Hydrogen Sulfide Removal from Flare Gas

Round 1

Reviewer 1 Report

Comments and Suggestions for Authors

Need to discuss the need for amine regeneration otherwise the process just transfers sulfur from air to water.

Need to discuss the effect of pool height on the pressure drop of the flare gas system and the implications on the costs.

Author Response

1. Need to discuss the need for amine regeneration otherwise the process just transfers sulfur from air to water.

Correct. The following was added to “Results and Discussion”:

 It should be noted that a regeneration step is required to remove hydrogen sulfide from the amine solution. This can be achieved by increasing the temperature of the amine solution to 100–120°C using a multi-stage tower (17). Nevertheless, most refineries have an amine regeneration tower, so the stream can be easily regenerated without requiring additional capital investment for the tower.

 

2. Need to discuss the effect of pool height on the pressure drop of the flare gas system and the implications on the costs

The flare gas is at atmospheric pressure, so there will be a further pressure drop.

Reviewer 2 Report

Comments and Suggestions for Authors

Manuscript ID: gases-4272742

Title: Hydrogen Sulfide Removal from Flare Gas

 

The manuscript investigates hydrogen sulfide removal from flare gas by replacing seal drum water with 45 wt% MDEA solution via UniSIM® simulation.  Although the topic aligns with the scope of Gases, the work in its current form lacks sufficient scientific rigor, simulation validation, process mechanism analysis, and engineering practicality to meet the publication standard of the journal.

1. The simulation model is oversimplified with only a single‑stage rate‑based absorber, failing to reflect the real two‑phase flow and mass transfer behavior of gas bubbling through the seal drum liquid pool. Establish a two‑phase flow and mass transfer model matching the actual seal drum structure; consider bubble size, residence time, and interfacial area for more realistic H₂S absorption.
2. No experimental data or industrial operating data are used to validate the simulation results; the conclusion solely relies on unconfirmed computational output. Introduce laboratory batch absorption data or industrial plant data to verify the reliability of UniSIM® calculation; provide error analysis and model confidence evaluation.
3. Key operating parameters (e.g., MDEA regeneration, corrosion control, solvent loss) for industrial implementation are completely ignored, weakening engineering applicability. Add discussion on MDEA solvent regeneration, rich amine heat stability, corrosion inhibition measures, and operational cost balance to enhance practical value.
4. The discussion of results is superficial, without in‑depth analysis of mass transfer kinetics or the interaction between H₂S‑MDEA under flare gas conditions. Analyze the mass transfer kinetic process of H₂S in MDEA solution; clarify the influence mechanism of loading ratio and liquid pool height on removal efficiency.
5. The manuscript lacks comparison with mature H₂S removal technologies for flare gas, making the technical advantages and application boundaries unclear. Compare with other flare gas sweetening methods (e.g., low‑temperature adsorption, membrane separation); highlight the novelty and applicable scenarios of the amine seal drum scheme.

Author Response

1. The simulation model is oversimplified with only a single‑stage rate‑based absorber, failing to reflect the real two‑phase flow and mass transfer behavior of gas bubbling through the seal drum liquid pool. Establish a two‑phase flow and mass transfer model matching the actual seal drum structure; consider bubble size, residence time, and interfacial area for more realistic H2S absorption.

Correct. The model is simple but this is the only available tool at our facility. Using experimental data will support the model but we also lack the experimental setup. The simulation results gives the maximum hydrogen sulfide removal efficiency as it does not take into consideration the above parameters. The following statement was added in “Results and Discussion”:

It is also worth noting that the above results for hydrogen sulfide removal efficiency remain theoretical because many parameters were not considered, including bubble size, residence time, and interfacial area. Moreover, the presence of light hydrocarbons may form a thin film on the MDEA solution, thereby disrupting the gas-liquid interface. Experimental data is necessary to validate the findings.

 

2. No experimental data or industrial operating data are used to validate the simulation results; the conclusion solely relies on unconfirmed computational output. Introduce laboratory batch absorption data or industrial plant data to verify the reliability of UniSIM® calculation; provide error analysis and model confidence evaluation.

Correct. Experimental data is needed to validate the model; however, we lack the equipment, and to the best of my knowledge, there is no published data on the simulation of the amine pool using UniSIM® rate-based absorber. Therefore, the results are theoretical and this will open the opportunity for further studies for validation.

 

3. Key operating parameters (e.g., MDEA regeneration, corrosion control, solvent loss) for industrial implementation are completely ignored, weakening engineering applicability. Add discussion on MDEA solvent regeneration, rich amine heat stability, corrosion inhibition measures, and operational cost balance to enhance practical value.

The following was added to the “Results and Discussion”:

It should be noted that a regeneration step is required to remove hydrogen sulfide from the amine solution. This can be achieved by increasing the temperature of the amine solution to 100–120°C using a multi-stage tower (17). Nevertheless, most refineries have an amine regeneration tower, so the stream can be easily regenerated without requiring additional capital investment for the tower.

It is also worth noting that the above results for hydrogen sulfide removal efficiency remain theoretical because many parameters were not considered, including bubble size, residence time, and interfacial area. Moreover, the presence of light hydrocarbons may form a thin film on the MDEA solution, thereby disrupting the gas-liquid interface. Experimental data is necessary to validate the findings. Furthermore, the rich amine solution containing hydrogen sulfide may cause corrosion to carbon steel. Actually, the amine solution containing hydrogen sulfide only will form a protective film of iron (II) sulfide (FeS). However, due to high gas velocities, the layer can be destroyed, exposing the bare metal (18). Therefore implementation of corrosion mitigation measures may be necessary.  

           

4. The discussion of results is superficial, without in‑depth analysis of mass transfer kinetics or the interaction between H2S‑MDEA under flare gas conditions. Analyze the mass transfer kinetic process of H2S in MDEA solution; clarify the influence mechanism of loading ratio and liquid pool height on removal efficiency.

The following was added to “Methodology”:

The absorption of hydrogen sulfide into the amine solution is described by the following fast reaction (10):

R_2 R_1 N+H_2 S⟶R_2 R_1 NH^++HS^-

The reaction is also controlled by the mass transfer resistance where hydrogen sulfide molecule must diffuse through the gas-liquid interface to reach the amine (11). To take into account the previous limitation, the liquid seal drum was modeled in UniSIM® using a rate-based absorber with a one stage of separation.

The following was added to “Results and Discussion”:

It was expected that increasing the amine flow rate (decreasing the molar loading) would improve the removal efficiency, as there would be more MDEA molecules available to remove additional hydrogen sulfide.

The improvement in removal efficiency with pool height can be attributed to an extended residence time, as the gas bubble takes a longer path to reach the surface. Also, the hydrostatic pressure for higher pools is expected to increase due to the added force exerted by the amine. This will increase the partial pressure of hydrogen sulfide for better removal.

 

5. The manuscript lacks comparison with mature H2S removal technologies for flare gas, making the technical advantages and application boundaries unclear. Compare with other flare gas sweetening methods (e.g., low‑temperature adsorption, membrane separation); highlight the novelty and applicable scenarios of the amine seal drum scheme.

The following was added to “Introduction”:

Furthermore, technologies such as membranes and pressure swing adsorption will require capital investment, operational cost, and additional equipment or space for installation and integration.

This innovative solution is easy to implement, as no additional equipment or space is required. Furthermore, the amine can be regenerated using the available regeneration unit in most refineries, thereby eliminating the need for capital investment.

Reviewer 3 Report

Comments and Suggestions for Authors

The term “hydrogen sulfide-to-amine molar loading” in the final sentence of the Abstract should be clarified by specifying the flow rates of both streams to make the statement more explicit.

Regarding the H₂S stripping vessel shown in Figure 1, two additional processing factors should be considered: (1) whether the heat generated during neutralization affects the efficiency of H₂S removal, and (2) how to maintain sufficient contact area between the flare gas and the amine solution to achieve the desired removal performance. In particular, how does the pool height influence this second aspect?

Furthermore, how does the “salting-in effect”, namely, the dissolution of light hydrocarbons into the aqueous MDEA solution, impact H₂S removal efficiency? This is a common concern and should be addressed.

Author Response

1. The term “hydrogen sulfide-to-amine molar loading” in the final sentence of the Abstract should be clarified by specifying the flow rates of both streams to make the statement more explicit.

The following was added to “Abstract”:

Removal efficiency of up to 72.5% was achieved with a hydrogen sulfide-to-amine molar loading of 0.2 (4:20 ratio).

 

2. Regarding the H₂S stripping vessel shown in Figure 1, two additional processing factors should be considered: (1) whether the heat generated during neutralization affects the efficiency of H₂S removal, and (2) how to maintain sufficient contact area between the flare gas and the amine solution to achieve the desired removal performance. In particular, how does the pool height influence this second aspect?

Yes, the exothermic reaction will generate heat, and according to the simulation, the temperature will increase by only 2 °C. However, the amine liquid in the pool is continuously pumped, so the effect can be neglected.

Increasing the pool height will extend the residence time for the gas inside the pool and this increases the removal efficiency. The contact area is maintained by the continuous pumping of amine liquid. The following was added to “Results and Discussion”:

The improvement in removal efficiency with pool height can be attributed to an extended residence time, as the gas bubble takes a longer path to reach the surface. Also, the hydrostatic pressure for higher pools is expected to increase due to the added force exerted by the amine. This will increase the partial pressure of hydrogen sulfide for better removal.

 

3. Furthermore, how does the “salting-in effect”, namely, the dissolution of light hydrocarbons into the aqueous MDEA solution, impact H₂S removal efficiency? This is a common concern and should be addressed.

Indeed. The light hydrocarbons may condensate and form a film over the MDEA solution, thereby reducing the efficiency. Experimental work is needed to validate the results, but we lack the setup.

The following was added to “Results and Discussion”:

It is also worth noting that the above results for hydrogen sulfide removal efficiency remain theoretical because many parameters were not considered, including bubble size, residence time, and interfacial area. Moreover, the presence of light hydrocarbons may form a thin film on the MDEA solution, thereby disrupting the gas-liquid interface. Experimental data is necessary to validate the findings.

Round 2

Reviewer 2 Report

Comments and Suggestions for Authors

Accept in current manuscript of gases-4272742.