Process for removing acid compounds from gaseous effluents using tertiary amine-based absorbent solutions

Abstract

The present invention relates to a method for removing acid compounds contained in a gaseous effluent, which comprises contacting the gaseous effluent with an absorbent solution comprising water, 20% to 28% by weight of pentamethyldipropylenetriamine and 5% to 35% by weight of N-methyldiethanolamine in an absorption tower.

Description

Technical Field

[0001] The present invention relates to the field of processes for the deacidification of gaseous effluents. The invention is advantageously applied to the treatment of gases of industrial origin, natural gas and gases resulting from the fermentation of biomass. Background Art

[0002] Commonly used gas deacidification processes employ aqueous amine solutions to remove acid compounds present in the gas, in particular carbon dioxide (CO2), hydrogen sulfide (H2S), carbon oxysulfide (COS), carbon disulfide (CS2), sulfur dioxide (SO2) and mercaptans (RSH), such as methyl mercaptan (CH3SH), ethyl mercaptan (CH3CH2SH) and propyl mercaptan (CH3CH2CH2SH). The gas is deacidified by contact with an absorbent solution, which is then thermally regenerated.

[0003] These acid gas deacidification processes are also often referred to as "solvent scrubbing" using "chemical" solvents, which are different from "physical" solvents used for absorption, which are not based on chemical reactions, but on solubility, which is directly dependent on and proportional to the partial pressure of the entity in the gas phase. The partial pressure is the product of the concentration of the entity in the phase multiplied by the total operating pressure. "Chemical" solvents advantageously benefit from two effects of increasing the solubility of the entity.

[0004] The chemical solvent corresponds to an aqueous solution containing a reactant that preferentially reacts with the acid compounds (H2S, CO2, COS, CS2, etc.) present in the gas to be treated to form a salt, without reacting with other non-acid compounds of the gas. After contact with the solvent, the acid compounds of the gas to be treated will become less, and they will be selectively transferred to the solvent in the form of salts. The chemical reaction is reversible, which allows the solvent loaded with acid compounds to be subsequently deacidified, for example, under the action of heat, on the one hand, so as to release the acid compounds in gaseous form, which can then be stored, converted or used in various applications, and on the other hand, so as to regenerate the solvent, which returns to its initial state and can therefore be reused in a new stage of reaction with the acid gas to be treated. The stage in which the solvent reacts with the acid gas is usually called the absorption stage, and the stage in which the solvent is deacidified is called the solvent regeneration stage.

[0005] In general, in this case, the performance quality of the separation of acid compounds from gases depends primarily on the nature of the reversible reaction chosen. Conventional methods for the deacidification of acid gases are usually "amine" methods, that is to say they are based on the reaction of acid compounds with amines in aqueous solution. These reactions fall within the general context of acid / base reactions. For example, H2S, CO2 or COS are acid compounds, while amines are basic compounds, especially in the presence of water. The reaction mechanism and the nature of the resulting salts generally depend on the structure of the amine used.

[0006] For example, document US Pat. No. 6,852,144 describes a process for removing acid compounds from hydrocarbons using an aqueous absorbent solution of N-methyldiethanolamine (MDEA) or triethanolamine containing a high proportion of at least one compound selected from the group consisting of piperazine and / or methylpiperazine and / or morpholine.

[0007] The performance quality of the process for deacidification of acid gases by washing with amines directly depends on the nature of the amines present in the solvent. These amines can be primary, secondary or tertiary amines. Each of them can exhibit one or more identical or different amine functional groups.

[0008] To improve the performance qualities of the acid removal process, more efficient amines are continually sought, particularly those that are able to absorb more acid gas and regenerate with less energy.

[0009] One limitation of the absorbent solutions currently used in "selective" deacidification applications is that the absorption selectivity of H2S relative to CO2 is not sufficient. This is because, in certain cases of natural gas deacidification, one seeks to selectively remove H2S while limiting the absorption of CO2 as much as possible. This limitation is particularly important for gases to be treated that already contain a CO2 content less than or equal to the required specifications. Therefore, one seeks the maximum absorption capacity for H2S and the maximum absorption selectivity for H2S relative to CO2. This selectivity allows maximizing the amount of gas to be treated and recovering acid gas with the highest possible H2S concentration at the regenerator outlet, which can limit the size of the downstream sulfur pipeline unit and ensure better operation of the unit. In some cases, in order to concentrate the H2S of the acid gas, an H2S enrichment device is required. This type of amine scrubbing device installed to treat acid gas also seeks the most selective amine.

[0010] It is well known that severely sterically hindered tertiary or secondary amines have slower kinetics for capturing CO2 than less hindered primary or secondary amines. On the other hand, amines, especially severely sterically hindered tertiary or secondary amines, generally have instantaneous kinetics for capturing HS. Therefore, these severely sterically hindered tertiary and secondary amines can be used to selectively remove HS based on different kinetic performance qualities.

[0011] Therefore, tertiary amines (such as MDEA) or hindered secondary amines that exhibit slow reaction kinetics with CO 2 are usually used. However, they exhibit limited selectivity when acid gas is charged at high levels.

[0012] Another limitation of many absorbent solutions commonly used in complete deacidification applications is that the absorption kinetics of CO2 or COS are too slow. In cases where the required specifications of CO2 or COS are extreme, i.e. close to complete purification from these compounds, one usually seeks the fastest possible reaction kinetics in order to reduce the height of the absorption column. This is because, if the reaction is very slow, very tall columns must be considered in order to allow sufficient time for the chemical reaction to proceed. In fact, the absorption column represents a major part of the capital cost of the process, especially when pressurization equipment is involved.

[0013] Regardless of whether one is looking for maximum absorption kinetics for CO2 and COS in a complete deacidification application of all acid pollutants or minimum kinetics for the capture of CO2 in a selective deacidification application (selective absorption of H2S relative to CO2), it is always desirable to use an absorbent solution with the maximum possible circulation capacity for the pollutants that one wishes to remove from the gaseous effluent to be treated (e.g. natural gas). This circulation capacity is denoted Δα and corresponds to the difference in loading level between the absorbent solution withdrawn from the bottom of the absorption tower and the absorbent solution feeding said tower (α represents the number of moles of acid compound absorbed per kg of absorbent solution n). 酸气体 This is because, the greater the circulating capacity of the absorbent solution, the more limited the flow rate of the absorbent solution which must be employed to deacidify the gas to be treated. In gas treatment processes, a reduction in the flow rate of the absorbent solution generally has a great effect on reducing capital costs, particularly in terms of the size of the columns (if their diameter can be reduced, and also by reducing the size of other equipment, such as heat exchangers, pumps and flash tanks).

[0014] Another important aspect of the operation of treating gases by solvents or cleaning industrial flue gases remains the regeneration of the separating agent, in order to purify the solvent and free it from the pollutants accumulated during the absorption stage. Depending on the type of absorption (physical and / or chemical), regeneration is generally envisaged by decompression and / or by distillation and / or by entrainment with a vaporized gas known as "stripping gas". The energy consumption required for the regeneration of the solvent can be very high, especially in the case of low acid gas partial pressures or high chemical bonding forces, and can represent a considerable operating cost of the deacidification process.

[0015] It is well known to those skilled in the art that the energy required for regeneration by distillation of amine solution can be broken down under three different headings: the energy required to heat the absorbent solution between the top and bottom of the regenerator, the energy required to reduce the partial pressure of the acid gas in the regenerator by vaporization of the stripping gas, and the energy required to break the chemical bond between the amine and the acid compound. The first two headings are proportional to the flow rate of the absorbent solution, which must be circulated in the unit to achieve a given purification performance, i.e., the specification of the solvent to be regenerated. Therefore, in order to reduce the energy consumption associated with solvent regeneration, it is still preferred to maximize the circulation capacity of the solvent. This is because, the larger the circulation capacity of the absorbent solution, the more limited the flow rate of the absorbent solution that must be used to deacidify the gas to be treated.

[0016] In the search for more efficient amines that can reduce circulation flow rates and regeneration energy, patent US6267939 and patent application WO09156273 provide absorbent solutions based on specific polyamines, such as N,N,N',N'-tetramethyldipropylenetriamine (TMDPTA) or pentamethyldiethylenetriamine (PMDETA).

[0017] In order to reduce the regeneration energy of the deacidification process, documents FR2877858, FR2895273, FR2900843, FR2898284, FR2900842, FR2986441 and FR2986442 provide the use of an absorbent solution which, when absorbing a certain amount of acid gas, forms two phases, and only the phase loaded with acid gas needs to be regenerated. However, this solution includes the disadvantage of being incompatible with conventional high-pressure deacidification equipment, since it requires additional stages and equipment items as well as multiple precautions to keep the operation under control. This is because the separation of a single-phase liquid absorbent solution into two liquid phases is also called a stratification phenomenon, which can lead to serious operating problems during the absorption process or at higher temperatures in the upstream or regeneration stage if the methods and equipment items are not suitable for handling the two phases. These problems are particularly described in documents FR3014101 and WO2015177333. Under the operating conditions of the absorber (also called absorption tower), this liquid / liquid phase separation can disrupt the transfer of acid gas to the absorbent solution and make the tower unstable. It also disrupts the liquid / gas phase equilibrium, which is very important for the performance of the deacidification cycle, especially for the regeneration phase. In addition, it may cause sudden changes in the composition of the liquid stream, irregular flows, making the process unstable, its control impossible and its performance random.

[0018] Another problem is the stability of the absorbent solution, in particular the thermal stability of the amine. The absorbent solution can decompose under the effect of temperature, which limits the operating conditions of the process, in particular the temperature at which the solvent regeneration is carried out. For example, increasing the temperature of the regenerator by 10°C doubles the thermal decomposition rate of monoethanolamine (MEA). Therefore, the regeneration of aqueous solutions of alkanolamines (such as MEA) is carried out at a regenerator bottom temperature of around 120°C, and for more stable amines (such as MDEA), it is even 130°C. Due to these regenerator bottom temperatures, acid gases (CO2, H2S, COS, CS2, etc.) are obtained at a moderate pressure of 0.1-0.3 MPa. Depending on the nature and application of the regenerated acid gas, the acid gas can be sent to a treatment unit or compressed for reinjection and isolation. In particular, in order to overcome this thermal stability problem, patent application WO04082809 provides, for example, the use of an absorbent aqueous solution containing a high concentration, typically greater than 60% by weight, of a tertiary polyamine (such as pentamethyldipropylenetriamine (PMDPTA)).

[0019] Other problems are often encountered, such as corrosiveness of the absorbent solution, or foaming of the absorbent solution.

[0020] This is because amine-based absorbent solutions (e.g. based on alkanolamines such as MEA, diethanolamine (DEA) or MDEA) are known to be corrosive to steel equipment items used in gaseous effluent deacidification processes. These corrosion risks lead to the necessity to adopt rather stringent measures, such as the equipment items being made of corrosion-resistant alloys, which may be more expensive or less mechanically resistant, or the use of corrosion inhibitors, which increase the cost of the solution, accumulate irreversibly and possibly in a fouling manner, and for which it is recommended to continuously monitor the effective content present.

[0021] Foaming of absorbent solutions is a known problem in gaseous effluent deacidification processes, which can have various detrimental consequences, such as premature blocking of absorber or regenerator towers leading to reduced production capacity, treated gas exceeding target specifications, amine loss due to entrainment in treated gas or acid gas, and even unit shutdown. Amine absorbent solutions are known to have a tendency to foam, especially when they come into contact with liquid hydrocarbons. This problem is usually solved by adding defoamers, which in turn increases operating costs and complicates the process (needs to monitor levels, add filters, etc.).

[0022] In this context, it is difficult to find a formulation of an absorbent compound capable of removing acid compounds from any type of effluent, allowing the deacidification process to be operated at low operating costs (including regeneration energy) and capital costs (including the cost of the absorption tower) and meeting the requirements of absorption capacity, selectivity, chemical stability (especially to temperature), low corrosivity and limited foaming. Summary of the invention

[0023] It is therefore an object of the present invention to meet the needs of the prior art and to overcome one or more of the above-mentioned disadvantages of the prior art.

[0024] Thus, the present invention provides a method for removing acid compounds (e.g. CO2, H2S, COS, CS2 or mercaptans) from a gas, which uses an aqueous absorbent solution comprising a specific combination of at least two specific amines, which unexpectedly exhibits at least one of the following effects:

[0025] - limited foaming compared to conventional solutions, especially in the presence of hydrocarbons and under degradation conditions, such as in operating units;

[0026] - Less corrosive than conventional solutions;

[0027] - Higher stability, ie reduced degradation, in particular in the presence of molecular oxygen, compared to prior art absorbent solutions based on polyamines.

[0028] Furthermore, the inventors demonstrated that the use of this specific combination of a specific amine and an activator (e.g., piperazine) in aqueous solution can improve the cyclic absorption capacity and absorption kinetics of CO2 compared to a reference formulation (e.g., a mixture of MDEA and piperazine).

[0029] The absorbent solution of the invention also makes it possible to limit the flow rate of the absorbent solution used in the process, since it has good performance qualities in terms of the circulation capacity for absorbing acid gases, in particular CO2 and H2S, and has an absorption selectivity for H2S. These performance qualities are superior to those of MDEA and also to those polyamines cited in the prior art, especially the latter in terms of the circulation capacity for absorbing acid gases.

[0030] According to the invention, the absorbent solution is advantageously in single-phase form under the operating conditions of the process, more particularly at least under the absorption conditions until the solution enters the regenerator, which in particular dispenses with a post-absorption separation stage by settling.

[0031] Thus, according to a first aspect, the present invention provides a process for removing acid compounds contained in a gaseous effluent, comprising carrying out an absorption stage of acid compounds by contacting the gaseous effluent with an absorbent solution comprising:

[0032] -water;

[0033] - 20% to 28% by weight of pentamethyldipropylenetriamine;

[0034] - 5% to 35% by weight of N-methyldiethanolamine.

[0035] According to one or more embodiments of the present invention, the absorbent solution comprises 10-30 wt% of N-methyldiethanolamine and preferably 42-70 wt% of water.

[0036] According to one or more embodiments of the present invention, the absorbent solution contains 37 wt% to 75 wt% water.

[0037] According to one or more embodiments of the present invention, the absorbent solution comprises:

[0038] - 5% to 20% by weight of N-methyldiethanolamine; and

[0039] - 0.5% to 20% by weight of at least one activating compound comprising a primary or secondary amine functional group selected from the group consisting of:

[0040] -piperazine;

[0041] -1-Methylpiperazine;

[0042] -Homopiperazine;

[0043] -N-(2-hydroxyethyl)piperazine;

[0044] -3-(Methylamino)propylamine;

[0045] -N,N'-dimethyl-1,6-hexanediamine;

[0046] -N-methyl-1,6-hexanediamine;

[0047] -N,N',N'-trimethyl-1,6-hexanediamine;

[0048] -2-amino-2-methyl-1-propanol.

[0049] In this case, the absorbent solution may contain 5% to 15% by weight of N-methyldiethanolamine, preferably 10% to 15% by weight of N-methyldiethanolamine.

[0050] Preferably, the activating compound is piperazine.

[0051] Advantageously, the absorbent solution comprises 0.5% to 10% by weight of said at least one activating compound, preferably 0.5% to 6% by weight of said at least one activating compound, more preferably 1% to 6% by weight of said at least one activating compound.

[0052] According to one or more embodiments of the present invention, the absorbent solution additionally comprises at least one physical solvent selected from the group consisting of methanol, ethanol, 2-ethoxyethanol, triethylene glycol dimethyl ether, tetraethylene glycol dimethyl ether, pentaethylene glycol dimethyl ether, hexaethylene glycol dimethyl ether, heptaethylene glycol dimethyl ether, octaethylene glycol dimethyl ether, diethylene glycol butoxyacetate, glycerol triacetate, sulfolane, N-methylpyrrolidone, N-methylmorpholin-3-one, N,N-dimethylformamide, N-formylmorpholine, N,N'-dimethylimidazolin-2-one, N-methylimidazole, ethylene glycol, diethylene glycol, triethylene glycol, thiodiglycol, propylene carbonate and tributyl phosphate.

[0053] According to one or more embodiments of the present invention, the absorbent solution does not contain an anti-foaming additive.

[0054] According to one or more embodiments of the present invention, the absorption stage of the acid compound is carried out at a pressure of 0.1 MPa-20 MPa and a temperature of 20°C-100°C.

[0055] According to one or more embodiments of the present invention, an absorbent solution loaded with an acid compound is obtained after the absorption stage, and the method comprises subjecting the absorbent solution loaded with an acid compound to at least one regeneration stage at a pressure of 0.1 MPa-1 MPa, preferably 0.1 MPa-0.5 MPa and at a temperature of 100°C-180°C, preferably 110°C-140°C.

[0056] According to one or more embodiments of the present invention, the absorbent solution is a single-phase solution during the absorption stage in the absorption tower and at least until it enters the regeneration tower for the regeneration stage. Preferably, the temperature in the absorption tower and at least until it enters the regeneration tower is lower than or equal to 110°C.

[0057] According to one or more embodiments of the present invention, the gaseous effluent is selected from natural gas, synthesis gas, combustion flue gas, refinery gas, acid gas produced by an amine unit, tail gas produced by a unit for converting H2S by the Claus process to produce sulfur, gas produced by biomass fermentation, gas produced by a cement plant or incinerator flue gas.

[0058] The process of the invention can be used to selectively remove H 2 S relative to CO 2 from a gaseous effluent comprising H 2 S and CO 2 , preferably from natural gas.

[0059] The method of the present invention can also be used for decarbonization of biogas.

[0060] Other objects and advantages of the invention will become apparent on reading the following description of certain exemplary embodiments of the invention, given by way of non-limiting example, which description proceeds with reference to the accompanying drawings described hereinafter. BRIEF DESCRIPTION OF THE DRAWINGS

[0061] Figure 1 Shown is a flow chart of a method for treating acid gaseous effluent. This figure does not contain all components required to implement the method, such as heat exchangers, pumps, mixers, etc. It only represents the elements necessary to understand the present invention, and those skilled in the art can supplement it to implement the present invention. DETAILED DESCRIPTION

[0062] The present invention provides for the removal of acid compounds from aqueous effluents by using an aqueous absorbent solution, the composition of which will be described in detail below. Following the details regarding the composition of the absorbent solution, the process will be described in more detail.

[0063] Composition of absorbent solution

[0064] The absorbent solution used to remove acid compounds contained in the gaseous effluent comprises:

[0065] -water;

[0066] - 20% to 28% by weight of pentamethyldipropylenetriamine (PMDPTA); and

[0067] - 5% to 35% by weight of N-methyldiethanolamine (MDEA).

[0068] MDEA is a tertiary monoamine which, used in aqueous solution, constitutes the reference absorbent solution in the field of gas deacidification, in particular for the selective absorption of H 2 S relative to the CO 2 contained in the gas.

[0069] PMDPTA is a tertiary polyamine, more specifically a tertiary triamine, having the formula:

[0070] Chemical formula 1

[0071]

[0072] It is known in the prior art that polyamines offer an advantage over monoamines in that more reaction sites can be achieved per unit weight of product and may have an increased absorption capacity. However, polyamines are not equal in terms of acid gas absorption capacity, performance in selective removal of H2S, and chemical stability under the conditions of the acid gas treatment process. In addition, some polyamines used in aqueous solution can lead to demixing, that is, the separation of a single-phase liquid absorbent solution into two liquid phases under certain conditions of temperature and acid gas loading level.

[0073] The combination of PMDPTA and MDEA in aqueous solution in the concentrations indicated prevents separation of the absorbent solution into two liquid phases (i.e., stratification under the temperature and load level conditions typically encountered during the absorption and circulation to the regenerator stages) while achieving a particularly high acid gas absorption capacity.

[0074] The inventors have also demonstrated that, unexpectedly, a specific combination of these two amines in aqueous solution exhibits limited foaming in the presence of hydrocarbons and under degradation conditions of the absorbent solution, excellent chemical stability, reduced corrosiveness to metal equipment items used in the deacidification process, and very good performance qualities for the selective absorption of H2S relative to CO2 contained in the gaseous effluent to be treated.

[0075] According to one embodiment, the absorbent solution comprises 10 wt% to 30 wt% MDEA.

[0076] The absorbent solution may contain 37% to 75% by weight water.

[0077] When the solution contains 10 wt% to 30 wt% MDEA, the absorbent solution preferably contains 42 wt% to 70 wt% water.

[0078] Everywhere in the description the sum of the weight fractions (expressed as wt. %) of the different compounds of the absorbent solution is equal to 100 wt. % of the original absorbent solution (i.e. the absorbent solution without taking into account absorbed acid gases or other co-absorbed or degradation products).

[0079] Unless otherwise stated, concentration ranges are understood to be inclusive of the limits.

[0080] In this specification, pressure is expressed as an absolute value unless otherwise specified.

[0081] According to one embodiment, the aqueous absorbent solution comprises 20 wt% to 25 wt% PMDPTA and 25 wt% to 35 wt% MDEA.

[0082] According to a specific embodiment, the absorbent solution consists of an aqueous solution consisting of 20-28 wt % PMDPTA and 5-35 wt % MDEA, preferably consisting of 20-25 wt % PMDPTA and 25-35 wt % MDEA.

[0083] According to one embodiment, the absorbent solution comprises:

[0084] -water;

[0085] - 22 wt% to 28 wt% PMDPTA; and

[0086] -5 wt% to 35 wt% MDEA.

[0087] In this case, the absorbent solution may consist of an aqueous solution of 22-28 wt % PMDPTA and 5-35 wt % MDEA, preferably 22-25 wt % PMDPTA and 25-35 wt % MDEA.

[0088] According to another embodiment, the absorbent solution comprises:

[0089] -water;

[0090] - 20% to 28% by weight of PMDPTA;

[0091] - 5% to 20% by weight of MDEA; and

[0092] - 0.5% to 20% by weight of at least one activating compound comprising a primary or secondary amine functional group selected from the group consisting of:

[0093] -piperazine;

[0094] -1-Methylpiperazine;

[0095] -Homopiperazine;

[0096] -N-(2-hydroxyethyl)piperazine;

[0097] -3-(Methylamino)propylamine;

[0098] -N,N'-dimethyl-1,6-hexanediamine;

[0099] -N-methyl-1,6-hexanediamine;

[0100] -N,N',N'-trimethyl-1,6-hexanediamine;

[0101] -2-amino-2-methyl-1-propanol.

[0102] According to this embodiment, the absorbent solution may comprise a mixture of activating compounds as listed above, as is understood by the expression "at least one activating compound".

[0103] An activation compound is understood to mean a compound capable of accelerating the absorption kinetics of CO2, in some cases COS, contained in the gas to be treated. In this specification, reference to an "activation solution" is intended to mean an absorbent solution comprising such an activation compound.

[0104] According to the invention, this activation solution is particularly used in applications for non-selective deacidification of the gas to be treated, such as complete deacidification of the gas, that is to say when CO2 and COS need to be removed to meet very strict specifications, namely high purification performance qualities.

[0105] Preferably, according to this embodiment relating to the activation solution, the absorbent solution comprises 0.5-10 wt.-% of the at least one activating compound, preferably 0.5-6 wt.-% of the at least one activating compound, more preferably 1-6 wt.-% of the at least one activating compound.

[0106] According to this embodiment involving the activation solution, the concentration of MDEA in the absorbent solution is preferably 5% to 15% by weight, preferably 10% to 15% by weight. In this case, the absorbent solution may contain 0.5% to 10% by weight of the at least one activation compound, preferably 0.5% to 6% by weight of the at least one activation compound, more preferably 1% to 6% by weight of the at least one activation compound.

[0107] Preferably, according to this embodiment relating to the activation solution, the absorbent solution comprises at least one activating compound which is piperazine. More preferably, the absorbent solution comprises an activating compound which is piperazine.

[0108] According to another preferred embodiment, the absorbent solution comprises and can consist of:

[0109] -water;

[0110] - 20% to 28% by weight of PMDPTA, preferably 22% to 27% by weight of PMDPTA;

[0111] - 5% to 20% by weight of MDEA, preferably 5% to 15% by weight of MDEA; and

[0112] 0.5% to 20% by weight of piperazine, preferably 0.5% to 10% by weight of piperazine, more preferably 1% to 6% by weight of piperazine.

[0113] The concentration of water is variable and represents the weight supplement to the sum of the other compounds included in the absorbent solution.

[0114] According to the invention, the water concentration is variable.

[0115] Preferably, the absorbent solution comprises at least 37% by weight of water and at most 75% by weight of water.

[0116] According to one embodiment, the absorbent solution comprises an organic compound that is non-reactive with the acid compound, which is generally referred to as a "physical solvent", which can increase the solubility of at least one or more acid compounds of the gaseous effluent. Thus, according to this embodiment, the absorbent solution can comprise 5 wt%-50 wt% of the physical solvent.

[0117] For example, the absorbent solution may contain at least one physical solvent, such as alcohols, ethers, ether alcohols, ethers of ethylene glycol and polyethylene glycols, ethylene glycol thioethers, esters and alkoxy esters of ethylene glycol and polyethylene glycols, glycerides, lactones, lactams, N-alkylpyrrolidones, derivatives of morpholine and morpholin-3-one, imidazoles and imidazolinones, N-alkylpiperidone, cyclotetramethylene sulfone, N-alkylformamides, N-alkylacetamides, ether ketone alkyl carbonates or alkyl phosphates and their derivatives. For example and without limitation, the physical solvent can be methanol, ethanol, 2-ethoxyethanol, triethylene glycol dimethyl ether, tetraethylene glycol dimethyl ether, pentaethylene glycol dimethyl ether, hexaethylene glycol dimethyl ether, heptaethylene glycol dimethyl ether, octaethylene glycol dimethyl ether, diethylene glycol butoxyacetate, glycerol triacetate, cyclopentane, N-methylpyrrolidone, N-methylmorpholin-3-one, N,N-dimethylformamide, N-formylmorpholine, N,N'-dimethylimidazolin-2-one, N-methylimidazole, ethylene glycol, diethylene glycol, triethylene glycol, thiodiglycol, propylene carbonate or tributyl phosphate.

[0118] Properties of the gaseous effluent

[0119] According to the invention, the absorbent solution can be used for deacidification of the following gaseous effluents: natural gas, synthesis gas, combustion flue gas, refinery gas, acid gas from amine units, tail gas from units for converting H2S by Claus process to produce sulfur, biogas (such as gas from biomass fermentation), gas from cement plants or flue gas from incinerators. These gaseous effluents contain one or more of the following acid compounds: CO2, H2S, mercaptans (e.g. methyl mercaptan (CH3SH), ethyl mercaptan (CH3CH2SH), propyl mercaptan (CH3CH2CH2SH)), COS, CS2 or SO2.

[0120] Combustion flue gases are produced in particular by burning hydrocarbons, biogas or coal in boilers or gas turbines, for example for the purpose of generating electricity. For example, at least 70% by weight, preferably at least 80% by weight, or even at least 90% by weight of the CO contained in the combustion flue gases can be absorbed by the deacidification process according to the invention. This removal of CO can be expressed by the term "decarbonization" of the gas. These flue gases generally have a temperature of 20° C. to 60° C. and a pressure of 0.1 MPa to 0.5 MPa and may contain 50% to 80% by volume of nitrogen (N2), 5% to 40% by volume of CO2, 1% to 20% by volume of oxygen (O2) and some impurities (for example SO x Compounds and NO x compounds, if they are not removed upstream of the deacidification process). In particular, the deacidification process of the present invention is particularly suitable for absorbing CO2 contained in combustion flue gases comprising a low CO2 partial pressure, for example a CO2 partial pressure of less than 0.02 MPa.

[0121] The deacidification method of the present invention can be used to deacidify synthesis gas. Synthesis gas contains carbon monoxide CO, hydrogen H2 (usually H2 / CO ratio equal to 2), water vapor (usually in saturated state at the temperature of washing) and CO2 (about 10 volume %). The pressure is usually 2-3MPa, but can reach up to 7MPa. It can additionally contain sulfur-containing impurities (H2S, COS, etc.), nitrogen-containing impurities (NH3, HCN) and halogen-containing impurities.

[0122] The deacidification method of the present invention can be used to deacidify natural gas. Natural gas mainly consists of gaseous hydrocarbons, but may contain the following acid compounds: CO2, H2S, mercaptans, COS or CS2. The content of these acid compounds varies greatly, and the content of CO2 can reach up to 70% by volume, and the content of H2S can reach up to 40% by volume. The temperature of the natural gas can be 10°C-100°C. The pressure of the natural gas to be treated can be 1-20MPa. The present invention can be used to achieve the specifications generally required for deacidified gas, namely less than 2% by volume of CO2, even less than 50ppm by volume of CO2, for subsequent liquefaction of natural gas, and less than 4ppm by volume of H2S, and less than 50ppm by volume, even less than 10ppm of total sulfur.

[0123] The deacidification method of the present invention can be used to deacidify biogas, typically gas produced by biomass fermentation, which is usually pretreated to remove impurities, such as H2S, mercaptans or siloxanes. These gases are usually at a temperature of 5°C-60°C and a pressure of 0.1-2MPa, and may contain 30%-75% by volume of methane, 0%-40% by volume of nitrogen (N2), 15%-50% by volume of CO2 and 0%-10% by volume of oxygen (O2). In particular, the deacidification method of the present invention is advantageously used to remove CO2 from biogas, which has the significant feature of usually containing a large amount of oxygen, such as a few tenths of a percent to a few percent by volume of oxygen. It is known that amines are usually sensitive to oxygen and are more easily decomposed in the presence of oxygen. Therefore, the present invention is particularly suitable for the treatment of biogas, especially because the absorbent solution has good chemical stability in the presence of oxygen.

[0124] Process for removing acid compounds from gaseous effluents

[0125] The process of the present invention for removing acid compounds from a gaseous effluent comprises a stage of absorbing the acid compounds by contacting the gaseous effluent with an absorbent solution.

[0126] The absorption phase is followed by a regeneration phase, e.g. Figure 1 shown.

[0127] In the present invention, various parameter ranges (such as pressure range and temperature range) of a given stage can be used alone or in combination. For example, in the present invention, a preferred pressure value range can be combined with a more preferred temperature value range.

[0128] refer to Figure 1 , the equipment for deacidification of gaseous effluent comprises an absorption tower C1, which is provided with a device for contacting gas and liquid, such as random packing, structured packing or plate. The gaseous effluent to be treated is transported by pipeline 1 at the bottom of tower C1. Pipeline 4 can introduce an absorbent solution at the top of tower C1. Pipeline 2 can discharge the treated (deacidified) gas, and pipeline 3 can transport the absorbent solution rich in acid compounds after absorption to regeneration tower C2. The regeneration tower C2 is equipped with internal features for contacting gas and liquid, such as plates, random packing or structured packing. The bottom of tower C2 is equipped with a reboiler R1, which provides the heat required for regeneration by evaporating a portion of the absorbent solution. The solution rich in acid compounds is introduced at the top of regeneration tower C2 through pipeline 5. Pipeline 7 can discharge the gas rich in acid compounds released during the regeneration process at the top of tower C2, and the pipeline 6 at the bottom of tower C2 can transport the regenerated absorbent solution to absorption tower C1. The heat exchanger E1 can recover the heat of the regenerated absorbent solution from the tower C2 to heat the absorbent solution rich in acid compounds discharged from the absorption tower C1.

[0129] The absorption stage consists in bringing the gaseous effluent arriving through line 1 into contact with the absorbent solution arriving through line 4. During the contact, the amine functions of the absorbent solution molecules react with the acid compounds contained in the effluent, thereby obtaining a gaseous effluent poor in acid compounds, which is discharged through line 2 at the top of the column C1, and an absorbent solution rich in acid compounds, which is discharged through line 3 at the bottom of the column C1 for regeneration.

[0130] The absorption stage of the acid compound can be carried out at a pressure of 0.1-20 MPa, preferably 2-10 MPa, in the tower C1 when used for treating natural gas, and preferably at a pressure of 0.1-0.3 MPa when used for treating industrial flue gas.

[0131] The absorption stage of the acid compound can be carried out at a temperature in the column C1 of 20°C to 100°C, preferably 30°C to 90°C, or even 30°C to 60°C.

[0132] The regeneration phase comprises in particular the heating and optionally the decompression of the absorbent solution rich in acid compounds, in order to release the acid compounds in gaseous form. The absorbent solution rich in acid compounds coming out of the tower C1 is introduced into the heat exchanger E1 where it is heated by the fluid coming from the regeneration tower C2 and circulating in the pipe 6. The heated solution at the outlet of E1 is introduced into the regeneration tower C2 through the pipe 5 at a temperature generally less than or equal to 110°C.

[0133] In the regeneration tower C2, the acid compound is released in a gaseous form by contacting the absorbent solution arriving through the pipeline 5 with the steam generated in the reboiler and is discharged at the top of the tower C2 through the pipeline 7. The regenerated absorbent solution (i.e., the absorbent solution with less acid compounds) is discharged through the pipeline 6, cooled in E1, and then recycled to the absorption tower C1 through the pipeline 4.

[0134] The regeneration stage can be carried out by thermal regeneration, optionally assisted by one or more decompression stages. For example, the absorbent solution rich in acid compounds discharged by pipe 3 can be sent to the first flash tank (not shown) before it enters the heat exchanger E1 after optional heating. In the case of natural gas, the reduction in pressure makes it possible to obtain a gas discharged at the top of the tank, which contains most of the aliphatic hydrocarbons absorbed by the absorbent solution together. The gas can be optionally washed with a portion of the regenerated absorbent solution, and the gas thus obtained can be used as a fuel gas. The flash tank is preferably operated at a pressure lower than the absorption tower C1 and higher than the regeneration tower C2. The pressure is usually set according to the use conditions of the fuel gas, usually 0.2-1.5MPa, preferably about 0.5-1.5MPa. The operating temperature of the flash tank is substantially the same as the temperature of the absorbent solution obtained at the bottom of the absorption tower C1.

[0135] The absorbent solution then contains a reduced amount of acid gases after the decompression stage. In a particular embodiment of the invention (not shown), it can be partially recycled to the absorption tower C1 for a new absorption cycle, possibly at a different level than the regenerated absorbent solution produced by the tower C2. In this case of partial recycling of the absorbent solution to the absorption tower, another part of the absorbent solution produced by the decompression stage is introduced into the regeneration tower C2.

[0136] In a particular embodiment of the invention (not shown), after the depressurization stage, the absorbent solution is completely recycled to the absorption column C1 and the regeneration column C2 is not used.

[0137] The regeneration can be carried out under the conditions that the pressure in the column C2 is 0.1 MPa-0.5 MPa, preferably 0.1 MPa-0.4 MPa, or even up to 1 MPa, and the temperature in the column C2 is 100° C.-180° C., preferably 100° C.-140° C., more preferably 110° C.-140° C., more preferably 115° C.-140° C., still more preferably 115° C.-130° C. For example, in the case where the acid gas is sent to the atmosphere or a downstream treatment process (e.g., Claus process) or a tail gas treatment process, the regeneration temperature in the column C2 is 115° C.-130° C.

[0138] According to a preferred embodiment, the regeneration is carried out at a pressure of 0.1-0.5 MPa, preferably 0.1-0.4 MPa and a temperature of 110-140°C, more preferably 115°C-130°C in column C2.

[0139] According to the present invention, the liquid absorbent solution is advantageously maintained as a single-phase solution during the absorption phase in the absorber C1 and during the circulation of the solution rich in acid compounds at least until entering the regeneration tower C2. This is because the specific formulation of the absorbent solution minimizes the risk of stratification of the absorbent solution during absorption and circulation of the solution to the regeneration tower. This is because such stratification may be the source of operational problems. This is because, if the solution is in the form of two separated phases in the absorber, the acid compound flow transferred from the gas to the absorbent solution will be strongly affected, so the tower height must usually be adjusted (increase the size of the tower). Therefore, this phenomenon leads to implementation difficulties and is difficult to model in view of the complexity of the system. In addition, the solution in the form of two separated liquid phases may require a separation device (e.g., separation by sedimentation) to be installed upstream of the regeneration tower, which increases the complexity and cost of the method. Therefore, the method of the present invention avoids these problems.

[0140] According to the invention, the absorbent solution minimizes corrosion of equipment items of the gaseous effluent deacidification plant, the surfaces of which comprise steel and are in contact with said solution.

[0141] These devices can be made of low alloy steel (also called carbon steel) or stainless steel. Low alloy steel is understood to mean steel consisting mainly of iron, in particular of at least 90% by weight of iron, 0.01% by weight to 2.5% by weight of carbon, and at least one alloying element selected from aluminum, chromium, cobalt, copper, manganese, molybdenum, nickel, niobium, phosphorus, silicon, titanium, tantalum or vanadium, the individual content of the at least one alloying element being less than 5% by weight. This definition does not exclude the presence of other elements limited to 1% by weight. Stainless steel is less sensitive to corrosion and differs from low alloy steel in that its chromium content is greater than 11.5% by weight.

[0142] The equipment items involved are, without limitation, absorption and regeneration towers for gas / liquid contact, pipes connecting different elements of the equipment, elements located in chambers (such as plates, structured packing or random packing), exchangers, pumps and valves, or tanks.

[0143] According to the invention, items of equipment comprise surfaces consisting essentially of steel, but this does not exclude the presence of other materials used in the manufacture of these items of equipment.

[0144] Due to its limited corrosive capacity, the absorbent solution can limit the corrosion of equipment items of the deacidification plant and can also limit or eliminate the use of corrosion inhibitors in the process of the invention.

[0145] Another advantage offered by the process of the invention for deacidification of gaseous effluents using an absorbent solution is the limitation of the foaming phenomenon. Foaming usually impairs the performance quality of the process and even leads to unit shutdown. Today, foaming is still a phenomenon that is difficult to control, but is still crucial for the operation of deacidification units.

[0146] Surprisingly, the absorbent solution can limit foaming in the presence of aliphatic or aromatic hydrocarbons that may be initially present in the gas to be treated and / or under certain degradation conditions of the solution reflecting its conditions of use. It is thus conceivable to limit or even avoid the use of antifoaming additives usually used to overcome the foaming problems of amine solutions. Therefore, according to one embodiment, the absorbent solution does not contain antifoaming additives.

[0147] An antifoam additive is understood to mean any additional compound or mixture of additional compounds in the absorbent solution, besides the abovementioned compounds which may participate in the composition of the absorbent solution, which is able to prevent foaming of the absorbent solution or to remove foam that has already formed.

[0148] Traditionally, defoaming additives are used by initial dosing, which involves periodically injecting a defoaming solution into the absorbent solution to reach a few tenths of a percent by weight, and then adjusting the dosing based on the foam level observed on the unit. Silicon-based organic compounds such as polydialkylsiloxanes or silicone resins are commonly used, which are usually emulsions in water. It is worth noting that excessive or improper use of defoaming additives can exacerbate foaming problems, which makes the use of such additives difficult to manage.

[0149] A test that can be advantageously used in the laboratory to characterize the foaming ability of a solution and / or the need to use an antifoaming additive consists in determining the height of the foam produced in a cylindrical glass container of the graduated cylinder type, the solution then being stirred, the height of the foam being expressed as a percentage relative to the initial height of the solution, as a function of time.

[0150] For example, a solution with a volume of 50 ml is carried out at 20°C, placed in a 250 ml beaker and stirred for 4 minutes at 1200 rpm using a 5-blade stirrer. Immediately after stopping stirring (t0) and at 30 seconds, the height of the foam generated above the surface of the solution is measured and expressed as a percentage of the initial height. The uncertainty in the measurement corresponds to 2.5% of the initial height.

[0151] According to the invention, the absorbent solution exhibits resistance to degradation, in particular in the presence of oxygen, thus limiting the production of by-products that promote corrosion by phenomena well known to those skilled in the art. Chemical stability is also mentioned in this specification to express this resistance to degradation, in particular at high temperatures, such as those operated during regeneration of the absorbent solution.

[0152] The process of the invention advantageously makes it possible to selectively remove H2S relative to CO2 in the gas to be treated, such as natural gas. This is because the absorbent solution exhibits good performance qualities in such applications, in particular relatively slow CO2 absorption kinetics and a high absorption capacity for H2S, which makes effective selective removal possible and also makes it possible to reduce the flow rate of the absorbent solution used.

[0153] The process of the invention can advantageously be used for the non-selective deacidification of gaseous effluents, for example for the decarbonization of combustion flue gases or the decarbonization of biogas, in particular due to the good performance qualities of the activated absorbent solution with regard to its ability to absorb acid gases, in particular CO2, and with regard to the absorption kinetics and chemical stability of CO2.

[0154] Example

[0155] The following examples illustrate, in a non-limiting manner, the performance qualities of absorbent solutions according to the invention for removing acid compounds, such as CO 2 or H 2 S, contained in gaseous effluents.

[0156] As absorbent solution in these examples, an aqueous PMDPTA solution in combination with MDEA was used. The compositions of these solutions used in the process of the invention are summarized in Table 1 below.

[0157] Some absorbent solutions also contain piperazine (Pz) which is used as an activator.

[0158] Table 1

[0159]

[0160] The first step (Examples 1 and 2) shows that certain physicochemical properties of absorbent solutions A and B (particularly the miscibility of the components), with or without Pz, are very different from the aqueous PMDPTA solutions of the prior art.

[0161] The compositions of the absorbent solutions based on PMDPTA used in the prior art (absorbent solutions C, D, E), as well as absorbent solution F based on another polyamine pentamethyldiethylenetriamine (PMDETA) (according to document WO04082809 or US6267939), and two other absorbent solutions M and N based on another polyamine N,N,N',N'-tetramethyldipropylenetriamine (TMDPTA) (for example disclosed in document US6267939 or WO09156273A2) are given in Table 2 below.

[0162] Table 2

[0163]

[0164] Examples 3-5 illustrate the advantages of the absorbent solution used in the present invention in terms of chemical stability, limitation of corrosion and foaming problems compared to various aqueous solutions of MDEA with or without Pz (the absorbent solutions are shown in Table 3 below). The absorbent solutions given in Table 3 constitute the reference solvent for the treatment of acid gases. Some characteristics of the solution used in the process of the present invention are also compared with the characteristics of a 40 wt. % aqueous solution of diethanolamine (DEA) (absorbent solution x given in Table 3) as a reference solvent also for the treatment of acid gases.

[0165] Table 3

[0166] Absorbent solution H <![CDATA[MDEA (50 wt%) + H2O]]> Absorbent solution I <![CDATA[MDEA (47 wt%) + H2O]]> Absorbent solution J <![CDATA[MDEA (45% by weight) + H2O]]> Absorbent solution K <![CDATA[MDEA (39 wt%) + Pz (6 wt%) + H2O]]> Absorbent solution L <![CDATA[MDEA (40 wt%) + Pz (3.3 wt%) + H2O]]> Absorbent solutionx <![CDATA[DEA (40 wt%) + H2O]]>

[0167] In the absorbent solutions given in Tables 1-3, the sum of the weight fractions expressed as weight % of the various compounds and water equals 100 weight % of the original absorbent solution, i.e. the absorbent solution without taking into account absorbed acid gases or other co-absorbed or degradation products.

[0168] In Example 3, the chemical stability of absorbent solution B was compared with absorbent solution K and absorbent solution F based on MDEA and Pz according to the prior art documents WO04082809 and US6267939. The chemical stability of absorbent solution B was also compared with prior art absorbent solution M containing 50% TMDPTA and prior art absorbent solution N containing 25% TMDPTA, 15% MDEA and 5% Pz, which is a solution similar to absorbent solution B according to the invention, but in which PMDPTA is replaced by TMDPTA.

[0169] In Example 4, the corrosiveness of absorbent solutions A and B was compared to prior art absorbent solution J based on MDEA, prior art absorbent solution L based on MDEA and Pz, and a 40 wt % DEA aqueous solution.

[0170] Finally, in Example 5, the foaming characteristics of absorbent solutions A and B were compared to prior art absorbent solution J based on MDEA and prior art absorbent solution K based on MDEA and Pz.

[0171] Example 1: Miscibility at 40°C. Effect of CO2 loading level

[0172] The stratification phenomenon observed in the aqueous PMDPTA solution loaded with CO2 described in document FR 2877858 can be eliminated by combining PMDPTA with MDEA in the ratio defined in the present invention. The absorbent solution comprises replacing a certain weight percentage of PMDPTA with an equal weight percentage of MDEA of the present invention.

[0173] Depending on the composition of the PMDPTA-based absorbent solution and the composition of the gas to be treated, in particular the CO2 partial pressure, a liquid / liquid phase separation may occur, which is called stratification. For a given absorbent solution (i.e. a given concentration of amine and water), the conditions under which stratification occurs at 40°C were determined by laboratory tests (in a fully stirred gas / liquid reactor) by gradually increasing the CO2 partial pressure and the resulting varying CO2 loading level (α = n 酸气体 / n 胺 , n 酸气体 is the number of moles of acid gas, n 胺 is the number of moles of amine in the liquid solution) determined at physicochemical equilibrium.

[0174] Based on the results of these laboratory tests, the absorbent solution can be used Figure 1 The absorbent solution based on PMDPTA and MDEA defined in the present invention is particularly suitable for this type of process, since it remains a single-phase solution under operating conditions corresponding to those of the absorption column, ie typically 40° C.

[0175] The focus here is on the liquid / liquid equilibrium at 40°C, which corresponds to the low temperature in the absorption column. Laboratory tests were performed on absorbent solutions A and C with a tertiary amine concentration of 50 wt%. The results obtained for the various absorbent solutions are summarized in Table 4 below.

[0176] Table 4

[0177]

[0178] From the results in Table 4, it can be seen that solution A can obtain a single-phase absorbent solution under the operating conditions representing the operating conditions of the absorption tower (in this embodiment, a CO2 partial pressure of 0.3 MPa and 40°C, corresponding to a CO2 loading level of 1.24).

[0179] On the other hand, it can be seen that the absorbent solution of the prior art containing 50 wt% PMDPTA (solution C) exhibits delamination at loading levels of 0.7-1.5.

[0180] Example 2: Effect of Temperature on Miscibility

[0181] The stratification phenomenon observed in the aqueous solution of PMDPTA can be eliminated by PMDPTA and MDEA with the ratio combination defined in the present invention.This specific combination can also prevent any stratification phenomenon observed in the PMDPTA solution when there is no activator or when there is activator (for example piperazine).

[0182] Depending on the composition of the PMDPTA-based absorbent solution and the optional presence of primary or secondary amines and the temperature of the absorbent solution, liquid / liquid phase separation (diffusion phenomenon) may occur.

[0183] For a given absorbent solution (i.e. given concentrations of amine and water), the temperature at which demixing occurs is determined by laboratory tests in a thermostatically controlled oil bath, carried out by gradually increasing the temperature of the oil bath in which the absorbent solution is immersed. Demixing is detected by observing the change in the transparency of the mixture: when demixing occurs the mixture becomes turbid.

[0184] Based on the results of these laboratory tests, the absorbent solution can be used Figure 1 The deacidification process described in . The absorbent solution based on PMDPTA and MDEA in the ratio defined in the invention is particularly suitable for this type of process, since it can remain single-phase at the temperature conditions after passing through the load / effluent exchanger (generally less than or equal to 110° C.).

[0185] Laboratory tests were performed on activated absorbent solutions (B and G) with a tertiary amine concentration of 40 wt% and a Pz concentration of 5 wt%. The results obtained with the different absorbent solutions are summarized in Table 5 below. The solutions were loaded with CO2 at a loading level of 1 mol / mole of amine, which represents the conditions at the outlet of the load / effluent exchanger.

[0186] Table 5

[0187]

[0188] According to the results in Table 5, it is found that the absorbent solutions (solutions A and B) used in the present invention can completely eliminate the stratification phenomenon observed in the prior art solutions C and G. Therefore, absorbent solutions A and B are advantageous because they can obtain a single-phase absorbent solution at a CO2 load level and temperature (generally less than or equal to 110°C) corresponding to the outlet of the load / effluent exchanger.

[0189] On the other hand, it can be seen that the solutions loaded with 50% CO2 and containing PMDPTA (solution C of the prior art) or 30% PMDPTA and 5% Pz (solution G of the prior art) exhibit stratification at temperatures below 110°C (i.e., 95°C for solution G and 40°C for solution C).

[0190] Example 3: Stability of absorbent solution

[0191] The amines of the absorbent solution used according to the invention exhibit the remarkable feature of being particularly resistant to degradation which may occur in the acid removal unit.

[0192] The degradation tests of the absorbent solutions were carried out in a closed reactor, the temperature of which was controlled by a regulating system. 3 A liquid volume of 200 mL was injected into the reactor for the test. Before any gas was injected, all dissolved contaminants in the solution were previously degassed by maintaining a vacuum, after which the reactor was placed in a heating jacket at a set temperature and placed under magnetic stirring. The liquid volume was then flushed overnight at a total pressure of 0.2 MPa and 60°C by a gas stream consisting of 23 Sl / hour of a mixture of nitrogen and CO2 at a partial pressure of 0.17 MPa to reach a loading level representative of the load solution at the bottom of the absorber. After saturation, the CO2-saturated absorbent solution was heated at 140°C for 15 days in a closed reactor. The solution was then cooled to 80°C, after which it was flushed at this temperature by a nitrogen stream of 30 Sl / hour at a pressure of 0.2 MPa to remove CO2. The solution was then analyzed to determine the concentration of residual amines.

[0193] The effect of oxygen on the degradation of the absorbent solution was also studied by replacing part of the nitrogen with air during the saturation phase at 60 °C and extending this phase for 3 days. The air and nitrogen flow rates and the total pressure were adjusted to achieve the desired oxygen partial pressure, while the CO2 partial pressure was kept at 0.17 MPa during the saturation phase.

[0194] The relative degradation rates of solution B, prior art TMDPTA-based solution M, prior art solution N (similar to solution B, but in which PMDPTA is replaced by TMDPTA), prior art solution F containing 50% PMDETA, and reference absorbent solution K containing 39 wt % MDEA and 6 wt % Pz under CO2 pressure for 15 days in the absence of oxygen during the loading phase are given in Table 6 below. The relative degradation rates are calculated by dividing the degradation rate of the amine in the absorbent solution by the degradation rate of the absorbent solution K under the same experimental conditions.

[0195] The degradation rate (DR) of amines was calculated by the following equation:

[0196]

[0197] in:

[0198] [A] is the total concentration of amines in the degraded solution,

[0199] [A]° is the total concentration of amines in the undegraded solution, and

[0200] W 最初 and W 最终 is the weight of the solution before and after the degradation test.

[0201] The concentrations [A] and [A]° were determined by gas chromatography.

[0202] Table 6

[0203] Absorbent solution Amine concentration of absorbent solution (wt%) (remainder is water) Relative DR B 27%PMDPTA+13%MDEA+5%Pz 1 N 27%TMDPTA+13%MDEA+5%Pz 1.3 F 50% PMDETA 6 M 50%TMDPTA 6.3 K 39% MDEA + 6% Pz 1

[0204] The relative degradation rates DR at 15 days are given in Table 7 below in the presence of oxygen in the saturation loading phase under CO2 pressure and with the oxygen partial pressure maintained at 0.02 MPa for 3 days.

[0205] Table 7

[0206]

[0207] According to Table 6, this example shows that the polyamines described in the prior art differ in terms of chemical stability compared to the reference solution and the solution used according to the invention.

[0208] The absorbent solution used in the present invention exhibits a chemical stability comparable to that of the reference solution under CO2 pressure and in the absence of oxygen, unlike the polyamine solutions of the prior art.

[0209] Furthermore, according to Table 7, the absorbent solution used in the present invention exhibits increased oxygen resistance compared to the reference solution K.

[0210] This is particularly advantageous in amine units for processing synthesis gas (syn) and natural gas (which are usually protected from oxygen degradation by special precautions), or in the case of post-combustion CO2 capture or in decarbonization applications when processing biogas from biomass fermentation (which may contain from a few tenths to several percent oxygen).

[0211] Example 4: Corrosiveness of absorbent solution

[0212] The corrosion resistance of the metallurgical materials used in the process is an important point to be confirmed during the introduction of new technology.

[0213] The corrosiveness of the absorbent solution was investigated by autoclave tests under conditions more severe than the application conditions. The results can be compared with tests carried out on different reference absorbent solutions: an MDEA solution (solution J), a solution comprising a mixture of MDEA and Pz (solution L) and an aqueous DEA solution (40 wt. % DEA and 60 wt. % water).

[0214] As it is known that amine solutions are more corrosive in the presence of degradation products, the first stage consisted of the degradation of solutions A and B at 140 °C in 3.5 MPa of CO2 for one week.

[0215] These degraded solutions were subsequently used to perform corrosion tests on lengths of AISI 1020 carbon steel and AISI 316L stainless steel, the chemical compositions of which are given in Table 8 below (values ​​are given in weight %). Iron (not shown in Table 8) is the major element in all of these alloys.

[0216] Table 8

[0217]

[0218] The first test was conducted at 110°C at 3.5 MPa of CO2 to load the solution at temperatures and CO2 loading levels representative of the extreme conditions that may be encountered between the absorber bottom and the regenerator inlet.

[0219] The second test was carried out at 135° C. under nitrogen after extracting (by stripping) the CO 2 from the previous solution, in order to represent the conditions of the absorbent solution at the regenerator outlet (loading level of the regeneration solution less than 0.1 mol / mol).

[0220] For each test, two lengths of carbon steel and two lengths of stainless steel were placed on a rotating stand (circumferential speed close to 0.4 m / s). These lengths were provided in sheets with a side length of 26 mm and a thickness of 1 mm. Before each test, each sample was polished with 600 grade sandpaper, then carefully degreased in ethanol and rinsed with deionized water, and weighed.

[0221] At the end of the test, each sample was subjected to appropriate surface cleaning before weighing to remove deposits of corrosion products, following the method described in document ASTM G1.

[0222] The corrosion rate is calculated from the weight change and is expressed in μm / year.

[0223] The corrosion rates obtained in these tests are given below in Table 13 (data for the first test) and Table 14 (data for the second test) and are compared with the corrosion rates obtained in similar tests conducted in Solution J and Solution L.

[0224] The corrosion rates (μm / year) obtained after testing at 110°C for 4 weeks under rich load conditions (saturated at 3.5 MPa of CO2) are listed in Table 9.

[0225] The corrosion rates (μm / year) obtained after testing for 4 weeks at 135°C (solutions A and B) or 120°C (reference solution) under lean conditions (loading level less than 0.1 mol / mol) are listed in Table 10.

[0226] The results show that the absorbent solution used in the present invention is less corrosive than the reference solution.

[0227] Table 9

[0228]

[0229] Table 10

[0230]

[0231] Example 5: Foaming of absorbent solutions saturated with hydrocarbons or containing compounds produced by amine degradation

[0232] The foaming test carried out enables the evaluation of the foaming capacity of the absorbent solution. The foaming test consists in determining the height of the foam produced after stirring the solution; the test is expressed as a percentage relative to the initial height of the solution, as a function of time.

[0233] It is carried out at 20°C on a volume of 50 ml of solution placed in a 250 ml beaker and stirred at 1200 rpm using a 5-blade stirrer for 4 minutes.

[0234] The height of the foam generated above the surface of the solution was measured immediately (t0) and at 30 seconds after stopping stirring and expressed as a percentage of the initial height of the liquid.

[0235] The uncertainty in the measurement was evaluated at 2.5% of the initial height.

[0236] Reference absorbent solutions J and K and absorbent solutions A and B according to the invention were investigated.

[0237] The effects of foaming on certain anionic products, which are usually caused by oxidative degradation of the amines, were observed on absorbent solutions A and J. To represent the composition of the aged solutions, various carboxylic acids were added to absorbent solutions A and J in the following amounts, expressed as ppm by weight relative to the fresh absorbent solution, namely 3000 ppm by weight of glycolic acid, 500 ppm by weight of oxalic acid, 40000 ppm by weight of formic acid and 6000 ppm by weight of acetic acid, i.e. the total amount of carboxylic acids added represented 4.95% by weight of the fresh absorbent solution.

[0238] In order to observe their foaming ability of absorbent solutions for acid gases in hydrocarbon-containing gaseous effluents, Pz-activated absorbent solutions B and K were saturated with these compounds by contacting the absorbent solutions with a few milliliters of n-hexane or toluene at ambient temperature. The solutions B and K saturated with hydrocarbons were subsequently recovered by sedimentation separation and then subjected to foaming tests.

[0239] Finally, the foaming capacity of the absorbent solution B according to the invention was compared with that of a reference absorbent solution K and an absorbent solution G according to the prior art, which were degraded under the anaerobic conditions described in Example 7 and to which a carboxylic acid mixture was added in an amount of 4.95% by weight of the degraded absorbent solution, the composition of which was as described above.

[0240] The foam heights observed in absorbent solutions A and J in the presence of carboxylic acid after cessation of stirring and 30 seconds are listed in Table 11 as a percentage of the height before stirring.

[0241] Table 11

[0242]

[0243] The results show that under the test conditions, in the presence of acid compounds representative of oxidative degradation, the absorbent solution A according to the invention does not exhibit a significant foaming effect, whereas the reference absorbent solution J has a tendency to foam under the same stirring conditions.

[0244] The foam heights observed in absorbent solutions B and K saturated with n-hexane or toluene at the time stirring was stopped and after 30 seconds are listed in Table 12 as a percentage of the height before stirring.

[0245] Table 12

[0246]

[0247] The results show that under the test conditions, the solution B of the present invention saturated with n-hexane did not show a significant foaming effect, while the reference absorbent solution K based on MDEA and Pz saturated with n-hexane had a foaming tendency under the same stirring conditions.

[0248] It also turns out that in the presence of toluene, the absorbent solution B according to the invention exhibits a foaming factor which is almost halved relative to the reference solution K based on MDEA and Pz.

[0249] This significant effect makes it possible to envisage, for example, that the use of the absorbent solution of the invention enables delayed blockages compared to a reference absorbent solution on an absorption tower and that, all other things being equal, it enables an increase in the capacity of an existing gas treatment unit, that is, for a given solvent flow rate, an increase in the flow rate of acid gas that can be treated.

[0250] In order to build new plants for treating gases containing hydrocarbon acids (for example in the case of natural gas) and to use the absorbent solution according to the invention, it is also possible to envisage a reduction in the diameter of the absorption tower and thus in its costs for a given gas flow rate and a given absorbent solution flow rate, compared with the usual sizing rules for absorbent solutions.

[0251] The foam heights observed at the time of stopping stirring and after 30 seconds for the degraded absorbent solutions B, G and K under the anaerobic degradation conditions defined in Example 7 are listed in Table 13 as a percentage of the height before stirring, to which a carboxylic acid mixture having a composition as described above in an amount of 4.95% by weight of the degraded solution was added.

[0252] Table 13

[0253]

[0254] The results show that, under the test conditions, the solution degraded from the solution B of the invention has a foaming effect reduced by a factor of 2 compared to the absorbent solution degraded from the reference solution K based on MDEA and Pz under the same conditions. Unexpectedly, it was also found that the absorbent solution degraded from the absorbent solution B of the invention containing 27% by weight of PMDPTA showed a foaming tendency after 30 seconds, which was also reduced by a factor of 2 compared to the absorbent solution degraded from the prior art absorbent solution G containing 30% by weight of PMDPTA, which shows a delayed effect of the appearance of foam.

Claims

1. A method for removing acid compounds contained in a gaseous effluent, comprising carrying out an absorption stage of acid compounds by contacting the gaseous effluent with an absorbent solution, the absorbent solution comprising: -water; - 20% to 28% by weight of pentamethyldipropylenetriamine; - 5% to 35% by weight of N-methyldiethanolamine, in, The absorbent solution additionally comprises at least one physical solvent selected from the group consisting of methanol, ethanol, 2-ethoxyethanol, triethylene glycol dimethyl ether, tetraethylene glycol dimethyl ether, pentaethylene glycol dimethyl ether, hexaethylene glycol dimethyl ether, heptaethylene glycol dimethyl ether, octaethylene glycol dimethyl ether, diethylene glycol butoxyacetate, glycerol triacetate, sulfolane, N-methylpyrrolidone, N-methylmorpholin-3-one, N,N-dimethylformamide, N-formylmorpholine, N,N′-dimethylimidazolin-2-one, N-methylimidazole, ethylene glycol, diethylene glycol, triethylene glycol, thiodiglycol, propylene carbonate and tributyl phosphate.

2. The method of claim 1, wherein: The absorbent solution contains 10% to 30% by weight of N-methyldiethanolamine.

3. The method of claim 1, wherein: The absorbent solution contains 37% to 75% by weight of water.

4. The method of claim 1, wherein: The absorbent solution contains: - 5% to 20% by weight of N-methyldiethanolamine; and - 0.5% to 20% by weight of at least one activating compound comprising a primary or secondary amine functional group selected from the group consisting of: -piperazine; -1-Methylpiperazine; -Homopiperazine; -N-(2-hydroxyethyl)piperazine; -3-(Methylamino)propylamine; -N,N'-dimethyl-1,6-hexanediamine; -N-methyl-1,6-hexanediamine; -N,N',N'-trimethyl-1,6-hexanediamine; -2-amino-2-methyl-1-propanol.

5. The method of claim 4, wherein: The absorbent solution contains 5% to 15% by weight of N-methyldiethanolamine.

6. The method according to any one of claims 4 and 5, wherein: The activating compound is piperazine.

7. The method of claim 4, wherein: The absorbent solution comprises 0.5% to 10% by weight of the at least one activating compound.

8. The method of claim 4, wherein: The absorbent solution does not contain antifoam additives.

9. The method of claim 4, wherein: The absorption stage of the acid compound is carried out at a pressure of 0.1 MPa-20 MPa and a temperature of 20°C-100°C.

10. The method of claim 4, wherein: An absorbent solution loaded with acid compounds is obtained after the absorption stage, the method comprising subjecting said absorbent solution loaded with acid compounds to at least one regeneration stage at a pressure of 0.1 MPa to 1 MPa and at a temperature of 100° C. to 180° C.

11. The method of claim 10, wherein: The absorbent solution is a single-phase solution during the absorption stage in the absorption tower and at least until entering the regeneration tower where the regeneration stage is performed.

12. The method of claim 4, wherein: The gaseous effluent is selected from natural gas, synthesis gas, combustion flue gas, refinery gas, acid gas from an amine unit, tail gas from a unit for converting H2S by the Claus process to produce sulfur, gas from biomass fermentation, gas from a cement plant or incinerator flue gas.

13. A process for the selective removal of H2S relative to CO2 from a gaseous effluent comprising H2S and CO2 as claimed in any one of the preceding claims.

14. A method for decarbonizing biogas as claimed in any one of claims 1 to 12.

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