The corrosion problem of H2S

H2S itself is not highly corrosive, but it can easily destroy the oxide layer on the surface of stainless steel, allowing corrosive substances to cause corrosion of the stainless steel.

First, the original poster needs to clarify the environment in which hydrogen sulfide corrosion occurs – is it high temperature or low temperature? Only by knowing the specific medium conditions can we determine the degree of corrosion and select the appropriate material? Corrosion by high-temperature hydrogen sulfide (above 220 degrees) is more affected by temperature than by concentration; however, since the corrosive product ferrous sulfide forms a protective layer, the corrosion is not severe. High-chromium steels such as Cr9 and 0Cr13 can be used for this purpose. For low-temperature hydrogen sulfide corrosion (below 120 degrees), there is no corrosion in the anhydrous condition; in the presence of water, it is what is commonly referred to as wet hydrogen sulfide corrosion. The forms of this corrosion include hydrogen blistering, hydrogen-induced cracking, stress-induced hydrogen-induced cracking, and sulfide stress corrosion cracking. Carbon steel and low-alloy steel are sensitive to wet hydrogen sulfide corrosion. The use of steel resistant to HIC minimizes susceptibility to hydrogen embrittlement and HIC damage; detailed material and forging guidelines can be found in NACE Publication 8X194.

To deal with low-temperature wet hydrogen sulfide corrosion, 09Cr2AlMoRe or 08Cr2AlMo can be used.

Materials such as S32003/N08367/N6625 can all be used in H2S environments, but their application depends on temperature and concentration; 625 has the highest tolerance

Our company uses 08Cr2AlMo material for H2S, and the results are good

A516-70 per the American standard can be used, with controlled low levels of P and S; it is a typical HIC-resistant steel.

High-temperature corrosion of sulfides is essentially active sulfur corrosion driven by H2S; at high temperatures, organic sulfides can be converted into active sulfur of sulfides, which then reacts with the surface of carbon steel to cause corrosion. The equipment corrosion in the stabilization systems at the top of the fractionation tower and the absorption tower is actually high-temperature hydrogen chloride corrosion, as well as low-temperature chloride stress cracking corrosion. Domestic corrosion investigations show that the uniform corrosion of carbon steel equipment by wet hydrogen sulfide reaches its highest rate at 80 °C, while the corrosion rate is lowest at 110–120 °C. At the beginning of operation, the corrosion rate can reach 1 mm/a; as operation time increases, this rate rises rapidly. After 1,500–2,000 hours of operation, the corrosion rate approaches 0.3 mm/a. This shows that H2S-induced corrosion is not very significant. However, since the crude oil being processed contains large amounts of chlorides such as sodium chloride, calcium chloride, and magnesium chloride, these substances decompose when heated above 100°C in contact with water, producing hydrogen chloride gas. Even at lower temperatures, if naphthenic acids are present, sodium chloride can also hydrolyze, becoming a major source of hydrogen chloride in the crude oil. The chlorine content in the corrosive substances is 27.2%, which is much higher than the sulfur content of 10.2%. It can be seen that the corrosives in the distillation column top and the absorption and stabilization system are mainly caused by HCl, followed by H2S.

The content of different metal components in the material directly affects its corrosion resistance; for example, the higher the levels of Cr and Ni, the greater the material’s corrosion resistance. Therefore, when selecting a material, it is advisable to choose ones with high levels of Cr and Ni in order to prevent sulfur from causing corrosion in the equipment.

Different environments and different H2S-containing working media need to be analyzed comprehensively; in most cases, tests are required to select the material with the best cost-performance ratio. Not the best, but the most suitable.

Here is my recent essay for reference: 3.0 Material Selection and Mitigation Measures in Wet Hydrogen Sulfide Environments 3.1 Equipment and pipelines made of carbon steel or low-alloy steel used in wet hydrogen sulfide stress corrosion environments must meet the following requirements: ① The materials used should be killed steel； ② The material should be in a hot-rolled state (limited to carbon steel), annealed, normalized, normalized + tempered, or quenched and tempered state ； ③ The carbon equivalent CE of the material shall not be greater than 0.43 ； CE = C + Mn/6 + (Cr + Mo + V)/5 + (Ni + Cu)/15 ； In the formula: the symbols of various elements represent the percentage content of those elements in the steel ； ④ Carbon steel or low-alloy steel pipe components formed by hot working shall undergo heat treatment to restore their mechanical properties, and their hardness shall not exceed HB225 ； ⑤ For equipment or pipeline components made of carbon steel or low-alloy steel that are subjected to cold forming, stress-relief heat treatment shall be carried out after forming when the degree of cold deformation exceeds 5%, and their hardness shall not exceed HB200. However, for carbon steel pipe components, stress-relief heat treatment is not required when the degree of cold deformation is no more than 15% and the hardness is no more than HB190 ； ⑥ When the thickness of the steel plate used for equipment enclosures or welded pipes is greater than 20 mm, ultrasonic testing shall be carried out in accordance with JB/T4730, and it must meet the requirements of grade II ； ⑦ In principle, stress-relief heat treatment should be carried out on equipment or pipelines after welding, and the heat treatment temperature should be set at the upper limit specified by the standards. The hardness of welded joints made of carbon steel or carbon-manganese steel after heat treatment should not exceed HB200, while the hardness of base materials and welded joints made of other low-alloy steels should not exceed HB237. For weld joints that cannot undergo post-weld heat treatment, welding procedures should be employed to ensure a hardness of no more than HB185 (limited to carbon steel). ⑧ The hardness must be determined using a hammer impact testing method; HB values obtained through other methods cannot be used. 3.2 Equipment and steel plate coiled pipes made of carbon steel or low-alloy steel that operate in an environment subject to severe corrosion by wet hydrogen sulfide must, in addition to meeting the existing requirements, also comply with the following requirements: ① The material shall be in a normalized, normalized+tempered, or quenched and tempered state ； ② When the tensile strength of the material is greater than 480 MPa, its chemical composition must be such that S ≤ 0.002%, P ≤ 0.008%, and Mn ≤ 1.30%; in addition, a HIC resistance test or a constant-load tensile test (NACE TM0177) must be carried out. Steel resistant to hydrogen-induced cracking is expensive. Most refineries now use these steels only for the most critical equipment under the harshest operating conditions, such as the air cooler tube banks and separators in hydrocracking effluent systems ； 3.3 Equipment and pipelines made of other materials used in wet hydrogen sulfide stress corrosion environments shall meet the following requirements: ① The hardness of the base metal and welded joints of chromium-molybdenum steel equipment and pipelines after heat treatment shall not exceed HB225 (1Cr-0.5Mo, 1.25Cr-0.5Mo), HB235 (2.25Cr-1Mo, 5Cr-1Mo), or HB248 (9Cr-1Mo) ； ② The hardness of the base metal and welded joints of ferritic stainless steels, martensitic stainless steels, and austenitic stainless steels shall not exceed HRC 22; the carbon content in austenitic stainless steels shall not be greater than 0.10%, and such steels shall have undergone solution treatment or stabilization treatment ； ③ The hardness of the base metal and welded joints of duplex stainless steel shall not exceed HRC 28, and its ferrite content shall be within the range of 35–65% ； ④ The hardness of carbon steel bolts should not exceed HB200, while the hardness of alloy steel bolts should not exceed HB225. ⑤ The valve core material should preferably be stainless steel from the 12Cr or 18Cr-8Ni series; when a carbon steel valve core is used, its hardness value should not exceed HB200. 3.4 Other mitigation measures ① Protecting the steel surface (including the alloy coating and paint) from the effects of wet hydrogen sulfide ； ② Process changes that affect the pH of the aqueous phase and/or the concentration of ammonia or cyanide can help reduce damage. A common practice is to use wash water injection to dilute the HCN (hydrogen cyanide) concentration, for example in fluidized bed catalytic cracking units ； ③ Note: Ammonium polysulfide is a corrosion inhibitor that can convert cyanides into harmless thiocyanates ； ④ Hydrogen-cracking-resistant steels can be used to minimize susceptibility to bulging and hydrogen-cracking damage. Detailed material and construction guidelines can be found in NACE Publication 8X194 ； ⑤ Sulfide stress corrosion cracking can generally be prevented by methods such as preheating, post-weld heat treatment, control of welding procedures, and carbon equivalent control, in order to limit the hardness of the welds and heat-affected zones to a maximum of 200 HB. Depending on the operating environment, small areas with a hardness of 22HRC should be able to resist sulfide stress corrosion cracking. For other details, see NACE RP0472 ； ⑥ Post-weld heat treatment can help minimize the sensitivity to stress-induced hydrogen cracking. Post-weld heat treatment has limited value in preventing the formation of bulges and hydrogen-induced cracking damage, but it helps to reduce residual stresses and strength levels, which otherwise could promote crack propagation. ⑦ However, it is best to use wet fluorescent magnetic powder, eddy current testing, radiographic testing, or AC magnetic flux leakage testing methods for crack detection ； ⑧ Ultrasonic testing methods, including external ultrasonic shear wave testing, can be used. Ultrasonic shear wave testing is particularly effective for volume inspection and crack size assessment ； ⑨ Grinding away the cracks or removing them using thermal arc air gouging is a viable method for determining the depth of the cracks ； Acoustic emission testing can be used to monitor crack propagation ； ⑩ Avoid deformation, bending, cold working, and shot blasting of the metal. ⑪ Use hydrogen-crack resistant alloys, such as Monel (70% nickel, 30% copper), Inconel, and 300 series stainless steels.

Ultimately, isn’t H2S corrosion still caused by hydrogen ions turning into hydrogen, leading to hydrogen-induced cracking?

High-temperature hydrogen sulfide causes chemical corrosion; it may produce a small amount of hydrogen, but this is generally not sufficient to cause hydrogen corrosion. Wet hydrogen sulfide causes electrochemical corrosion; the hydrogen atoms generated adhere to and penetrate into steel, and these hydrogen atoms in the steel lead to hydrogen embrittlement, which in turn triggers sulfide stress corrosion cracking ； Hydrogen atoms that migrate to defects such as metal inclusions can combine to form hydrogen gas, generating high internal pressures that lead to the formation of hydrogen bubbles and hydrogen-induced cracking ； Under high tensile stress, the development of hydrogen-induced cracking along the wall thickness can lead to stress-guided hydrogen-induced cracking.