Analysis of the corrosion mechanism on the inner wall of light hydrocarbon storage tanks in the petrochemical industry

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This post was last edited by Wang Wei2 on 2020-6-23 at 14:00. Analysis of the corrosion mechanism on the inner wall of light hydrocarbon storage tanks in the petrochemical industry. Light hydrocarbon storage tanks are one of the main stationary devices in natural gas production. Due to the severe corrosion of the inner wall, large amounts of money are spent each year on repairs, requiring significant investment in human resources, materials, and financial resources. This not only increases costs but also gradually creates potential hazards that could lead to accidents. Therefore, it is necessary to investigate the corrosion condition of light hydrocarbon storage tanks, study their corrosion mechanisms, and propose effective anti-corrosion measures to control corrosion, thereby reducing maintenance costs, extending service life, lowering production costs, and ensuring safe operation. The corrosion of metals occurs under the influence of two or more factors, and the same is true for the corrosion of light hydrocarbon storage tanks. 1. Electrochemical corrosion caused by water contained in light hydrocarbon liquids: For production purposes, small amounts of water are mixed into light hydrocarbons. At the areas where the coating is damaged, iron reacts with water through the following electrochemical reactions: Anodic reaction: Fe → Fe2+ + 2e-. Anodic reaction: 1/2O2 + H2O + 2e- → 2OH-. Overall reaction: Fe2+ + 2OH- → Fe(OH)2. Further oxidation occurs: 4Fe(OH)2 + O2 + 2H2O → 4Fe(OH)3. Iron hydroxide loses some water to form rust: 2Fe(OH)3 + 2H2O → Fe2O3·H2O. Under normal conditions, the rate of these electrochemical reactions is not very fast; it does not reach the high rates of 0.4–1.4 mm/year mentioned above. So what is it that causes such a high corrosion rate of the tank walls? This should be analyzed from the perspective of galvanic corrosion. When the anti-corrosion coating is damaged, the potential of the exposed metal is more negative (the standard electrode potential for iron is -0.44 V), while the electrode potential of the coating is more positive; this creates a corrosion cell between the exposed metal and the coating. The anode is the metal exposed beneath the damaged coating, while the cathode is the coating that has not been damaged. It is particularly important to emphasize that the corrosion cell formed here has a large cathode and a small anode; under such conditions, the corrosion rate increases exponentially, resulting in the higher corrosion rate mentioned above. According to the XPS analysis results, the component in the oxide sample is iron tetraoxide. The reason is that the samples taken were obtained from waste light hydrocarbon tanks that had been exposed to air for a long time; Fe2O3·H2O on the tank walls reacted with oxygen in the air over time to form magnetite. 2. Hydrogen sulfide corrosion: Hydrogen sulfide dissociates in aqueous light hydrocarbon liquids: H2S → H+ + HS-, HS- → H+ + S2-. The corrosion of tank walls by such light hydrocarbon liquids containing H2S is an electrochemical reaction: Anodic reaction: Fe → Fe2+ + 2e; Cathodic reaction: 3H+ + 3e → H2 + H+, Fe2+ + S2- → FeS. It can be seen that the final product of hydrogen sulfide corrosion is FeS. Although the FeS film is insoluble in light hydrocarbon liquids, it does not provide protection; the corrosion process mentioned above can continue beneath the film, and at an even faster rate. H2S corrosion can also be verified from the following three aspects: (1) Generally, H2S causes corrosion of steel in the form of general corrosion, which leads to a \"uniform\" thinning of the metal surface, often resulting in an uneven surface texture. (2) When metal is corroded by H2S, scale-like sulfide corrosion products are formed. (3) The corrosion products of iron sulfide are sometimes flaky and sometimes in the form of black sludge. The dark brown corrosion products illustrate this.