How to control the hydrogen sulfide content in dry gas?

Methods for controlling hydrogen sulfide in dry gas: The first method is to control the sulfur content in the raw materials, which provides control at the source; the second method is to carry out control during the production process by adding sulfur transfer agents, thereby transferring the sulfur from the oil and gas to the flue gases.

The hydrogen sulfide generated during the reaction process, aside from a small amount that is entrained into the regenerator, should in principle all be concentrated in the dry gas. To reduce the hydrogen sulfide content in dry gas, it is necessary to reduce the sulfur content in the catalytic feedstock. Additionally, the sulfur transfer agents that I am aware of are used to reduce the emission of sulfides in catalytic flue gases; they transfer the sulfur from coke into the reaction gas in the form of hydrogen sulfide, rather than in the opposite direction as mentioned above!

The control of sulfur content mainly relies on control at the source, with reducing it in crude oil being the most important approach. Furthermore, the dry gas from the entire plant can be treated in a dry gas desulfurization unit to control its sulfur content; however, the sulfur content in the dry gas obtained through absorption and stabilization in the coking process is basically uncontrollable, and the effect of water injection is minimal.

There seem to be some doubts regarding the poster’s statement. Hydrogen sulfide is a way in which sulfur is transferred, and it is generally preferred by factories over SOX. Typically, it is not controlled. Of course, if its concentration during operation exceeds the limits allowed by the design of the equipment systems, it can cause corrosion to the pipes at the top of the tower as well as to the heat exchange equipment. To prevent such corrosion, corrosion inhibitors can be injected into the pipes at the top of the tower, or the sulfur content in the raw materials can be controlled.

1. Control the sulfur content of raw materials. 2. Vulcanization transfer agent. 3. It is possible to appropriately control the amount of gas used for analysis and improve the absorption efficiency.

I think it’s difficult for us to control the sulfur content in the raw materials; the key is dry gas desulfurization. By focusing on desulfurization, we can reduce corrosion in the dry gas pipelines

The crude oil used in processing is becoming increasingly heavy, and an increase in the S and N contents is inevitable; the goal can be achieved by converting it into a form with lower hazard. If possible, carry out pre-hydrogenation first. Nowadays, most are vulcanization converters, metal passivators, and the like. Alkali (ammonia water) is added to the top of the distillation column to reduce the S and N content in the product. The absorption system controls the S and N contents of stable gasoline and liquefied gas.

First, we need to determine whether the crude oil being processed is high-sulfur or low-sulfur; this is determined by the properties of the raw material. Our control measures mainly involve ensuring the proper operation of the dry gas desulfurization system, as well as regulating the amounts of rich gas and lean liquid that are recycled. Additionally, it’s important to consider the quality of the lean ammonia solution itself, as well as whether the components in the rich gas could cause foaming in the ammonia solution, thereby reducing its ability to absorb hydrogen sulfide.

It mainly involves control at the source, as well as installing dry gas desulfurization units

I believe that, from the perspective of the operation of reaction, fractionation, and absorption systems, hydrogen sulfide in dry gas is almost uncontrollable – if there is less of it in the dry gas, there will be more in the gasoline. Therefore, the best approach is to install dry gas desulfurization facilities as a backup, or to hydrogenate the catalyst feedstock first.

Currently, many refineries along the coast process high-sulfur crude oil from the Middle East, which inevitably results in the release of H2S. Under typical catalytic cracking conditions and levels of conversion, the distribution of sulfur compounds from the feedstock oil in the catalytic cracking products is as follows: 45–55% of the sulfur in the feedstock is converted into H2S and ends up in the gaseous products, 35–45% of the sulfur goes into the liquid products, and about 5–10% of the sulfur ends up in the coke. Sulfur deposited on the coke generates SOX in the regenerator (generally a mixture with >90% SO2 and <10% SO3). Catalytic cracking sulfur transfer promoters capture SOX in the FCC regenerator and release it as H2S in the reactor and stripping section. Therefore, it is better for sulfur to be released in the form of H2S, rather than being emitted into the atmosphere as SOx.

Catalytic dry gas does not have its hydrogen sulfide content controlled, while catalytic cracking sulfur transfer agents transfer the sulfur in coke into the reaction gas stream in the form of hydrogen sulfide, thereby reducing the emissions of sulfides in the catalytic flue gas. The function of the SOx transfer catalyst is for metal oxides to capture SOx during the regeneration process, preventing it from entering the flue gas; the sulfur that is captured is then reduced to H2S in a reaction, and the metal oxides return to their original state at the same time. The H2S generated in the reactor enters the distillation system together with the reaction products, allowing for sulfur recovery using conventional methods. It is a special type of catalyst in which a metal oxide that can reduce SOx is added to the catalyst, without affecting the high activity of the molecular sieve catalyst. When in use, the device must operate in a fully regenerative mode, with a high oxygen content in the flue gas – typically 2–3% – and essentially no CO present. The passivator in the device should be in a certain proportion to the cracking catalyst.