What is the function of the circulating hydrogen desulfurization system in the hydrogenation unit?

The desulfurization system of the hydrogenation unit generally consists of three parts: Circulating hydrogen desulfurization, low fraction gas desulfurization, and fuel gas desulfurization. It is very necessary to set up a desulfurization system. If there is too much hydrogen sulfide in the circulating hydrogen, it will corrode the pipeline equipment, causing rust to accumulate on the catalyst bed and causing an increase in pressure drop. At the same time, from a chemical equilibrium point of view, the presence of hydrogen sulfide in the circulating hydrogen is not conducive to the desulfurization reaction. There is hydrogen sulfide in the low-fractionated gas. Part of this low-fragmented gas is replenished into the system as new hydrogen, which will cause an increase in the concentration of hydrogen sulfide in the circulating hydrogen. If there is hydrogen sulfide in the fuel gas, it will corrode the pipes, form rust, and block the burner. In addition, hydrogen sulfide will burn to generate sulfur dioxide, which will pollute the atmosphere.

Most of the sulfur and nitrogen compounds in the raw materials are converted into H2S and NH3 during the hydrocracking process. H2S and NH3 are partially dissolved in the oil phase during the reaction, and the other part is sometimes discharged outside the device through the tail gas. There is also a part of H2S that reacts with ammonia in the stream to generate (NH4)2S and NH4HS, which are washed and discharged. The existence of H2S has both advantages and disadvantages. Since most non-precious metal catalysts are used in the hydrocracking process, a certain H2S partial pressure must be maintained in the system to prevent the sulfide catalyst from being reduced. Excessive H2S partial pressure has no obvious effect on the hydrodenitrification activity and cracking activity of the sulfide-type hydrocracking catalyst, but it has a significant inhibitory effect on the hydrodesulfurization activity and aromatic saturation capacity of the catalyst. In particular, noble metal catalysts will change to the sulfide state under higher H2S partial pressure, resulting in reduced activity. After the hydrocracking product leaves the cracking bed, the very small amount of olefins present will react with H2S to form mercaptans, which will increase product corrosion. If the sulfur content of the raw material is too high, in addition to forming NH4HS and clogging the system, the corrosion rate of the equipment will also increase. Usually the H2S in the system reaches more than 2%, and desulfurization measures must be taken to remove H2S in the high-pressure system.

To be precise, the desulfurization system of the hydrogenation unit generally consists of 2 parts: Cyclic hydrogen desulfurization (high-pressure desulfurization), gas desulfurization (low-pressure desulfurization) Cyclic hydrogen desulfurization mainly increases the concentration of circulating hydrogen and reuses the hydrogen after reaction. Circulating hydrogen comes from high-fractionated gas. The less hydrogen sulfide in circulating hydrogen, the better. The hydrogenation catalyst is in a sulfurized state. To avoid being reduced during the reaction, it needs to be carried out in a certain hydrogen sulfide atmosphere. Generally, circulating hydrogen has a secondary line for desulfurization, which is used to adjust the circulating hydrogen sulfide content. Generally, the circulating hydrogen sulfur content is controlled to be less than 1000PPM. Gas is generally used as fuel and hydrogen production raw materials, which all require desulfurization. This part comes from low fraction, stripping tower and splitter tower. The cleaner the desulfurization, the better.

The desulfurization system of our installation does not desulfurize the fuel gas! Cyclic hydrogen desulfurization mainly removes sulfur sulfides, mainly hydrogen sulfide, which has a strong corrosive effect on equipment! Regarding sulfur corrosion, please refer to the following: Characteristics of sulfur corrosion Sulfur corrosion runs through the entire refining process. There is no precise correspondence between the total sulfur content in crude oil and its corrosiveness, which mainly depends on the type, content and stability of sulfur compounds. If the inactive sulfur in crude oil is easily converted into active sulfur, even if the sulfur content is very low, it will cause serious corrosion to the equipment. This causes sulfur corrosion to occur in various parts of the refinery unit. 　　During crude oil processing, sulfur corrosion does not exist in isolation. Sulfur interacts with inorganic salts, naphthenic acids, nitrogen compounds, water, hydrogen, ammonia and other corrosive media to form a variety of complex corrosive environments. 　　Considering the corrosive environment, sulfur corrosion can be divided into high-temperature (greater than 240°C) chemical corrosion, low-temperature hydrogen sulfide electrochemical corrosion, and two more special corrosions - sulfuric acid dew point corrosion and polythionic acid corrosion. ； Considering the corrosion form, sulfur corrosion can be divided into uniform corrosion, pitting corrosion, crevice corrosion, stress corrosion cracking (SCC), hydrogen bubbling (HB) caused by wet hydrogen sulfide, hydrogen-induced cracking (HIC), sulfur-containing compound stress corrosion cracking (SSCC) and stress-oriented hydrogen-induced cracking (SOHIC). 　　The H2S present in crude oil and the H2S generated by the gradual decomposition of organic sulfur-containing compounds under different conditions form a corrosive environment together with corrosive media (such as HCl, NH3, etc.) formed during crude oil processing and artificially added corrosive (or corrosive) media (such as ethanolamine, furfural, water, etc.), causing severe corrosion in low-temperature parts of the device (especially gas-liquid phase change parts). A typical corrosive environment is HCl+H2S+H2O at the top of the normal and vacuum tower of the normal and vacuum distillation unit. ； HCN+H2S+H2O type corrosive environment at the top of the fractionation tower of the catalytic cracking unit ； H2S＋NH3＋H2＋H2O type corrosive environment of effluent air cooler of hydrocracking and hydrorefining units ； RNH2 (ethanolamine) + CO2 + H2S + H2O type corrosive environment of dry gas desulfurization equipment regeneration tower and gas absorption tower. 　The HCl+H2S+H2O type corrosive environment mainly exists in the top circulation system of the atmospheric and vacuum distillation unit and in parts where the temperature is lower than 150°C, such as the tower body, trays or packing at the top of the atmospheric tower, primary distillation tower, vacuum tower, and top condensation cooling system. Generally, the gas phase part has mild corrosion, the liquid phase part has severe corrosion, and the gas-liquid phase change part, that is, the dew point part, is the most serious. HCN+H2S+H2O type corrosive environment. The sulfur-containing compounds in crude oil form H2S under the reaction conditions of catalytic cracking. At the same time, some nitrogen compounds also exist in the cracked products in a certain proportion, of which 1% to 2% of the nitrogen compounds exist in the form of HCN, thus forming an HCN+H2S+H2O corrosive environment in the absorption and desorption system of the catalytic cracking unit. The temperature of this part is 40~50℃, and the pressure is 1.6 MPa. The presence of HCN promotes the corrosion of H2S+H2O. 　　Cyanide plays two roles in alkaline H2S+H2O solution: ①Dissolve the protective film of iron sulfide, accelerate the corrosion of hydrogen sulfide, and create a metal surface that is conducive to the penetration of hydrogen into the steel. ； ②Cyanide can remove corrosion inhibitors from solutions. 　　In the absorption and desorption system, as the CN- concentration increases, the corrosiveness also increases. When the total nitrogen content in the catalytic cracking feedstock is greater than 0.1%, it will cause serious corrosion of the equipment. When the CN- concentration is greater than 500 mg/L, corrosion is obviously promoted. The following process anti-corrosion measures can be taken to deal with this kind of corrosion:: ①Wash with water to remove cyanide ； ②Inject polysulfide corrosion inhibitor to eliminate cyanide. 　　Material anti-corrosion measures can also be used: The cylinder body is made of carbon steel (killed steel) + 3mm 0Cr13Al steel composite plate or 0Cr13 steel. It can also be made of chromium-molybdenum steel (12Cr2AlMoV). It is welded with 317 electrodes and heat treated at 750°C after welding. The hardness of the weld and heat-affected zone should be less than HB 200. The filler can be 0Cr13 steel or aluminized carbon steel. However, in the environment of HCN+H2S+H2O, when stainless steel electrodes are used to weld carbon steel or chromium-molybdenum steel, hydrogen sulfide stress corrosion cracking is very easy to occur, and attention should be paid to it. RNH2+CO2+H2S+H2O type corrosive environment The corrosion parts are in the bottom system of the regeneration tower and the rich liquid pipeline system of dry gas and liquefied petroleum gas desulfurization (temperature is higher than 90°C, pressure is about 0.2 MPa). 　　In alkaline media (pH value is not less than 8), the corrosion form is stress corrosion cracking and uniform thinning caused by CO2 and amines. Uniform corrosion is mainly caused by CO2, while stress corrosion cracking is caused by amines, CO2 and H2S and the stress on the equipment. 　　Carbon steel equipment and pipelines with operating temperatures above 90°C should be subjected to post-weld stress relief heat treatment to prevent stress corrosion cracking caused by carbonate under alkaline conditions. In S+H2S+RSH+RCOOH (naphthenic acid) type corrosive environment, for crude oil with an acid value exceeding 0.5 mgKOH/g, no matter how high the sulfur content is, the anti-corrosion measures should also be considered as acid-containing crude oil. Naphthenic acid can form soluble corrosion products. The corrosion form is corrosion pits and grooves with sharp edges. In the high temperature area, there are two corrosion peaks (at 270~280℃ and 350~400℃) as the temperature increases. The flow rate of the logistics has a greater impact on corrosion. The corrosive parts of naphthenic acid are located in places with high flow rates. As the flow rate increases, the corrosion rate also increases. The corrosion products of hydrogen sulfide are insoluble and mostly cause uniform corrosion, which worsens as the temperature increases. The corrosive effects of the two are carried out at the same time. If the sulfur content is lower than a certain critical value, the corrosion will be aggravated. That is to say, naphthenic acid destroys the hydrogen sulfide corrosion product and generates oil-soluble iron naphthenate and H2S, allowing the corrosion to continue. If the sulfur content is higher than the critical value, H2S forms a stable iron sulfide protective film on the metal surface, which slows down the corrosion effect of naphthenic acid. In other words, low-sulfur and high-acid corrosion is more serious than high-sulfur and high-acid corrosion. The corrosion conditions of S+H2S+RSH+RCOOH type corrosion parts are basically the same as those of S+H2S+RSH type corrosion parts. However, in refineries that process high-acid value crude oil, serious corrosion parts are concentrated in the pressure reduction furnace, the pressure reduction oil transfer line and the lower part of the pressure reduction tower feed section. 　　For crude oil with higher acid value and strong corrosiveness, high-temperature corrosion inhibitors can be added from the process. ； Steels such as 1Cr18Ni10Ti or 316L can be used in corroded areas. ； In terms of design, the diameter of the oil transfer line can be increased to reduce the flow rate. ； During construction, the welds on the inner walls of pipelines and equipment should be smoothed to prevent eddy currents. 　H2+H2S type corrosive environment, when the H2S volume concentration is below 1%, the corrosion rate increases rapidly as the H2S concentration increases. When it exceeds 1%, the corrosion rate basically does not change. 　　In the range of 315 to 480°C, the corrosion rate increases sharply as the temperature increases. For every 55°C increase in temperature, the corrosion rate approximately triples. 　　The corrosion rate gradually decreases with time. The corrosion rate over 500 h is only 1/3 to 1/11 of the corrosion rate in a short time. 　　Pressure has no effect on corrosion rate. But in pure high-temperature hydrogen, pressure has a great influence on hydrogen corrosion. 　　In high-temperature H2S+H2 type corrosion environment, the main factors affecting the corrosion rate are temperature and H2S concentration. Currently, engineering design determines materials based on corrosion rate estimates based on ASCouper and JWGormon curves. Generally speaking, the corrosion rate of 18-8Ti austenitic stainless steel is acceptable when the design temperature is not greater than 450°C.