Regeneration tower corrosion prevention and control method

Abstract

The present application relates to a kind of regeneration tower corrosion prevention and control method, comprising the following steps: S1, to the regeneration tower is carried out multiphase flow software simulation extraction regeneration tower different parts several positions flow field parameters calculate chemical corrosion and erosion corrosion;S2, to the regeneration tower accessory pipeline is carried out multiphase flow software simulation extraction regeneration tower accessory pipeline different parts several positions flow field parameters calculate chemical corrosion and erosion corrosion;S3, according to the analysis data of step S1 and step S2, the corrosion risk behavior analysis of regeneration tower and its accessory pipeline is carried out, confirms that chemical corrosion is mainly function;S4, according to the analysis result of step S3, by reducing the concentration of hydrogen sulfide in water to reduce the rate of chemical corrosion, by improving temperature to reduce the concentration of hydrogen sulfide dissolved in water to improve process conditions;S5, the process conditions of regeneration tower after step S4 are improved are used in alcohol amine method desulfurization system.A beneficial effect is that the corrosion of regeneration tower in alcohol amine method desulfurization system is relieved, prevention and control.

Description

[Technical Field]

[0001] This invention relates to the field of petrochemical technology, specifically to a method for corrosion control in regeneration towers. [Background Technology]

[0002] With the increase in the processing of sulfur-containing crude oil in China, the hydrogen sulfide content generated during the refining process has also increased, posing a significant threat to environmental protection. Furthermore, the presence of H2S or CO2 in the feedstock causes corrosion to the equipment. Recent reports indicate that, because desulfurization units are mostly made of carbon steel, the severe corrosion caused by H2S not only leads to thinning and perforation of equipment and pipelines, but also to material leaks and unplanned shutdowns, seriously affecting normal production operations. Moreover, corrosion products cause foaming and degradation of the desulfurizing agent, increasing desulfurizing agent consumption and process energy consumption.

[0003] The corrosion behavior of amine desulfurization units is extremely complex. The regeneration tower, reboiler, lean and rich liquor heat exchangers, and high-temperature rich liquor pipelines are all areas prone to severe corrosion, with the regeneration tower being the most severely corroded component. Corrosion morphologies include electrochemical corrosion, chemical corrosion, stress corrosion, and hydrogen bubbling. Domestic and international research indicates the following corrosive media and locations: H2S-CO2-H2O type corrosion at the top of the desulfurization regeneration tower; H2S-CO2-RNH2-H2O type corrosion at temperatures of 90–120℃ in the regeneration tower, rich liquor pipelines, reboiler at the bottom of the regeneration tower, and solvent reactivation vessel. Several domestic refineries have observed different types of corrosion. To maintain the sustainable development of petrochemical enterprises and meet increasingly stringent national environmental standards, the removal of hydrogen sulfide from amine desulfurization units is of paramount importance, significantly impacting the safe and stable operation of the unit. Corrosion control of the regeneration tower is therefore imperative.

[0004] Alkylamine desulfurization is a typical absorption reaction process. It utilizes a weakly alkaline aqueous solution of amine (complex methyldiethanolamine), which has a strong absorption capacity for hydrogen sulfide and a relatively fast chemical reaction rate, as the absorbent. Inside the desulfurization tower, it is brought into countercurrent contact with dry gas and liquefied petroleum gas at room temperature, allowing the amine to absorb both. The main equipment involved includes a regeneration tower, a stripping tower, heat exchangers, and separation equipment. As an emerging branch of mechanics, liquid-solid two-phase, gas-solid, and gas-liquid two-phase flows are collectively referred to as two-phase fluid mechanics. Liquid-solid mixtures, as a type of two-phase fluid, are widely found in nature and in various fields such as energy, chemical industry, petroleum, mining, construction, water conservancy, light industry, metallurgy, and environmental protection.

[0005] This invention provides a technical improvement to the corrosion control method for regeneration towers. [Summary of the Invention]

[0006] The purpose of this invention is to provide a method for mitigating and controlling corrosion in the regeneration tower of an alcohol amine desulfurization system.

[0007] To achieve the above objectives, the present invention provides a method for corrosion control in regeneration towers, used to mitigate and control corrosion in regeneration towers within an alcohol amine desulfurization system, comprising the following steps:

[0008] S1. Multiphase flow simulation of the regeneration tower is performed. The scouring corrosion is analyzed by the scouring and wear behavior of the flow field and component distribution in different parts. The chemical corrosion is analyzed by the volume percentage distribution of H2S and liquid water inside the regeneration tower. The flow field parameters of several locations in different parts of the regeneration tower are extracted to calculate chemical corrosion and scouring corrosion.

[0009] S2. Multiphase flow simulation of the auxiliary pipeline of the regeneration tower is performed. The shear stress distribution of the auxiliary pipeline of the regeneration tower is analyzed to detect scouring corrosion. The flow field parameters at several locations in different parts of the auxiliary pipeline of the regeneration tower are extracted to calculate chemical corrosion and scouring corrosion.

[0010] S3. Based on the analysis data from steps S1 and S2, conduct corrosion risk behavior analysis on the regeneration tower and its auxiliary pipelines to confirm that chemical corrosion plays a major role.

[0011] S4. Based on the analysis results of step S3, the chemical corrosion rate is reduced by decreasing the concentration of hydrogen sulfide in the water, and the process conditions are improved by increasing the temperature to reduce the concentration of hydrogen sulfide dissolved in the water.

[0012] S5. Apply the improved regeneration tower process conditions from step S4 to the alcohol amine desulfurization system.

[0013] Preferably, step S1 analyzes the scouring corrosion by analyzing the distribution of local vectors at the top and reflux inlet of the regeneration tower, velocity vector at the feed inlet, velocity vector near the steam inlet connecting to the reboiler outlet, shear stress near the top outlet, shear stress near the feed inlet, and shear stress near the steam inlet connecting to the reboiler outlet. Flow field parameters at eight corrosion analysis reference points at different locations in the regeneration tower are extracted to calculate chemical corrosion and scouring corrosion.

[0014] Preferably, in step S2, the auxiliary pipelines of the regeneration tower include the feed inlet pipeline, the top outlet pipeline, the reboiler outlet pipeline, the lean liquor outlet pipeline, the steam inlet pipeline, and the reflux inlet pipeline. Flow field parameters at 14 different locations of the auxiliary pipelines of the regeneration tower are extracted for corrosion analysis reference points to calculate chemical corrosion and erosion corrosion.

[0015] Preferably, the corrosion risk behavior of the regeneration tower and its associated pipelines in step S3 occurs in areas where hydrogen sulfide accumulates, near pipeline bends, and in areas with relatively high flow velocities.

[0016] Preferably, the hydrogen sulfide accumulation sites include the feed distributor, the reflux liquid distributor, the vicinity of the top outlet pipe, and the reflux pipeline, which pose a risk of chemical corrosion; the inner side of the pipeline bends is subject to more severe erosion corrosion than the outer side; the areas with relatively high flow velocities include the connection between the steam inlet and the regeneration tower, the gap between the liquid distributor and the tower wall, and the connection between the tower top and the outlet, which pose a risk of erosion corrosion.

[0017] Preferably, the improved process conditions in step S4 are to keep the steam flow rate of the steam inlet pipeline constant, increase the steam temperature of the steam inlet pipeline to increase heat input, and increase the overall temperature.

[0018] Preferably, the basic operating conditions of the alcohol amine desulfurization regeneration tower are: rich liquid inlet flow rate of 75t / hr, inlet temperature of 70℃, reflux inlet flow rate of 10t / hr, and the steam temperature of the steam inlet pipeline is increased from 120℃ to 170℃.

[0019] Preferably, the improved process conditions in step S4 are to keep the steam temperature of the steam inlet pipeline constant and increase the steam flow rate of the steam inlet pipeline, thereby increasing the heat input and raising the overall temperature.

[0020] Preferably, the basic operating conditions of the alcohol amine desulfurization regeneration tower are: rich liquid inlet flow rate of 75t / hr, inlet temperature of 70℃, and reflux inlet flow rate of 10t / hr. The steam flow rate of the steam inlet pipeline is increased from 1.8kg / s to 2.5kg / s.

[0021] The corrosion control method for regeneration towers of the present invention has the following beneficial effects: by analyzing the risk behavior of chemical corrosion and multiphase flow corrosion during the operation of the regeneration tower process, the effective areas of chemical corrosion and scouring corrosion are located; further, based on the structure of the corrosion, it is determined that chemical corrosion plays a major role; further, the operating process conditions of the regeneration tower trays are determined and the process operating conditions are optimized. [Attached Image Description]

[0022] Figure 1 This is a schematic diagram of a corrosion control method for a regeneration tower.

[0023] Figure 2 This is a schematic diagram of the reference point for corrosion analysis of the regeneration tower.

[0024] Figure 3 This is a schematic diagram of the regeneration tower and its associated pipelines.

[0025] Figure 4 This is a schematic diagram of the reference point for corrosion analysis of the feed inlet pipeline of the regeneration tower.

[0026] Figure 5 This is a schematic diagram of the reference point for corrosion analysis of the regeneration tower return pipeline.

Detailed Implementation Methods

[0027] The present invention will now be further described with reference to the embodiments and the accompanying drawings.

[0028] Example 1

[0029] This embodiment implements a method for corrosion prevention and control in regeneration towers.

[0030] Figure 1 This is a schematic diagram of a corrosion control method for a regeneration tower. (See attached diagram.) Figure 1 As shown, this embodiment presents a method for corrosion control in a regeneration tower, used to mitigate and control corrosion in the regeneration tower of an alcohol amine desulfurization system, comprising the following steps:

[0031] S1. Multiphase flow simulation of the regeneration tower is performed. The scouring corrosion is analyzed by the scouring and wear behavior of the flow field and component distribution in different parts. The chemical corrosion is analyzed by the volume percentage distribution of H2S and liquid water inside the regeneration tower. The flow field parameters of several locations in different parts of the regeneration tower are extracted to calculate chemical corrosion and scouring corrosion.

[0032] S2. Multiphase flow simulation of the auxiliary pipeline of the regeneration tower is performed. The shear stress distribution of the auxiliary pipeline of the regeneration tower is analyzed to detect scouring corrosion. The flow field parameters at several locations in different parts of the auxiliary pipeline of the regeneration tower are extracted to calculate chemical corrosion and scouring corrosion.

[0033] S3. Based on the analysis data from steps S1 and S2, conduct corrosion risk behavior analysis on the regeneration tower and its auxiliary pipelines to confirm that chemical corrosion plays a major role.

[0034] S4. Based on the analysis results of step S3, the chemical corrosion rate is reduced by decreasing the concentration of hydrogen sulfide in the water, and the process conditions are improved by increasing the temperature to reduce the concentration of hydrogen sulfide dissolved in the water.

[0035] S5. Apply the improved regeneration tower process conditions from step S4 to the alcohol amine desulfurization system.

[0036] Example 2

[0037] This embodiment implements a method for corrosion prevention and control in regeneration towers.

[0038] This embodiment presents a method for improving corrosion in reboiler bends. By analyzing chemical corrosion and multiphase flow scouring corrosion during the regeneration tower process, the method locates the areas affected by corrosion and scouring corrosion. Furthermore, it determines the structure of corrosion and chemical corrosion, and further designs and optimizes the regeneration tower operating conditions.

[0039] 1. Corrosion Analysis of Regeneration Tower

[0040] The multiphase flow within the regeneration tower was analyzed. The flow field and component distribution at different locations determine the erosion and wear behavior. This analysis included local vector measurements at the top and reflux inlet, the feed inlet velocity vector, the velocity vector near the steam inlet connecting to the reboiler outlet, and the shear stress distribution near the top outlet. The analysis showed that the top outlet and the steam inlet connecting to the reboiler outlet, as well as the feed inlet (where the flow velocity is higher), are the key areas for significant erosion corrosion.

[0041] Further analysis of the shear stress distribution at different locations within the regeneration tower, including the shear stress distribution near the feed inlet and the shear stress distribution near the steam inlet connecting to the reboiler outlet, also indicates that the shear stress near the steam inlet connecting to the reboiler outlet is relatively large, resulting in a significant scouring and corrosion effect.

[0042] The chemical corrosion of the regeneration tower is mainly affected by the flow rate and the concentration of H2S dissolved in liquid water. A large amount of H2S is distributed in the upper part of the tower; if liquid water is present in this area, it will lead to severe corrosion. An analysis of the volume percentage distribution of H2S and liquid water inside the regeneration tower was conducted. Based on the above analysis of H2S and water distribution, it can be seen that the H2S concentration is higher in the upper part of the tower, while the volume percentage of liquid water does not change much from the feed inlet to the steam inlet in the lower part. Furthermore, the return water may flow directly to the wall of the feed inlet distributor. Therefore, chemical corrosion is likely to be greater near the feed inlet. Although there is more liquid water in the lower part, the H2S content is lower, and although the H2S content is high at the top, the water content is low.

[0043] Multiple locations were selected, and chemical corrosion and erosion corrosion were calculated separately. Figure 2 This is a schematic diagram of the reference points for corrosion analysis of the regeneration tower. (See attached diagram.) Figure 2 As shown in the figure, flow field parameters at eight locations were extracted to calculate chemical corrosion and erosion corrosion. Table 1 shows the corrosion rate at reference points for corrosion analysis of the regeneration tower, and the results indicate that chemical corrosion plays a major role.

[0044] Table 1 Corrosion Rate Reference Point for Corrosion Analysis of Regeneration Tower

[0045] Location Chemical corrosion rate (mm / year) Erosion rate (mm / year) Total corrosion rate (mm / year) 1 0.59 9.82E-05 0.59 2 4.68 7.32E-03 4.68 3 2.67 1.65E-06 2.67 4 4.81 4.96E-04 4.81 5 2.32 1.26E-07 2.32 6 3.3 3.7E-04 3.3 7 0.01 6.96E-06 0.01 8 0.01 2.14E-06 0.01

[0046] 2. Corrosion analysis of pipelines 1-6

[0047] Figure 3 This is a schematic diagram of the regeneration tower and its associated pipelines. (See attached diagram.) Figure 3As shown in the attached diagram, the pipeline markings are as follows: 1. Feed inlet pipeline, 2. Top outlet pipeline, 3. Reboiler outlet pipeline, 4. Lean liquor outlet pipeline, 5. Steam inlet pipeline, 6. Return inlet pipeline. Analysis of the shear stress distribution in the feed inlet pipeline, top outlet pipeline, reboiler outlet pipeline, lean liquor outlet pipeline, steam inlet pipeline, and return inlet pipeline reveals that due to the presence of H2S in pipelines 2 and 6, both scouring corrosion and chemical corrosion must be considered. For pipelines 1, 3, 4, and 5, only scouring corrosion needs to be considered. The diagram shows that the shear stress is generally higher at the pipeline inlet and bends, resulting in more pronounced scouring corrosion.

[0048] Figure 4 This is a schematic diagram of the reference point for corrosion analysis of the feed inlet pipeline of the regeneration tower. (See attached diagram.) Figure 4 As shown, five corrosion analysis reference points were set on the feed inlet pipeline of pipeline 1. Table 2 is a corrosion rate table for the feed inlet pipeline of the regeneration tower. As shown in Table 2, five corrosion analysis reference points were selected at different parts of pipeline 1 to analyze the scouring corrosion rate and chemical corrosion rate of each locality.

[0049] Table 2 Corrosion Rate of Inlet Pipeline of Regeneration Tower

[0050] Location Chemical corrosion rate (mm / year) Erosion rate (mm / year) Total corrosion rate (mm / year) 1 0 9.19E-06 9.19E-06 2 0 9.31E-05 9.31E-05 3 0 0.151 0.151 4 0 0.0178 0.0178 5 0 3.80E-06 3.80E-06

[0051] Five corrosion analysis reference points were selected: one at the top outlet of pipeline 2, one at the reboiler outlet of pipeline 3, one each at the inner and outer sides of the lean liquor outlet bend of pipeline 4, and one at the steam inlet of pipeline 5. Table 3 shows the corrosion rates of pipelines 2, 3, 4, and 5 in the regeneration tower, as shown in Table 2. The scouring corrosion rate and chemical corrosion rate of each local area were analyzed.

[0052] Table 3 Corrosion Rates of Pipelines 2, 3, 4, and 5 in the Regeneration Tower

[0053] Location Chemical corrosion rate (mm / year) Erosion rate (mm / year) Total corrosion rate (mm / year) 1 1.97 1.55E-06 1.97 2 0 9.07E-05 9.07E-05 3 0 5.83E-04 5.83E-04 4 0 2.57E-08 2.57E-08 5 0 0 0

[0054] Figure 5 This is a schematic diagram of the reference point for corrosion analysis of the regeneration tower return pipeline. (See attached diagram.) Figure 5 As shown, four corrosion analysis reference points were set on the return port pipeline of pipeline 6. Table 4 is a corrosion rate table for the return port pipeline. As shown in Table 4, different parts of pipeline 6 were selected to analyze the scouring corrosion rate and chemical corrosion rate of each locality.

[0055] Table 4 Corrosion Rate of Pipeline 6

[0056] Location Chemical corrosion rate (mm / year) Erosion rate (mm / year) Total corrosion rate (mm / year) 1 72 2.98E-08 2.98E-08 2 18 0.819 0.819 3 2 3.35E-03 3.35E-03 4 1 1.53E-03 1.53E-03

[0057] 3. Corrosion risk behaviors

[0058] Analysis of corrosion rates at different locations reveals that chemical corrosion has a far greater impact on the walls of the regeneration tower and pipelines than erosion corrosion. Therefore, the corrosion risk is significantly higher in areas where H2S accumulates within the tower, such as near the feed distributor, reflux liquid distributor, and top outlet pipeline. For pipeline 6 (reflux port), the corrosion risk is also substantial due to the presence of H2S (approximately 2%) dissolved in the water.

[0059] Regarding erosion corrosion, the corrosion rate is highly dependent on the velocity at the reference point, the pipe shape, and the liquid volume fraction at that location. For straight pipes, the erosion corrosion rate is very small, almost negligible; for bends, corrosion is more severe on the inside of the bend than on the outside. Furthermore, areas with relatively high flow velocities, such as the connection between the steam inlet and the regeneration tower, the gap between the liquid distributor and the tower wall, and the connection between the tower top and the outlet, are areas where erosion corrosion is more severe. However, for straight pipe sections where only steam flows, erosion corrosion is negligible.

[0060] 4. Optimize process conditions

[0061] Chemical corrosion primarily occurs when hydrogen sulfide ionizes in water and reacts chemically with the steel; gaseous hydrogen sulfide itself is not the main cause. Therefore, reducing the hydrogen sulfide content in the water can decrease the rate of chemical corrosion. To reduce the hydrogen sulfide content, the temperature can be increased, thereby reducing the concentration of dissolved hydrogen sulfide in the water. From this perspective, the process conditions that can be modified are:

[0062] (1) Keep the inlet flow rate of the steam inlet pipeline (pipeline 5) constant, and increase the temperature of the inlet of the steam inlet pipeline (pipeline 5) (from 120℃ to 170℃) to increase the heat input and increase the overall temperature.

[0063] (2) Keep the inlet temperature of the steam inlet pipeline (pipeline 5) constant, and increase the flow rate of the steam inlet pipeline (pipeline 5) (from 1.8 kg / s to 2.5 kg / s) to increase the heat input and increase the overall temperature.

[0064] In the following implementation scheme, the basic operating conditions are: rich liquid inlet flow rate of 75t / hr, inlet temperature of 70 degrees Celsius, and reflux inlet flow rate of 10t / hr.

[0065] The optimization method described in this embodiment is as follows:

[0066] (1) Increasing the steam inlet temperature can reduce the rate of chemical corrosion;

[0067] (2) Changing the water vapor flow rate can significantly improve the chemical corrosion rate;

[0068] (3) The feed inlet is always impacted by the water from the upper return port, and there is always a large amount of H2S in the upper part. Therefore, reducing the flow rate can reduce the chemical corrosion rate; however, the flow field near the feed inlet is relatively complex and is prone to forming local high flow velocity areas. Optimizing and reducing the flow rate can reduce the corrosion rate of the feed inlet.

[0069] Implementation Plan 1: Increase the operating temperature of the steam entering the regeneration tower from the reboiler.

[0070] Keep the inlet flow rate of the steam inlet pipeline (pipeline 5) constant, and increase the temperature of the inlet of the steam inlet pipeline (pipeline 5) (from 120℃ to 170℃) to increase the heat input and raise the overall temperature.

[0071] Since chemical corrosion primarily occurs when hydrogen sulfide ionizes in water and reacts chemically with steel, gaseous hydrogen sulfide itself is not the main cause. Therefore, reducing the hydrogen sulfide content in the water can decrease the rate of chemical corrosion. In this embodiment, increasing the operating temperature of the steam entering the regeneration tower from the reboiler can promote the desorption of hydrogen sulfide, thereby reducing the concentration of dissolved hydrogen sulfide in the water.

[0072] (1) Comparison of velocity field distribution

[0073] Velocity cloud distribution analysis at steam inlet temperatures of 120℃ and 170℃ shows that the steam entering from the reboiler has a relatively high velocity, flows towards the upper part of the tower, and is mainly close to the reboiler inlet side. As the steam diffuses to the surroundings and the steam condenses, the velocity gradually decreases. Increasing the steam temperature reduces the rate of steam condensation, thus reducing the rate of velocity decrease.

[0074] (2) Comparison of temperature field distribution

[0075] Temperature cloud distribution analysis at steam inlet temperatures of 120℃ and 170℃ shows that increasing the steam inlet temperature does increase the temperature at the top of the tower, but the overall temperature does not increase significantly. This is mainly because the enthalpy difference between steam at 170℃ and steam at 120℃ is about 100kJ / kg, while the latent heat of steam to liquid water reaches 2200kJ / kg. Therefore, increasing the steam temperature does not have a significant effect on increasing the overall temperature.

[0076] (3) Comparison of component distribution

[0077] Analysis of the liquid phase volume fraction and gas phase H2S mass fraction at steam inlet temperatures of 120℃ and 170℃ shows that the high concentration of H2S shifts upward, mainly due to the slower rate of water vapor condensing into liquid water (superheated steam first condenses into saturated water vapor, and then into liquid water).

[0078] (4) Corrosion analysis comparison

[0079] Adopted and Figure 2 Eight corrosion analysis reference points with the same basic operating conditions were used. Table 5 compares the corrosion rates at steam inlet temperatures of 120℃ and 170℃. The corrosion rate results are shown in Table 5, indicating a slight overall decrease in the total corrosion rate. A detailed analysis of the influencing factors reveals that the main issue is the slightly increased flow velocity at each point, which accelerates the chemical corrosion rate. However, the slightly decreased liquid water content at each point leads to a slight decrease in the concentration of H2S dissolved in water, thus reducing the chemical corrosion rate.

[0080] Table 5 Comparison of corrosion rates at steam inlet temperatures of 120℃ and 170℃

[0081]

[0082] Implementation Plan 2: Increase the flow rate from the reboiler to the regeneration tower

[0083] In this embodiment, the inlet temperature of the steam inlet pipeline (pipeline 5) is kept constant, and the flow rate of the steam inlet pipeline (pipeline 5) (from the reboiler to the regeneration tower) is increased (from 1.8 kg / s to 2.5 kg / s), thereby increasing the heat input and raising the overall temperature.

[0084] (1) Comparison of velocity field distribution

[0085] Velocity cloud distribution analysis at steam inlet flow rates of 1.8 kg / s and 2.5 kg / s shows that the steam entering from the reboiler has a higher velocity, flows towards the upper part of the tower, and is mainly close to the reboiler inlet side. As the steam diffuses to the surrounding area and the steam condenses, the velocity gradually decreases. Increasing the steam flow rate results in a larger influence range of the high-velocity zone.

[0086] (2) Comparison of temperature field distribution

[0087] Temperature cloud distribution analysis at steam inlet flow rates of 1.8 kg / s and 2.5 kg / s shows that increasing the steam inlet flow rate reduces the low-temperature region at the feed inlet, mainly due to the input of more heat. However, the impact on the upper part is not significant. Considering that the calculation is transient and only lasted for about 3 minutes, it may be due to time constraints and the upper region of the tower has not yet been fully affected.

[0088] (3) Comparison of component distribution

[0089] Analysis of the liquid phase volume fraction and gas phase H2S mass fraction at steam inlet flow rates of 1.8 kg / s and 2.5 kg / s shows that the high concentration of H2S shifts upward, mainly due to the increased steam flow rate.

[0090] (4) Corrosion analysis comparison

[0091] Adopted and Figure 2 Eight corrosion analysis reference points with the same basic operating conditions were used. Table 6 compares the corrosion rates at steam inlet flow rates of 1.8 kg / s and 2.5 kg / s. The corrosion rate results are shown in Table 6. It can be seen from the table that the overall corrosion rate has increased. This is mainly due to the increased flow rate at each reference point, and the increased liquid water content. This is primarily because the increased inlet steam flow rate causes some water vapor to condense in the upper part of the tower, leading to an increase in water content near the upper walls, which in turn increases the dissolved H2S in the water, resulting in a higher chemical corrosion rate.

[0092] Table 6. Comparison of corrosion rates at steam inlet flow rates of 1.8 kg / s and 2.5 kg / s

[0093]

[0094] Those skilled in the art will understand that all or part of the steps of the above embodiments can be implemented by hardware or by a program instructing related hardware. The program can be stored in a computer-readable storage medium, such as a magnetic disk, optical disk, read-only memory (ROM), or random access memory (RAM).

[0095] The above description is only a preferred embodiment of the present invention. It should be noted that those skilled in the art can make several improvements and additions without departing from the principle of the present invention, and these improvements and additions should also be considered within the scope of protection of the present invention.

Claims

1. A method for corrosion control in a regeneration tower, used to mitigate and control corrosion in a regeneration tower within an alcohol amine desulfurization system, characterized in that... Includes the following steps: S1. Multiphase flow simulation of the regeneration tower was performed. Erosion corrosion was analyzed by the distribution of local velocity vectors at the top and reflux inlet of the regeneration tower, velocity vector at the feed inlet, velocity vector near the steam inlet connecting to the reboiler outlet, shear stress near the top outlet, shear stress near the feed inlet, and shear stress near the steam inlet connecting to the reboiler outlet. Chemical corrosion was analyzed by the volume percentage distribution of H2S and liquid water inside the regeneration tower. Flow field parameters at eight corrosion analysis reference points in different parts of the regeneration tower were extracted to calculate chemical corrosion and erosion corrosion. S2. The auxiliary pipelines of the regeneration tower include the feed inlet pipeline, the top outlet pipeline, the reboiler outlet pipeline, the lean liquor outlet pipeline, the steam inlet pipeline, and the reflux inlet pipeline. Multiphase flow software simulation is performed on the auxiliary pipelines of the regeneration tower. The shear stress distribution of the auxiliary pipelines of the regeneration tower is analyzed to detect erosion corrosion. The flow field parameters of 14 reference points for corrosion analysis at different locations of the auxiliary pipelines of the regeneration tower are extracted to calculate chemical corrosion and erosion corrosion. S3. Based on the analysis data from steps S1 and S2, conduct corrosion risk behavior analysis on the regeneration tower and its auxiliary pipelines to confirm that chemical corrosion plays a major role. S4. Based on the analysis results of step S3, the chemical corrosion rate is reduced by decreasing the concentration of hydrogen sulfide in the water, and the process conditions are improved by increasing the temperature to reduce the concentration of hydrogen sulfide dissolved in the water. S5. Apply the improved regeneration tower process conditions from step S4 to the alcohol amine desulfurization system.

2. The corrosion control method for a regeneration tower according to claim 1, characterized in that: The corrosion risk behavior of the regeneration tower and its associated pipelines in step S3 occurs in areas where hydrogen sulfide accumulates, near pipeline bends, and in areas with high flow velocities.

3. The corrosion control method for a regeneration tower according to claim 2, characterized in that: The areas where hydrogen sulfide accumulates include the feed distributor, the reflux liquid distributor, the area near the top outlet pipe, and the reflux pipeline, which pose a risk of chemical corrosion. The inner side of the pipeline bends is subject to more severe erosion corrosion than the outer side. The areas with relatively high flow velocities include the connection between the steam inlet and the regeneration tower, the gap between the liquid distributor and the tower wall, and the connection between the tower top and the outlet, which pose a risk of erosion corrosion.

4. The corrosion control method for a regeneration tower according to claim 3, characterized in that: The improved process conditions in step S4 are to keep the steam flow rate of the steam inlet pipeline constant, increase the steam temperature of the steam inlet pipeline to increase heat input, and thus increase the overall temperature.

5. The corrosion control method for a regeneration tower according to claim 4, characterized in that: The basic operating conditions of the alcohol amine desulfurization regeneration tower are: rich liquid inlet flow rate of 75t / h, inlet temperature of 70℃, and reflux inlet flow rate of 10t / h. The steam temperature in the steam inlet pipeline is increased from 120℃ to 170℃.

6. The corrosion control method for a regeneration tower according to claim 3, characterized in that: The improved process conditions in step S4 are to keep the steam temperature in the steam inlet pipeline constant and increase the steam flow rate in the steam inlet pipeline, thereby increasing the heat input and raising the overall temperature.

7. The corrosion control method for a regeneration tower according to claim 6, characterized in that: The basic operating conditions of the alcohol amine desulfurization regeneration tower are: rich liquid inlet flow rate of 75t / h, inlet temperature of 70℃, and reflux inlet flow rate of 10t / h. The steam flow rate of the steam inlet pipeline is increased from 1.8kg / s to 2.5kg / s.

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