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Chapter 6 Common types of corrosion and maintenance of equipment in residue hydrotreating units. For residue hydrodesulfurization units, the process is complex and the procedure is rather lengthy. Its notable characteristics are hydrogen exposure, high temperature and pressure; moreover, a relatively high concentration of sulfur or hydrogen sulfide is present in the system. Based on the characteristics of the unit, the aspects related to damage caused by corrosion and metallurgical issues during operation, as well as the measures for protection against such damage, are described as follows: The residue oil hydrodesulfurization unit is subject to the following types of corrosion and metallurgical problems: (1) high-temperature hydrogen corrosion; (2) hydrogen embrittlement; (3) wet hydrogen sulfide corrosion; (4) corrosion caused by high-temperature sulfur or a combination of sulfur hydrogen sulfide and hydrogen; (5) corrosion due to ammonium hydrosulfide; (6) stress corrosion cracking of austenitic stainless steel in the presence of polyoxysulfates; (7) hydrogen-induced delamination of the surfacing layer on austenitic stainless steel; (8) temper embrittlement of Cr-Mo steel; (9) chloride ion corrosion; (10) alkali embrittlement; (11) sulfate dew point corrosion caused by low-temperature flue gases. Each type of corrosion and damage is explained in relation to the specific conditions of this unit. High-temperature hydrogen corrosion occurs when, under high temperature and pressure conditions, hydrogen penetrates into steel. It then chemically reacts with the carbon in unstable carbides within the steel to form methane. Since methane cannot escape from the steel, it accumulates in intergranular voids and at sites of non-metallic inclusions. This leads to blistering and cracking of the steel, as well as a decrease and deterioration in its strength, ductility, and toughness; intergranular fracture also occurs. Once damage occurs, the consequences are severe; this is the primary concern for hydrogenation units. In the reaction section, components such as heating furnaces, reactors, thermal separators, heat exchangers for reaction streams, and pipelines are all susceptible to high-temperature hydrogen corrosion; therefore, materials capable of withstanding high-temperature hydrogen corrosion under the respective operating conditions must be selected. The selection is usually made in accordance with the practices recommended by the American Petroleum Institute (API941), namely \"Steels for High-Temperature and High-Pressure Hydrogen-Handling Operations in Refineries and Petrochemical Plants\" (also known as the Nelson curve). A certain safety margin can also be considered based on usage conditions and experience. Based on the maximum hydrogen partial pressure in the process of this device, the service limit temperature for 2.25Cr-1Mo steel should not exceed 454℃ ； 1.25Cr-0.5Mo should not exceed 330°C. During operation, it is essential to prevent abnormal overheating. Additionally, during maintenance while in use, if welding is required, post-weld heat treatment must be carried out. Hydrogen embrittlement is a phenomenon in which steel becomes brittle due to hydrogen itself. After hydrogen atoms penetrate the steel, they weaken the bonds between its atoms, resulting in a significant decrease in the steel’s elongation, reduction of area, and impact toughness. However, this brittleness is reversible; once hydrogen is removed from the steel, its mechanical properties can be restored. The susceptibility to low-temperature hydrogen cracking and the strength of steel are related to the hydrogen content and the stress at the location within the container. The most important factor determining a steel’s resistance to hydrogen embrittlement is its strength value; the sensitivity of the steel to cracking increases as strength rises. Hydrogen embrittlement cracking in high-strength steel may occur at temperatures below about 150°C. When hydrogen comes into direct contact with steel, it is absorbed by the steel and diffuses into its interior in an atomic state, dissolving in the ferrite to form a solid solution. This makes the steel more brittle and reduces its plasticity; such brittleness is proportional to the solubility of hydrogen in the steel. When the hydrogen concentration in steel is 6–7×10-6, the elongation σ and reduction of area ψ of the steel are only 20%–30% of their original values. In reactors operating under high temperature and pressure, hydrogen diffuses directly into the steel. At typical operating temperatures and hydrogen partial pressures, the concentration of hydrogen in the reactor walls ranges from 2 to 6×10^-6. During shutdown, if the reactor cools too rapidly, preventing hydrogen from diffusing out of the steel, delayed hydrogen cracking can occur at temperatures below 150°C. In the hydrogenation units of refineries, during shutdowns, the hydrogenation reactors are kept at a constant temperature at low pressure until they cool down to 150°C; this process helps to remove the dissolved hydrogen from the steel. It is an effective measure to prevent hydrogen embrittlement. Depending on the way hydrogen penetrates into the steel, its concentration in the steel varies, as does the sensitivity of the steel to damage. In aqueous solutions containing hydrogen sulfide, the hydrogen concentration in steel has been measured to exceed 10×10-6, thereby increasing its susceptibility to hydrogen embrittlement cracking. Hydrogen embrittlement caused by this mechanism of corrosion-induced hydrogen absorption is commonly referred to as sulfide cracking. The difference between sulfide cracking and hydrogen cracking lies only in the amount and mechanism by which hydrogen enters the steel; the fundamental cause of this type of cracking is hydrogen embrittlement. Wet hydrogen sulfide corrosion occurs when the medium at the joints of chemical containers meets the following conditions simultaneously, thereby creating a wet H2S stress corrosion environment: (1) Temperature is less than or equal to (60+2P)℃ ； (P is pressure) ； (2) The H2S partial pressure is greater than or equal to 0.00035 MPa, which corresponds to a H2S solubility in water at room temperature of greater than or equal to 10×10-6 ； (3) The medium contains liquid water or is at a temperature below the dew point of water ； (4) PH < 9 or the presence of cyanide. Mechanisms and forms of wet hydrogen sulfide corrosion: (1) For carbon steel, the main forms of corrosion are corrosion thinning, pitting, and cratering ； (2) For some carbon steels (with high carbon content, boiling steel, high levels of impurities in the steel), low-alloy steels, and stainless steels, the main form of corrosion is corrosion cracking. There are 4 types of cracking: a. hydrogen bubbling (HB), b. hydrogen-induced cracking (HIC), c. sulfide stress corrosion cracking (SSCC), d. stress-oriented hydrogen-induced cracking (SOHIC). Hydrogen bubbling (HB): During the hydrogen sulfide corrosion process, hydrogen atoms released penetrate into the steel, where they form hydrogen molecules and accumulate in certain critical areas of the steel such as non-metallic inclusions, metallurgical discontinuities, and layers. As the number of hydrogen molecules increases, the pressure generated rises continuously, leading to interface cracking and the formation of bubbles. Hydrogen bubbling often occurs at inclusions and metallurgical discontinuities in steel, with its distribution parallel to the steel plate surface. Hydrogen bubbling does not require any external stress (load stress or residual stress); therefore, conceptually, it does not fall under the category of stress corrosion failure. Hydrogen-Induced Cracking (HIC): In areas within the steel where hydrogen blisters form, as the hydrogen pressure continues to increase, small blister cracks tend to interconnect, resulting in hydrogen-induced cracking with a stepped appearance. Hydrogen-induced cracking does not require external stress (load stress or residual stress); therefore, conceptually, it does not fall under the category of stress corrosion failure. Sulfide stress corrosion cracking (SSCC): In liquid water, hydrogen sulfide, through electrochemical processes, generates hydrogen atoms during cathodic reactions; these hydrogen atoms penetrate into the steel and dissolve within its lattice, leading to an increase in brittleness. (The hydrogen atoms enter the steel’s internal lattice, where they form hydrogen molecules as a result of chemical interactions; this causes deformation of the steel’s lattice, resulting in a decrease in toughness and an increase in brittleness.) Cracking occurs under the effect of external tensile stresses or residual stresses. Stress-oriented hydrogen-induced cracking (SOHIC): Stress-oriented hydrogen-induced cracking occurs when, under the influence of stress, the rows of small cracks that form due to hydrogen accumulation at inclusions and defects develop in a direction perpendicular to the stress, that is, in the direction of the wall thickness of pressure vessels and pipelines. Equipment, pipelines, fittings, etc., used in a wet hydrogen sulfide environment should be made of killed steel, with the content of impurities such as P and S reduced as much as possible. To reduce the high stress concentration areas in equipment and components, stress-relieving heat treatment must be carried out after machining to ensure that the hardness of the welds and their surrounding areas remains below acceptable levels. When corrosive treatment of sulfur-containing crude oil is carried out with high-temperature sulfur or hydrogen sulfide in the presence of hydrogen, uniform corrosion caused by high-temperature sulfur occurs in equipment and pipelines operating at high temperatures of 240–425°C. The essence of corrosion is the conversion of organic sulfides into hydrogen sulfide and elemental sulfur, which react with ferrite in steel to form iron sulfide. The corrosion reactions caused by sulfur and hydrogen sulfide require a certain temperature to occur; corrosion generally starts at temperatures above 240°C, manifesting itself primarily as thinning of the material. The higher the chromium content in steel, the better its corrosion resistance. Alloy steels with a Cr content greater than 5% exhibit good resistance to high-temperature sulfur corrosion. Materials such as Cr5MO, Cr9MO, Cr13, and 18-8 are generally chosen. 12CrMo, 15CrMo, 1.25Cr-0.5Mo, and 2.25Cr-1Mo are commonly used heat-resistant steels for hydrogen service, but they are not suitable for applications subject to high-temperature sulfur corrosion. Hydrogen sulfide can also decompose into sulfur and hydrogen at 350–400°C, and the corrosion caused by the resulting active sulfur is more severe than that caused by hydrogen sulfide. Therefore, when processing hydrogen sulfide-containing streams in high-temperature environments above 240°C or in oil products with high sulfur content under operating conditions above 300°C, steel with a higher nickel-chromium content (18% chromium and 10% nickel) is generally chosen to address corrosion issues. In the presence of both hydrogen sulfide and hydrogen, its corrosion effect on steel is more severe than when hydrogen sulfide is present alone, as hydrogen acts as a catalyst during the corrosion process, accelerating it. In this case, the corrosion rate can be estimated using the COUPER curve (i.e., the equal corrosion curve of steel under hydrogen sulfide and hydrogen conditions), after which the appropriate material can be selected. Ammonium hydrosulfide corrosion, caused by hydrosulfide of ammonium, is a product of the reaction between ammonia and H2S generated during hydroprocessing. As the reaction stream cools down, NH3 and H2S combine to form solid NH4HS salts, which deposit in the tubes of the high-pressure air coolers and in the pipelines downstream of them. This accumulation of amines often leads to rapid corrosion of the tubes. The degree of corrosion of NH4HS is highly related to the KP coefficient. The Kp coefficient is the product of the mole percentage (mol%) of NH3 and the mole percentage (mol%) of H2S in the stream entering the air cooler; that is, KP=. Since the corrosion caused by high-pressure air is a very complex phenomenon with many influencing factors, its corrosion behavior cannot be determined by a single parameter. For the carbon steel high-pressure air coolers used in this device, it is beneficial to control the following aspects to ensure safe use. (1) The Kp coefficient must be less than 0.5 ； (2) The flow velocity of the fluid in the air-cooled tube bundle is controlled between 4.6 and 6 m/s, while it is 9 m/s in the upstream and downstream pipes ； (3) The content of hydrides and ammonia in the logistics should be minimized. Additionally, the NH4HS concentration in the aqueous phase of the high-pressure separator can also be used as a rough indicator to estimate the degree of pipe corrosion. Generally, corrosion may occur when the NH4HS concentration is around 2 wt%, and the higher the concentration, the more severe the corrosion. However, there are cases where no corrosion occurs even at a concentration of 5 wt%; therefore, this can only serve as a guide for optimizing the water injection volume. Polythionic acid stress corrosion cracking in austenitic stainless steels occurs when air, water, and iron sulfide rust are all present; under such conditions, polythionic acid is formed. Together with tensile stress, it can cause brittle cracking in austenitic stainless steels; cracks can form rapidly even at room temperature. Although stable stainless steel with strong corrosion resistance is used, great care must still be taken to avoid stress corrosion cracking when austenitic stainless steel equipment is opened and exposed to air or moisture. The best way to protect this steel is to keep it dry and out of contact with air. Alternatively, heating can be used to prevent moisture from condensing. If this cannot be done, it will come into contact with air and moisture. A method that can be adopted at this time is to neutralize it with an alkaline solution before the austenitic stainless steel comes into contact with air or moisture; austenitic stainless steel equipment that is not to be opened during maintenance should be sealed in a nitrogen atmosphere. This is because the focus of maintenance work carried out during each maintenance cycle varies. Therefore, the protection methods adopted for austenitic stainless steel during each maintenance cycle must be recorded, and these methods should be reviewed and approved by the technical supervisors responsible for maintenance, processes, and equipment. The following are the general rules to be followed for equipment and pipelines during maintenance work: Reactors, heat exchangers, and the connected stainless steel pipelines with an austenitic stainless steel surfacing on their inner walls should be washed thoroughly with an alkaline solution at a concentration of 1.5–2.5% before being cleaned or inspected. When the equipment is exposed to air, any residual alkali solution should be allowed to remain on the equipment. When using ultrasound to inspect austenitic stainless steel pipes, vessels, heating furnace tubes, etc., water must not be used as a coupling agent in place of oil or lubricating grease, unless a neutralizing wash is performed prior to the inspection. To prevent \"alkali embrittlement\" corrosion of austenitic stainless steel in high-temperature environments with the presence of alkalis, pipes and equipment that have been subjected to neutralization cleaning should be cleaned with deionized water containing very low levels of chloride ions to remove any residual alkali from the metal surface before being put back into use. Hydrogen-induced delamination of austenitic stainless steel surfacing layers occurs in equipment equipped with such surfacing layers when it operates in high-temperature, high-pressure hydrogen environments. Hydrogen penetrates into the vessel walls, and when the equipment stops operating, differences in the solubility and diffusion rates of hydrogen in the base material and the austenitic stainless steel surfacing layer cause a large amount of hydrogen to accumulate in the transition layer. The significant difference in linear expansion between these two materials generates substantial residual stresses, leading to delamination between the base material and the surfacing layer. This type of damage is influenced by operational conditions and factors such as hydrogen partial pressure, temperature, cooling rate during shutdown, and the frequency of repeated shutdowns. To prevent or mitigate the occurrence or propagation of such spalling cracks, it is necessary to strictly follow the operating procedures during equipment use, avoid unplanned emergency shutdowns as much as possible, and establish shutdown conditions that allow oxygen to be released from the vessel walls as much as feasible during normal shutdowns in order to reduce residual hydrogen levels. Additionally, during routine inspections, it is also necessary to use ultrasonic technology for detection to determine whether delamination has occurred or is progressing. To prevent brittleness in 2.25Cr-1Mo and 1.25Cr-0.5Mo steel equipment caused by the tempering brittleness of Cr-Mo steel, for such equipment in the reaction sections that operate within the brittleness temperature range (usually 325–575°C), during restarts or shutdowns after the plant is put into operation for the first time, the equipment should not be pressurized at low temperatures. It should be ensured that when the temperature is below 93°C, the pressure applied to steel equipment made of 2.25Cr-1Mo and 1.25Cr-0.5Mo steels is limited such that the stress generated by this pressure does not exceed 20% of the yield limit of the steel. For this device, when the pressure in the high-pressure system is above 6.27 MPa, the temperature must be maintained above 93°C ； In other words, before increasing the pressure from 6.27 MPa, the temperature must first rise above 93°C. Additionally, during emergency pressure relief, the pressure should be released urgently to below 6.27 MPa, and the temperature must not drop suddenly below 93°C. Only in this way can the equipment material be prevented from suffering from temper embrittlement damage. Moreover, during startup and shutdown, excessive thermal stress caused by too rapid temperature changes should also be avoided. Generally, when the wall temperature of the equipment is below 150°C, the heating and cooling rate should not exceed 25°C per hour. When chloride ions corrode stainless steel used in heat exchanger tubes for seawater, industrial water, etc., or in other piping, towers, containers, etc., stress corrosion cracking often occurs due to ion concentration resulting from trace amounts of CL- ions present in the environment. There are also various explanations for chloride stress corrosion cracking: (1) Adsorption theory: Under stress, chloride ions adsorb at the crack tip, leading to a decrease in the bonding force between M-MO atoms and thus their destruction. The continuous occurrence of this process leads to the expansion of SCC. (2) Electrochemical theory: Stress corrosion cracking is a phenomenon that occurs due to the dissolution of the anodic region on the metal surface. And stress has the effect of accelerating anodic dissolution. (3) Film failure theory: When a metal is subjected to tensile stress, dislocation movement creates slip steps, which in turn leads to the failure of the passivation film and the exposure of a fresh surface. The high reactivity of this fresh surface facilitates further corrosion, resulting in the continuous progression of SCC. (4) Corrosion product wedging theory: Many people believe that the wedging effect of corrosion products formed within stainless steel cracks is what causes the crack to propagate. (5) Hydrogen embrittlement theory: At the crack tip, a cathodic reaction corresponding to the anodic reaction occurs. The hydrogen generated or processed enters the steel, causing hydrogen-induced cracking. Alkali-brittle metals undergo brittle cracking under the combined effect of sustained tensile stress (including applied loads, thermal stresses, and residual stresses resulting from cold working, hot working, or welding) and certain corrosive media. This is characterized by the appearance of corrosion cracks or even fractures; the origin points of these cracks are often at the bottom of pitting corrosion holes or small pits ； Crack propagation occurs in three types: intergranular, transgranular, and mixed. The main crack is usually perpendicular to the stress direction and often branches ； The ends of the cracks are sharp; the degree of corrosion on the inner walls of the cracks and on the outer surface of the metal is usually very mild. The expansion rate at the ends of the cracks is high, and the fracture zones at those ends exhibit characteristics of brittle failure. Austenitic stainless steel heat exchangers used in media containing chloride ions are prone to stress corrosion cracking, such as the fracture of austenitic stainless steel air-cooled tube bundles and the breakdown of the tower bottom lining; as well as boiler alkali embrittlement, also known as caustic embrittlement ； Spalling of turbine impellers ； Certain steels crack in humid hydrogen sulfide-containing atmospheres, suffering from sulfide stress cracking. Environments prone to stress corrosion cracking: high-temperature alkaline solutions (NaOH, Ca(OH)2, LiOH), chloride aqueous solutions, seawater, marine atmosphere, polyoxosulfuric acids, high-temperature and high-pressure oxygen-containing pure water, water vapor (260°C), concentrated boiler water, H2SO4 at 260°C, humid air (90% humidity), NaCl+H2O, hot NaCl, wet magnesium chloride insulators, H2S aqueous solutions. Sulfuric acid dew point corrosion of low-temperature flue gases occurs primarily in the low-temperature areas of heating furnaces and boiler air preheaters. The raw materials used in heating furnaces and boilers contain sulfides, which generate SO2 and SO3 during combustion. At lower temperatures, when in contact with supercooled metal, SO2 and SO3 react with water to form sulfurous acid and sulfuric acid, causing corrosion of the equipment. In addition, sulfuric acid and sulfurous acid also adhere to the dust in the flue gas; upon condensation, they form yellow deposits that are difficult to remove, thereby blocking the tubes of the air preheater. Equipment maintenance (1): Carry out regular switching (jogging) of pump equipment as well as scheduled turning of the shafts, to keep the spare equipment in good standby condition. (2) Ensure proper equipment lubrication by adhering to the \"three-stage filtration\" and \"five fixed principles\" for lubrication, and keep the lubricant storage equipment clean and tidy. The so-called “three-stage filtration”: from the large oil storage tank to the on-site oil storage tank (first-stage filtration), from the on-site oil storage tank to the oil jug (second-stage filtration), and from the oil jug to the fueling point (third-stage filtration) ； Five fixes: fixed location, fixed time, fixed quality, fixed quantity, fixed person. (3) The equipment, motors, and pump bodies in the responsible area (including oil cups), as well as the area around the pump bases, must be cleaned once per shift; there should be no standing water or oil stains or any other signs of dirt, with the channels clean to the bottom, the shafts visible, and the equipment showing its original color. (4) The pumps, valves, and screws in the pump room should be kept clean and shiny, and lubricated with oil once a week ； Lubricate the outdoor valve screws with butter. The valve handwheel and nuts are complete, with no signs of looseness, rust, or dirt. (5) The safety accessories in the device, such as pressure gauges, thermometers, and level gauges, are complete and in good condition; any damaged ones should be replaced promptly. (6) One must understand the “four knowledges and three skills” for using equipment” ； Four understandings: understanding the structure, principles, performance, and applications of equipment ； Three skills: know how to operate, know how to maintain, and know how to troubleshoot faults. (7) Four prohibitions for equipment operation: operation is prohibited at excessive temperature, pressure, speed, or load. (8) Daily equipment maintenance: Daily maintenance, also known as routine maintenance, refers to the upkeep tasks that are carried out on a daily basis by the operators as part of their regular duties. Operators are required to carry out the following tasks in each shift: inspect and lubricate the equipment before starting work, strictly follow the operating procedures during the shift, and thoroughly clean and wipe the equipment 15 to 20 minutes before ending the shift (with an appropriate extension on weekends), recording the condition of the equipment in the shift handover log. (9) Equipment maintenance adheres to the \"one point, two inspections\" system: \"One point\" refers to the operators conducting regular inspections of the equipment at their respective stations, ensuring stable operation, strictly complying with procedural rules, and preventing the equipment from operating under conditions of excessive temperature, pressure, or load ； “The \"two rounds of inspections\" refer to the practice where the workshop equipment supervisors and equipment technicians conduct two rounds of daily inspections of the installation equipment, while fitters, electricians, and instrument maintenance teams carry out daily inspections of the areas under their responsibility; any issues detected are addressed promptly to ensure the proper operation of the equipment.