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Sulfur Corrosion and Protection of Equipment in Petroleum Processing Units Summary of Sulfur Corrosion and Protection of Equipment in Petroleum Processing Units: Various corrosion types such as low-temperature light oil corrosion, wet hydrogen sulfide corrosion, and high-temperature sulfur corrosion that are common and serious in the processing of sulfur-containing crude oil, the formation process of corrosive media, corrosion conditions, corrosion mechanisms, and the process and material anti-corrosion measures taken are discussed. At the same time, the two special corrosion types of sulfuric acid dew point corrosion and polythionic acid stress corrosion cracking are also introduced in terms of corrosion mechanisms and anti-corrosion measures. Subject words: Sulfur, chlorine, hydronaphthenic acid corrosion and corrosion control during the oil refining process. From the perspective of corrosion and protection of refinery equipment, sulfur in crude oil is generally divided into active sulfur and inactive sulfur. Elemental sulfur, H2S and low molecular mercaptans can directly interact with metals and cause corrosion of equipment, so they are collectively called active sulfur. The remaining sulfur-containing compounds that cannot interact directly with metals are collectively called inactive sulfur. Inactive sulfur can be partially decomposed into active sulfur under the action of high temperature, high pressure and catalyst. Some sulfur-containing compounds begin to decompose at temperatures of 120°C. Sulfur compounds in crude oil interact with other corrosive media such as oxides, chlorides, nitrogen compounds, cyanides, naphthenic acids, and hydrogen to form a variety of sulfur-containing corrosive environments. The content and form of sulfur in different fractions of crude oil vary, but they all increase with the increase of boiling point and are enriched in residual oil. 1 Characteristics of sulfur corrosion Sulfur corrosion occurs throughout the entire oil 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. Therefore, sulfur corrosion involves many devices, diverse corrosion environments, and complex transformation relationships of sulfur-containing compounds, which brings many difficulties to the kinetics and thermodynamics research of sulfur corrosion, the formulation of anti-corrosion measures, and the selection of equipment for processing sulfur-containing crude oil. 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). 2 Corrosion and protection of low-temperature light oil parts 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 serious corrosion in the low-temperature parts of the device (especially the gas-liquid phase change part). 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. 2.1 HCl+H2S+H2O type corrosive environment This 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. 2.1.1 Corrosion conditions The boiling points of HCl and H2S are very low (standard boiling points are -84.95°C and -60.2°C respectively). Therefore, HCl and H2S formed during crude oil processing are accumulated at the top of the normal pressure tower along with oil and gas. When encountering steam condensation water below 110°C, a strongly acidic corrosive medium with a pH value of 1 to 1.3 will be formed, causing corrosion to the equipment. For carbon steel, it is uniform corrosion, for 0Cr13 steel, it is pitting corrosion, and for austenitic stainless steel, it is chloride stress corrosion cracking. Some data show that under the condition of no process anti-corrosion, the corrosion rate of carbon steel can reach 2 mm/a, and the corrosion rate of the inlet part of the carbon steel shell-and-tube cooler tube bundle in the atmospheric tower is as high as 6.0~14.5 mm/a. The corrosion form is uniform corrosion. ； The Cr13 float valve at the top of the atmospheric tower showed pitting corrosion with a corrosion rate of 1.8 to 2.0 mm/a. A refinery once used Cr18-Ni8 steel as the top lining of the atmospheric pressure tower. After 5 years, large-area chloride stress corrosion cracking occurred. A refinery used 1Cr18Ni9Ti steel as the tube bundle of the air cooler at the top of the atmospheric tower. After 90 days of use, all the tubes and the tube sheet expansion joint transition zone suffered brittle fracture. After adopting technological anti-corrosion, the corrosion rate of the tube bundle of the air cooler at the top of the atmospheric tower is 0.1~0.3 mm/a, and the corrosion rate of the carbon steel tube bundle of the shell-and-tube cooler is 0.8 mm/a. The tube bundle of the shell-and-tube cooler at the top of the atmospheric tower of a refinery uses 1Cr18Ni9Ti steel. After strengthening process anti-corrosion measures, stress corrosion cracking occurred after 5 years of use. 2.1.2 Process anti-corrosion measures As for the corrosion control technology at the top of the crude oil distillation tower, in addition to doing a good job in deep electrical desalination, it is still the "three injections", that is, water injection, corrosion inhibitor injection and neutralizer injection in the system. In the past, ammonia injection was the main cause of corrosion under ammonium salt scale, accounting for 80% of equipment damage, and its corrosion rate was 20 times that of uniform corrosion. Iron sulfide accounts for 70% to 80% of the sediment under the scale, and the rest is coke and heavy hydrocarbons. Iron sulfide is the least soluble salt in the crude oil distillation overhead system, and its solubility depends on pH and sulfur compound concentration. The corrosion mechanism is due to the potential difference formed between clean or micro-covered areas. But conventional wisdom holds that neutralizing salt causes many of the problems at the top of the tower. The hydrolysis of these salts brings the pH value to 4. Excessive use of neutralizers to increase the pH value will cause the deposition of iron sulfide and eventually lead to the destruction of the top of the tower. Some research results show that the optimal pH value range of the atmospheric tower overhead system is lower than the range recommended in the past (5.5 to 7.0), as shown in Table 1. Table 1 Recommended optimal pH value for atmospheric pressure tower overhead system H2S/mg.L-1 pH value 20/50 5.1～5.6/4.9～5.4 100/200 4.8～5.3/4.6～5.1 Due to the high concentration of chloride ions in the corrosive environment at the top of the atmospheric and vacuum distillation unit, coupled with the influence of various stresses, it is easy to cause chloride ion stress corrosion cracking, so the material of the low-temperature light oil part is difficult to upgrade. Most domestic refineries still use carbon steel for their atmospheric and vacuum tower top condensation and cooling systems. Therefore, the traditional anti-corrosion method with "one stripping and four injection" as the core content is extremely important. Considering the impact of sodium ions on the processing technology of the secondary processing unit, the refinery has changed "one stripping and four injections" to "one stripping and three injections". “"One desalination" is the deep desalination of crude oil. On the one hand, it is the deep removal of sodium salt. Since sodium ions can easily cause poisoning of hydrodesulfurization catalysts, there are strict requirements on the sodium ion content in raw oil. For example, a refinery processing imported sour crude oil requires that the sodium ion content in the crude oil be less than 1 mg/L after deep desalination. On the other hand, in order to reduce the corrosion caused by HCl at the top of the tower, the electric desalination device is required to not only remove sodium ions, but also effectively remove calcium, magnesium, and iron ions. Minimize the generation of HCl in the tower top condensation cooling system. At present, most of the "three tops" of atmospheric and vacuum distillation units in refineries use ammonia injection, but the neutralization effect is poor and excessive injection is required. In this way, the generated NH4Cl is easy to scale, which can easily cause clogging on the one hand, and corrosion under the scale on the other hand. After processing imported sour crude oil, the H2S content in the tower top condensation cooling system increases, and the problems of scaling and corrosion become more prominent. Some refineries use the injection of organic amines and achieve good neutralization effects, but organic amines are expensive. Therefore, some refineries use the method of mixing ammonia and organic amines in a certain proportion, and the effect is also better. Some refineries inject water-soluble corrosion inhibitors such as 7019 into the "three tops", but their protection area is small, membrane integrity is poor, and membrane repair is difficult. Some refineries use oil-soluble corrosion inhibitors and select appropriate injection locations to achieve good corrosion inhibition effects. The newly developed neutralizing corrosion inhibitor in China has both neutralizing and corrosion-inhibiting effects. It is multi-purpose and has good application effect. The "three agents" (emulsifier, corrosion inhibitor and neutralizer) of domestic refinery atmospheric and vacuum distillation units are generally injected manually, which is difficult to achieve timing and quantification. The newly developed "three-agent" automatic injection system can automatically adjust the injection amount of chemicals according to the material flow. It has been tried out in some refineries and has achieved good results. However, compared with intelligent injection systems such as automatic signal acquisition and feedback, there is still a big gap. Currently, the Equipment Research Institute of Luoyang Petrochemical Engineering Company is conducting research in this area and has made progress. 2.1.3 Material anti-corrosion The selection of corrosion-resistant metal materials at the top of the crude oil distillation tower is a key to the selection of process equipment. Developed in Europe and America * * , the material of this part has always been Monel alloy (UNS No.4400) before the 1990s. The equipment shell material is carbon steel + Monel alloy composite steel, and all internal parts are Monel alloy. In the early 1990s, it was found that this alloy was sensitive to wet hydrogen sulfide stress corrosion cracking, so its use above 120°C was not recommended. The original design of the atmospheric and vacuum distillation unit of a foreign refinery was: The tower body is made of carbon steel + Monel alloy, and the internal parts are still made of Monel alloy. However, in the detailed design, the corrosion-resistant metal material shell was changed to carbon steel + Hastelloy C-4 alloy, and the internal parts were changed to Hastelloy C-4 alloy (UNS No. 6455). In Japan, alloys such as SUS 405 (0Cr13Al) and Monel are used as corrosion-resistant materials in this part. In the selection of materials for the overhead condensation and cooling system of atmospheric and vacuum distillation units, domestic refineries continued to try to use austenitic stainless steel and aluminum-magnesium alloy in the overhead condensation and cooling system in the 1980s and 1990s. As a result, the equipment quickly corroded, perforated, and cracked. Some refineries have also tried to use titanium alloy heat exchangers, but due to their high price, it is difficult to promote them. Regarding the tower top condensation cooling system, the current domestic consensus is that the equipment should be made of carbon steel, the construction management of coatings should be strengthened, and the "one removal and three injection" should be strictly controlled, which can basically control the corrosion of the tower top condensation cooling system. 2.2 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. 2.3 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. 3 Corrosion and protection of wet hydrogen sulfide Wet hydrogen sulfide corrosion environment, that is, H2S + H2O type corrosion environment, refers to the corrosive environment generated in pressure vessels and pipelines when water or aqueous streams coexist with H2S below the dew point. Wet hydrogen sulfide environment widely exists in the light oil parts of secondary processing units of refineries, such as the absorption stabilization part of the fluid catalytic cracking unit, the dry gas and liquefied petroleum gas desulfurization part of the product refining unit, the stripper of the acid water stripping unit, the cooler, high-pressure separator and downstream equipment of the hydrocracking unit and hydrodesulfurization unit. 3.1 Corrosion mechanism In the H2S+H2O corrosive environment, two types of corrosion occur on carbon steel equipment: Uniform corrosion and wet hydrogen sulfide stress corrosion cracking. Forms of cracking include hydrogen bubbling, hydrogen-induced cracking, sulfide stress corrosion cracking and stress-directed hydrogen-induced cracking. Hydrogen bubbling is caused by the hydrogen atoms precipitated during the corrosion process of sulfur-containing compounds penetrating into the steel, gathering and forming molecules at cracks, inclusions, defects, etc. in the steel, thereby forming a large expansion force. As the number of hydrogen molecules increases, the pressure on the lattice interface continues to increase, eventually causing the interface to crack and forming hydrogen bubbling, which is distributed parallel to the surface of the steel plate. Hydrogen bubbling does not require external stress to occur. Hydrogen-induced cracking is due to the occurrence of hydrogen bubbling areas inside the steel. When the pressure of hydrogen continues to increase, small bubbling cracks tend to connect with each other to form hydrogen-induced cracking with ladder-like characteristics. The banded distribution of MnS inclusions in steel increases susceptibility to hydrogen-induced cracking. Hydrogen-induced cracking also occurs without external stress. Sulfide stress corrosion cracking is when hydrogen atoms generated in a wet hydrogen sulfide environment penetrate into the interior of steel and dissolve in the crystal lattice, causing hydrogen embrittlement and cracking under the action of external stress or residual stress. It usually occurs in high-hardness areas such as weld beads and heat-affected zones. Stress-directed hydrogen-induced cracking is the formation of rows of small cracks that develop in the direction perpendicular to the stress due to the accumulation of hydrogen at inclusions and defects under the guidance of stress. It usually occurs in the heat-affected zone and high stress concentration zone of welded joints, such as nozzles, geometric mutations, crack-like defects or stress corrosion cracking. 3.2 Corrosion status Domestic corrosion investigation reports indicate that the uniform corrosion of carbon steel equipment by wet hydrogen sulfide intensifies as the temperature increases. The corrosion rate is the highest at 80°C and the lowest at 110~120°C. In addition, in the first few days of construction, the corrosion rate can reach more than 10 mm/a, and decreases rapidly as the operation time of the device increases. After 1500-2000 h, the corrosion rate tends to 0.3 mm/a. In 1984, the ethanolamine absorption tower of the Raymond III refinery of the U.S. company Unocal exploded and caused a fire, which was caused by hydrogen sulfide stress corrosion cracking. In 1995, a wet hydrogen sulfide stress corrosion cracking accident also occurred in an ammonia settling tank in a gas refining unit of a domestic refinery. The upper limit concentration of wet hydrogen sulfide that will not cause cracking of pressure vessels has not yet been established, but the empirical value in industry is 50 mg/L. Exxon divides pressure vessels in wet hydrogen sulfide corrosion environments into two categories, namely H2S concentration greater than 50 mg/L, cyanide concentration greater than 20 mg/L and H2S concentration greater than 50 mg/L, and stipulates key inspection items for each type. 3.3 Anti-corrosion measures In corrosive environments where the hydrogen sulfide concentration is greater than 50 mg/L, the shell should be made of carbon steel or carbon-manganese steel with a tensile strength not greater than 414 MPa. ； In corrosive environments where the hydrogen sulfide concentration is greater than 50 mg/L and the cyanide concentration is greater than 20 mg/L, the shell should be made of carbon steel or carbon-manganese steel + 0Cr13 steel composite steel plate, and the internal parts should be made of 0Cr13 steel. When selecting carbon steel or carbon-manganese steel as the shell material, the following measures should be taken: ①The hardness of the weld should be limited to no greater than HB 200 ； ②Avoid welding alloys with high composition ； ③Post-weld heat treatment of process equipment ； ④100% ultrasonic inspection when plate thickness exceeds 200 mm ； ⑤Conduct 100% radiographic inspection of welds. When carbon-manganese steel is used as the shell material, the banded distribution of MnS increases the susceptibility to hydrogen-induced cracking, and the segregation of Mn easily produces martensite and bainite, which increases the tendency of cracking in the post-weld structure. Based on these research results, it is believed that low alloy steel containing Mn is not suitable for manufacturing pressure vessels in wet hydrogen sulfide environments. The current common practice is to control the Mn content. For example, the domestic 16MnDR steel stipulates that the Mn content is less than 1.60%, while the corresponding steel grade TStE 355 in Japan stipulates that the Mn content is around 1.4%. Reducing the sulfur content in steel (less than 0.005%) can reduce the susceptibility to hydrogen-induced cracking. However, the general method of checking hydrogen-induced cracking (such as NACE TM 0284) is not enough to detect the tendency of stress-oriented hydrogen-induced cracking. 4 Corrosion and protection of sulfur at high temperatures The corrosive environment of high-temperature sulfur-containing compounds refers to the corrosive environment formed by sulfur, H2S and mercaptans in heavy oil parts above 240°C. Typical high-temperature sulfur-containing compound corrosion environments exist in the atmospheric and vacuum distillation units, the lower part of the vacuum tower and bottom pipes, atmospheric residual oil and vacuum residual oil heat exchangers, etc. ； The lower part of the main fractionation tower of the fluidized catalytic cracking unit, the lower part of the main fractionation tower of the delayed coking unit, etc. In the corrosive environment of these high-temperature sulfur-containing compounds, the corrosion rate of carbon steel is above 1.1 mm/a. In hydrogen-facing devices such as hydrocracking and hydrorefining, the presence of hydrogen accelerates the corrosion of hydrogen sulfide, forming a high-temperature H2S+H2 corrosion environment above 240°C. Typical examples are reactors of hydrocracking units and hydrodesulfurization units, and naphtha hydrorefining reactors in the raw material refining section of catalytic reforming units. 4.1 Corrosion mechanism Under high temperature conditions, active sulfur reacts directly with metals. It appears in various parts in contact with the logistics, showing uniform corrosion, among which H2S is the most corrosive. The chemical reaction is as follows: H2S+Fe→FeS+H2 S+Fe→FeS RSH+Fe→FeS+ The high-temperature sulfur corrosion rate of unsaturated hydrocarbons depends on the amount of active sulfur in the crude oil and is also related to the total sulfur content. The increase in temperature not only promotes the chemical reaction between active sulfur-containing compounds and metals, but also promotes the decomposition of inactive sulfur. When the temperature is higher than 240°C, sulfur corrosion gradually intensifies as the temperature increases. Especially at 350 to 400°C, H2S can decompose into sulfur and hydrogen. The decomposed elemental sulfur is more corrosive than H2S. The corrosion is most severe at 430°C, and the decomposition is almost complete at 480°C, and the corrosion begins to weaken. High-temperature sulfur corrosion starts very quickly, and the corrosion rate will remain constant after a certain period of time. This is because a protective film of iron sulfide is formed. The higher the flow rate of the logistics, the easier it is for the protective film to fall off, and corrosion will start again after falling off. 4.2 Anti-corrosion measures Anti-corrosion materials are mainly used for this type of corrosion parts. Considerable field experience shows that ferritic stainless steel composite plates such as carbon steel + 0Cr13 or 0Cr13Al steel (SUS 405) can be used for high-temperature parts of the tower body. The chromium content of 0Cr13 steel is greater than 11.7%. Its alloy design conforms to the n/8 rule and has good corrosion resistance. The expansion coefficient of this kind of steel is similar to that of carbon steel, making it easy to be used in the manufacture of composite panels. Not only can it withstand high-temperature sulfur corrosion well, but it is also cheap. Refining companies such as the United States, Germany, Iran and domestic Maoming Petrochemical Company all have long-term experience in use. The tower internal parts can be made of 0Cr13 steel, 12AlMoV steel and aluminized carbon steel, and the heat exchanger tubes can be made of Cr5Mo and aluminized carbon steel. Cr18Ni10Ti steel (SUS 321) can also be selected as the tower body material. Its resistance to sulfur corrosion and naphthenic acid corrosion is better than that of 0Cr13 or 0Cr13Al steel, and it has good processing performance. However, Cr18Ni10Ti steel (SUS 321) is not as resistant to stress corrosion cracking as 0Cr13 or 0Cr13Al steel, so polythionic acid corrosion must be controlled. Cr5Mo steel should be used for pipelines, but 316L steel can be used for parts with severe erosion and corrosion such as oil transfer line elbows. For example, the high-speed section of the oil transfer line of the atmospheric and vacuum distillation unit of Maoming Petrochemical Company originally used Cr5Mo steel, but the elbow area was severely eroded and corroded. After replacing it with 316L steel, it has been running well for 5 years. Aluminized carbon steel, which has been used in my country's oil refining units for many years, mainly solves the corrosion caused by organic acids and sulfur in high-temperature areas. Practice has proven that after aluminizing, the corrosion resistance and oxidation resistance of the carbon steel trays of the atmospheric tower, the carbon steel packing of the pressure reduction tower, the internal components of the tower, the tube bundles of the heat exchanger in the high-temperature area, and the furnace tubes of the heating furnace are greatly improved, and are comparable to those of 18-8 steel and 316L steel. Many refineries in Japan also use this material, which is mainly used for pipes and tower packings with corrosive media. The service life is more than 6 years. 5 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. 6 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. 7 Stress corrosion cracking and protection caused by polythionic acid are most likely to occur on equipment made of stainless steel or high alloy materials in oil refining units, generally reaction towers and their linings and internal components, storage tanks, heat exchangers, pipes, heating furnace tubes, etc. in high-temperature, high-pressure hydrogen-containing environments, especially equipment made of austenitic stainless steel in hydrodesulfurization, hydrocracking, catalytic reforming and other devices. Polythionic acid generally does not form when these equipment are operated under dry conditions of high temperature, high pressure, lack of oxygen and water. However, when the device is corroded by sulfur during operation, sulfur-containing compounds are generated on the surface of the equipment. When oxygen (air) and water enter during the shutdown of the device, polythionic acid (H2SXO6) reacts with the sulfur-containing compounds generated on the surface of the equipment. Even when the equipment is in a "cold state", there is usually tensile stress (including residual stress and applied stress). Under the combined effect of polythionic acid and this tensile stress, austenitic stainless steel and other high-alloy steels produce sensitization conditions, and polythionic acid stress corrosion cracking may occur. 7.1 Cracking Mechanism The surface of equipment made of stainless steel or high alloy materials reacts with H2S and active sulfur in the environment during operation to generate FeS. When the equipment is shut down or repaired, the temperature in the system decreases, and the surface of the equipment is fully contacted with oxygen and moisture in the air, and reacts to generate polythionic acid. Among the polythionic acid produced, the largest amount of H2S4O6 is produced. Stainless steel and high alloy materials, especially those that have been welded or "sensitized" near the 370-815°C area, are most susceptible to stress corrosion cracking. Even after these materials have been thermally stabilized, stress corrosion cracking will occur if they stay in the sensitized area for a long time. Polythionic acid stress corrosion cracking is often closely related to the intergranular corrosion of austenitic stainless steel. It first causes polythionic acid intergranular corrosion, and then causes polythionic acid stress corrosion cracking. This is mainly due to the sensitization of austenitic stainless steel or the precipitation and precipitation of chromium carbides near the intergranules during use, resulting in severe chromium deficiency near the intergranules. Therefore, intergranular corrosion of polythionic acid occurs first in these areas. Due to the existence of tensile stress in the material, polythionic acid stress corrosion cracking will occur in some weak areas of the equipment. 7.2 Anti-corrosion measures Since polythionic acid stress corrosion cracking occurs when the equipment is shut down, when the device is shut down due to shutdown, maintenance, etc., strict protection should be taken to prevent harmful substances such as external oxygen and moisture from entering the system. For 18-8 stainless steel, when the pH value of the medium environment is not greater than 5, polythionic acid stress corrosion cracking may occur. Therefore, the pH value of the medium environment must be strictly controlled on site. Alkaline washing can neutralize the generated polythionic acid and control the pH value within an appropriate range. Nitrogen purging can remove air and protect equipment. Many studies have shown that it is beneficial to add stabilizing elements such as Ti and Nb to the alloy or to stabilize the weld bead, which can effectively prevent chromium carbides from precipitating at the grain boundaries and stabilize the alloy phase. The lower the carbon content of the steel, the better it is in resisting stress corrosion cracking. Ultra-low carbon stainless steels such as 316L and 317L are better in resisting cracking than the corresponding 316 and 317 steels. It is generally believed that Ti/C and Nb/C must reach a certain value and must be stabilized to effectively resist cracking. At present, stabilized austenitic stainless steel with a Ti/C value of 7 to 8 is mostly used as a corrosion-resistant material in engineering design. However, for special components in special parts, such as expansion joints of catalytic cracking regeneration flue gas pipelines, it is recommended to use alloy steel with a higher alloy degree, such as Incone 1625, Incoloy 800 or B-315, etc. B-315 and FN-2 are domestic steel grades. The performance of expansion joints made of B-315 and FN-2 is not inferior, and its price is lower than Incone 1625 and Incoloy 800. Many refineries have widely adopted it. 8 High-temperature flue gas sulfuric acid dew point corrosion and protection The fuel oil in the heating furnace will generate high-temperature flue gas during the combustion process. The high-temperature flue gas contains a certain amount of SO2 and SO3. In the low-temperature part of the heating furnace, SO3 and moisture in the air condense at the dew point part to generate sulfuric acid, resulting in sulfuric acid dew point corrosion, which seriously corrodes the equipment. In refineries, it often occurs in low-temperature parts of heating furnaces such as air preheaters and flues, economizers and pipes of waste heat boilers, etc. 8.1 Corrosion mechanism Heavy fuel oil usually contains 2% to 3% sulfur and sulfur-containing compounds, which mostly generate SO2 and SO3 during combustion. Dry SO3 has almost no corrosion on equipment, but when it combines with steam in the flue gas to form sulfuric acid vapor, it does * * The dew point of the flue gas is increased, condensation occurs at the dew point part of the device, and the equipment is severely corroded. Research shows that high-temperature flue gas sulfuric acid dew point corrosion is essentially different from ordinary sulfuric acid corrosion. Ordinary sulfuric acid corrosion is the reaction between sulfuric acid and iron on the metal surface to generate FeSO4. Sulfuric acid dew point corrosion in high-temperature flue gas also first generates FeSO4, but FeSO4 further reacts with SO2 and O2 in the flue gas under the catalytic action of soot deposits to generate Fe2(SO4)3, and Fe2(SO4)3 has a catalytic effect on the conversion process of SO2 to SO3. When the pH value is lower than 3, Fe2(SO4)3 itself will corrode the metal to generate FeSO4, forming a corrosion cycle of FeSO4, Fe2(SO4)3, and FeSO4. * * Accelerates the process of corrosion, reportedly: For equipment made of ordinary carbon steel, the minimum time for corrosion and perforation in China is 12 days. 8.2 Anti-corrosion measures The degree of sulfuric acid dew point corrosion not only depends on the sulfur content in the fuel oil, but is also affected by the conversion rate of SO2 to SO3 and the water content in the flue gas. Therefore, correctly measuring the dew point of flue gas plays a key role in determining the corrosion-prone parts of the heating furnace, selecting equipment materials, and formulating anti-corrosion measures. Since there is basically no problem of sulfuric acid dew point corrosion in flue gas above the dew point, corrosion prevention can be achieved by increasing the exhaust temperature based on accurate measurement of the flue gas dew point. However, this method will cause a waste of energy by discharging high-temperature flue gas. In order to solve the problem of sulfuric acid dew point corrosion in high-temperature flue gas, a new steel type resistant to sulfuric acid dew point corrosion - ND steel was developed in China in the 1990s. Trace elements Cu, Sb and Cr are added to ND steel, and a special smelting and rolling process is used to ensure that an alloy layer rich in Cu and Sb can be formed on its surface. When ND steel is under sulfuric acid dew point conditions, a dense passivation film containing Cu, Sb and Cr is easily formed on its surface. This passivation film is a reactant of sulfuric acid corrosion. As the reaction products accumulate, the anode potential gradually increases, which soon passivates the anode, and ND steel completely enters the passivation zone. This steel type has been used in the heating furnace systems of several refineries and has achieved good results. Corrosion-resistant sintered alloy coating is also a method to solve the dew point corrosion of high-temperature flue gas sulfuric acid. The coating adopts the principle of superalloy corrosion-resistant alloying and is prepared through a special process. Its maximum use temperature is around 600°C (800°C for short-term use), it has excellent thermal conductivity, is closely combined with the base material, and its thermal expansion performance matches well with the steel base material. Industrial applications have shown that its resistance to sulfuric acid dew point corrosion is obvious. 9 Conclusion The corrosion of sour crude oil is quite complex, and the types of corrosion are far more than these. The anti-corrosion technology involved in this article is far from enough. In order to reduce the degree of corrosion of equipment processing Middle Eastern sour crude oil, most domestic refineries use the method of blending sour crude oil with domestic crude oil to reduce the total sulfur content of crude oil. Individual refineries have taken controlling the blending ratio as an important means to control corrosion. Low-temperature HCl+H2S+H2O electrochemical corrosion is also a problem that has not yet been completely solved. Only by doing a good job of "four injections" on the basis of deep electrical desalination work, selecting the right agent, adding it correctly, precise control and timely detection can corrosion be effectively controlled. Solving the corrosion of processing sour crude oil cannot only solve a certain type of corrosion, but needs to be complete and standardized, and the impact on petroleum products must also be considered. Corrosion monitoring technology, corrosion database (corrosion files) and analysis of corrosion failure cases are also very important aspects of anti-corrosion work in sour crude oil processing, and they should be paid enough attention and strengthened in the work.