CN107580522B

CN107580522B - Process for removing aromatics from a lean acid gas feed for sulfur recovery

Info

Publication number: CN107580522B
Application number: CN201680024440.8A
Authority: CN
Inventors: E·菲拉特; G·佩迪; B·马雷斯
Original assignee: Axens SA
Current assignee: Axens SA
Priority date: 2015-04-30
Filing date: 2016-04-28
Publication date: 2021-07-13
Anticipated expiration: 2036-04-28
Also published as: RU2017135359A3; CA2982686A1; RU2017135359A; EP3288667A1; AU2016256240A1; RU2705974C2; MX2017013900A; CN107580522A; WO2016174120A1

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 removing aromatics from a lean acid gas feed for sulfur recovery

Technical Field

The invention relates to the recovery of sulfur from a sulfur-containing stream containing CO prior to sulfur recovery₂And less than 20 mol.% H₂Removal of aromatic hydrocarbons (BTX) such as benzene, toluene, ethylbenzene and xylene, and carbon atoms (C) having 4 carbon atoms or more from the lean acid gas of S₄ ⁺) A process for producing aliphatic hydrocarbons.

Background

Natural gas, as captured from naturally occurring deposits, is composed primarily of light aliphatic hydrocarbons such as methane, propane, butane, pentane, and isomers thereof. Certain contaminants are naturally present in the gas and must be removed before the purified gas is delivered for private use or commercial environments. These contaminants include those having 4 carbon atoms or more (C)₄ ⁺) And aromatic hydrocarbons such as benzene, toluene, ethylbenzene and xylene, collectively referred to as "BTX", but more importantly an acid component such as hydrogen sulfide (H)₂S) and carbon dioxide (CO)₂)。

The presence of hydrogen sulfide in industrial gases poses serious environmental problems and is detrimental to plant structure, requiring constant maintenance. Therefore, the removal of H from gas streams is strictly required₂S, particularly in natural gas plants.

H in natural gas₂The removal and treatment of S is typically by inclusion of H under natural gas pressure₂S with a liquid amine solvent, typically 40-100bar (considered "high pressure"), thus allowing H to form₂S is absorbed by the amine solvent. Due to absorption of H₂Maintaining high pressure, carbon dioxide (CO) during S₂) Aromatic hydrocarbons and C₄ ⁺The aliphatic hydrocarbon is simultaneously absorbed by the amine solvent. Thereby obtaining a "sweet" or purified natural gas meeting environmental standards and recovering a gas containing a major portion of the Contaminants (CO)₂、H₂S, aromatic hydrocarbons and C₄ ⁺Aliphatic hydrocarbons). The contaminated amine solvent is then passed to a regeneration zone where it is recovered under high temperature (typically about 130 ℃) and low pressure conditions (typically about 2-3 barA). Also obtain and contain CO₂、H₂S, aromatic hydrocarbons and C₄ ⁺Acid gases of aliphatic hydrocarbons.

The presence of H in the acid gas obtained after purification of natural gas₂S remains problematic, so installation of a Sulfur Recovery Unit (SRU) will introduce toxic sulfur compounds, such as H₂S, transformed into harmless elemental sulfur.

For containing H₂The common process for the gas stream desulfurization of S is the Claus process, which operates by two main process steps. The first process step is carried out in a furnace wherein hydrogen sulfide is converted to elemental sulfur and sulfur dioxide at a temperature of about 1100-. The sulphur dioxide thus obtained is reacted with hydrogen sulphide in the furnace to elemental sulphur by means of a Claus reaction. Thus, in the first step of the Claus process, about 60-70% of the H in the feed gas is₂S is converted and most of the aromatics and C₄ ⁺The aliphatic hydrocarbons are removed.

In order to obtain a higher sulfur recovery, at least one catalytic step is continued following the Claus reaction according to equation 1:

the Claus process is well suited to contain more than 55 mol.% H₂S, wherein a first combustion step operating at a temperature above 1200 ℃ may be performed sufficiently to convert 60-70% of the H₂S conversion and simultaneous destruction of aromatics and C₄ ⁺An aliphatic hydrocarbon. However, using the Claus process results in less than 55 mol.% H₂Recovery of sulfur from the acid gas feed of S is more complicated: the first combustion step cannot be carried out at a sufficiently high temperature or due to the presence of a large amount of CO in the feed to cool the combustion reaction to below 1100 c₂And the first combustion step is not carried out at all, or when CO is present₂When the content exceeds 85%, the combustion reaction is even inhibited. This allows for aromatics and C₄ ⁺The aliphatic hydrocarbon is protected from combustion in the first thermal step of the Claus process and is not reacted in the catalytic step. However, these aromatic hydrocarbons and C₄ ⁺Aliphatic hydrocarbons are detrimental to the installed units because they deactivate the catalyst operating 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 hydrogen from compositions containing less than 55 mol.% H₂Poverty of SRemoval of aromatics and C from sour gas feed₄ ⁺Aliphatic hydrocarbons, making them suitable for use in sulfur plants. For example, an Acid Gas Enrichment (AGE) process, wherein a lean acid gas (typically obtained from a regeneration zone operating at about 130 ℃ and 2-3barA) is treated in an absorber at its pressure of 3barA (considered "low pressure") using an alternative solvent that may be employed. Due to the "low pressure" in AGE operations, the solvent preferentially absorbs H₂S instead of CO₂And aromatic hydrocarbons and C₄ ⁺The level of aliphatic hydrocarbons is much lower. After the solvent is regenerated, enriched H is obtained₂S and CO depletion₂Aromatic hydrocarbons and C₄ ⁺Acid gases of aliphatic hydrocarbons. When it can increase H in acid gas₂To an S content of more than 55 vol.%, allowing the acid gas obtained to be conventionally treated by Claus, the AGE process is generally selected to remove aromatics and C before the Claus catalytic step by treatment in a Claus furnace at a temperature higher than 1100 ℃₄ ⁺An aliphatic hydrocarbon. For example, patent application EP2402068 discloses the treatment of acid gases with two absorption steps. In the process, the enriched H obtained from the first absorption zone is₂The solvent of S is sent to a desorption zone where heat is supplied to desorb H₂S and promotes the formation of enriched H₂S gas. Then a portion of this enriched H is₂The gas of S is sent to another H₂The S absorption zone is further enriched. However, when H is present in the acid gas₂AGEs are unsatisfactory when the initial concentration of S is too low (typically less than 20. mol.%) to reach a concentration above 55 mol.% after enrichment.

Another for removing aromatic hydrocarbon and C₄ ⁺A solution to aliphatic hydrocarbons is gas stripping of the rich amine solvent, typically fuel gas stripping, from the "high pressure" sour natural gas absorber prior to its regeneration. The fuel gas flow will remove aromatic hydrocarbons and C in the lean acid gas₄ ⁺Aliphatic hydrocarbons, so that depleted aromatic hydrocarbons and C can be obtained₄ ⁺An aliphatic hydrocarbon amine solvent. Comprising aromatic hydrocarbons and C₄ ⁺Fuel gas of aliphatic hydrocarbons will be used as combustibles of incinerators or utility boilers, in which pollutants will be destroyed. However, in this case the gas is gaseousIn the extraction process, aromatics and C are removed from rich amine₄ ⁺Aliphatic hydrocarbons vary with stripping fuel gas flow rate: the higher the fuel gas flow rate, the more removal. However, the fuel gas is used in the unit as feed for the incinerator and/or utility boilers and its flow rate is therefore still limited by the requirements of the incinerator or utility boilers. In order to properly remove aromatic hydrocarbons and C₄ ⁺Aliphatic hydrocarbons, it is necessary to use extremely large amounts of fuel gas well above the fuel gas required to operate the incinerator and/or utility boilers. This will therefore result in high waste of fuel gas, especially when the rich amine solvent obtained from the "high pressure" sour natural gas absorber is high in aromatics and aliphatic hydrocarbons. In this case, for the removal of aromatics and C from lean acid gas prior to sulfur recovery₄ ⁺The problem of aliphatic hydrocarbons, fuel gas stripping, would not provide a satisfactory solution.

Another option considered in the industry is the absorption of aromatics and C from acid gases in a regenerable activated carbon bed or molecular sieve₄ ⁺An aliphatic hydrocarbon. Although technically feasible, due to the necessary regeneration cycles of the carbon bed, and due to the presence of, for example, H₂Contaminants of S, the difficulty of stabilizing the products from these regeneration zones, these processes are still expensive.

Therefore, sufficient H cannot be achieved when AGE does not₂In S enrichment, there remains a need for a sulfur recovery catalyst that contains less than 20 mol.% H₂The lean acid gas of S is effective in removing aromatic hydrocarbons (BTX) such as benzene, toluene, ethylbenzene and xylene, and has 4 carbon atoms or more (C)₄ ⁺) A process for producing aliphatic hydrocarbons.

Brief description of the invention

The object of the present invention is to provide a catalyst for the reduction of carbon monoxide from a gas containing CO₂And less than 20 mol.% H₂Removal of aromatic hydrocarbons (BTX) such as benzene, toluene, ethylbenzene and xylene, and carbon atoms (C) having 4 carbon atoms or more from the lean acid gas of S₄ ⁺) The aliphatic hydrocarbon of (a), the process comprising:

a) mixing the lean acid gas (1) with H in a first absorption zone (2)₂S-selective liquid absorbent solution (29) to produce spent H₂S and comprises CO₂Aromatic hydrocarbons and C₄ ⁺A stream of aliphatic hydrocarbons (3) and also comprising co-absorbed C₄ ⁺Aliphatic hydrocarbons, aromatic hydrocarbons and CO₂Is enriched in H₂An absorbent solution (4) of S,

b) subjecting said enriched H₂The absorbent solution (4) of S is introduced into a non-thermal stripping zone (8) where it is contacted with a stripping gas stream (7), preferably fuel gas, to obtain spent C₄ ⁺Aliphatic and aromatic hydrocarbons and comprising H₂S and CO₂And also comprising H₂S and CO₂Is enriched in aromatic hydrocarbons and C₄ ⁺A stripping gas stream (10) of aliphatic hydrocarbons,

c) in a second absorption zone (12) the product obtained in step b) also comprises H₂S and CO₂Is enriched in aromatic hydrocarbons and C₄ ⁺Stripping gas stream (10) of aliphatic hydrocarbons with H₂S-selective liquid absorbent solution (28) to obtain depleted H₂S and comprising aromatic hydrocarbons, C₄ ⁺Aliphatic hydrocarbons and CO₂And also co-absorbed aromatic hydrocarbons, C₄ ⁺Aliphatic hydrocarbons and CO₂Is enriched in H₂S absorbent solution (14), said H₂The S-selective liquid absorbent solution is preferably the same as used in step a),

d) depletion C obtained in step b)₄ ⁺An absorbent solution (9) of aliphatic and aromatic hydrocarbons is introduced into a desorption zone (16) in which H₂The S-selective liquid absorbent solution (17) is absorbed and produces depleted C₄ ⁺Of aliphatic and aromatic hydrocarbons comprising H₂S and CO₂The lean acid gas (21).

The invention also relates to a process for the preparation of a catalyst from a mixture comprising CO₂And less than 20 mol.% H₂A process for recovering sulfur from a lean S gas, the process comprising:

i) pretreating the catalyst for removing aromatic hydrocarbons and C according to the method₄ ⁺Lean acid gas (1) of aliphatic hydrocarbons to obtain depleted C₄ ⁺Aliphatic and aromatic lean acid gases (21) or (26),

ii) at least part of said depletion C₄ ⁺The pre-treated lean acid gas (21) or (26) of aliphatic and aromatic hydrocarbons is mixed with an oxygen-containing gas, such as air, to obtain a gas comprising H₂A stream of S and oxygen gas,

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

iv) after optional preheating, recycling depleted C from step ii) and optional step iii)₄ ⁺The lean acid gas of aliphatic and aromatic hydrocarbons enters a catalytic reactor containing a catalyst system that catalyzes H with oxygen₂Direct oxidation of S and/or with sulfur dioxide (SO)₂) Catalysis H₂Claus reaction of S to recover spent H₂S and elemental sulphur.

Brief description of the drawings

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

Figure 1 schematically illustrates a preferred method of the invention. The dashed lines represent alternative embodiments of the invention.

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

Detailed Description

Step a

The process for removing aromatic hydrocarbons (BTX) from a lean acid gas according to the present invention comprises a first step a): mixing the lean acid gas (1) with H in a first absorption zone (2)₂S-selective liquid absorbent solution (29) to produce spent H₂S and comprises CO₂Aromatic hydrocarbons and C₄ ⁺A gas stream (3) of aliphatic hydrocarbons, and also comprising co-absorbed C₄ ⁺Aliphatic hydrocarbons, aromatic hydrocarbons and CO₂Is enriched in H₂S absorbent solution (4).

The purpose of step a) is to minimize H in the gas feed₂S content so as to obtain a spent H suitable for combustion in an incinerator (33) and discharge into the atmosphere₂S (3). The gas (3) leaving the first absorption zone (2) is depleted of H₂S and comprises CO₂Aromatic hydrocarbons and C₄ ⁺An aliphatic hydrocarbon.

H in lean acid gas₂The S content is reduced by H₂S-selective liquid absorbent solution (29) absorbs H₂And (S) is obtained. Thus, at the bottom of the first absorption zone (2), an enriched H is obtained₂S in a liquid absorbent solution. However, even if the first absorption step a) is operated at a relatively low pressure (1-8barA), a part of the aromatics and C contained in the lean acid gas (1) is₄ ⁺The aliphatic hydrocarbons will be co-absorbed simultaneously by the liquid absorbent solution (29) and will require further treatment.

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

-75-99.925 mol.% CO₂，

-250mol.ppm to 20 mol.% of H₂S, preferably 500mol.ppm to 15 mol.% H₂S, more preferably 500mol.ppm to 10 mol.% H₂S and even more preferably 500mol.ppm to 5 mol.% of H₂S，

-500mol.ppm-5 mol.% of C₄ ⁺Aliphatic hydrocarbons and aromatic hydrocarbons, and a mixture thereof,

the percentages are expressed in moles on a dry basis relative to the total moles of the acid-lean gas. In practice, the acid-depleted gas is typically saturated with water.

In a preferred embodiment, the process of the invention comprises CO₂And less than 20 mol.% H₂Lean gas of S is derived from methane (CH)₄) And ethane (C)₂H₆)、CO₂、H₂S and C₄ ⁺Natural gas of aliphatic and aromatic hydrocarbons.

In fact, this natural gas is used as combustible and therefore should not contain any contaminants, such as acid gases (CO)₂、H₂S). H in natural gas₂The specification for the S concentration is very strict and its maximum concentration should be kept below 4ppm mol. On the other hand, CO₂Should preferably be kept below 2% depending on the subsequent use of natural gas and legislation. Therefore, it requires treatment daysNatural gas to remove acid gas (CO) contained therein₂、H₂S). Purified natural gas is then obtained that meets transport, storage and private or commercial use standards, and at the same time also produces a product that contains CO₂、H₂S and aromatic hydrocarbons and C₄ ⁺Acid-lean gases of aliphatic hydrocarbons. This lean acid gas needs to be treated prior to sulfur recovery.

Thus, in preferred embodiments, the CO comprises₂And less than 20 mol.% H₂The lean acid gas of S is obtained according to the following process, which comprises:

a) will comprise methane (CH)₄) And ethane (C)₂H₆)、CO₂、H₂S and C₄ ⁺The natural gas of aliphatic and aromatic hydrocarbons is contacted with a liquid absorbent solution in an absorption zone to produce depleted H₂S and CO₂And comprises methane (CH)₄) And ethane (C)₂H₆) And enriched in H₂S and CO₂And further comprising co-absorbed C₄ ⁺Absorbent solutions of aliphatic and aromatic hydrocarbons,

b) subjecting said enriched H₂S and CO₂And further comprising co-absorbed C₄ ⁺Introducing an absorbent solution of aliphatic and aromatic hydrocarbons into a desorption zone, wherein the liquid absorbent solution is recovered and produces a product comprising CO₂And less than 20 mol.% H₂Lean acid gas of S.

The natural gas used to obtain the acid-depleted gas for the purposes of the present invention comprises C₄ ⁺Aliphatic and aromatic hydrocarbons, and with CO₂In comparison with a small amount of H₂S (e.g. CO)₂Quantity ratio of (H)₂The amount of S is at least 4 times higher).

Step a) may preferably be carried out in:

a temperature of from 50 to 200 ℃, preferably of from 110 ℃ to 145 ℃, and

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

H₂The S-selective liquid absorbent solution may be any known absorbent conventionally used by those skilled in the art, such as chemical solvents, substancesPhysical solvents and mixtures thereof. When a chemical solvent is used as the liquid absorbent solution, it may be combined with a physical solvent to enhance absorption of contaminants typically present in the lean acid gas.

For example, the chemical solvent may include alkali metal carbonates and phosphates, or alkanolamines, preferably in the form of an aqueous solution.

The alkanolamine is preferably selected from tertiary alkanolamines and sterically hindered alkanolamines. The sterically hindered alkanolamine may be selected from the group consisting of 2-amino-2-methylpropanol, 2-amino-2-methyl-1, 3-propanediol, 2-amino-2-hydroxymethyl-1, 3-propanediol, 2-amino-2-ethyl-1, 3-propanediol, 2-hydroxymethylpiperidine, 2- (2-hydroxyethyl) piperidine, 3-amino-3-methyl-1-butanol and mixtures thereof.

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

The physical solvent may include, for example, substituted or unsubstituted sulfolane or mercaptoethanol.

In a preferred embodiment, H₂The S-selective liquid absorbent solution comprises an amine, preferably an alkanolamine, more preferably a tertiary or sterically hindered alkanolamine, even more preferably Methyldiethanolamine (MDEA). Aqueous Methyldiethanolamine (MDEA) is a preferred liquid absorbent solution according to the present invention.

In another preferred embodiment, H₂The S-selective liquid absorbent solution may be a mixture of alkanolamine and mercaptoethanol.

Can also be introduced into the liquid absorbent solution to enhance H₂S to CO₂Of an absorption-selective additive component, such as an acidic component, e.g. phosphoric acid (H)₃PO₄)。

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 alkanolamine in the aqueous solution is 5 to 60 wt.%, preferably 25 to 50 wt.%. If a physical solvent is used as a component of the absorbent liquid, it may be present in an amount of 2 to 50% by weight, preferably 5 to 45% by weight.

The absorption step a) is preferably carried out:

a temperature of from 10 to 100 ℃, preferably a temperature of from 30 to 70 ℃, more preferably a temperature of from 40 to 60 ℃, and

a pressure of from 1 to 8barA, preferably from 1.5 to 4 barA.

Spent H leaving the first absorption zone (2)₂The gas stream (3) of S preferably comprises CO₂Aromatic hydrocarbons and C₄ ⁺Aliphatic hydrocarbons and in particular comprising:

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

60-99 mol.% aromatics and C contained in the lean acid gas (1)₄ ⁺Aliphatic hydrocarbons, more preferably 80-98 mol.%,

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

The depletion H leaving the first absorption zone (2) can then be₂The stream (3) of S is transferred to an incinerator (33) where it is burned to destroy the remaining H₂S and aromatic hydrocarbons and C contained therein₄ ⁺Aliphatic hydrocarbons to meet the air emission standards. Alternatively, depletion H can be₂The stream (3) of S is compressed, injected and discharged into underground storage, rather than incinerated and released into the atmosphere.

Enriched H leaving the first absorption zone (2)₂The absorbent solution (4) of S also contains co-absorbed C₄ ⁺Aliphatic hydrocarbons, aromatic hydrocarbons and CO₂. In a preferred embodiment, the enriched H leaving the first absorption zone (2)₂The absorbent solution (4) of S comprises:

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

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

-0.5-40 mol.% of C contained in the lean acid gas (1)₄ ⁺Aliphatic and aromatic hydrocarbons, more preferably 1-10 mol.%.

Step b

Then the enriched H leaving the first absorption zone (2)₂The absorbent solution (4) of S is sent to a non-thermal stripping zone (8) where it is contacted with a stripping gas stream (7), preferably fuel gas, to obtain spent C₄ ⁺Aliphatic and aromatic hydrocarbons and comprising H₂S and CO₂And also comprising H₂S and CO₂Is enriched in aromatic hydrocarbons and C₄ ⁺A stripping gas stream (10) of aliphatic hydrocarbons.

In fact, further to the first absorption step a), H is enriched₂The absorbent solution (4) of S also contains co-absorbed C₄ ⁺Aliphatic hydrocarbons and aromatic hydrocarbons.

Therefore, the object of step b) is to use as little H as possible₂S, removing as much C as possible from the absorbent solution₄ ⁺Aliphatic hydrocarbons and aromatic hydrocarbons such that when a lean acid gas is recovered, it is free of high concentrations of impurities that can poison the sulfur recovery unit catalyst. This is achieved by enriching H in a non-thermal stripping step₂The absorbent solution (4) of S is contacted in countercurrent with a stripping gas stream (7), such as a fuel gas stream.

The stripping step of the prior art is usually enriched in H simply by heating₂The absorbent solution of S is either produced as a stripping fluid or by direct injection of the fluid in the stripping zone. Supplying heat to the stripping zone increases the acid gases, particularly H, from the absorbent solution₂Chemical desorption of S and its removal with a stripping stream is facilitated. Thus, substantial depletion of H is obtained by a conventional stripping step of the prior art₂Absorbent solution of S. In contrast, the stripping step of the claimed process is in a sense non-thermal, at which stage no significant heat or energy is provided to the process. By operating the stripping step without significant heating, H can be more selectively stripped₂C above S₄ ⁺Aliphatic and aromatic hydrocarbons to obtain depleted C₄ ⁺Aliphatic and aromatic hydrocarbons and comprising H₂S and CO₂And also a small amount of H, and₂s, but significantly less than H from the thermal stripping step₂Enrichment of S with aromatics and C₄ ⁺A stripping gas stream (10) of aliphatic hydrocarbons.

The resulting absorbent solution (9) is depleted in C₄ ⁺Aliphatic hydrocarbons and aromatic hydrocarbons. The stripping gas stream (7) will preferentially enrich from H₂Removal of (strip off) H from S absorbent solution (4)₂C above S₄ ⁺Aliphatic and aromatic hydrocarbons, but also a portion of H which will be contained in the absorbent solution (4)₂S and CO₂And (4) carrying away. Thus, the stripping gas stream (10) leaving the stripping zone (8) is enriched in aromatics and C₄ ⁺Aliphatic hydrocarbons, and also comprises H₂S and CO₂。

The stripping gas stream used in the stripping zone of the process of the present invention may preferably be a fuel gas stream, but may also be any combustible gas that meets the requirements of combustible standards, such as natural gas, hydrogen, and/or comprises predominantly H₂And CO, or other inert gases containing primarily 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 in the utility boiler.

In a preferred embodiment, the stripping gas stream is a fuel gas, and preferably the fuel gas (7) used in the stripping zone (8) is a combustible gas for an incinerator (33) and/or utility boiler in the operating unit. In practice, the plant in which the process of the invention is carried out generally comprises incinerators and/or utility boilers for various purposes. The incinerator and boiler must be supplied with fuel gas. One advantage of the present invention is that the fuel gas required for feeding the incinerator and/or utility boiler of the plant is first used as a stripping gas stream and then recovered and re-routed to its original path for feeding the incinerator and/or utility boiler. The utility boiler (not shown in the figures) generates steam which can be fed to the boiler of the plant in which the claimed process is carried out, for example the boiler (18) in fig. 1. The fuel gas flow rate in the stripping zone is limited by the flow of combustible gas required to operate the incinerator (33) and/or utility boiler. In this embodiment, the fuel gas is continuously used as stripping gas stream in the stripping zone (8) and the incinerator and/or utility boilers are operated as combustible gas, 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 be enriched with H₂Countercurrent contact of the absorbent solution (4) of S.

The absorption step b) is preferably carried out:

a temperature of from 50 to 150 ℃, preferably a temperature of from 60 to 130 ℃, more preferably a temperature of from 70 to 110 ℃, and

a pressure of from 1 to 8barA, preferably from 1.5 to 4 barA.

To enrich H₂The absorbent solution of S (4) meets the pressure conditions required in the stripping zone, it may be necessary to pass it through a pump (5) or through a valve before entering the stripping zone.

Enrichment of H in certain cases where installation is limited, for example in terms of the flow rate of the stripping gas stream₂The absorbent solution of S (4) may also be raised in temperature by a heater (6) prior to entering the stripping zone (8) to effect removal of aromatics and C₄ ⁺An aliphatic hydrocarbon. In this embodiment, the heat supplied to the stripping step should be controlled to increase aromatics and C₄ ⁺Removal of aliphatic hydrocarbons while ensuring that there is only a minimal amount of H₂S is desorbed from the absorbent solution to avoid obtaining a solution that will be enriched in H₂Stripping gas stream (7) of S. In fact, the stripping gas stream (7) is enriched in H₂In the case of S, it would be necessary to increase the size of the second absorption zone to ensure complete removal of H₂And S. In a preferred embodiment, the temperature increase in heater (6) may be achieved by recycling at least a portion of the H recovered from desorption zone (16) and/or exiting heat exchanger (heater 15) in heater (6)₂S-selective liquid absorbent solution (17). Thus, H₂The S-selective liquid absorbent solution serves as a heat source for the heater (6).

The stripping gas stream (10) leaving the stripping zone (8) is enriched in aromatics and C, as described above₄ ⁺Aliphatic hydrocarbons, but also H₂S and CO₂. It preferably comprises:

is contained in the entering stripping zone (8)50-99 mol.%, preferably 85-99 mol.%, of aromatic hydrocarbons and C in the absorbent solution (4) of (a)₄ ⁺An aliphatic hydrocarbon(s),

-5-40 mol.%, preferably 5-20 mol.% of CO contained in the absorbent solution (4) entering the stripping zone (8)₂，

-1-20 mol.%, preferably 1-10 mol.%, of H contained in the absorbent solution (4) entering the stripping zone (8)₂S。

The absorbent solution (9) leaving the stripping zone (8) is depleted C₄ ⁺Aliphatic and aromatic hydrocarbons, and preferably comprises:

-80-99 mol.%, preferably 90-99 mol.%, of H contained in the absorbent solution (4) entering the stripping zone (8)₂S，

-1-50 mol.%, preferably 1-15 mol.%, of aromatic hydrocarbons and C contained in the absorbent solution (4) entering the stripping zone (8)₄ ⁺An aliphatic hydrocarbon(s),

-60-95 mol.%, preferably 70-90 mol.%, of CO contained in the absorbent solution (4) entering the stripping zone (8)₂。

In a preferred embodiment, the absorbent solution (9) leaving the stripping zone (8) comprises 0.01-10 mol.% of aromatics and C contained in the lean acid gas (1)₄ ⁺Aliphatic hydrocarbons, more preferably 0.1-5 mol.%.

Step c

In a second absorption zone (12), the product obtained in step b) also comprises H₂S and CO₂Is enriched in aromatic hydrocarbons and C₄ ⁺Stripping gas stream (10) of aliphatic hydrocarbons with H₂S-selective liquid absorbent solution (28) to obtain depleted H₂S and comprising aromatic hydrocarbons, C₄ ⁺Aliphatic hydrocarbons and CO₂And also co-absorbed aromatics, C₄ ⁺Aliphatic hydrocarbons and CO₂Is enriched in H₂S absorbent solution (14), said H₂The S-selective liquid absorbent solution is preferably the same as used in step a).

In particular, more than 80% of the enriched aromatics obtained in step b) and C are separated₄ ⁺Stripping gas of aliphatic hydrocarbons (10)A stream, preferably more than 90%, more preferably all of the stripping gas stream (10) is passed to the second absorption zone (12).

In fact, further to the stripping step b), the stripping gas stream (10) is enriched in aromatics and C₄ ⁺Aliphatic hydrocarbons, but also H₂S and CO₂。

Therefore, the purpose of step c) is to remove as much H as possible from the stripping gas stream (10)₂S to recover a stripping gas stream suitable for further use as a combustible, such as fuel gas for an incinerator (33) and/or a power plant boiler. Alternatively, depletion H can be₂The stripping gas stream of S is compressed, injected and discharged into an underground storage reservoir, rather than incinerated and released into the atmosphere. This is achieved by enriching the aromatics and C₄ ⁺Stripping gas stream (10) of aliphatic hydrocarbons with H₂S-selective liquid absorbent solution (28), said H₂The S-selective liquid absorbent solution is preferably used in step a).

E.g. H₂The S-selective liquid absorbent solution (28) may be obtained by introducing a main solvent stream (29) into the first absorption zone.

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

Optionally, in order to enrich aromatics and C₄ ⁺Aliphatic hydrocarbons but also H₂S and CO₂The stripping gas stream (10) meets the desired temperature conditions in the second absorption zone (12) and it may be necessary to 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 CO₂And in particular comprises:

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

-60-99 mol.% of aromatic hydrocarbons (BTX) and C contained in the stripping gas stream (10) leaving the stripping zone (8)₄ ⁺Aliphatic seriesHydrocarbons, more preferably 80 to 98 mol.% and

-0.01-20 mol.% of H contained in the stripping gas stream (10) leaving the stripping zone (8)₂S, more preferably 0.02-5 mol.%.

Depleted H leaving the second absorption zone (12)₂S and comprising aromatic hydrocarbons, C₄ ⁺Aliphatic hydrocarbons and CO₂Meets the standard requirements for combustibles such as combustion gases and can therefore be used as a feed to an incinerator (33) and/or a power plant boiler where the associated aromatics (BTX) and C will be destroyed₄ ⁺Aliphatic hydrocarbons and residual sulfur species. Alternatively, depletion H can be₂The stripping gas stream (13) of S is compressed, injected and discharged into an underground storage reservoir, rather than being incinerated and released into the atmosphere.

Enriched H leaving the second absorption zone (12)₂The absorbent solution (14) of S also contains co-absorbed aromatic hydrocarbons (BTX), C₄ ⁺Aliphatic hydrocarbons and CO₂。

In a preferred embodiment, the enriched H leaving the second absorption zone (12)₂The absorbent solution of S comprises:

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

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

-80-99.99 mol.% of H contained in the stripping gas stream (10) leaving the stripping zone (8)₂S, more preferably 95-99.98 mol.%.

According to the co-absorbed aromatic hydrocarbons (BTX), C therein₄ ⁺The amount of aliphatic hydrocarbon can be such that the enriched H leaving the second absorption zone (12)₂The absorbent solution (14) of S is recycled back to the stripping zone (8) to replenish the enriched H₂S, and/or may be introduced directly into the desorption zone (16) to replenish the aromatic-depleted absorbent solution (9) obtained in step b).

In a preferred embodiment, the enriched H leaving the second absorption zone (12) is₂Complete regeneration of the S absorbent solution (14)Recycled to the stripping zone to replenish the enriched H₂S absorbent solution (4) in order to reduce the H enrichment sent to the desorption zone (16)₂Aromatic hydrocarbons (BTX) and C in absorbent solution (9) of S₄ ⁺Content of aliphatic hydrocarbons.

With its H enrichment leaving the first absorption zone₂The stripping zone (8) and the second absorption zone (12) are designed to significantly reduce the spent H entering the desorption zone (16) compared to the content in the absorbent solution of S (4) and even compared to its initial content in the lean acid gas (1)₂Aromatics (BTX) and C in absorbent solution of S₄ ⁺Content of aliphatic hydrocarbons.

Step d

Further depleting C from the stripping zone (8)₄ ⁺An absorbent solution (9) of aliphatic and aromatic hydrocarbons, optionally supplemented with enriched H leaving the second absorption zone (12)₂An absorbent solution (14) of S is introduced into a desorption zone (16) in which H is introduced₂S-selective liquid absorbent solution (17) recovery and production of spent C₄ ⁺Of aliphatic and aromatic hydrocarbons comprising H₂S and CO₂The lean acid gas of (a).

In fact, the absorbent solution (9) leaving the stripping step b) and the second absorption step C) is depleted in C₄ ⁺Aliphatic and aromatic hydrocarbons, but still containing H₂S and CO₂。

The purpose of step d) is therefore to absorb as much H as possible from the absorbent solution (9)₂S and CO₂To recover purified absorbent solution that can be recycled back to the first and/or second absorption zone. This is done by heating the absorbent solution (9) in a desorption zone (16).

The absorption step d) is preferably carried out:

a temperature of from 50 to 200 ℃, preferably a temperature of from 70 to 180 ℃, more preferably a temperature of from 110 ℃ to 145 ℃, and

a pressure of from 1 to 4barA, preferably from 1.5 to 3 barA.

In a preferred embodiment, the spent C recovered from the stripping zone (8)₄ ⁺The absorbent solution (9) of aliphatic and aromatic hydrocarbons may also be presentBefore entering the desorption zone, the temperature thereof is raised by means of a heater (15) in order to reduce the energy consumption of the fluid circulation in the desorption zone. The temperature increase in the heater (15) is preferably obtained by recycling at least a portion of the regenerated liquid absorbent solution (17) recovered from the desorption zone (16) in the heater (15). Therefore, the regenerated liquid absorbent solution (17) serves as a heating medium for the heater (15).

Generating steam in a desorption zone (16) to provide for removal of H from the absorbent solution₂S、CO₂Hydrocarbons and aromatics such as BTX. The steam may be generated by heat exchange with any heating means (steam, hot oil, furnace, burner, boiler) present in the liquid absorbent solution at the bottom of the desorption zone (16).

Therefore, the desorption zone (16) preferably comprises a boiler (18) of steam circulation at its bottom, so as to allow enrichment with H₂And (4) regenerating the absorbent solution of S.

The regenerated liquid absorbent solution (17) leaving the bottom of the desorption zone (16) can then be used as H₂The S-selective liquid absorbent solution (29) is returned to the first absorption zone (2) and/or is used as H₂The S-selective liquid absorbent solution (28) is returned to the second absorption zone (12).

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

The lean acid gas (21) leaving the desorption zone (16) also comprises steam and vaporized absorbent solution. Water from the steam and vaporized absorbent solution carried by the lean acid gas (21) leaving the desorption zone (16) may be partially separated from the lean acid gas (21) depleted in aromatic hydrocarbons in the condenser (22) and further captured in a reflux drum (23) as an accumulator. The water and absorbent solution may then be recycled back to the desorption zone (16) by means of a pump (25) to limit the loss of water and absorbent solution. The lean acid gas (26) depleted in aromatics is recovered. Preferably, the condenser is operated at a temperature of more preferably 20 to 70 ℃, even more preferably 40 to 60 ℃.

Depleted of aromatic hydrocarbon (21) or (26)Hydrocarbons and C₄ ⁺Aliphatic hydrocarbons, and preferably includes 0.01 to 10 mol.% aromatics (BTX) and C contained in the lean acid gas entering the process₄ ⁺Aliphatic hydrocarbons, more preferably 0.1-5 mol.%.

Furthermore, the lean acid gas (21) or (26) depleted in aromatic hydrocarbons recovered at the end of the process of the invention preferably has a higher H than the lean acid gas (1) entering the process₂S/CO₂A ratio.

In a preferred embodiment, the aromatic-depleted lean acid gas (21) or (26) recovered after the desorption zone (16) can be partially recycled to supplement the lean acid gas (1) entering the process, and/or to supplement the enriched aromatic and C₄ ⁺Aliphatic hydrocarbons but also H₂S and CO₂Of the stripping gas stream (10).

The inventors have the advantage of finding that the particular continuity of the absorption and stripping steps according to the invention makes it possible to obtain a catalyst system comprising less than 20 mol.% H₂Removal of large amounts of aromatics, such as BTX and C, from S-lean acid gas₄ ⁺Aliphatic hydrocarbons, although these steps alone are not sufficient to achieve this goal. Contrary to expectations of those skilled in the art, the resulting depleted aromatics and C₄ ⁺The lean acid gas of aliphatic hydrocarbons is suitable for subsequent sulfur recovery treatment, even if not enriched in H₂S reaches a proportion of more than 55 mol.%, which is necessary for correct operation in a Claus furnace (first step of sulfur recovery), which contains sufficiently small amounts of aromatic hydrocarbons, such as BTX and C₄ ⁺Aliphatic hydrocarbons to allow a sulfur recovery unit for partial bypass operation of the furnace, 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 requirements of the incinerator (33) and/or the power plant boiler.

In a preferred embodiment, the aromatic hydrocarbons such as benzene, toluene, ethylbenzene and xylenes (BTX) and C in the lean acid gas (21) or (26) recovered at the end of the process of the invention₄ ⁺The content of aliphatic hydrocarbons should be as low as possible and not higher than 500mol.ppm, preferably from 1 to 500mol.ppm, in order to prevent deactivation of the Claus catalyst in the subsequent sulfur recovery unit.

₂Process for recovering sulphur from lean acid gas comprising less than 20 mol.% HS

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

It is therefore another object of the invention to remove the CO from the gas containing stream₂And less than 20 mol.% H₂A process for recovering sulfur from a lean S gas, the process comprising:

i) pretreatment for aromatics and C removal according to the methods described previously₄ ⁺Lean acid gas (1) of aliphatic hydrocarbons to obtain depleted C₄ ⁺Aliphatic and aromatic lean acid gases (21) or (26),

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

iv) after optional preheating, recycling depleted C from step ii) and optional step iii)₄ ⁺The lean acid gas of aliphatic and aromatic hydrocarbons enters a catalytic reactor containing a catalyst system that catalyzes H with oxygen₂Direct oxidation of S and/or with sulfur dioxide (SO)₂) Catalysis H₂Claus reaction of S to recover spent H₂S and elemental sulfur (32).

Typically, elemental sulphur is recovered in a condenser.

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

According to the depletion C obtained in the pretreatment step i)₄ ⁺H in lean acid gas (21) or (26) of aliphatic hydrocarbon and aromatic hydrocarbon₂S content, the sulfur recovery process can be easily modified by those skilled in the art.

When C is exhausted₄ ⁺H in lean acid gas (21) or (26) of aliphatic hydrocarbon and aromatic hydrocarbon₂When the S content is less than 15 mol.%, the sulfur recovery methodIt may be preferred to be a catalytic direct oxidation process only (without thermal step iii). In this case, the spent C may be introduced into the catalytic reactor before entering the catalytic reactor₄ ⁺The lean acid gas (21) or (26) of aliphatic and aromatic hydrocarbons is preheated.

When C is exhausted₄ ⁺H in lean acid gas (21) or (26) of aliphatic hydrocarbon and aromatic hydrocarbon₂The conventional Claus process coupling the thermal step iii) and the catalytic Claus step iv) can be operated with an S content of between 15 and 55 mol.%. In this case, only a portion of C is typically depleted₄ ⁺Acid-lean gases (21) or (26) of aliphatic and aromatic hydrocarbons are fed into the furnace and the remaining acid-lean gases are oxidized directly in the furnace by the burner bypass of the furnace. Taking into account the high content of inert gases, such as CO, in the lean acid gas₂And/or N₂Such partial bypassing of the burner of thermal step iii) is required to maintain a stable flame in the burner.

Optionally and preferably, the catalytic direct oxidation process may be assisted by an internal cooler such as SmartSulf^TMHot coating of the technology etc. proceeds isothermally or pseudo-isothermally. This technique is advantageous for catalytic reactors after Claus thermal step (iii), and even more advantageous for direct oxidation without Claus thermal step (iii), thus H in lean acid gas (21) or (26)₂The S content may be considered to be less than 15 mol.%.

SmartSulf^TMThe technique is disclosed in detail in the US2013/0129589 document, the entire content of which is incorporated herein by reference.

According to a preferred embodiment, the catalyst is selected from the group consisting of CO₂And less than 20 mol.% H₂Step iv) of the process for recovering sulphur from the S-lean acid gas comprises and/or is followed by:

iv.1 after optional preheating, subjecting the mixture comprising H₂The lean acid gas of S and oxygen is transferred to a first section of the first reactor, which first section comprises a non-cooled adiabatic bed comprising H catalyzed with oxygen₂S oxidation and catalysis of H with sulfur dioxide₂A first catalyst for S oxidation, wherein the maximum temperature of the adiabatic bed is T1,

iv.2 transferring the lean acid gas from the first portion of the first reactor to a second portion of the first reactor, the second portion comprising a second catalyst, which may be different from the first catalyst, and the second portion being maintained at a temperature T2, wherein T2 ≦ T1 and T2 is above the dew point temperature of elemental sulfur, resulting in depleted H₂The air flow of the S is controlled by the control system,

iv.3 depletion of H₂The stream of S is transferred to a sulphur condenser to obtain a sulphur depleted stream,

iv.4 optionally preheating the sulphur depleted gas stream,

iv.5 transferring the sulphur depleted gas stream into a first section of a second reactor comprising a non-cooled adiabatic bed comprising the same catalyst as the first section of the first reactor, wherein the first section of the second reactor is operated at a temperature above the dew point of elemental sulphur such that no elemental sulphur deposits as a liquid or solid on the catalyst in the first section of the second reactor,

iv.6 transferring the gas stream from the first part of the second reactor to a second part of the second reactor, which second part of the second reactor comprises the same catalyst as the second part of the first reactor and which second part is maintained at a temperature equal to or below the dew point of elemental sulphur, such that elemental sulphur is deposited as a liquid or solid on the catalyst in the second part of the second reactor and a desulphurised gas stream is obtained which meets the requirements of air emission standards,

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

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

In this method, steps iv.1-iv.7 correspond to SmartSulf^TMProvided is a technique.

Step iv.7 of switching the operating conditions of the first and second reactor and simultaneously switching the gas flow makes it possible to desorb the elemental sulphur condensed on the catalyst operated in the second reactor. In fact, when operating at the first location (at a higher temperature), the second reactor is operated at a higher temperature, thereby desorbing the sulfur condensed on the catalyst when the reactor was previously operated at the second location (at a lower temperature).

The spent H leaving the sulfur recovery unit in step iv) can then be recycled₂The lean S gas (32) is transferred to an incinerator (33) where it is combusted to destroy remaining H₂S and aromatic hydrocarbons and C contained therein₄ ⁺Aliphatic hydrocarbons to meet the air emission standards. Alternatively, depletion H can be₂The stream (3) of S is compressed, injected and discharged into underground storage, rather than being incinerated and released into the atmosphere.

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

Example 1

The process for recovering sulphur from a lean acid gas (1) as shown in figure 2 is operated using an acid gas comprising:

o 10.0 mol.% of H₂S,

O 82.1 mol.% CO₂And are and

o 2500mol.ppm of BTX,

o 180mol.ppm of C₄ ⁺，

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

The lean acid gas is fed to the first absorption zone (2) at a pressure of 1.7bar and a flow rate of 2800 kmol/h. In the first absorption zone (2), the lean acid gas is contacted at 480m³A flow rate of/h, a 45 wt% (11 mol.%) aqueous Methyldiethanolamine (MDEA) solution (29) introduced at a temperature of 45 ℃ and a pressure of 1.55 barA.

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

92.8 mol.% CO₂，

ο<100ppm mol of H₂S, and

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

ο230ppm C₄ ⁺(represents C in the lean acid gas)₄ ⁺All of the initial amounts of),

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

The MDEA solution (4) leaving the first absorption zone (2) absorbs almost the entire amount of H in the lean acid gas₂S, and co-absorbs about 8% of the BTX originally present in the lean acid gas. The solvent reached a temperature of about 62 ℃.

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

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

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:

-95.0 mol.% of methane,

5.0 mol.% ethane.

It enters the stripping zone under the following conditions:

flow rate: 200kmol/h of the reaction solution,

temperature: at a temperature of 15 c,

o pressure: 7.0 barA.

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 of the reaction solution,

temperature: at a temperature of 90 c,

o 18.5 mol%CO₂，

O 6.4 mol.% of H₂S, and

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

Subsequently, the fuel gas stream (10) leaving the stripping zone (8) is passed through a heat exchanger and enters the second absorption zone (12) at a temperature of 45 ℃. In the second absorption zone (12), the fuel gas stream (10) leaving the stripping zone (8) is contacted at 30m³A Methyldiethanolamine (MDEA) solution introduced at a flow rate, a temperature of 45 ℃ and a pressure of 4.0 barA.

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

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

o 19.6 mol.% CO₂，

ο<100mol.ppm of H₂S, and

1350mol.ppm BTX (85% of BTX entering the second absorption zone of fluid 16, and about 5% of BTX in the method entering fluid 1).

The fuel gas stream (13) meets the standard requirements for combustibles and can therefore be used as a feed in an incinerator (33) and/or a utility boiler, where the associated aromatics (BTX) and C will be destroyed₄ ⁺Aliphatic hydrocarbons and residual sulfur species.

Enriched H leaving the second absorption zone (12)₂The MDEA solution of S (14) is recycled to the stripping zone to replenish the enriched H₂MDEA solution of S (4).

The BTX depleted MDEA solution (9) leaves the stripping zone (8) at a temperature of 87 ℃ 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 ℃ and a pressure of 2.4 barA.

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

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

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

o 45.5 mol.% CO₂，

O 49.2 mol.% of H₂S，

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

4.9 mol.% of H₂O。

The process of the present invention makes it possible to reduce the BTX content of the treated lean acid gas by 97%. Even if H₂The S content is less than 55 mol.%, and the treated lean acid gas is also suitable for subsequent treatment in a sulfur recovery unit.

The acid gas obtained was then used in the Claus process with a 10% stream of acid gas bypassing the thermal step (furnace), and 2 reactors for operating the catalytic step (SmartSulf)^TMTechnique) is processed. A sulfur recovery of 99.3% was obtained. 107 tons of bright yellow solid sulfur were recovered daily meeting sulfur recovery standards without further treatment.

Example 2

The process for recovering sulfur from a lean acid gas as shown in fig. 2 operates using an acid gas comprising:

o 0.2 mol.% of H₂S,

92.0 mol.% CO₂And are and

o 1500mol.ppm of BTX,

o 180mol.ppm of C₄ ⁺，

The lean acid gas is sent to the first absorption zone (2) at a flow rate of 2800 kmol/h. In the first absorption zone (2), the lean acid gas is contacted at 335m³A flow rate of/h, a 45 wt% (11 mol.%) aqueous Methyldiethanolamine (MDEA) solution (29) introduced at a temperature of 45 ℃ and a pressure of 1.55 barA.

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

92.8 mol.% CO₂，

ο<100mol.ppm of H₂S, and

1510mol.ppm of BTX (92%),

ο195mol.ppm C₄ ⁺(represents C in the lean acid gas)₄ ⁺All initial amounts of).

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

The MDEA solution (4) leaving the first absorption zone (2) absorbs almost the entire amount of H in the lean acid gas₂S and co-absorbed about 8% BTX and reached a temperature of about 55 ℃.

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

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

-95.0 mol.% of methane,

5.0 mol.% ethane.

It enters the stripping zone under the following conditions:

flow rate: the concentration of the catalyst is 360kmol/h,

temperature: at a temperature of 15 c,

o pressure: 7.0 barA.

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 and the concentration of the catalyst,

temperature: at the temperature of 93 ℃,

o8.4 mol.% CO₂，

O 0.1 mol.% of H₂S, and

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

The fuel gas stream leaving the stripping zone (8) is then passed through a heat exchanger and enters the secondary absorption zone (12) at a temperature of 45 ℃. In the second absorption zone (12), the fuel gas stream leaving the stripping zone (8) is contacted at 12m³Flow rate/h, Methyldiethanolamine (MDEA) solution introduced at a temperature of 45 ℃ and a pressure of 4.0 barA.

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

o 9.1 mol.% CO₂，

ο<100mol.ppm of H₂S, and

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

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

The 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 ℃ and a pressure of 2.4 barA.

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

o 90.8 mol.% CO₂，

O 3.4 mol.% of H₂S, and

o 220mol.ppm BTX (1% of BTX entering the method),

o 5.8 mol.% of H₂O。

The process of the present invention makes it possible to reduce the BTX content of the treated acid-lean gas by 99 mol.%. Even if H₂The S content is much less than 55 mol.%, and the treated lean acid gas is also suitable for subsequent treatment in a sulfur recovery unit.

The acid gas obtained was then treated by direct oxidation (SmartSulf) in 2 reactors^TMA technique). A sulfur recovery of 98% was obtained. 2 tons of bright yellow solid sulfur were recovered daily that met the sulfur recovery criteria without further treatment.

Claims

1. From the inclusion of CO₂And less than 20 mol.% H₂Removal of aromatics and C having 4 or more carbon atoms from S-lean acid gas₄ ⁺A process for aliphatic hydrocarbons, the process comprising:

a) mixing lean acid gas 1 (1) with H in a first absorption zone (2)₂S-selective liquid absorbent solution 29 (29) to produce depleted H₂S and comprises CO₂Aromatic hydrocarbons and C₄ ⁺A stream of aliphatic hydrocarbons (3) and also comprising co-absorbed C₄ ⁺Aliphatic hydrocarbons, aromatic hydrocarbons and CO₂Is enriched in H₂Absorbent solution 4 (4) of S,

b) subjecting said enriched H₂The absorbent solution 4 (4) of S is introduced into a non-thermal stripping zone (8) where it is contacted with a stripping gas stream 7 (7) to obtain spent C₄ ⁺Aliphatic and aromatic hydrocarbons and comprising H₂S and CO₂Absorbent solution 9 (9) and also H₂S and CO₂Is enriched in aromatic hydrocarbons and C₄ ⁺A stripping gas stream 10 (10) of aliphatic hydrocarbons,

c) in a second absorption zone (12) the product obtained in step b) also comprises H₂S and CO₂Is enriched in aromatic hydrocarbons and C₄ ⁺Stripping gas stream 10 (10) of aliphatic hydrocarbons with H₂S-selective liquid absorbent solution 28 (28) to obtain depleted H₂S and comprising aromatic hydrocarbons, C₄ ⁺Aliphatic hydrocarbons and CO₂And also co-absorbed aromatics, C₄ ⁺Aliphatic hydrocarbons and CO₂Is enriched in H₂Absorbent solution of S14 (14),

d) depletion C obtained in step b)₄ ⁺An absorbent solution 9 (9) of aliphatic and aromatic hydrocarbons is introduced into a desorption zone 16, in which H is introduced₂S-selective liquid absorbent solution 17 (17) is recovered and produces spent C₄ ⁺Of aliphatic and aromatic hydrocarbons comprising H₂S and CO₂The lean acid gas 21 (21).

2. The method according to claim 1, wherein the stripping gas stream 7 (7) used in the stripping zone (8) is a combustible gas that meets combustible standard requirements and is a combustible gas for operating an incinerator (33) and/or a utility boiler.

3. The method of any of claims 1-2, wherein the lean acid gas 1 (1) comprises:

-75-99.925 mol.% CO₂，

-250mol.ppm to 20 mol.% of H₂S，

the percentages are expressed in moles on a dry basis relative to the total moles of the acid-lean gas.

4. The method of any one of claims 1-2, wherein the H₂The S-selective liquid absorbent solution comprises:

-a chemical solvent, which is a mixture of,

-a physical solvent, the solvent being selected from the group consisting of,

or mixtures thereof.

5. The method of any one of claims 1-2, wherein the H₂The S-selective liquid absorbent solution comprises an amine.

6. The method of any one of claims 1-2, wherein the H₂S-selective liquid absorbent solution containing a compound capable of enhancing H₂S faces to CO₂The absorption selective additive component of (1).

7. The process according to any one of claims 1-2, wherein the absorption steps a) and c) are carried out at:

at a temperature of from-10 to 100 ℃, and

at a pressure of between 1 and 8 barA.

8. The process of any one of claims 1-2, wherein the non-thermal stripping in step b) is at:

at a temperature of from-50 to 150 ℃, and

at a pressure of between 1 and 8 barA.

9. The process according to any one of claims 1-2, wherein the enriched H leaving the second absorption zone (12) is₂S absorbent solution 14 (14) is recycled back to the stripping zone (8) to replenish the enriched H₂S absorbent solution 4 (4) and/or directly into the desorption zone (16) to replenish the absorbent solution depleted in aromatic hydrocarbons 9 (9) obtained in step b).

10. The process according to any one of claims 1-2, wherein spent C recovered from the stripping zone (8)₄ ⁺Absorbent solutions of aliphatic and aromatic hydrocarbons 9 (9) are passed through a heat exchanger 15 to raise their temperature before entering the desorption zone.

11. The process according to claim 10, wherein the temperature increase in the heat exchanger (15) is carried out by recirculating in the heat exchanger (15) at least a portion of the H recovered from the desorption zone (16)₂S selective liquid absorbent solution 17 (17).

12. The method of any one of claims 1-2, wherein the enrichment in H₂The absorbent solution 4 (4) of S is passed through a heater (6) to raise its temperature before entering the stripping zone (8).

13. The method according to claim 12, wherein the temperature increase in the heater (6) is performed by recirculating in the heater (6) at least a portion of the H recovered from the desorption zone (16)₂S selective liquid absorbent solution 17 (17).

14. The process of claim 13 wherein an aromatic-depleted acid-lean gas 21(21) or acid-lean gas 26(26) is partially recycled to provide the acid-lean gas 1 (1) and/or to provide the enriched H₂S、CO₂And a stripping gas stream of aromatics 10 (10).

15. The method of any one of claims 1-2, wherein the comprises CO₂And less than 20 mol.% H₂The lean acid gas of S is obtained according to the following process, which comprises:

a) will comprise methane (CH)₄) And ethane (C)₂H₆）、CO₂、H₂S and C₄ ⁺The natural gas of aliphatic and aromatic hydrocarbons is contacted with a liquid absorbent solution in an absorption zone to produce depleted H₂S and CO₂And comprises methane (CH)₄) And ethane (C)₂H₆) And enriched in H₂S and CO₂And further comprising co-absorbed C₄ ⁺Absorbent solutions of aliphatic and aromatic hydrocarbons,

16. The process of claim 1, wherein the aromatic hydrocarbons are benzene, toluene, ethylbenzene, and xylenes.

17. The method of claim 1, wherein the stripping gas stream 7 (7) is a fuel gas.

18. The process of claim 1, wherein H in step c)₂The S-selective liquid absorbent solution is the same as used in step a).

19. The process according to claim 2, wherein the stripping gas stream 7 (7) used in the stripping zone (8) is natural gas, hydrogen and/or comprises H₂And CO.

20. The process of claim 3 wherein the acid-lean gas 1 (1) comprises 500mol.ppm to 15 mol.% H₂S。

21. The process of claim 3 wherein the acid-lean gas 1 (1) comprises 500mol.ppm to 10 mol.% H₂S。

22. The method of claim 4, wherein the chemical solvent is an alkali metal carbonate and phosphate, or an alkanolamine, and the physical solvent is a substituted or unsubstituted sulfolane or mercaptoethanol.

23. The method of claim 22, wherein the chemical solvent is in the form of an aqueous solution.

24. The method of claim 22, wherein the H is₂The S-selective liquid absorbent solution comprises a mixture of alkanolamine and mercaptoethanol.

25. The method of claim 6, wherein the H can be enhanced₂S faces to CO₂The absorption-selective additive component of (a) is phosphoric acid (H)₃PO₄）。

26. The method of claim 7, wherein the absorbing steps a) and c) are at:

at a temperature of from-30 to 70 ℃, and

at a pressure of between 1.5 and 4 barA.

27. The method of claim 7, wherein the absorbing steps a) and c) are at:

a temperature of from 40 to 60 ℃ and

at a pressure of between 1.5 and 4 barA.

28. The method of claim 8, wherein the non-thermal stripping in step b) is at:

at a temperature of from-60 to 130 ℃, and

at a pressure of between 1.5 and 4 barA.

29. The method of claim 8, wherein the non-thermal stripping in step b) is at:

a temperature of from 70 to 110 ℃ and

at a pressure of between 1.5 and 4 barA.

30. The process according to claim 11, characterized in that the absorbent solution 9 (9) depleted of C4+ aliphatic and aromatic hydrocarbons, recovered from the stripping zone (8), is passed through a heat exchanger (15) to increase its temperature before entering the desorption zone, the temperature increase in said heat exchanger (15) being obtained by recycling at least one of the aliphatic and aromatic hydrocarbons in said heat exchanger (15)Part of the H recovered from the desorption zone (16)₂S selective liquid absorbent solution 17 (17), wherein the enrichment of H₂S absorbent solution 4 (4) is passed through a heater (6) to increase its temperature before entering the stripping zone (8), the temperature increase in the heater (6) being achieved by recycling at least a portion of the H recovered from the desorption zone (16) and/or exiting the heat exchanger (15) in the heater (6)₂S selective liquid absorbent solution 17 (17).

31. From the inclusion of CO₂And less than 20 mol.% H₂A process for the recovery of sulfur from a lean acid gas of S, the process comprising:

i) pretreating the catalyst for removing aromatics and C in a process according to any one of claims 1-30₄ ⁺Lean acid gas 1 (1) of aliphatic hydrocarbon to obtain exhausted C₄ ⁺The lean acid gas 21(21) or the lean acid gas 26(26) of aliphatic hydrocarbon and aromatic hydrocarbon,

ii) at least part of said depletion C₄ ⁺The pre-treated acid-lean gas 21(21) or 26(26) of aliphatic and aromatic hydrocarbons is mixed with an oxygen-containing gas to obtain a gas comprising H₂A stream of S and oxygen gas,

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

iv) after optional preheating, the spent C recovered from step ii) and optional step iii) is subjected to₄ ⁺The lean acid gas of aliphatic and aromatic hydrocarbons enters a catalytic reactor containing a catalyst system that catalyzes H₂Direct oxidation of S with oxygen and/or catalysis of H₂Sulfur dioxide (SO) for S₂) Claus reaction of (2) to recover spent H₂S and elemental sulphur.

32. The method according to claim 31, wherein step iv) comprises and/or is followed by:

iv.1 after optional preheating, subjecting the mixture comprising H₂The lean acid gas of S and oxygen is transferred to a first section of the first reactor, which first section comprises an uncooled, adiabatic bed containing catalytic H₂Oxidation of S with oxygen and catalysis of H₂S with sulfur dioxide, wherein the maximum temperature of the adiabatic bed is T1,

iv.4 optionally preheating the sulphur depleted gas stream,

iv.5 transferring the sulphur depleted gas stream into a first section of a second reactor, the first section comprising a non-cooled adiabatic bed comprising the same catalyst as the first section of the first reactor, wherein the first section of the second reactor is operated at a temperature above the dew point of elemental sulphur such that no elemental sulphur deposits as a liquid or solid on the catalyst in the first section of the second reactor,

33. The process according to any one of claims 31 to 32, wherein in step iv) the spent H leaving the sulfur recovery unit may be subsequently subjected to₂Gas stream (3) of S, said depletion H₂S stripping gas stream 13 (13) and/or the depleted H₂The lean S gas 32 (32) is transferred to an incinerator (33) where it is combusted to destroy remaining H₂S and aromatic hydrocarbons and C contained therein₄ ⁺Aliphatic hydrocarbons to meet the air emission standards, or compressed, injected and discharged into underground storage rather than incinerated and released into the atmosphere.

34. The method of any one of claims 31-32, wherein the oxygen-containing gas is air.