Why cannot steam be introduced into hydrogen-handling equipment?

It is mainly determined by the material of the hydrogen pipeline

It is due to the special requirements regarding the materials of the reactor and high-pressure heat exchangers; when steam condenses into water, it can cause damage to the materials of these equipment； Catalysts are most sensitive to water, as contact with water can damage them and reduce their service life. It is mainly to protect the equipment and catalysts.

When our facility was put into operation for the first time, we considered using steam to purge the high-pressure pipelines; however, the designers did not agree with this approach. We discussed this issue with the technical staff at the design institute, and they explained that austenitic stainless steel is quite delicate. Steam usually contains many impurities, such as high levels of chloride ions, and when it cools and turns into condensed water, it can easily cause damage to austenitic stainless steel pipelines.

Many heating devices in refining plants seem to be capable of being heated by steam, but in practice, furnaces that are costly and energy-intensive are used as well, and this is due to the fact that catalysts cannot come into contact with water.

Common types of corrosion in hydrogenation units 1. Hydrogen corrosion: Hydrogen corrosion occurs under high temperature and pressure conditions, where molecular hydrogen partially decomposes to form atomic hydrogen or ionic hydrogen, which then diffuses into the steel through the metal lattice and grain boundaries. The hydrogen that penetrates the steel reacts chemically with unstable carbides, resulting in the formation of methane bubbles (involving the nucleation and growth of methane), as per the reaction Fe3C + 2H2 → CH4 + Fe. These methane bubbles accumulate in intergranular voids and non-metallic inclusions. Methane has very low diffusion capacity within the steel, so it accumulates in the existing micro- or sub-micro-pores at the grain boundaries, creating localized high pressures that lead to stress concentration, widening of the grain boundaries, and the development of cracks. Initially, these cracks are very small, but over time they connect with each other, leading to a decrease in the strength, ductility, and toughness of the steel, as well as intergranular fracture. Since this embrittlement phenomenon is the result of a chemical reaction, it is irreversible in nature, and is also known as permanent embrittlement. There are two forms of hydrogen corrosion that occur in equipment operating in high-temperature, high-pressure hydrogen: one is surface decarburization, and the other is internal decarburization. Surface decarburization does not cause cracks, which is similar to the decarburization that occurs when steel is exposed to gases such as air, oxygen, or carbon dioxide. The effects of surface decarburization are generally evident: the strength and hardness of the steel decrease locally, while its ductility increases. Internal decarburization occurs because hydrogen diffuses into the steel and reacts to form methane; since methane cannot diffuse out of the steel, it accumulates near grain boundaries or inclusions. Very high local stresses are generated, causing the steel to develop cracks, fissures, or bulges, and its mechanical properties are altered as a result. Factors causing hydrogen corrosion: ① Operating temperature, hydrogen partial pressure, and contact time. The higher the temperature or pressure, the earlier the onset of high-temperature hydrogen corrosion. A hydrogen partial pressure of 8.0 MPa serves as a threshold; effects are relatively mild below this value, while they become more pronounced above it. An operating temperature of 200°C is another critical point – above this temperature, the degree of hydrogen corrosion in steel increases as the temperature of the medium rises. The concentration of hydrogen in steel can be expressed by the following formula: C = 134.9P1/2exp(–3280/T), where C represents the hydrogen concentration, P is the partial pressure of hydrogen in MPa, and T is the temperature in K. It can be seen from this formula that temperature has a more significant effect on the hydrogen concentration in steel than the system’s partial pressure of hydrogen. ② The addition of alloying elements in steel. Elements that cannot form stable carbides in steel (such as nickel and copper) have no effect on improving the hydrogen corrosion resistance of steel ； By adding elements to steel that form very stable carbides (such as chromium, molybdenum, vanadium, titanium, tungsten, etc.), the activity of carbon can be reduced, thereby enhancing the steel’s resistance to hydrogen corrosion. Regarding the effect of impurities, studies on 2.25Cr–1Mo steel have shown that tin and antimony increase the density, size, and formation rate of methane bubbles. ③ Processing process. The hydrogen corrosion resistance of steel is also closely related to its microstructure. The tempering process also affects the hydrogen corrosion resistance of steel. For the quenched state, hydrogen corrosion occurred after only a short period of heating. However, upon tempering, the higher the tempering temperature, the better the resistance to hydrogen corrosion becomes, as stable carbides can be formed. Additionally, for chromium-molybdenum steel equipment used in hydrogen-rich environments, post-weld heat treatment also has the effect of improving hydrogen corrosion resistance. Tests have shown that if the welds of 2.25Cr–1Mo steel are not heat-treated, the temperature at which hydrogen corrosion occurs is more than 100°C lower than the temperature indicated by the Nelson curve. ④ Thermal stress on steel. The creep strength decreases in high-temperature hydrogen, especially as the presence of secondary stresses (such as thermal stresses or those induced by cold working) accelerates high-temperature hydrogen corrosion. When there is no deformation, steel has a longer \"incubation period\"; as the degree of cold deformation increases, this \"incubation period\" gradually shortens. When the deformation reaches 39%, there is no such \"incubation period\" under any testing conditions – cracks occur immediately upon exposure to hydrogen under these conditions. Therefore, for the pressure-bearing components of hydrogen-service pressure vessels, attention should be paid to using heat treatment to eliminate residual stresses ； ⑤ The effects of the stainless steel composite layer and the surfacing layer: Due to the different solubilities and diffusion coefficients of hydrogen in austenitic stainless steel and ferritic steel, an austenitic stainless steel composite layer and surfacing layer with complete metallurgical bonding can reduce the hydrogen partial pressure acting on the base material. How to prevent hydrogen corrosion: ① Use internal insulation to reduce the wall temperature of the cylinder ； ② Hydrogen-corrosion resistant steel plates are used for the reactor vessel ； ③ Use hydrogen-resistant linings (such as 0Cr13, 1Cr18Ni9Ti, etc.). ④ Adopt a multi-layer structure; exhaust holes and special gas collection layers can be provided on the wall to collect and remove the hydrogen that seeps in from the inner cylinder. ⑤ A catalyst-lined tubular reactor is used, with fresh hydrogen flowing through the annular space to cool the tube walls. ⑥ In practical applications, for a given device, hydrogen corrosion in the weld area cannot be ignored. This is because, generally, the hydrogen corrosion resistance of welded joints is inferior to that of the base material, and this weakness is particularly evident in the area near the coarse grains in the heat-affected zone, which warrants attention. 2. Hydrogen corrosion incubation period: Under the action of high-temperature and high-pressure hydrogen, the failure of steel does not occur suddenly; rather, it goes through a process during which the mechanical properties of the steel do not change significantly. This process is known as the incubation period or gestation period. The length of the incubation period depends on the type of steel and the conditions of exposure. Under harsh conditions, the incubation period is short; damage can occur within just a few hours. In conditions of high temperature but low pressure, the incubation period may be longer. Knowing the hydrogen corrosion incubation period of steel is very important for determining the safe operating time of equipment. 3. Hydrogen-induced cracks Hydrogen-induced cracks are also known as induced cracks. This is due to hydrogen diffusing into the steel while the reactor is operating in high-temperature, high-pressure hydrogen environments. During the cooling process after the reactor is shut down, if the cooling rate is too fast, hydrogen does not have enough time to escape from the steel, resulting in a certain amount of hydrogen remaining trapped within it. This severe loss of tensile ductility can lead to the formation of cracks. In operation, when the device is shut down, a shutdown procedure that allows for a more thorough release of hydrogen should be adopted. For example, the cooling rate during shutdown should not be too high, and a higher temperature (above 350°C) should be maintained for an extended period of time. 4. Hydrogen embrittlement Hydrogen embrittlement refers to the embrittling phenomenon caused by the retention of hydrogen in steel. In steel that has suffered from hydrogen embrittlement, its elongation and reduction of area decrease significantly. This is due to atomic hydrogen invading the steel, which weakens the bonding forces between the crystalline atoms, or as a result of it precipitating in a molecular state around the crystals or impurities. However, under certain conditions, if hydrogen can be released more thoroughly, the mechanical properties of the steel can still be restored. This characteristic is quite different from hydrogen embrittlement; therefore, hydrogen embrittlement is reversible and is also known as a one-time embrittlement phenomenon. For equipment operating in high-temperature and high-pressure environments, the vessel walls absorb a certain amount of hydrogen while in operation. During the shutdown process, the cooling rate is too fast, causing subcritical crack propagation at temperatures below 150°C, which poses a threat to the safe operation of the equipment. Measures to prevent hydrogen embrittlement: ① Minimize the strain amplitude, as this is helpful for improving service life. Measures such as reducing thermal stress and avoiding stress concentration are all effective. ② Try to maintain high ductility in the surfacing metal. ③ When the device is shut down, the cooling rate should not be too fast; moreover, during this shutdown process, it is necessary to allow as much of the hydrogen absorbed by the steel to be released (through staged isothermal dehydrogenation, generally at temperatures between 260 and 427°C), in order to reduce the residual hydrogen content in the vessel walls. Additionally, it is also very important to avoid unplanned shutdowns (emergency venting) as much as possible. Because in this case, the residual hydrogen concentration in the wall will be very high. 5. Stress corrosion: Stress refers to the amount of internal force acting per unit area. The stress perpendicular to the cross-section is called normal stress, while the stress parallel to the cross-section is called shear stress. The failure of metal materials under the combined action of static tensile stress and a corrosive environment is known as stress corrosion. The reason for the generation of corrosion stress is, firstly, the internal stress that increases the internal energy of the steel. The stability of steel under stress inevitably decreases, which in turn lowers the electrode potential. The greater the internal stress, the worse the chemical stability, and the lower the electrode potential. Therefore, the areas with high stress become the anode. Subsequently, this stress (especially tensile stress) damages the protective film on the metal surface; once the protective film is damaged, cracks form, and these cracks become the anodes. The other areas without stress become the cathode, thus forming a corrosion cell that accelerates corrosion. Austenitic stainless steels are relatively sensitive to stress corrosion and are prone to it, which may be related to their tendency to undergo slip, that is, twinning. Due to stress concentration at slip zones and twinning boundaries, they are prone to corrosion damage. Cracks generally occur through the grains, but they can also form between them. The cracks resulting from this stress corrosion have a knife-like shape, which is why it is referred to as \"knife-edge corrosion\". The reason for edge corrosion in austenitic stainless steel is, in addition to the uneven stresses in the weld seam, the precipitation of chromium carbides from the austenite during the cooling process after welding. This results in chromium depletion at the grain boundaries, and edge corrosion occurs in the weld area or the heat-affected zone. The temperature in a certain portion of the heat-affected zone is likely to be within the sensitization range for chromium-depleted carbides in austenite (450–850°C), which leads to chromium depletion at the grain boundaries and the formation of grain boundary cracks. Methods to prevent stress corrosion: ① Use heat treatment to eliminate residual stresses from welding and cold working, as well as carry out stabilization and solution treatment ； ② Ultra-low carbon (less than 0.03%) stainless steel or stainless steel stabilized with niobium and titanium is used, and ultra-low carbon or niobium-containing welding electrodes are employed for welding. 6. Corrosion mechanism of austenitic stainless steels by pyromultisulfic acid. Stress corrosion cracking characterized by pyromultisulfic acid is a brittle cracking phenomenon that occurs in a metal (steel) under the combined action of tensile stress and a specific corrosive environment. Austenitic stainless steels are relatively sensitive to sulfide stress corrosion cracking. Stress corrosion cracking caused by polythiosulfuric acids (H2SxO6, x=3~6) also falls under the category of sulfide stress corrosion cracking, and it is generally intergranular cracking. During the shutdown of refining units, when the system temperature and pressure drop, water vapor is condensed; or when the equipment is opened for maintenance, its interior and pipelines come into contact with moist air. When iron/chromium sulfides react chemically with hydrogen and oxygen, sulfurous acid and polythionic acid are produced, thereby causing corrosion. In petrochemical plant equipment, sulfide stress corrosion cracking of austenitic stainless steel or pipes is a common occurrence. Polysulfate stress corrosion cracking has also occurred in hydrogenation units. To prevent austenitic stainless steels from suffering from peroxysulfate corrosion, the following measures are recommended: ① Use ultra-low carbon grades (C≦0.03%) or stable stainless steels (SUS321, SUS347). Austenitic-ferritic duplex stainless steels also prove effective, as they are not susceptible to cracking caused by peroxysulfate stress. In manufacturing, residual stresses caused by cold working or welding should be eliminated or reduced as much as possible, and care should be taken to design the structure in such a way that no stress concentrations occur or that they are minimized. ② Keep the metal surface of austenitic stainless steel equipment or pipelines dry, that is, free from contact with air and water or in a heated state. That is, after the plant is shut down, the austenitic stainless steel equipment or pipelines that do not require maintenance are sealed off using valves or blind flanges, and nitrogen is filled inside to maintain a positive pressure, thereby isolating them from air. If the temperature falls below 38°C and liquid water begins to form, anhydrous ammonia must be injected into the system at a concentration of around 5000 PPm. This is especially true for the heating tubes, which need to maintain a temperature of over 149°C during shutdowns and maintenance periods in order to stay dry. ③ For austenitic stainless steel equipment, pipelines, and heating furnace tubes that cannot be maintained at above 149°C and require maintenance, they should be neutralized and rinsed using a solution of 1.5–2% sodium carbonate or sodium hydroxide. After rinsing, it is essential to use chloride-free deionized water for rinsing, in order to prevent residual alkali from remaining on the surface and causing alkali embrittlement, as well as from being carried onto the catalyst during startup and affecting its activity. Adding 0.5% sodium nitrate to the solution can reduce the likelihood of chloride stress corrosion cracking in stainless steel; however, it is necessary to avoid adding an excessive amount of sodium nitrate (not more than 0.5%), as this can lead to stress corrosion cracking in carbon steel. ④ Minimize the time that the metal surface of austenitic stainless steel is exposed to environments where stress corrosion may occur. In short, before each shutdown, specific measures for protecting austenitic stainless steel must be formulated based on the duration of the shutdown, and these measures must be approved through reviews by the equipment, process, production, and maintenance teams. 7. Other types of stress corrosion in austenitic stainless steels. In addition to suffering from stress corrosion in environments containing sulfur compounds, austenitic stainless steels can also be prone to stress corrosion in environments with oxidizing compounds and caustic soda. Other stress corrosion caused by neutralizing cleaning should be avoided. The sensitivity of austenitic stainless steel to chlorides is proportional to the concentration and temperature of the chlorides. During normal shutdown periods, chloride stress corrosion cracks generally do not occur, but at high temperatures, corrosion cracks, transgranular cracks, and cracks of both types may arise due to the concentration of chlorides. 8. The damage caused by chloride ions (Cl‑) to 18-8 austenitic stainless steel: In the presence of \"Cl‑\", 18-8 austenitic stainless steel is particularly susceptible to pitting corrosion. Pitting corrosion is very dangerous in production; it develops rapidly over a certain area and penetrates deeper, resulting in equipment damage due to localized failure. Or leakage may occur due to perforations in certain areas. The cause of pitting corrosion may be weak spots in the passivation film (oxide layer) on the surface of the stainless steel, which could result from local impurities or irregularities. When active (Cl‑) ions are present in the liquid, they are also easily adsorbed by the surface passivation film. In areas where the passivation film is weaker, chloride ions displace oxygen atoms on the surface and take their place. As a result, soluble chlorides are formed at the sites where Cl‑ ions are adsorbed, and small pores gradually develop in these areas. After the formation of these pores, an unfavorable situation arises: the pores act as the anode, while the passivated surface functions as the cathode. With the cathode having a larger area and the anode having a smaller one, this configuration creates a corrosion cell that **accelerates the rate of corrosion. When the pits resulting from pitting corrosion connect with each other, cracks are formed, leading to severe damage to the steel. To prevent chloride ions from causing corrosion in austenitic stainless steel, the chloride content in the water used for cleaning or pressure testing of such equipment and pipelines must be less than 30 μg/g. The conditions that must be met for stainless steel chloride stress cracking (SCC) to occur are: the presence of chlorides, free water, dissolved oxygen, tensile stress, and a temperature ranging from 60 to 210°C. Therefore, to prevent chloride stress cracking in stainless steel, it is necessary to reduce the entry of chlorides into the system (including feed oil and fresh hydrogen), as well as to minimize the formation of free water in low-temperature areas. Areas where chlorides tend to accumulate should have their excess liquid drained regularly, in order to prevent accumulation and corrosion. 9. Temper embrittlement of chromium-molybdenum steel: Temper embrittlement in chromium-molybdenum steel refers to the degradation of a material’s fracture toughness that occurs when the steel is maintained at temperatures between 370 and 575°C for an extended period of time, or when it is cooled slowly from these temperatures. Once the material develops temper brittleness, its impact toughness is significantly reduced, and its ductile-brittle transition temperature shifts toward higher temperatures. In addition to the aforementioned phenomena and characteristics, temper brittleness also has the following two features: ① This brittification phenomenon is reversible; that is, by heating the hardened steel to above 600°C and then rapidly cooling it, the steel can regain its original toughness ； ②Crystal boundary fractures present on the fracture surface of a steel specimen that has become brittle can disappear when the specimen is heated and then rapidly cooled. Impurity elements in the chemical composition of chromium-molybdenum steel have a significant impact on temper embrittlement; high levels of P, Si, and Mn all contribute to embrittlement. During the heat treatment process, the austenitization temperature and the cooling rate from austenitization have a significant impact on temper brittleness. Measures to prevent temper embrittlement in 2.25Cr-1Mo steel equipment: ① Minimize the elements in the steel that can increase brittleness sensitivity, paying special attention to the weld metal. ② An appropriate heat treatment process must be selected during manufacturing. ③ A hot-start operation plan is adopted. When the equipment is at normal operating temperatures, failure caused by temper brittleness does not occur, as these temperatures are much higher than the brittle transition temperature of the steel. However, after long-term use of 2.25Cr-1Mo steel equipment, if temper brittleness occurs, the transformation temperature increases to a certain extent in all areas, including the base material and welds. Under such circumstances, brittle failure may occur during startup and shutdown processes. Therefore, a higher minimum boosting temperature must be used during startup and shutdown, which is the hot-state startup and shutdown method. During operation, heat the system first and then increase the pressure; when shutting down, reduce the pressure first and then lower the temperature. ④ Control the stress level and the heating/cooling rate during startup and shutdown. The sudden brittle failure that occurs in hardened steel is related to two factors: the stress level and the size of the defects. When the stress level in the material is very high, even a small stress value can cause brittle fracture. Therefore, the stress should be kept within a certain level. Additionally, during startup and shutdown, it is also necessary to avoid excessive rates of temperature change, which could lead to an uneven stress distribution in the reactor body and certain key components, thereby causing significant thermal stress. When the temperature is below 150°C, it is advisable that the heating and cooling rate not exceed 25°C/h. 10. Hydrogen-induced delamination of the surfacing layer: In hydrocracking units, certain equipment used in high-temperature and high-pressure environments (such as reactors) has a stainless steel surfacing layer several millimeters thick applied to its inner surface in order to resist corrosion by hydrogen sulfide; this stainless steel is usually of the austenitic type. Main causes of surfacing layer delamination: Surfacing layer delamination is also a form of hydrogen-induced delayed cracking. In reactors operated in a hydrogen environment under high temperature and pressure, hydrogen will penetrate and diffuse into the vessel walls. Due to the different crystal structures of the Cr-Mo steel (2.25Cr-1Mo steel) used to manufacture the reactor body and the austenitic stainless steels (Tp.309 and Tp.347) used for the cladding layer, the solubility and diffusion rates of hydrogen differ as well. This results in a discontinuous hydrogen concentration at the interface between the cladding layer and the base material. When the reactor is cooled from its normal operating temperature to room temperature, the supersaturation of hydrogen in the base material is much higher than that in the cladding layer; consequently, the hydrogen absorbed in the transition zone – the area where the chemical composition changes due to the dilution of the cladding metal by the base material – diffuses from the side of the base material toward the side of the cladding layer. However, the diffusion coefficient of hydrogen in austenitic stainless steels is lower than that in Cr-Mo steels; as a result, hydrogen diffuses very slowly within the surfacing layer. This leads to the accumulation of large amounts of hydrogen on the side of the surfacing layer at the interface of the transition zone, causing embrittlement. Furthermore, due to the large difference in linear expansion coefficients between the base material and the surfacing layer material, the hydrogen pressure generated by the combination of supersaturated dissolved hydrogen into molecules causes high stresses. These reasons can lead to the delamination of the surfacing layer. This delamination does not occur immediately upon cooling from the operating temperature to room temperature; rather, it becomes apparent after a certain period of time (a specific incubation period is required). Macroscopically, the path of delamination extends along the interface between the surfacing layer and the base material, with delamination occurring between the stainless steel and the base material, which is why this phenomenon is referred to as delamination. Among the many factors that affect the delamination of the surfacing layer, operating temperature and hydrogen pressure are the most important parameters; the higher the hydrogen pressure and operating temperature, the more likely delamination will occur. Because it is closely related to the amount of hydrogen that penetrates into the reactor wall under operating conditions. The higher the hydrogen pressure and temperature, the more hydrogen infiltrates. After exposure to high-temperature and high-pressure hydrogen, the faster it is cooled, the more likely delamination will occur. This is because the cooling rate has a significant impact on the amount of hydrogen absorbed in the transition zone of the surfacing layer. When hydrogen is retained in the transition zone of the surfacing layer, the more times of repeated heating and cooling there are, the more likely delamination will occur and adverse developments will be facilitated. Because of the large difference in linear expansion coefficients between the surfacing layer material and the base material, repeated heating and cooling causes the accumulation of thermal stress. Post-weld heat treatment is also a very important factor affecting delamination. Methods to prevent the spalling of the surfacing layer during operation: It is necessary to strictly follow the regulations regarding temperature and pressure increases as well as decreases, and to control the rate of pressure reduction (usually 1.5–2.0 MPa/h). This helps to allow gases trapped in the steel to escape, reducing internal stresses and thus playing a positive role in preventing spalling. Additionally, it is essential to avoid operating beyond the specified temperature and pressure limits, and to conduct regular inspections of the inner walls of the reactor. 11. Characteristics of H2S-NH3-H2O type corrosion: In hydrocracking units, which often contain sulfur and nitrogen, hydrogenation leads to the formation of corrosive agents such as H2 and NH3 in the reaction effluents; these agents react with each other to form ammonium hydrosulfide, namely NH3 + H2S → NH4HS. The sublimation temperature of ammonium hydrosulfide is 120°C; therefore, during the cooling of this effluent in a high-pressure air cooler, solids often form in the air-cooling tubes and downstream pipes. NH4HS is soluble in water, so water is generally injected upstream of the air cooler for flushing. This results in a notable H2S-NH3-H2O type corrosion. The temperature range in which this corrosion occurs is between 38 and 204°C, which coincides with the typical operating temperature range for such air-cooled equipment. This type of corrosion is mostly localized, generally occurring in high-velocity areas or turbulent zones as well as in dead corners (such as at the inlet of tube bundles or at bends). The main factors affecting this corrosion are: ① the concentration of hydrogen and hydrogen sulfide ； The higher the concentration, the more severe the corrosion ； ②The flow velocity of the fluid within the pipe; the higher the flow velocity, the more severe the corrosion. Of course, if the flow velocity is too low, amine salts will deposit, leading to localized corrosion of the pipe ； ③The presence of certain substances has an impact: for example, the presence of cyanides has a strong effect on corrosion, and the presence of oxygen (mainly introduced through water) also accelerates corrosion, among other things. 12. Hydrogen sulfide corrosion: Hydrogen sulfide is an inevitable gas component in the hydrogenation process. In addition to H2S being generated from the sulfides present in the feedstock during hydrogenation, DMDS also needs to be added during pre-sulfidization. Part of this sulfur reacts with the catalyst, while the excess produces H2S. To maintain the catalyst’s activity, a certain concentration of hydrogen sulfide in the recycled hydrogen is also required. Therefore, hydrogen sulfide corrosion is a problem that cannot be ignored; hydrogen sulfide reacts with iron to form ferrous sulfide. The reaction is as follows: Fe + H2S = FeS + H2. This is a type of rust that is brittle, prone to falling off, and ineffective; it poses a serious threat to reactors, heat exchangers, and high-pressure pipelines. The factors affecting the corrosion rate of hydrogen sulfide are mainly temperature and hydrogen sulfide concentration. At temperatures below 200–250°C, hydrogen sulfide causes little to no corrosion to steel; however, when the temperature exceeds 260°C, corrosion accelerates, and this increase becomes more pronounced as the temperature rises. In particular, between 315–480°C, for every 55°C increase in temperature, the corrosion rate doubles. The higher the hydrogen sulfide concentration and partial pressure, the more severe the corrosion; the rate reaches its maximum when the volume concentration of hydrogen sulfide exceeds 1%. In addition, substances such as water and acidic compounds also affect the corrosion caused by hydrogen sulfide; for example, in the presence of HCl, FeS + HCl → FeCl2 + H2S. Among these, the impact of water is particularly severe. **The \"Regulations on the Inspection of Pressure Vessels\" issued by the Bureau of Quality and Technical Supervision in 1999 define the environment of wet hydrogen sulfide stress corrosion as follows: ① Temperature ≤ (60 + 2P)°C, where P is the pressure in MPa (gauge pressure) ； ②The hydrogen sulfide partial pressure ≥ 0.00035 MPa, which is equivalent to a solubility in room-temperature water of ≥ 10 mg/L ； ③The medium contains liquid water or is below the dew point of water ； ④pH < 9 or the presence of cyanide (HCN). The corrosion caused by wet hydrogen sulfide is mainly due to electrochemical corrosion and the diffusion of hydrogen atoms generated by reactions into the steel. The mechanism is as follows: H2S → H+ + HS–; HS– → H+ + S2–; Fe2+ + S2– = FeS↓; Fe2+ + HS– = FeS + H+; H+ + 2e → 2H↑ (diffuses into the steel) → H2 (cathodic reaction). The ways in which wet hydrogen sulfide causes damage to steel include: ① uniform corrosion. Surface corrosion caused by electrochemical corrosion leads to thinning of the shell wall. ②Hydrogen bubbling (HB). During the corrosion process, hydrogen atoms released penetrate into the steel, where they form hydrogen molecules and accumulate in certain key areas, causing interfacial cracking (without the need for external stress). Bubbles are formed, and their growth is parallel to the surface of the steel plate. ③Hydrogen-induced cracking (HIC). In the areas of hydrogen bubbling within the steel, as the pressure of hydrogen continues to increase, the small bubbling cracks tend to connect with each other, resulting in hydrogen-induced cracking characterized by a stepped pattern. The banding of MnS inclusions in steel increases susceptibility to HIC. The occurrence of HIC does not require external stress. ④Stress-oriented hydrogen-induced cracking (SO-HIC). Stress-guided hydrogen-induced cracking is the development of rows of small cracks perpendicular to the stress direction, which are formed due to hydrogen accumulation at impurities and defects under stress guidance. SOHIC often occurs in the heat-affected zone and areas with high stress concentration at weld joints, where stress concentration is frequently caused by crack defects or stress corrosion cracks. ⑤Sulfide stress corrosion cracking. The hydrogen atoms generated by hydrogen sulfide corrosion penetrate into the interior of the steel and dissolve in its lattice, leading to embrittlement; cracks form under the effect of applied stress or residual stress. Sulfide stress corrosion cracking typically occurs in the high-hardness areas of the weld heat-affected zone. The corrosion caused by hydrogen sulfide not only damages equipment and pipelines, but also the corrosion products that enter the reactor can clog the bed layers, leading to an increase in pressure differences and affecting the start-up time. Methods to prevent corrosion by high-temperature hydrogen sulfide include: ① Controlling the hydrogen sulfide concentration in the circulating gas so that it does not exceed the specified range ； ②Use steel materials resistant to hydrogen sulfide corrosion or adopt anti-corrosion measures, such as stainless steel linings or aluminized steel. Measures to prevent corrosion caused by wet hydrogen sulfide include: for environments with low hydrogen sulfide levels and less severe corrosion, ordinary carbon steel is often used, with an appropriate increase in the corrosion allowance, and post-weld heat treatment to eliminate stress is incorporated into the manufacturing process. For applications with moderate corrosivity, HIC-resistant steel can be used; the most commonly used grades abroad are SA561-Gr.65, 70 (HIC) (similar to 16Mn). For applications with extremely harsh corrosive conditions, an isolation method can be employed, namely by applying a layer of corrosion-resistant metal on the inner wall (or through cladding), such as ferritic stainless steel, duplex stainless steel, nickel alloys, or anti-corrosion coatings.

Another point that is often overlooked is that if steam is introduced into the hydrogen system, it will condense into water droplets. Since the pressure of the circulating gas is usually around 150–170 kilograms, such high pressure drives these water droplets to move rapidly and randomly, exerting a very large force on the pipe walls, which can damage the pipes

Hydrogen-handling equipment generally requires water injection at the back side to prevent ammonium salt crystals from clogging the tube bundles; it should be fine.

Because the pipelines in hydrogen-rich environments are made of special materials, water accelerates their corrosion.