STUDY OF THE TEMPERATURE DEPENDENCE OF THE DEGREE OF PURIFICATION OF NATURAL GASES FROM SOUR COMPONENTS USING COMBINATIONS OF MEA AND DEA ALKANOLAMINE SOLUTIONS

ABSTRACT

A technology has been developed for purifying natural gas from sour compounds using amine solutions and for preparing an optimal variant of the solution. Calculations were carried out to determine the optimal fractional composition of amine solutions — monoethanolamine (MEA) and diethanolamine (DEA). By adding ethers to these solutions, new combined absorbents were obtained, and experimental studies were conducted. Different ratios of MEA and DEA were used, and scientific results were obtained concerning the purification of natural gas from sour components [1,2,3,4].

АННОТАЦИЯ

Разработана технология очистки природного газа от кислых соединений с использованием растворов аминов и приготовление оптимального варианта раствора. Проведены расчеты по определению оптимального фракционного состава растворов аминов-моноэтаноламина (МЭА) и диэтаноламина (ДЭА). Путем добавления к этим растворам эфиров получены новые комбинированные абсорбенты и проведены экспериментальные исследования. Использовались различные соотношения МЭА и ДЭА, получены научные результаты по очистке природного газа от кислых компонентов [1,2,3,4].

Keywords: Amine solutions, acidic component, alkanolamine, monoethanolamine, diethanolamine, inhibitor, electrodialysis, polyethanolglycol, absorbent.

Ключевые слова: Растворы аминов, кислотный компонент, алканоламин, моноэтаноламин, диэтаноламин, ингибитор, электродиализ, полиэтанолгликоль, абсорбент.

Research methods. When purifying natural gas from toxic sour gas components, the selection criteria and conditions for choosing optimal or combined absorbents, as well as the analysis of their production technologies, were examined. Various alkanolamine purification methods used in the primary processing of oil and gas raw materials—such as mono-, diethanol-, triethanolamine, and methyldiethanolamine solutions—were analyzed for their efficiency in absorbing hydrogen sulfide, carbon dioxide, mercaptans, and sulfur compounds. The prevention of foaming in absorbing solutions and the influence of absorber design features on the efficiency of purification were studied. A column-type absorber was recommended for use. Factors influencing the efficiency of amine purification—such as the content of acidic gases and heat-resistant salts in natural gas—and the techno-economic feasibility of the process were discussed [1,2,3,4,5,6,7].

Natural gases, along with hydrocarbons, contain sour gases such as carbon dioxide (CO₂), hydrogen sulfide (H₂S), mercaptans (RSH), and others, which under certain conditions complicate the transportation and utilization of oil and gas products. To prevent possible complications during primary processing, transportation, and utilization, a set of necessary measures is pre-developed to meet established standards for the content of toxic components in natural gas.

Considering these factors, it is possible to achieve deep purification of gases from undesirable components and to obtain valuable products by carefully selecting the main criteria for purification technologies and absorbents [6,7,8].

In the chemical industry, numerous methods and technologies are used for gas purification, which differ in the types of absorbents used, the efficiency of sour component removal, and the volumes of raw materials processed.

The main objective of this research is to scientifically develop the technology for obtaining composite amine-based absorbents and to establish a methodology for purifying natural gas from sour components using these composite absorbents.

To solve the issues related to purifying natural gas from sour components, this research utilized statistical data from literature reviews, as well as the results of theoretical and experimental studies, ensuring the effective use of scientific information.

The use of diethanolamine as an amine absorbent in the regeneration process of gas purification at the MGQIZ facility is characterized by disadvantages, namely, a high level of corrosion activity, high solvent consumption, relatively high solvent loss, high energy consumption for its regeneration process, and its connection with the properties of DEA. The main purpose of the study is the process of purifying gas from sour components using amine purification methods, and it is necessary to quickly solve the problems of its operation, which lead to aggravation of the problems [8,9].

The interaction of H₂S and CO₂ with amines occurs depending on the type of amine used. The presence of substituents on the nitrogen atom influences the reactivity of the amine [2,7,8,9]. Compared with MEA and DEA, hydrogen sulfide removal is generally more selective - that is, it is characterized by a lower amount of unabsorbed carbon dioxide.

The difference in reaction rates between H₂S and CO₂ with amines is significant: during the absorption of H₂S, the mass transfer resistance is mainly concentrated in the gas phase, whereas for CO₂, it occurs primarily in the liquid phase. For MEA, the reaction with H₂S (an instantaneous reaction) proceeds much faster than the reaction with CO₂ (a slower reaction), and this rate difference is even greater compared to secondary amines.

The fast reaction of hydrogen sulfide and the slower reaction with CO₂ make it possible to use this difference in the selective removal of H₂S from gas mixtures containing CO₂ when using diethanolamine (DEA). In this case, the absorber must be designed such that the gas–liquid contact time is sufficient to ensure the almost complete absorption of hydrogen sulfide, while being too short for significant carbon dioxide removal.

The selectivity of the process toward hydrogen sulfide increases as the gas–liquid contact time decreases [9,11,12,13].

The advantages of MEA over DEA are:

- high thermal stability and low corrosion activity of the solution compared to DEA;

- low heat of reaction of H2S and CO2, i.e. the possibility of reducing the amount of heat required for regeneration of the absorbent;

- does not form non-regenerable amides in the reaction with carboxylic acids and corrosion inhibitors, so that amine loss does not occur, and solid deposits do not form on the internal surfaces of the heat exchanger;

- due to the low pressure of saturated vapors, amine loss due to volatility is reduced;

- the required consumption of MEA and DEA is slightly higher than that of MDEA.

- Analysis of the influence of the process parameters and the inclusion of absorbents on the absorption process of mass transfer devices. MDEA has a high absorption activity towards hydrogen sulfide. The slow reaction rate of MDEA with CO2 can be overcome to a practical extent by the addition of one or two chemically active primary or secondary amines to form a mixture of amines in water. In addition, the slow reaction rate of MDEA with CO2 can be achieved by the parameters of the absorber, the design, and the type of plates (nozzles), i.e., by ensuring the appropriate contact time. In order to effectively use MDEA to remove the main amount of CO2, its residence time in the liquid phase must be long enough for the reaction of CO2 to occur. At lower pressures, the addition of a highly reactive amine enhances the ability of the solution to remove CO2. Thus, in the field of application of MDEA, the requirements for a product gas cannot be met, and the use of an amine mixture can improve the performance of the device. The sequence of the technological process of amine purification. The absorption process is carried out in a column-type apparatus, i.e., in the absorber, Figure 1.

The chemical reaction takes place in the liquid phase on the contact surfaces of the absorber nozzle (dish), i.e., in the contact of the raw material streams in a continuous countercurrent flow: natural gas - from bottom to top and amine solution - from top to bottom.

During the contact of the phases, chemisorption of H2S and CO2 with liquid absorbers is carried out, forming chemical compounds.

The saturation of amine solutions with sour components is followed by regeneration in a desorber—specifically, a stripping column—where chemical reactions decompose the absorbed compounds: the amine is regenerated, while the gases are released through heat absorption (an endothermic reaction). The desorption process occurs as a result of reduced pressure and increased temperature. To maintain stable operating conditions, an antifoaming agent is added to the system.

To remove impurities, the regenerating amine solution is filtered through activated carbon.The reliability of the gas purification unit using amine solutions for sulfur removal decreases under the following conditions:

• decomposition of amines due to side reactions and thermal degradation;
• corrosion of equipment and pipelines;
• resin formation;
• foaming in the gas purification (drying) system;
• deposition of solid contaminants on the surfaces of pipelines and equipment.

The presence of excessive foaming in the system leads to absorbent loss and deterioration of the commercial gas quality. The main external indicator of foam formation is a sharp increase in pressure drop within the column.

 The corrosion rate depends on numerous variable factors. The corrosion activity of amines generally decreases in the following order: MEA > DEA > MDEA [13].

The relative concentrations of CO₂ and H₂S in the sour gas also affect corrosion. CO₂ is considered more corrosive than H₂S. However, the absolute concentrations of CO₂ and H₂S are not the only determining parameters—their ratio defines the composition of the hot amine solution.

In addition, corrosion is influenced by both physical and chemical parameters, as well as by the type of steel used in the construction of the equipment. The corrosion rate increases with rising temperature and with an increase in CO₂ concentration in the solution. Therefore, as the CO₂ content in the solution increases, the volume of solution sent for filtration should be increased.

If no erosion of iron sulfide occurs on the metal surface, a protective film can form on the metal construction. Considering this, purification of gases with low CO₂ and high H₂S content using highly saturated amine solutions is permissible.

Analysis of the Obtained Results. Factors Affecting the Efficiency of Amine Purification and the Sequence of the Purification Process.One of the main disadvantages of amine purification technology is the high regeneration temperature of amine solutions and their decomposition in the presence of oxygen. In addition, the cations of alkanolamines interact with the anions of organic acids (amine degradation products) and inorganic acids, resulting in the formation of heat-stable salts (ICHT). These salts are stable compounds that do not decompose under typical regeneration conditions [14]. As a result, such salts deposit on the walls of heat exchange equipment, form corrosion layers, and increase energy consumption during heat transfer.

The accumulation of ICHT in the absorption system leads to several operational issues, such as a decrease in CO₂ absorption capacity, deterioration of the physicochemical properties of the solution, increased corrosion activity, clogging, and erosion of equipment.

ICHT can be removed from amine solvents through distillation (ion exchange) or electrodialysis (YED) methods. However, both approaches can also remove charged particles together with ICHT components, and additional treatment may be required to eliminate neutral degradation products — for instance, by using sand filters and activated carbon.

In the gas purification process, MEA and DEA were used as amine components for the preparation of composite absorbents, while dimethyl ether and monomethyl ether of polyethylene glycol were used as the ether components.

In the initial stage of our research, aqueous solutions of amines and ethers at various concentrations were prepared. The compositions of the obtained composite absorbents are presented in Table 1 [16].

Table 1.

Composition of Composite Absorbents Prepared from Amines and Ethers for the Purification of Natural Gas from Sour Components

The formation of heat-stable salts ICHT occurs due to the presence of certain acidic components in the process gas and liquid phases. The interaction of amines with these components leads to irreversible reactions resulting in ICHT formation. Such contaminants typically include chloride, sulfate, formate, acetate, oxalate, thiocyanate, and thiosulfate ions. The resulting salts possess relatively strong chemical bonds, which cause the gradual accumulation of ICHTin the amine circulation system. When the concentration of these salts exceeds the permissible limit, various operational and maintenance problems arise.

Our scientific research is aimed at improving the quality of local natural gas to meet commercial gas standards. The main objective of the study is to purify natural gas from sour components — specifically hydrogen sulfide (H₂S) and carbon dioxide (CO₂) — by developing and implementing new-generation absorbents for use in the absorption process.

For the selective purification of natural gas using combined absorbents, a technology was developed based on the following composition: MEA + PEGDME + PEGMME (monoethanolamine + polyethylene glycol dimethyl ether + polyethylene glycol monomethyl ether).

The activity and selectivity of absorbent compositions based on MEA + PEGDME + PEGMME in removing sour components (CO₂ and H₂S) from natural gas were studied.

In our research, the following composite absorbents were used: MPP-1, MPP-2, MPP-3, MPP-4, MPP-5, and MPP-6, all prepared on the basis of monoethanolamine (MEA), polyethylene glycol dimethyl ether (PEGDME), and polyethylene glycol monomethyl ether (PEGMME).

The dependence of CO₂ removal efficiency on pressure for these compositions is shown in Figure 1 [18].

Figure 1. Pressure dependence of the CO2 removal rate of MPP-1, MPP-2, MPP-3, MPP-4, MPP-5 and MPP-6 absorbent compositions in natural gas

At the initial stage of our research, the activity and selectivity of the purification process of    natural gas from sour components — CO₂ and H₂S — were determined. The technological parameters of the absorption purification unit were as follows: inlet gas pressure to the absorber — 3–5 MPa; inlet gas temperature — 55°C; temperature of regenerated MDEA entering the absorber — 60°C. The composition of the gas contained 3.25% CO₂ and 0.81% H₂S.

The results of the study conducted to determine the dependence of CO₂ removal efficiency on pressure using absorbent compositions MPP-1, MPP-2, MPP-3, MPP-4, MPP-5, and MPP-6 showed that for this type of composite absorbents, the degree of CO₂ removal increased proportionally with pressure. Among all the tested compositions, the MPP-1 composition — consisting of 20% MEA, 5% PEGDME, 5% PEGMME, and 70% water — demonstrated the highest efficiency. At a pressure of 5 MPa, the CO₂ concentration in the gas decreased from 3.25% to 0.02%. During the absorption process, when the inlet gas pressure was 5 MPa, the outlet gas pressure was recorded as 4.7 MPa [16,17].

Based on these results, it was established that all the absorbent compositions developed in this study were able to reduce the CO₂ content in natural gas to levels meeting commercial gas quality requirements at a pressure of 4 MPa. Consequently, the next stage of the research focused on investigating the effect of gas and amine temperatures on the absorption purification process at 4 MPa.

Further research was conducted to study the activity and selectivity of absorbent compositions based on DEA + PEGDME + PEGMME in the purification of natural gas from sour components (CO₂ and H₂S).

In the next stage of the research on the purification of gases from acidic components, the activity and selectivity of absorbent compositions such as DPP-1, DPP-2, DPP-3, DPP-4, DPP-5, and DPP-6, based on DEA + PEGDME + PEGMME, were investigated for their ability to selectively remove sour components from natural gas. The operating conditions of the absorption process for these compositions were as follows: Pressure: 3–5 MPa, Inlet gas temperature: 55–30°C, Inlet absorbent temperature: 60–35°C. The obtained results are presented in Table 1 [9].

The results of the studies conducted to determine the activity and selectivity of absorbent compositions such as DPP-1, DPP-2, DPP-3, DPP-4, DPP-5, and DPP-6, based on DEA + PEGDME + PEGMME, for selectively absorbing acidic components from natural gas showed higher performance compared to compositions based on MEA + PEGDME + PEGMME. Specifically, under absorption conditions at a pressure of 3 MPa, with the amine inlet temperature at 35°C and the gas temperature at 30°C, it was observed that: When using the DPP-1 absorbent composition, the total sulfur (S) mass concentration in the natural gas decreased to 0.011 g/m³, and the molar fraction of CO₂ was reduced to 0.20%.When using the DPP-2 composition, the total sulfur concentration decreased to 0.032 g/m³, and the molar fraction of CO₂ dropped to 0.46%.When the gas pressure was increased to 5 MPa, and the corresponding gas/amine temperatures were 45°C and 40°C, respectively, the DPP-1 and DPP-2 absorbents further reduced the total sulfur concentration to 0.001 g/m³ [2, 7, 8].

Study of the activity and selectivity of absorbent compositions based on MEA+DEA+PEGDME+PEGMME in the process of purifying gases from sour components CO2 and H2S. In the next stage of our research on the purification of gases from sour components, the activity and selectivity of absorbent compositions such as MDPP-1, MDPP-2, MDPP-3, MDPP-4 and MDPP-5 based on MEA+DEA+ PEGDME+PEGMME in the selective absorption of sour components from natural gas were studied. The aim was to study the synergistic effect of MEA and DEA amines with PEGDME and PEGMME esters in the production of such absorbent compositions. The results of a study on the activity and selectivity of absorbent compositions such as MDPP-1, MDPP-2, MDPP-3, MDPP-4, and MDPP-5 in selectively absorbing sour components from natural gas are presented [8, 9].

It is worth noting that the absorbent compositions obtained on the basis of MEA+DEA+PEGDME+PEGMME showed better results than the compositions obtained using MEA and DEA. In particular, when the pressure of the absorption process was 3 MPa and the amine and gas temperatures were 40/35°C, respectively, the absorption purification with the MDPP-1 absorbent resulted in a decrease in the total sulfur content in the natural gas by 0.02 g/m3 and the carbon dioxide content by 0.35%, while the absorption with the MDPP-2 absorbent resulted in a decrease in the total sulfur content in the gas by 0.001 g/m3 and the carbon dioxide content by 0.36%, and the purification with the MDPP-5 absorbent resulted in a decrease in the total sulfur content in the gas by 0.001 g/m3 and the carbon dioxide content by 0.04%. We can see that these indicators improve further as the pressure of the natural gas entering the absorption process increases and the temperature of the amine and gas decreases [17, 18].

Comparison of the degree of purification of gases from sour components of composite absorbents based on amines and esters. In general, 17 new composite absorbents based on DEA, MEA, PEGDME and PEGMME were obtained for the purification of gases from sour components and their degree of purification of gases from sour components in the range of 3-5 MPa pressure, amine temperature 65-35 ° C and natural gas temperature 55-30 ° C was determined. In this case, their selectivity showed different results under the influence of pressure and temperature. Among these composite absorbents, samples such as DPP-1, DPP-2, DPP-3, MDPP-1, MDPP-2 and MDPP-3, MDPP-5 showed high indicators. In this case, we can see that the absorption degree in all these composite absorbents improved with a decrease in the temperature of the gas and amine entering the absorber and an increase in pressure. It can be seen that the highest results were obtained when the amine temperature was 40-35°C and the gas temperature was 35-30°C, i.e., the amine/gas temperatures were 40/35°C and 35/30°C, respectively. The results of the sulfur removal rate of these compositions from natural gas at the Absorbent/Gas temperatures of 40/35°C and 35/30°C and pressures of 3-5 MPa are presented in Figures 2 - 3.

Figure 2. Sulfur removal efficiency of composite absorbents from natural gas at absorbent/gas temperatures of 35/30oC

Figure 3. Sulfur removal rate from natural gas using composite absorbents at absorbent/gas temperatures of 40/35°C

The results of the study showed that at an Absorbent/Gas temperature of 35/30°C, DPP-1, MDPP-1, MDPP-2, MDPP-4 and MDPP-5 absorbents reduce the total sulfur concentration in the gas to the required 0.030 g/m3 under a pressure of 3 MPa. When the pressure was increased to 3.5 MPa, it was found that the DPP-2 composite absorbent also purifies the gas to the required level. As a result of these studies, it was possible to reduce the mass concentration of total sulfur in the gas to 0.001 g/m3, after which the sulfur content did not decrease. The results of the study, when the Absorbent/Gas temperature was increased to 40/35°C and the pressure was 3 MPa, the absorption process using DPP-1, MDPP-1, MDPP-2 and MDPP-5 samples achieved the required level of sulfur removal.

Conclusion. 1. Absorbent compositions for cleaning gases from sour components based on MEA+DEA+PGEDME+PEGMME were obtained and studies were carried out to determine their main physical properties.

2. The pressure dependence of the CO2 removal rate of the obtained absorbent compositions in natural gas was determined.

3. When the temperatures of the amine and gas were 40/35oC, respectively, and the absorption process was carried out under a pressure of 3MPa, the total sulfur content in the MPP-1 absorbent composition was reduced to 0.024 g/m3 and the CO2 content to 0.18%, and when the pressure was 3.5 MPa, the total sulfur content was reduced to 0.020 g/m3 and the CO2 content to 0.09%. These results are considered to be lower than the standard required values.

4. Using the DPP-1 absorbent composition, the mass concentration of total S was reduced to 0.011 g/m3, the molar fraction of CO2 to 0.20%, while using the DPP-2 absorbent composition, the mass concentration of total S in natural gas was reduced to 0.032 g/m3, the molar fraction of CO2 to 0.46%. It was found that when the gas pressure increased to 5 MPa and the gas/amine temperature was 45/40°C, respectively, using the DPP-1 and DPP-2 absorbents, the mass concentration of total S was reduced to 0.001 g/m3.

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