2S before sulfur recovery. Aromatic hydrocarbons (BTX), and methods for aliphatic hydrocarbons with 4 carbon atoms or more (C ₄ ⁺ ).

Brief description of the invention

It is an object of the present invention to provide the removal of aromatics (BTX) such as benzene, toluene, ethylbenzene and xylene from acid-lean gases containing _CO2 and less than ₂₀ mol.% H2S, and aromatics (BTX) with 4 carbon atoms or more A process for aliphatic hydrocarbons of carbon atoms (C ₄ ⁺ ), said process comprising:

a) Contacting the acid-depleted gas stream ( ₁ ) with an H2S selective liquid absorbent solution (29) in the first absorption zone ( ₂ ) to produce H2S depleted and containing _CO2 , aromatics and _C4 ⁺ A gas stream of aliphatic hydrocarbons (3) and an H2S _- enriched absorbent solution (4) also containing co-absorbed _C4 ⁺ aliphatic hydrocarbons, aromatics and _CO2 ,

b) The H2S _- enriched absorbent solution (4) is introduced into a non-thermal stripping zone (8) where it is contacted with a stripping gas stream (7), preferably fuel gas, to obtain _C4 ⁺ aliphatic Absorbent solution ( ₉ ) containing hydrocarbons and aromatics and containing H2S and _CO2 and a stripping gas stream ( ₁₀ ) enriched in aromatics and _C4 ⁺ aliphatic hydrocarbons also containing H2S and _CO2 ,

c) The aromatics- and _C4 ⁺ aliphatic _- enriched stripping gas stream (10) obtained in step b) also containing H2S and _CO2 is combined with H2S selectivity in the _second absorption zone (12) The liquid absorbent solution (28) is contacted to obtain a stripped gas stream ( ₁₃ ) depleted of H2S and containing aromatics, _C4 ⁺ aliphatics and _CO2 and also containing co-absorbed aromatics, _C4 ⁺ aliphatics and an H2S _- enriched absorbent solution (14) of _CO2 , said H2S _- selective liquid absorbent solution being preferably the same as used in step a),

d) The _C4 ⁺ aliphatic and aromatic depleted absorbent solution (9) obtained in step b) is introduced into the desorption zone ( ₁₆ ), where the H2S selective liquid absorbent solution (17) is absorbed and _A depleted acid gas comprising H2S and _CO2 depleted of _C4 ⁺ aliphatic and aromatic hydrocarbons is produced (21).

The present invention also relates to a method for recovering sulfur from acid-depleted gas containing _CO2 and less than ₂₀ mol.% H2S, the method comprising:

i) Pretreating the acid-depleted gas stream (1) for the removal of aromatics and _C4 ⁺ aliphatic hydrocarbons according to the above method to obtain acid-depleted gas (21) or (26) depleted of _C4 ⁺ aliphatic hydrocarbons and aromatics ),

ii) mixing at least part of said pretreated acid-depleted gas (21) or (26) depleted of _C4 ⁺ aliphatic hydrocarbons and aromatics with an oxygen-containing gas, such as air, to obtain H2S and oxygen _- comprising airflow,

iii) optionally, introducing part of the obtained aromatics-depleted acid gas (21) or (26) and oxygen into the furnace to recover elemental sulfur,

iv) passing the _C4 ⁺ aliphatic and aromatic depleted acid gas recovered from step ii) and optionally iii) after being optionally preheated, into a catalytic reactor comprising a catalyst system, _The catalyst system catalyzes the direct oxidation of H2S with oxygen and/or the Claus reaction of H2S with sulfur _dioxide (SO2 ₎ to recover an acid _- depleted gas stream depleted of H2S and elemental sulfur.

Brief description of the drawings

Hereinafter, the present invention will be explained in more detail with reference to the accompanying drawings.

Figure 1 schematically shows a preferred method of the invention. Dashed lines represent alternative embodiments of the invention.

Figure 2 shows a specific embodiment of the method of the present invention operated in an illustrative example.

Detailed description of the invention

step a

The process according to the invention for the removal of aromatics (BTX) from acid-lean gases comprises a first step a): In a first absorption zone (2) an acid-lean gas stream ( ₁ ) is combined with a H2S selective liquid absorbent solution ( 29) Contacting to produce a gas stream (3) depleted of H2S and containing _CO2 , aromatics and _{C4 +} aliphatics, ^{and enrichment also containing co-absorbed C4+} _aliphatics ^, aromatics and _CO2 Absorbent solution for H2S ( ₄ ).

The purpose of step a) is to minimize the H2S content of the gaseous feed in order to obtain a H2S _- depleted gas stream ( ₃ ) suitable for combustion in an incinerator (33) and discharge to the atmosphere. The gas (3) leaving the first absorption zone ( ₂ ) is depleted of H2S and contains _CO2 , aromatics and _C4 ⁺ aliphatics.

_The reduction of H2S content in the _{acid -} lean gas is obtained by absorbing H2S by the H2S selective liquid absorbent solution (29). Thus, at the bottom of the first absorption zone ( ₂ ), a liquid absorbent solution enriched in H2S is obtained. However, even if the first absorption step a) is operated at a rather low pressure (1-8 barA), part of the aromatics and _C4 ⁺ aliphatics contained in the acid-depleted gas (1) will be simultaneously absorbed by the liquid absorbent solution (29 ) co-absorbed and will require further processing.

Within the meaning of the present invention, acid-depleted gas preferably comprises:

-75-99.925mol.% CO ₂ ,

- 250 mol.ppm - 20 mol.% of H ₂ S, preferably 500 mol.ppm - 15 mol.% of H ₂ S, more preferably 500 mol.ppm - 10 mol.% of H ₂ S and even more preferably 500 mol.ppm - 5 mol.% H ₂ S,

-500mol.ppm-5mol.% of _C4 ⁺ aliphatic hydrocarbons and aromatics,

Percentages are expressed as moles on a dry basis relative to the total moles of lean acid gas. In practice, this acid-lean gas is usually saturated with water.

In a preferred embodiment, the acid-lean gas entering the process of the invention comprising CO ₂ and less than 20 mol.% H ₂ S is derived from methane (CH ₄ ) and ethane (C ₂ H ₆ ), CO ₂ , H ₂ S and C ₄ ⁺ aliphatic and aromatic hydrocarbons are obtained from natural gas.

In fact, this natural gas is used as a combustible and should therefore not contain any pollutants, such as acid gases (CO ₂ , H ₂ S). The specification of H ₂ S concentration in natural gas is very strict, and its maximum concentration should be kept below 4 ppm mol. On the other hand, the concentration of _CO2 should preferably be kept below 2%, depending on the subsequent use of natural gas as well as legislation. Therefore, natural gas needs to be treated to remove the acid gases (CO ₂ , H ₂ S) contained therein. Purified natural gas that meets standards for transportation, storage, and private or commercial use is then obtained, while also producing an acid-depleted gas containing _CO2 , H2S ^{, and aromatics and C4+} _{aliphatics .} This acid-lean gas needs to be treated prior to sulfur recovery.

Therefore, in a preferred embodiment, said acid-depleted gas comprising _CO2 and less than ₂₀ mol.% H2S is obtained according to the following method, said method comprising:

a) Natural gas comprising methane (CH ₄ ) and ethane (C ₂ H ₆ ), CO ₂ , H ₂ S and C ₄ ⁺ aliphatic and aromatic hydrocarbons is contacted with a liquid absorbent solution in the absorption zone to produce Natural gas streams depleted of H ₂ S and CO ₂ and including methane (CH ₄ ) and ethane (C ₂ H ₆ ), and enriched in H ₂ S and CO ₂ and also containing co-absorbed C ₄ ⁺ aliphatic and aromatic hydrocarbons absorbent solution,

b) The absorbent solution enriched in H2S and _CO2 and also containing co _- absorbed _C4 ⁺ aliphatic and aromatic hydrocarbons is introduced into a desorption zone where the liquid absorbent solution is recovered and a _CO2 -containing And less than 20mol.% H ₂ S acid-depleted gas.

The natural gas used to obtain the acid gas depletion for the purposes of the present invention contains _C4 ⁺ aliphatic and aromatic hydrocarbons, and a small amount of H2S compared to the amount of _{CO2 (} for example, the amount of _CO2 is higher _than the amount of H2S by at least 4 times).

Step a) may preferably be in:

- a temperature of 50-200°C, preferably a temperature of 110-145°C, and

- operating at a pressure of 1-8 barA, preferably 1.5-3 barA.

_The H2S selective liquid absorbent solution may be any known absorbent conventionally used by those skilled in the art, such as chemical solvents, physical solvents and mixtures thereof. When a chemical solvent is used as a liquid absorbent solution, it can be combined with a physical solvent to enhance the absorption of contaminants typically present in acid-lean gas streams.

For example, chemical solvents may include alkali metal carbonates and phosphates, or alkanolamines, preferably in aqueous solution.

The alkanolamines are preferably selected from tertiary alkanolamines and sterically hindered alkanolamines. Sterically hindered alkanolamines may be selected from 2-amino-2-methylpropanol, 2-amino-2-methyl-1,3-propanediol, 2-amino-2-hydroxymethyl-1,3- Propylene glycol, 2-amino-2-ethyl-1,3-propanediol, 2-hydroxymethylpiperidine, 2-(2-hydroxyethyl)piperidine, 3-amino-3-methyl-1-butanol and their mixtures.

Suitable alkanolamines include methyldiethanolamine (MDEA), triethanolamine, or one or more dipropanolamines, such as di-n-propanolamine or diisopropanolamine.

Physical solvents may include, for example, substituted or unsubstituted sulfolanes or mercaptoethanols.

_In a preferred embodiment, the H2S selective liquid absorbent solution comprises an amine, preferably an alkanolamine, more preferably a tertiary or sterically hindered alkanolamine, even more preferably methyldiethanolamine (MDEA ). Aqueous solutions of methyldiethanolamine (MDEA) are preferred liquid absorbent solutions according to the invention.

_In another preferred embodiment, the H2S selective liquid absorbent solution may be a mixture of alkanolamines and mercaptoethanol.

Additive components capable of enhancing the absorption selectivity of H2S to _CO2 , such as acidic components, such as phosphoric _acid (H3PO4 ₎ , may also be introduced in the liquid absorbent solution _.

The concentration of the aqueous alkanolamine solution can vary widely, and one skilled in the art can adjust the solution concentration to achieve a suitable level of absorption. Generally, the concentration of alkanolamines in the aqueous solution is 5-60% by weight, preferably 25-50% by weight. If a physical solvent is used as a component of the absorbent liquid, it may be present in an amount of 2-50% by weight, preferably 5-45% by weight.

Absorption step a) is preferably at:

- a temperature of 10-100°C, preferably a temperature of 30-70°C, more preferably a temperature of 40-60°C, and

- at a pressure of 1-8 barA, preferably at a pressure of 1.5-4 barA.

The H2S _- depleted gas stream (3) leaving the first absorption zone (2) preferably comprises _CO2 , aromatics and _C4 ⁺ aliphatic hydrocarbons, and in particular:

- 60-99 mol.% CO ₂ , more preferably 80-98 mol.%, contained in the lean acid gas (1),

- 60-99 mol.% of aromatics and _C4 ⁺ aliphatic hydrocarbons contained in the lean acid gas (1), more preferably 80-98 mol.%,

- 0.001-20 mol.% of H ₂ S contained in the lean gas (1), more preferably 0.002-5 mol.%.

The H2S _- depleted gas stream (3) leaving the first absorption zone ( ₂ ) can then be transferred to an incinerator (33) where it is combusted to destroy the remaining H2S as well as the aromatics and _C4 contained therein ⁺ Aliphatic hydrocarbons, so as to meet the standard requirements of air emissions. Alternatively, the H2S depleted gas stream ( ₃ ) could be compressed, injected and vented into underground storage instead of incinerated and released into the atmosphere.

The H2S _- enriched absorbent solution (4) leaving the first absorption zone (2) also contains co-absorbed _C4 ⁺ aliphatic hydrocarbons, aromatics and _CO2 . In a preferred embodiment, the H2S _- enriched absorbent solution (4) leaving the first absorption zone (2) comprises:

- 80-99.999 mol.% H ₂ S, more preferably 95-99.99 mol.%, contained in the lean acid gas (1),

- 0.5-40 mol.% of CO ₂ contained in the lean acid gas (1), more preferably 1-15 mol.%

- 0.5-40 mol.% of _C4 ⁺ aliphatic hydrocarbons and aromatics contained in the lean gas (1), more preferably 1-10 mol.%.

step b

The H2S _- enriched absorbent solution (4) leaving the first absorption zone (2) is then sent to a non-thermal stripping zone (8) where it is contacted with a stripping gas stream (7), preferably fuel gas, to obtain An absorbent solution ( ₉ ) depleted of _C4 ⁺ aliphatics and aromatics and containing H2S and _CO2 , ^{and a stripped gas stream enriched in aromatics and C4+} _{aliphatics also} containing H2S and _CO2 (10).

In fact, further to the first absorption step a), the H2S _- enriched absorbent solution (4) also contains co-absorbed _C4 ⁺ aliphatic and aromatic hydrocarbons.

Therefore, the purpose of step b) is to remove as much _C4 ⁺ aliphatic and aromatic hydrocarbons as possible from the absorbent solution with as little H2S as possible, so that when lean _acid gas is recovered, it does not contain high concentrations of energy Impurities that poison the sulfur recovery unit catalyst. This is done by contacting the H2S _- enriched absorbent solution (4) with a countercurrent flow of a stripping gas (7), such as a fuel gas stream, in a non-thermal stripping step.

The prior art stripping step is usually performed simply by heating the H2S _- enriched absorbent solution to produce the fluid as the stripping fluid, or by direct injection of the fluid in the stripping zone. Providing heat to the stripping zone increases the chemical desorption of _acid gases, especially H2S, from the absorbent solution and facilitates their removal with the stripping stream. Thus, a substantially H2S _- depleted absorbent solution is obtained by conventional stripping steps of the prior art. In contrast, the stripping step of the claimed process is athermal in the sense that no appreciable heat or energy is supplied to the process at this stage. By operating the stripping step without significant heating, the _C4 ⁺ aliphatics and aromatics above the H2S can be stripped more selectively to obtain a _C4 ⁺ aliphatics and aromatics _depleted and containing _H2 The absorbent solution of S and _CO2 ( ₉ ), ^{and the stripping gas stream enriched in aromatics and C4+} _{aliphatic hydrocarbons} (10 ).

The resulting absorbent solution (9) is depleted of _C4 ⁺ aliphatic and aromatic hydrocarbons. The stripping gas stream (7) will preferentially strip off the _C4 ⁺ aliphatic and aromatic hydrocarbons above the H2S from the H2S _- enriched absorbent solution ( ₄ ), but will also strip off the C4+ aliphatic and aromatic hydrocarbons contained in the absorbent solution Part of H ₂ S and CO ₂ in (4) is taken away. Thus, the stripping gas ( 10 ) leaving the stripping zone ( 8 ) is enriched in aromatics and C ₄ ⁺ aliphatic hydrocarbons and also contains H ₂ S and CO ₂ .

The stripping gas used in the stripping zone of the process according to the invention can preferably be a fuel gas stream, but can also be any combustible gas that meets the requirements of combustible standards, such as natural gas, hydrogen, and/or synthetic gas containing mainly H and _CO gas, or other inert gases mainly consisting of nitrogen or helium. Thus, the fuel gas or any combustible gas used in the stripping zone can be used as feed/combustible in the incinerator (33) and/or utility boiler.

In a preferred embodiment the stripping gas is a fuel gas and preferably the fuel gas (7) used in the stripping zone (8) is the incinerator (33) and/or utility boiler for operating the unit of flammable gases. In practice, the plant in which the method of the invention is carried out generally includes incinerators and/or utility boilers for various purposes. The incinerator and boiler must be supplied with gas. An advantage of the present invention is that the fuel gas required to feed the plant's incinerators and/or utility boilers is first used as stripping gas and then recovered and re-routed to its original path to feed the incinerators and/or utility boilers . This utility boiler (not shown in the figure) produces steam which can be fed to a boiler of the plant in which the claimed method is carried out, for example the boiler (18) in FIG. 1 . The fuel gas flow rate in the stripping zone is limited by the combustible gas flow required to operate the incinerator (33) and/or utility boiler. In this embodiment, the fuel gas is used continuously as stripping gas in the stripping zone ( 8 ) and as combustible gas to operate the incinerator and/or utility boiler, which is economically advantageous.

In this stripping step, a stripping gas stream (7) is preferably introduced into the bottom of the stripping zone in order to contact the countercurrent flow of the H2S _- enriched absorbent solution (4).

Absorption step b) is preferably at:

- a temperature of 50-150°C, preferably a temperature of 60-130°C, more preferably a temperature of 70-110°C, and

- at a pressure of 1-8 barA, preferably at a pressure of 1.5-4 barA.

In order for the H2S _- enriched absorbent solution (4) to meet the pressure conditions required for the stripping zone, it may be necessary to pass it through a pump (5) or through a valve before entering the stripping zone.

In some cases where the installation is restricted, for example in terms of the flow rate of the stripping gas stream, the H2S _- enriched absorbent solution (4) can also be passed through a heater (6) before entering the stripping zone (8). ) raises its temperature to efficiently remove aromatics and _C4 ⁺ aliphatics. In this embodiment, the heat supplied to the stripping step should be controlled to increase the removal of aromatics and _C4 ⁺ aliphatics, while ensuring that only a minimum amount of H2S is _desorbed from the absorbent solution to avoid obtaining _The H2S stripping gas stream (7) is collected. Indeed, in case the stripping gas stream ( ₇ ) is enriched in H2S, it will be necessary to increase the size of the _second absorption zone to ensure complete removal of H2S. In a preferred embodiment, the temperature increase in the heater (6) can be achieved by recycling in the heater (6) at least a portion of the H recovered from the desorption zone (16) and/or leaving the heat exchanger (heater 15) 2S selective liquid absorbent solution ( ₁₇ ). Therefore, the H2S selective liquid absorbent solution is used as a heat source for the heater ( ₆ ).

As mentioned above, the stripping gas stream ( 10 ) leaving the stripping zone ( 8 ) is enriched in aromatics and C ₄ ⁺ aliphatic hydrocarbons, but also contains H ₂ S and CO ₂ . It preferably contains:

- 50-99 mol.%, preferably 85-99 mol.%, of aromatics and _C4 ⁺ aliphatic hydrocarbons contained in the absorbent solution (4) entering the stripping zone (8),

- 5-40 mol.%, preferably 5-20 mol.% of _CO2 contained in the absorbent solution (4) entering the stripping zone (8),

- 1-20 mol.%, preferably 1-10 mol.%, of H2S contained in the absorbent solution ( ₄ ) entering the stripping zone (8).

The absorbent solution (9) leaving the stripping zone (8) is depleted of _C4 ⁺ aliphatic and aromatic hydrocarbons and preferably contains:

- 80-99 mol.%, preferably 90-99 mol.%, of H2S contained in the absorbent solution ( ₄ ) entering the stripping zone (8),

- 1-50 mol.%, preferably 1-15 mol.%, of aromatics and _C4 ⁺ aliphatic hydrocarbons contained in the absorbent solution (4) entering the stripping zone (8),

- 60-95 mol.%, preferably 70-90 mol.%, of _CO2 contained in the absorbent solution (4) entering the stripping zone (8).

In a preferred embodiment, the absorbent solution (9) leaving the stripping zone (8) comprises 0.01-10 mol.% aromatics and _C4 ⁺ aliphatics contained in the acid-lean gas (1), more preferably 0.1 -5mol.%.

step c

In the second absorption zone (12), the stripped gas stream (10 ^{) enriched in aromatics and C4+} _{aliphatic hydrocarbons} ( ₁₀ ) obtained in step b) also containing H2S and _CO2 is combined with H2S selective liquid The absorbent solution (28) is contacted to obtain a stripped gas stream ( ₁₃ ) depleted of H2S and comprising aromatics, _C4 ⁺ aliphatics and _CO2 , and also containing co-absorbed aromatics, _C4 ⁺ aliphatics and CO ₂ H ₂ S enriched absorbent solution ( 14 ), the H ₂ S selective liquid absorbent solution is preferably the same as used in step a).

In particular, more than 80%, preferably more than 90%, more preferably all of the stripping gas stream (10) obtained in step b) enriched in aromatics and _C4 ⁺ aliphatics (10) is sent to the second Absorption zone (12).

In fact, further to stripping step b), the stripped gas stream ( ₁₀ ) is enriched in aromatics and _C4 ⁺ aliphatic hydrocarbons, but also contains H2S and _CO2 .

The purpose of step c) is therefore to remove as much H2S as possible from the stripping gas stream ( ₁₀ ) to recover a stripping gas stream suitable for further use as combustibles, such as for an incinerator (33) and/or Fuel gas for power plant boilers. Alternatively, the H2S _- depleted stripping gas stream could be compressed, injected, and discharged into underground storage rather than incinerated and released into the atmosphere. This is accomplished by contacting the stripped gas stream ( ₁₀ ) enriched in aromatics and _C4 ⁺ aliphatic hydrocarbons in countercurrent with a H2S selective liquid absorbent solution ( ₂₈ ) which Preference is given to that used in step a).

For example, a H2S selective liquid absorbent solution ( ₂₈ ) may be obtained by introducing a primary solvent stream (29) into the first absorption zone.

The conditions of temperature and pressure operated in the second absorption zone (12) are preferably the same as previously disclosed for the first absorption zone in step a).

Optionally, in order to conform the stripping gas stream (10) enriched in aromatics and _C4 ⁺ aliphatics but also containing H2S and _CO2 to the desired temperature conditions in the _second absorption zone (12), it may be necessary Pass through a cooler (11) and optionally a separator to recover the condensed water before it enters the second absorption zone (12).

The stripping gas stream (13) leaving the second absorption zone (12) preferably comprises aromatics, _C4 ⁺ aliphatic hydrocarbons and _CO2 , and in particular comprises:

- 60-99 mol.% CO ₂ , more preferably 80-98 mol.%, contained in the stripping gas stream (10) leaving the stripping zone (8),

- 60-99 mol.% of aromatics (BTX) and _C4 ⁺ aliphatic hydrocarbons contained in the stripping gas stream (10) leaving the stripping zone (8), more preferably 80-98 mol.% and

- 0.01-20 mol.% of H2S, more preferably _0.02-5 mol.%, contained in the stripping gas stream (10) leaving the stripping zone (8).

The H2S _- depleted stripping gas stream (13) leaving the second absorption zone (12) and containing aromatics, _C4 ⁺ aliphatic hydrocarbons and _CO2 complies with the standard requirements for combustibles such as combustion gases and can therefore be used as an incinerator Furnace (33) and/or power plant boiler feed where associated aromatics (BTX) and _C4 ⁺ aliphatic hydrocarbons and remaining sulfur species will be destroyed. Alternatively, the H2S _- depleted stripping gas stream (13) can be compressed, injected and discharged into underground storage instead of being incinerated and released into the atmosphere.

The H ₂ S enriched absorbent solution ( 14 ) leaving the second absorption zone ( 12 ) also contains co-absorbed aromatics (BTX), C ₄ ⁺ aliphatic hydrocarbons and CO ₂ .

In a preferred embodiment, the H2S _- enriched absorbent solution leaving the second absorption zone (12) comprises:

- 1-40 mol.% CO ₂ , more preferably 2-20 mol.%, contained in the stripping gas stream (10) leaving the stripping zone (8),

- 1-40 mol.% of aromatics (BTX) and C ₄ ⁺ aliphatic hydrocarbons contained in the stripping gas stream (10) leaving the stripping zone (8), more preferably 2-20 mol.% and

- 80-99.99 mol.% of H2S, more preferably _95-99.98 mol.%, contained in the stripping gas stream (10) leaving the stripping zone (8).

Depending on the amount of aromatics (BTX), _C4 ⁺ aliphatics co-absorbed therein, the H2S _- enriched absorbent solution (14) leaving the second absorption zone (12) can be recycled back to the stripping zone (8 ) to replenish the H2S _- enriched absorbent solution (4), and/or can be introduced directly into the desorption zone (16) to replenish the aromatics-depleted absorbent solution (9) obtained in step b).

In a preferred embodiment, the H2S _- enriched absorbent solution (14) leaving the second absorption zone (12) is completely recycled to the stripping zone to replenish the H2S _- enriched absorbent solution (4 ) in order to reduce the content of aromatics (BTX) and C ₄ ⁺ aliphatic hydrocarbons in the H ₂ S-enriched absorbent solution (9) sent to the desorption zone (16).

The design of the stripping zone ( ₈ ) and A second absorption zone (12) to significantly reduce the content of aromatics (BTX) and _C4 ⁺ aliphatic hydrocarbons in the H2S _- depleted absorbent solution entering the desorption zone (16).

step d

The _C4 ⁺ aliphatic and aromatic depleted absorbent solution (9) leaving the stripping zone (8) is further optionally supplemented with the H2S _- enriched absorbent solution leaving the second absorption zone (12) (14), leading to a desorption zone ( ₁₆ ), where the H2S selective liquid absorbent solution (17) is recovered and produces a depleted _acid gas comprising H2S and _CO2 depleted of _C4 ⁺ aliphatic and aromatic hydrocarbons .

In fact, the absorbent solution (9) leaving the stripping step b) and the _second absorption step c) is depleted of _C4 ⁺ aliphatic and aromatic hydrocarbons, but still contains H2S and _CO2 .

The purpose of step d) is therefore to absorb as much H2S and _CO2 as possible from the absorbent solution ( ₉ ) in order to recover purified absorbent solution which can be recycled back to the first and/or second absorption zone. This is done by heating the absorbent solution (9) in the desorption zone (16).

Absorption step d) is preferably at:

- a temperature of 50-200°C, preferably a temperature of 70-180°C, more preferably a temperature of 110-145°C, and

- at a pressure of 1-4 barA, preferably at a pressure of 1.5-3 barA.

In a preferred embodiment, the _C4 ⁺ aliphatic and aromatic depleted absorbent solution (9) recovered from the stripping zone (8) may also be raised by a heater (15) before entering the desorption zone Its temperature in order to reduce the energy consumption of fluid circulation in the desorption zone. The temperature increase in the heater (15) is preferably obtained by recycling in the heater (15) at least a portion of the regenerated liquid absorbent solution (17) recovered from the desorption zone (16). Thus, the regenerated liquid absorbent solution (17) is used as a heating medium for the heater (15).

Steam is generated in the desorption zone ( ₁₆ ) to provide the energy required to remove H2S, _CO2 , hydrocarbons and aromatics such as BTX from the absorbent solution. Steam can be generated by any heating means (steam, thermal oil, furnace, burner, boiler) in heat exchange with the liquid absorbent solution present at the bottom of the desorption zone (16).

Therefore, the desorption zone ( 16 ) preferably comprises at its bottom a boiler ( 18 ) with steam circulation in order to allow regeneration of the H ₂ S enriched absorbent solution.

The regenerated liquid absorbent solution (17) leaving the bottom of the desorption zone (16) can then be returned to the first absorption zone ( ₂ ) as H2S selective liquid absorbent solution (29) and/or as H2S selective liquid absorbent solution (29 ₎ The liquid absorbent solution (28) is returned to the second absorption zone (12).

In order for the regenerated liquid absorbent solution (17) to comply with the required temperature and pressure conditions in the first absorption zone (2) and the second absorption zone (12), it may be necessary to pass it through a heat exchanger before entering the absorption zone (27) and pump (19) or through a valve.

The acid-lean gas (21 ) leaving the desorption zone (16) also contains steam and vaporized absorbent solution. The water from the steam and the vaporized absorbent solution carried by the acid-lean gas (21) leaving the desorption zone (16) can be partially separated from the acid-lean gas (21) depleted of aromatics in the condenser (22) and further Captured in the return tank (23) which acts as an accumulator. The water and absorbent solution can then be recycled back to the desorption zone (16) by pump (25) to limit losses of water and absorbent solution. Acid depleted gas (26) depleted of aromatics is recovered. Preferably, the condenser is operated at a temperature of more preferably 20-70°C, even more preferably 40-60°C.

The acid-lean gas (21) or (26) is depleted of aromatics and _C4 ⁺ aliphatics, and preferably includes 0.01-10 mol.% of aromatics (BTX) and _C4 ⁺ aliphatics contained in the acid-lean gas entering the process Hydrogen, more preferably 0.1-5mol.%.

Furthermore, the aromatics-depleted acid gas ( 21 ) or ( 26 ) recovered at the end of the inventive process preferably has a higher H ₂ S/CO ₂ ratio than the acid-depleted gas ( 1 ) entering the process.

In a preferred embodiment, the aromatics-depleted acid gas (21) or (26) recovered after the desorption zone (16) may be partially recycled to supplement the acid-depleted gas stream (1) entering the process, and/ Or a supplementary stripping gas stream ( ₁₀ ) enriched in aromatics and _C4 ⁺ aliphatics but also containing H2S and _CO2 .

The inventors have the advantage of finding that the specific continuity of the absorption and stripping steps according to the present invention makes it possible to remove large amounts of aromatics, such as BTX and _C4 ⁺ aliphatics, from acid-depleted gases containing less than ₂₀ mol.% H2S , although none of these steps alone is sufficient to achieve this goal. Contrary to the expectations of those skilled in the art, the resulting acid-lean gas depleted of aromatics and _C4 ⁺ aliphatics is suitable for subsequent sulfur recovery treatment because even without enrichment of H2S to a ratio greater _than 55 mol.%, It is necessary for proper operation in a Claus furnace (first step of sulfur recovery), it contains aromatics such as BTX and _C4 ⁺ aliphatics in small enough amounts to allow sulfur recovery for partial bypass operation of the furnace unit, or even no thermal step at all. In a preferred embodiment, the stripping gas stream (7) is combustible and its flow rate is adapted to the needs of the incinerator (33) and/or power plant boiler.

In a preferred embodiment, aromatics such as benzene, toluene, ethylbenzene and xylenes (BTX) and _C4 ⁺ aliphatic hydrocarbons in the acid-depleted gas (21) or (26) recovered at the end of the process according to the invention The content should be as low as possible and not higher than 500 mol.ppm, preferably 1-500 mol.ppm, to prevent deactivation of the Claus catalyst in the subsequent sulfur recovery unit.

Method for recovering sulfur from acid-lean gas containing less _than 20mol.% H2S

The resulting aromatics-depleted acid gas (21) or (26) is suitable for use as feed in the sulfur recovery unit (30).

Therefore, another object of the present invention is a process for recovering sulfur from acid-depleted gas containing _CO2 and less than ₂₀ mol.% H2S, the process comprising:

i) Pretreatment of the acid-depleted gas stream (1) for the removal of aromatics and _C4 ⁺ aliphatics according to the method described previously to obtain an acid-depleted gas (21) or (26) depleted of _C4 ⁺ aliphatics and aromatics ),

ii) mixing at least part of said pretreated acid-depleted gas (21) or (26) depleted of _C4 ⁺ aliphatic hydrocarbons and aromatics with an oxygen _- containing gas such as air to obtain a gas stream comprising H2S and oxygen ,

iii) optionally, introducing part of the resulting aromatics-depleted acid gas (21) or (26) and oxygen into the furnace to recover elemental sulfur,

iv) passing the _C4 ⁺ aliphatic and aromatic depleted acid gas recovered from step ii) and optionally iii) after being optionally preheated, into a catalytic reactor comprising a catalyst system, _The catalyst system catalyzes the direct oxidation of H2S with oxygen and/or the Claus reaction of H2S with sulfur _dioxide (SO2 ₎ to recover an acid _- lean gas stream depleted of H2S and elemental sulfur (32).

Typically, elemental sulfur is recovered in the condenser.

Step iv) may preferably be repeated several times, more preferably at least twice.

Depending _on the H2S content in the _C4 ⁺ aliphatic and aromatic depleted acid gas (21) or (26) obtained in the pretreatment step i), one skilled in the art can easily modify this sulfur recovery process .

When the H ₂ S content in the depleted acid gas (21) or (26) depleted of C ₄ ⁺ aliphatic and aromatic hydrocarbons is lower than 15 mol.%, the sulfur recovery method may preferably be only a catalytic direct oxidation method (athermal Step iii). In this case, the acid-depleted gas ( 21 ) or ( 26 ) depleted of C ₄ ⁺ aliphatic and aromatic hydrocarbons can be preheated before entering the catalytic reactor.

Coupled thermal step iii) and catalytic Claus step iv can be operated when the H2S content in the _C4 ⁺ aliphatic and aromatic depleted acid gas ( ₂₁ ) or (26) is between 15-55 mol.% ) of the conventional Claus method. In this case, usually only a part of the acid-depleted gas (21) or (26) depleted of _C4 ⁺ aliphatic and aromatic hydrocarbons is fed into the furnace, and the remaining acid-depleted gas is directly bypassed by the burner of the furnace. Oxidation is carried out in a furnace. Considering the high content of inert gases, such as CO ₂ and/or N ₂ , in the acid-lean gas, this partial bypass of the burner of thermal step iii) is required to maintain a stable flame in the burner.

Alternatively and preferably, the catalytic direct oxidation process can be carried out isothermally or pseudo-isothermally by means of an internal cooler such as a hot-dip coating of SmartSulf ^™ technology or the like. This technique is advantageous for catalytic reactors after Claus thermal step (iii), and even more favorable for direct oxidation without Claus thermal step (iii), thus in acid-lean gas (21) or (26) It can be considered when the H ₂ S content in it is less than 15mol.%.

SmartSulf ^™ technology is disclosed in detail in the document US2013/0129589, the entire contents of which are incorporated herein by reference.

According to a preferred embodiment, step iv) of the method for recovering sulfur from a lean acid gas comprising _CO2 and less than ₂₀ mol.% H2S comprises and/or is followed by:

iv.1 After optionally preheating, said acid _- lean gas stream comprising H2S and oxygen is transferred to a first part of a first reactor comprising an uncooled adiabatic bed comprising a first catalyst for catalytic oxidation of _H2S with oxygen and catalytic oxidation of H2S with sulfur _dioxide , wherein the maximum temperature of the adiabatic bed is T1,

iv.2 diverting said acid-depleted gas stream from a first portion of said first reactor to a second portion of said first reactor, the second portion comprising a second catalyst which may be different from the first catalyst, and the The second part is maintained at a temperature T2, where T2 ≤ T1 and T2 is above the dew point temperature of elemental sulfur, resulting in a H2S _- depleted gas stream,

_iv.3 transferring said H2S depleted gas stream to a sulfur condenser to obtain a sulfur depleted gas stream,

iv.4 optionally preheating said sulfur-depleted gas stream,

iv.5 diverting said sulfur-depleted gas stream into a first section of a second reactor comprising an uncooled adiabatic bed comprising the same catalyst as said first section of said first reactor , wherein the first part of the second reactor is operated at a temperature above the dew point of elemental sulfur such that no elemental sulfur is deposited on the catalyst as a liquid or solid in the first part of the second reactor,

iv.6 diverting said gas stream from a first portion of said second reactor to a second portion of said second reactor comprising a first two portions of the same catalyst, and the second portion is maintained at a temperature at or below the dew point of elemental sulfur such that elemental sulfur deposits on said catalyst as a liquid or solid in the second portion of said second reactor, and Obtain a desulfurized gas stream that meets the requirements of air emission standards,

iv.7 switching the operating conditions of said first reactor and said second reactor after a defined time and simultaneously switching the gas flow, so that the previous second reactor becomes the new first reactor, and the previous first reactor The reactor becomes the new second reactor.

In this preferred embodiment, in steps iv.2) and iv.6), the second part of the reactor can be maintained at a temperature equal to or below the dew point of elemental sulfur with the help of an internal cooler such as a thermocouple.

In this method, steps iv.1-iv.7 correspond to the SmartSulf ^™ technology.

The step iv.7 of switching the operating conditions of the first reactor and the second reactor and simultaneously switching the gas flow makes it possible to desorb elemental sulfur condensed on the catalyst operating in the second reactor. In effect, when operating in the first position (at a higher temperature), the second reactor operates at a higher temperature, thereby desorbing the Sulfur condensed on the catalyst.

_The H2S _- depleted acid-depleted gas stream (32) leaving the sulfur recovery unit in step iv) can then be transferred to an incinerator (33) where it is combusted to destroy the remaining H2S and the Aromatic hydrocarbons and C ₄ ⁺ aliphatic hydrocarbons, so as to meet the standard requirements of air emissions. Alternatively, the H2S depleted gas stream ( ₃ ) could be compressed, injected and vented into underground storage instead of being incinerated and released into the atmosphere.

The invention will be further illustrated in the following non-limiting examples.

Example 1

The method for recovering sulfur from acid-lean gas (1) as shown in Figure 2 operates with acid gas comprising:

○10.0mol.% H ₂ S,

○ 82.1 mol.% CO ₂ , and

○2500mol.ppm of BTX,

○ 180 mol.ppm of C ₄ ⁺ ,

o 7.3 mol.% water, the remainder other hydrocarbons such as methane, ethane and propane, and sulfur species such as mercaptans.

The acid-lean gas is sent to the first absorption zone (2) at a flow rate of 2800 kmol/h at a pressure of 1.7 bar. In the first absorption zone (2), the acid-depleted gas is contacted with 45 wt% ( ¹¹ mol.%) methyldiethanolamine (MDEA ) aqueous solution (29).

The gas stream (3) leaving the first absorption zone (2) at a flow rate of 2145 kmol/h comprises:

○ 92.8mol.% CO ₂ ,

○< _100ppm mol of H2S, and

○ 3000 ppm mol of BTX (representing 92% of the initial amount of BTX in acid-lean gas),

○ 230ppm C ₄ ⁺ (represents the entire initial amount of C ₄ ⁺ in lean acid gas),

o 6.4 mol.% water, the remainder other hydrocarbons such as methane, ethane and propane, and sulfur species such as mercaptans.

The MDEA solution (4) leaving the first absorption zone ( ₂ ) absorbs almost the entire amount of H2S in the lean gas and co-absorbs about 8% of the BTX initially present in the lean gas. The solvent reached a temperature of about 62°C.

Subsequently, the MDEA solution (4) leaving the first absorption zone (2) passes through the pump (5) and through the heater (6) to increase its temperature and pressure to enter stripping at a temperature of 92.0 °C and a pressure of 5 barA District (8).

As can be seen from Figure 2, the temperature increase in the heater (6) is obtained by recirculating in the heater (6) the MDEA solution (20) recovered from the desorption zone (16).

The heated MDEA solution enters a stripping zone (8) where it is contacted countercurrently with a natural gas stream (7) introduced at the bottom of the stripping zone.

The natural gas stream (7) has the following specifications:

○ 95.0mol.% methane,

o 5.0 mol.% ethane.

It enters the stripping zone under the following conditions:

○Flow rate: 200kmol/h,

○Temperature: 15°C,

○Pressure: 7.0barA.

The stripper was operated at a pressure of 5.0 barA.

The fuel gas stream (10) leaving the stripping zone (8) has the following specifications:

○Flow rate: 318kmol/h,

○Temperature: 90°C,

○ 18.5mol.% CO ₂ ,

○ 6.4 mol.% H ₂ S, and

o 1275 mol.ppm of BTX (65% of BTX entering the stripping zone).

Subsequently, the fuel gas stream (10) leaving the stripping zone (8) passes through a heat exchanger and enters the second absorption zone (12) at a temperature of 45°C. In the second absorption zone (12), the fuel gas stream (10) leaving the stripping zone ( ⁸ ) is contacted with methyldiethanolamine (MDEA ) solution.

The methyldiethanolamine (MDEA) solution is the same solution used in the first absorption zone (2).

The fuel gas stream (13) leaves the second absorption zone (12) at a flow rate of 255 kmol/h and has the following composition:

○ 19.6mol.% CO ₂ ,

○< _100mol.ppm of H2S, and

o 1350 mol.ppm of BTX (85% of the BTX entering the second absorption zone of stream 16, and about 5% of the BTX entering the process of stream 1).

The fuel gas stream (13) is combustible compliant and can therefore be used as feed in an incinerator (33) and/or utility boiler where associated aromatics (BTX) and _C4 ⁺ aliphatic hydrocarbons will be destroyed as well as the remaining Sulfur.

_The H2S enriched MDEA solution (14) leaving the second absorption zone (12) is recycled to the stripping zone to replenish the H2S enriched MDEA solution ( ₄ ).

The BTX-depleted MDEA solution (9) leaves the stripping zone (8) at a temperature of 87°C and contains 35% of the BTX entering the stripping zone (corresponding to a flow of about 3% of the BTX entering the process).

The BTX-depleted MDEA solution (9) is then introduced into a desorption zone (16) equipped with a boiler (18) operating at a temperature of 130°C and a pressure of 2.4 barA.

The regenerated MDEA solution (17) leaving the bottom of the desorption zone (16) is returned to the first absorption zone (2) and the second absorption zone (12).

The BTX-depleted acid gas (21 ) leaving the desorption zone (16) is passed through a condenser (22) and a reflux tank (23).

The temperature of the BTX-depleted acid gas ( 26 ) recovered at the end of the process of the invention is 45° C. and the flow rate is 570 kmol/h. It has the following composition:

○ 45.5mol.% CO ₂ ,

○ 49.2mol.% H ₂ S,

o 390 mol.ppm of BTX (3% of BTX entering the process), and

o 4.9 mol.% _H2O .

The method of the invention makes it possible to reduce the BTX content of the treated acid-lean gas by 97%. Even if the H ₂ S content is lower than 55 mol.%, the treated acid-lean gas is suitable for the subsequent treatment of the sulfur recovery unit.

The resulting acid gas is then treated in the Claus process with a 10% acid gas stream bypassing the thermal step (melter), and 2 reactors for operating the catalytic step (SmartSulf ^™ technology). A sulfur recovery of 99.3% was obtained. 107 tonnes of bright yellow solid sulfur was recovered per day meeting sulfur recovery standards without further treatment.

Example 2

The process for recovering sulfur from acid-lean gas as shown in Figure 2 operates with an acid gas comprising:

○0.2mol.% H ₂ S,

○ 92.0 mol.% CO ₂ , and

○1500mol.ppm of BTX,

○ 180 mol.ppm of C ₄ ⁺ ,

o 7.3 mol.% water, the remainder other hydrocarbons such as methane, ethane and propane, and sulfur species such as mercaptans.

The acid-lean gas is sent to the first absorption zone (2) at a flow rate of 2800 kmol/h. In the first absorption zone (2), the acid-depleted gas is contacted with 45 wt% ( ¹¹ mol.%) methyldiethanolamine (MDEA ) aqueous solution (29).

The gas stream (3) leaving the first absorption zone (2) at a flow rate of 2580 kmol/h comprises:

○ 92.8mol.% CO ₂ ,

○< _100mol.ppm of H2S, and

○ 1510mol.ppm of BTX (92%),

○ 195 mol.ppm C ₄ ⁺ (represents the entire initial amount of C ₄ ⁺ in lean acid gas).

o 6.6 mol.% water, the remainder being other hydrocarbons such as methane, ethane and propane, and sulfur species such as mercaptans.

The MDEA solution (4) leaving the first absorption zone ( ₂ ) absorbs almost the entire amount of H2S in the acid-lean gas, and a total of about 8% of BTX, and reaches a temperature of about 55°C.

Subsequently, the MDEA solution (4) leaving the first absorption zone (2) passes through the pump (5) and through the heater (6) to increase its temperature and pressure to enter stripping at a temperature of 93.0 °C and a pressure of 5 barA District (8).

As can be seen from Figure 2, the temperature increase in the heater (6) is obtained by recirculating in the heater (6) the MDEA solution (20) recovered from the desorption zone (16).

The heated MDEA solution enters a stripping zone (8) where it is contacted countercurrently with a natural gas stream (7) introduced at the bottom of the stripping zone.

The natural gas stream (7) has the following specifications:

○ 95.0mol.% methane,

o 5.0 mol.% ethane.

It enters the stripping zone under the following conditions:

○Flow rate: 360kmol/h,

○Temperature: 15°C,

○Pressure: 7.0barA.

The stripper was operated at a pressure of 5.0 barA.

The fuel gas stream leaving the stripping zone (8) has the following specifications:

○Flow rate: 465kmol/h,

○Temperature: 93°C,

○ 8.4mol.% CO ₂ ,

○ 0.1 mol.% H ₂ S, and

o 625 mol.ppm of BTX (89% of BTX entering the stripping zone).

Subsequently, the fuel gas stream leaving the stripping zone (8) passes through a heat exchanger and enters the second absorption zone (12) at a temperature of 45°C. In the second absorption zone (12), the fuel gas stream leaving the stripping zone (8) contacts a solution of methyldiethanolamine (MDEA) introduced at a flow rate of 12 m ³ /h at a temperature of 45°C and a pressure of 4.0 barA .

The methyldiethanolamine (MDEA) solution is the same solution used in the first absorption zone (2).

The fuel gas stream (13) leaves the second absorption zone (12) at a flow rate of 406 kmol/h and has the following composition:

○ 9.1mol.% CO ₂ ,

○< _100mol.ppm of H2S, and

o 680 mol.ppm of BTX (94% of the BTX entering the second absorption zone of stream 16, and about 7% of the BTX entering the process of stream 1).

The fuel gas stream (13) is combustible compliant and can therefore be used as feed in an incinerator (33) and/or utility boiler where associated aromatics (BTX) and _C4 ⁺ aliphatic hydrocarbons will be destroyed as well as the remaining Sulfur.

_The H2S enriched MDEA solution (14) leaving the second absorption zone (12) is recycled to the stripping zone to replenish the H2S enriched MDEA solution ( ₄ ).

The BTX-depleted MDEA solution (9) leaves the stripping zone (8) at a temperature of 89°C and contains 11% of the BTX entering the stripping zone (corresponding to a flow of about 1% of the BTX entering the process).

This MDEA solution (9) depleted of BTX is then introduced into a desorption zone (16) equipped with a boiler (18) operating at a temperature of 130°C and a pressure of 2.4 barA.

The regenerated MDEA solution (17) leaving the bottom of the desorption zone (16) is returned to the first absorption zone (2) and the second absorption zone (12).

The BTX-depleted acid gas (21 ) leaving the desorption zone (16) is passed through a condenser (22) and a reflux tank (23).

The temperature of the BTX-depleted acid gas ( 26 ) recovered at the end of the process of the invention is 45° C. and the flow rate is 160 kmol/h. It has the following composition:

○ 90.8mol.% CO ₂ ,

○ 3.4 mol.% H ₂ S, and

○ 220mol.ppm of BTX (1% of BTX entering the process),

o 5.8 mol.% _H2O .

The method according to the invention makes it possible to reduce the BTX content of the treated acid-lean gas by 99 mol.%. Even if the H ₂ S content is much lower than 55mol.%, the treated acid-lean gas is suitable for the subsequent treatment of the sulfur recovery unit.

The resulting acid gas is then treated by direct oxidation (SmartSulf ^TM technology) in 2 reactors. A sulfur recovery of 98% was obtained. 2 tons of bright yellow solid sulfur is recovered per day meeting sulfur recovery standards without further treatment.

Claims (18)

1. Removal of aromatics (BTX) such as benzene, toluene, ethylbenzene and xylene and those with ₄ carbon atoms or more ₍ C ₄ ⁺ ) the method of aliphatic hydrocarbons, said method comprising: a) Contacting the acid-depleted gas stream ( ₁ ) with an H2S selective liquid absorbent solution (29) in the first absorption zone ( ₂ ) to produce H2S depleted and containing _CO2 , aromatics and _C4 ⁺ A gas stream of aliphatic hydrocarbons (3) and an H2S _- enriched absorbent solution (4) also containing co-absorbed _C4 ⁺ aliphatic hydrocarbons, aromatics and _CO2 , b) The H2S _- enriched absorbent solution (4) is introduced into a non-thermal stripping zone (8) where it is contacted with a stripping gas stream (7), preferably fuel gas, to obtain _C4 ⁺ aliphatic Absorbent solution ( ₉ ) containing hydrocarbons and aromatics and containing H2S and _CO2 and a stripping gas stream ( ₁₀ ) enriched in aromatics and _C4 ⁺ aliphatic hydrocarbons also containing H2S and _CO2 , c) The aromatics- and _C4 ⁺ aliphatic _- enriched stripping gas stream (10) obtained in step b) also containing H2S and _CO2 is combined with H2S selectivity in the _second absorption zone (12) The liquid absorbent solution (28) is contacted to obtain a stripped gas stream ( ₁₃ ) depleted of H2S and containing aromatics, _C4 ⁺ aliphatics and _CO2 and also containing co-absorbed aromatics, _C4 ⁺ aliphatics and an H2S _- enriched absorbent solution (14) of _CO2 , said H2S _- selective liquid absorbent solution being preferably the same as used in step a), d) The _C4 ⁺ aliphatic and aromatic depleted absorbent solution (9) obtained in step b) is introduced into a desorption zone ( ₁₆ ), where the H2S selective liquid absorbent solution (17) is recovered and _A depleted acid gas comprising H2S and _CO2 depleted of _C4 ⁺ aliphatic and aromatic hydrocarbons is produced (21). 2. The method according to the preceding claim, wherein the stripping gas (7) used in the stripping zone (8) is a combustible gas meeting the combustible standard requirements, such as natural gas, _hydrogen and/or containing H and CO is a synthesis gas and is a combustible gas used to run the incinerator (33) and/or utility boiler. 3. The method according to any one of the preceding claims, wherein the acid-depleted gas stream (1) comprises: -75-99.925mol.% CO ₂ , - 250 mol.ppm - 20 mol.% of H ₂ S, preferably 500 mol.ppm - 15 mol.% of H ₂ S, more preferably 500 mol.ppm - 10 mol.% of H ₂ S and even more preferably 500 mol.ppm - 5 mol.% H ₂ S, -500mol.ppm-5mol.% of _C4 ⁺ aliphatic hydrocarbons and aromatics, The percentages are expressed in moles on a dry basis relative to the total moles of lean acid gas. 4. _A method according to any preceding claim, wherein the H2S selective liquid absorbent solution comprises: - chemical solvents, such as alkali metal carbonates and phosphates, or alkanolamines, preferably in the form of aqueous solutions, - physical solvents such as substituted or unsubstituted sulfolanes or mercaptoethanols, or a mixture thereof, such as a mixture of alkanolamine and mercaptoethanol. 5. _A method according to any preceding claim, wherein the H2S selective liquid absorbent solution comprises an amine, preferably an alkanolamine, more preferably a tertiary or sterically hindered alkanolamine , and even more preferably methyldiethanolamine (MDEA). 6. _A method according to any one of the preceding claims, wherein the H2S selective liquid absorbent solution comprises an additive component capable of enhancing the selectivity of absorption of _H2S to _CO2 , such as an acidic component, such as Phosphoric acid (H ₃ PO ₄ ). 7. The method according to any one of the preceding claims, wherein said absorbing steps a) and c) are at: - a temperature of 10-100°C, preferably a temperature of 30-70°C, more preferably a temperature of 40-60°C, and - at a pressure of 1-8 barA, preferably at a pressure of 1.5-4 barA. 8. The method according to any one of the preceding claims, wherein the non-thermal stripping in step b) is at: - a temperature of 50-150°C, preferably a temperature of 60-130°C, more preferably a temperature of 70-110°C, and - at a pressure of 1-8 barA, preferably at a pressure of 1.5-4 barA. 9. The method according to any one of the preceding claims, wherein the H2S _- enriched absorbent solution (14) leaving the second absorption zone (12) is recycled back to the stripping zone (8 ) to replenish said H2S _- enriched absorbent solution (14) and/or directly into the desorption zone (16) to replenish the aromatics-depleted absorbent solution (9) obtained in step b). 10. A process according to any one of the preceding claims, wherein the _C4 ⁺ aliphatic and aromatic depleted absorbent solution (9) recovered from the stripping zone (8) is prior to entering the desorption zone , to increase its temperature by heater (15). 11. The method according to the preceding claim, wherein the temperature increase in the heater (15) is achieved by recirculating in the heater (15) at least a portion of the Obtained by regenerating the liquid absorbent solution (17). 12. The method according to any one of the preceding claims, wherein the H2S _- enriched absorbent solution (4) is passed through a heater (6) to elevate it before entering the stripping zone (8). temperature. 13. The method according to the preceding claim, wherein the temperature increase in the heater (6) is recovered from the desorption zone (16) by recycling at least a part in the heater (6) and/or obtained from said H2S selective liquid absorbent solution ( ₁₇ ) leaving said heat exchanger (15). 14. Process according to the preceding claim, wherein the aromatics-depleted acid gas (21) or (26) is partially recycled to provide said acid-depleted gas stream ( ₁ ) and/or to provide said enriched H2S , CO ₂ and aromatics stripping gas stream (10). 15. The method according to any one of the preceding claims, wherein said acid-depleted gas comprising _CO2 and less than ₂₀ mol.% H2S is obtained according to the following method, said method comprising: a) Natural gas comprising methane (CH ₄ ) and ethane (C ₂ H ₆ ), CO ₂ , H ₂ S and C ₄ ⁺ aliphatic and aromatic hydrocarbons is contacted with a liquid absorbent solution in the absorption zone to produce Natural gas streams depleted of H ₂ S and CO ₂ and containing methane (CH ₄ ) and ethane (C ₂ H ₆ ) and H ₂ S and CO ₂ enriched and also containing co-absorbed C ₄ ⁺ aliphatic and aromatic hydrocarbons absorbent solution, b) The absorbent solution enriched in H2S and _CO2 and also containing co _- absorbed _C4 ⁺ aliphatic and aromatic hydrocarbons is introduced into a desorption zone where the liquid absorbent solution is recovered and a _CO2 -containing And less than 20mol.% H ₂ S acid-depleted gas. 16. A method of recovering sulfur from a lean acid gas comprising _CO2 and less than ₂₀ mol.% H2S, said method comprising: i) pretreating the acid-depleted gas stream (1) for the removal of aromatics and _C4 ⁺ aliphatic hydrocarbons in a process according to any one of claims 1-15 to obtain _C4 ⁺ aliphatic depleted Acid-depleted gases of hydrocarbons and aromatics (21) or (26), ii) mixing at least part of said pretreated acid-depleted gas (21) or (26) depleted of _C4 ⁺ aliphatic hydrocarbons and aromatics with an oxygen _- containing gas such as air to obtain a gas stream comprising H2S and oxygen , iii) optionally, introducing part of the obtained aromatics-depleted acid gas (21) or (26) and oxygen into the furnace to recover elemental sulfur, iv) After optionally preheating, the _C4 ⁺ aliphatic and aromatic depleted acid gas recovered from step ii) and optionally iii) is passed into a catalytic reactor comprising a catalyst system, said _The catalyst system catalyzes the direct oxidation of H2S with oxygen and/or the Claus reaction of H2S with sulfur _dioxide (SO2 ₎ to recover an acid _- depleted gas stream depleted of H2S and elemental sulfur. 17. The method according to the preceding claim, wherein step iv) comprises and/or is followed by: iv.1 After optionally preheating, said acid _- lean gas stream comprising H2S and oxygen is transferred to a first part of a first reactor comprising an uncooled adiabatic bed comprising a first catalyst for catalytic oxidation of _H2S with oxygen and catalytic oxidation of H2S with sulfur _dioxide , wherein the maximum temperature of said adiabatic bed is T1, iv.2 diverting said acid-depleted gas stream from a first portion of said first reactor to a second portion of said first reactor, the second portion comprising a second catalyst which may be different from the first catalyst, and the The second part is maintained at a temperature T2, where T2 ≤ T1 and T2 is above the dew point temperature of elemental sulfur, resulting in a H2S _- depleted gas stream, _iv.3 transferring said H2S depleted gas stream to a sulfur condenser to obtain a sulfur depleted gas stream, iv.4 optionally preheating said sulfur-depleted gas stream, iv.5 diverting said sulfur-depleted gas stream into a first section of a second reactor comprising an uncooled adiabatic bed comprising the same catalyst as said first section of said first reactor , wherein the first part of the second reactor is operated at a temperature above the dew point of elemental sulfur such that no elemental sulfur is deposited on the catalyst as a liquid or solid in the first part of the second reactor, iv.6 diverting said gas stream from a first portion of said second reactor to a second portion of said second reactor comprising a first two portions of the same catalyst, and the second portion is maintained at a temperature at or below the dew point of elemental sulfur such that elemental sulfur deposits on said catalyst as a liquid or solid in the second portion of said second reactor, and Obtain a desulfurized gas stream that meets the requirements of air emission standards, iv.7 switching the operating conditions of said first reactor and said second reactor after a defined time and simultaneously switching the gas flow, so that the previous second reactor becomes the new first reactor, and the previous first reactor The reactor becomes the new second reactor. 18. The process according to claims 15-17, wherein in step iv) the H2S-depleted gas stream (3), the H2S-depleted gas stream ( ₃ ), the H2S _- depleted gas stream leaving the sulfur recovery unit Stripping gas stream (13) and/or said H2S _- depleted acid _- depleted gas stream (32) is transferred to an incinerator (33) where it is combusted to destroy remaining H2S as well as aromatics and _C4 contained therein ⁺ Aliphatic hydrocarbons, thereby meeting air emission standards, or compressed, injected, and discharged into underground storage rather than incinerated and released into the atmosphere.