E-book material~Corrosion Prevention and Protection in Petrochemical Refineries (Chapter 6)

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Chapter 6 Analysis of Common Corrosion Cases in the Petrochemical Production Process. In petrochemical plants, corrosion in refineries is a serious issue; the types of corrosion mechanisms, the severity of the corrosion damage, and its impact on safe production are all greater than those in other types of plants. It is the responsibility of equipment managers to understand corrosion mechanisms, master anti-corrosion techniques, and select materials and equipment appropriately for inspection. This textbook uses the latest data from the American Petroleum Institute (API) and the Japanese Petroleum Institute, along with the author’s own experience, to be used as a reference for equipment managers in refineries. Due to time constraints, the charts and examples could not be included in their entirety, and there may be numerous errors; please understand. Section 1: Corrosion-Induced Thinning I. Corrosion by Hydrochloric Acid (HCL) The main refining units where HCl corrosion is a significant problem include crude oil distillation, hydrotreating, and catalytic reforming units. It is commonly referred to as the corrosive environment of H2O + HCl + H2S. Within the crude oil distillation unit, magnesium chloride and calcium chloride salts hydrolyze to form HCl, resulting in a dilute HCl in the overhead system. In hydrotreating units, HCl is formed due to the hydrogenation of organic chlorides in the feedstock; alternatively, HCl enters the unit together with the hydrocarbon feedstock or hydrogen, and condenses along with moisture into the effluent. In catalytic reforming units, chlorides can be stripped from the catalyst and combine with hydrogen, leading to HCl corrosion in the effluent pipelines or regeneration systems. Corrosive hydrochloric acid exists in a very wide range of concentrations; it is corrosive to many common materials, and corrosion typically occurs locally, especially when there are uneven concentrations or \"varying\" concentrations, or when chlorides containing ammonia or amine salts precipitate. Austenitic stainless steels are typically subject to pitting, and may also experience crevice corrosion and/or chloride stress corrosion cracking. If an oxidizing agent is present, or if the alloy has not undergone solution annealing, some nickel-based alloys may experience accelerated corrosion. In typical example distillation units, if carbon steel is used for the atmospheric pressure overhead condenser, the service life of the tube bundle is 2–3 years. The cause of corrosion is dew point corrosion of HCL on the condenser tube. Corrosion morphology: uniform corrosion and pitting corrosion. The inorganic salts in crude oil decompose into HCL when exposed to water during the heating process in the distillation unit; this HCL rises to the top of the tower along with hydrogen sulfide. Since HCL is more soluble than ammonia, it forms a highly acidic environment with a pH of 1–1.3 once it comes into contact with the condensed vapor water, thereby causing corrosion before ammonia does. Organochlorines present in crude oil, either naturally or added during oil extraction, decompose to produce HCL when heated; hydrogen used in the hydrogenation process also reacts with the organochlorines in the feedstock to generate HCL. HCL acts to remove the FeS protective film; as this process repeats itself, the cleaning accelerates the corrosion process. Enhancing the one-extraction-four-output design can effectively prevent corrosion in the low-temperature areas at the top of the tower. Example: The selection of tubing for the tower top condenser in a atmospheric pressure tower top condensation system – the cooling water has an average chloride ion content of 89 PPM. The circulating water temperature of the condenser is 330°C, while the tube wall temperature ranges from 38 to 660°C. The corrosion allowance for the condenser tubes is set at 1.25 millimeters (5 MPY). According to Table 1, the pH value is 2.5. Using Tables 2–5 to estimate the corrosion rate (MPY), the results are as follows: Estimated Corrosion Rate – Material: <380°C: 100; 38–660°C: 300; 66–930°C: 400; >930°C: 560. Remarks: Carbon steel: 300, 801, 402, 200, 250; 825 or 201340200 can be chosen; 625, 121, 575 can be chosen. C-276: 128, 30 can be chosen; B-2: 448, 16 can be chosen. 400, 412, 120, 999. From the above results, materials 825, 20, C-276, or B-2 can be selected; among these, materials 20 and 825 are more cost-effective. Material selection: International standards generally specify Monel alloy (400) and titanium. Titanium has high strength, low density, and a relatively affordable price, which is why many domestic refineries choose it. Two-phase steel 2205 is also used in China, with excellent results. There are very few successful examples of using surface treatment techniques, as the surface treatment process inevitably generates pores; even a single pore can lead to electrochemical corrosion perforation with a large cathode and a small anode. The material selection guidelines recommend carbon steel, duplex steel (2205), titanium, and Monel alloy. Which type to use depends on the quality requirements related to corrosion prevention as well as economic factors; some foreign factories opt for carbon steel in order to enhance corrosion protection (by adding alkali to neutralize HCL), with a tube bundle lifespan of 6 years. The content of organochlorine compounds in domestic crude oil is on the rise, and they have also been detected in Middle Eastern crude oil. The HCl formed by the thermal decomposition of organochlorines in the distillation and fractionation system increases the amount of HCl generated by the decomposition of inorganic salts. Domestically, a one-distillation-three-injection process is adopted; since no alkali is injected, corrosion increases at the condensation section at the top of the tower. A small amount of alkali injection is necessary. II. High-temperature sulfur corrosion and naphthenic acid corrosion: The processing units where sulfide corrosion and naphthenic acid corrosion occur most frequently are atmospheric and vacuum crude oil distillation units, as well as the feed systems of secondary processing units such as hydroprocessing, catalytic cracking, and coking units. In hydrotreating units, naphthenic acid corrosion has never been reported downstream of the hydrogen injection point or even upstream of the reactor. In catalytic cracking and coking units, naphthenic acids are thermally decomposed; therefore, this form of corrosion is generally not reported in the fractionation sections of these units, except in cases where the feedstock has not been cracked. When processing feedstocks containing naphthenic acids, the concentration of naphthenic acids in the lube oil extraction system is very high. It is worth noting that where naphthenic acids undergo thermal decomposition, small organic acids or carbon dioxide are produced, and these can affect the corrosivity of the condensed water. In China, crude oil with a total sulfur content of more than 1% is generally considered high-sulfur crude oil, while crude oil with an acid value of more than 0.5 mgKOH/g is considered acidic crude oil. High-temperature sulfide corrosion is usually a form of uniform corrosion that occurs at typical temperatures above 2040°C. It often causes corrosion in conjunction with naphthenic acids present in oils, whereas the corrosion caused by naphthenic acids is typically localized. Sulfides are naturally present in most crude oils, but their concentration varies depending on the type of crude oil. These naturally occurring compounds not only decompose when heated to form hydrogen sulfide, but they can also be corrosive in themselves. Sulfides are converted into H2S under the action of hydrogen and a catalyst in the hydrotreating unit. As is the case with sulfides, naphthenic acids occur naturally in certain crude oils. During crude oil distillation, these acids tend to concentrate in fractions with higher boiling points, such as heavy atmospheric gasoline, atmospheric residue, and vacuum gasoline. Naphthenic acids may also be present in vacuum residue, but often many more corrosive fractions are separated into the side-stream fractions. Materials with a low boiling point also have a low content of naphthenic acid; generally, when the acid content is low, corrosion manifests as pitting, while when the acid content is high, it takes the form of galling. Corrosion intensifies at high flow rates. Naphthenic acids can destroy the protective films on metal materials (sulfides or oxides), accelerating the rate of sulfide corrosion; they can also cause direct corrosion of the metal. The following outlines the key variables in corrosion: (A) In high-temperature sulfur corrosion environments, materials such as carbon steel and low-alloy steel form sulfide corrosion products, and the extent of protection is related to the aforementioned environmental factors. When the temperature and/or sulfur content are high enough, this corrosion product gradually reduces the protection provided by the material, thereby accelerating corrosion. (B) Adding an appropriate amount of chromium to carbon steel enhances the material’s corrosion resistance. Alloys containing 5%, 7%, and 9% chromium are often sufficient to ensure the corrosion resistance of the material in these environments. Generally, alloys with low chromium content (such as 1-1/4 Cr and 2-1/4 Cr) have not been shown to be more corrosion-resistant than carbon steel. Stainless steels like 12% Cr (410, 410S, 405 SS) and 304 SS can be used in environments with higher sulfur content and temperatures. (C) Sulfidation corrosion is related to the sulfur content present in the material, which is simply expressed as wt% S; generally, corrosion intensifies as the sulfur content increases. (D) High-temperature sulfur corrosion occurs at temperatures above about 2040°C, while the well-known naphthenic acid corrosion takes place in the temperature range of 204–3710°C; however, there are studies reporting that naphthenic acid can also cause corrosion outside this temperature range. Above 4000°C, naphthenic acid either decomposes or is distilled into the vapor phase ； Sulfidation corrosion occurs in both the liquid and vapor phases, whereas naphthenic acid corrosion occurs only in the liquid phase. (E) Most materials susceptible to naphthenic acid corrosion are carbon steels. Iron-chromium (5–12% Cr) alloys are generally used as corrosion-resistant materials; 12% Cr exhibits better corrosion resistance than carbon steel. At low acid levels, 304 SS stainless steel exhibits a certain resistance to naphthenic acid corrosion; however, at high acid concentrations, molybdenum-containing austenitic stainless steels (316 and 317 SS) are commonly used to resist acid corrosion. It has been found that 316-type stainless steel containing 2.5% Mo has the best resistance to naphthenic acid corrosion. (F) The “neutralization index” or “total acid number” (TAN) is the most common way of expressing the amount of naphthenic acids. The various acids that make up naphthenic acids have significantly different corrosive properties. TAN is determined using ASTM standard titration methods, and the results are reported in mg KOH/g; this value represents the amount of KOH required to neutralize the acids in 1 gram of oil sample. When both chromatic titration and potentiometric titration are used, the potentiometric method specified in ASTM D 664 is more widely adopted. It should be noted that neutralization titration neutralizes all acids present, not just naphthenic acids. For example, a hydrogen sulfide solution will represent the TAN of the sample. From a corrosion perspective, the TAN value of hydrocarbons is more valuable than that of crude oil as a whole; the TAN of hydrocarbons is an important parameter for determining the corrosion sensitivity to naphthenic acids. (G) Another important factor in corrosion is the flow rate of the material, especially in the presence of naphthenic acids. The increase in flow velocity enhances corrosivity by accelerating the removal of protective sulfides; this effect is most pronounced in liquid-vapor two-phase systems with very high velocities. When the flow velocity exceeds 30 m/s, the corrosion rate increases by 5 times. (H) At extremely low sulfur levels, and even when TAN is low, naphthenic acid corrosion may be more severe because protective sulfides may not have formed rapidly enough. Typical example: Distillation units experience severe corrosion at temperatures above 3000°C, under conditions of high flow rates and surging. Material selection: Based on the revised McMonomy curve (see Appendix A) and the SH/T 3096-2001 Guidelines for Material Selection in the Design of Key Equipment for Processing High-Sulfur Crude Oil. According to SH/T 3129-2002 “Guidelines for the selection of materials for main pipelines in key units processing high-sulfur crude oil”, Section 3, High-temperature H2S/H2 corrosion: H2S/H2 corrosion typically occurs in hydrogenation units, such as hydrodesulfurization units and hydrocracking units. High-temperature H2S/H2 corrosion is generally a form of uniform corrosion that occurs at typical temperatures above approximately 204°C. This form of sulfur corrosion is distinct from high-temperature sulfur and naphthenic acid corrosion. Once the sulfur-containing compounds undergo a catalytic reaction with H2, they are converted into hydrogen sulfide. In the presence of H2, the typical transformation of sulfur-containing compounds into H2S does not occur on a large scale; this is true even at high temperatures, unless a catalyst is present. Its corrosion rate is a function of the material structure, temperature, type of material being processed, and H2S concentration. In an H2S/H2 environment, a small amount of chromium (e.g., 5–9% Cr) can only moderately improve the corrosion resistance of steel. To significantly enhance the steel’s corrosion resistance, the Cr content must be at least 12%. If Cr and Ni are added further, the corrosion resistance of the steel can be substantially improved. Typical example: The distillation column of the residue hydrogenation unit in a refinery, with an operating pressure of 3.0 MPa, an operating temperature of 380°C, and tube material CR5MO. The oil produced from the thermal high-temperature bottom stream, along with hydrogen and hydrogen sulfide, is heated in a heater before being sent to the distillation tower. After three years of operation, it ruptured and caught fire due to the thinning of the furnace tube walls. Subsequent examination of the corrosion curve confirmed that 18-8 material should be selected, as the original CR5MO was not resistant to corrosion by hydrogen and hydrogen sulfide. Material selection: The correlation proposed by Couper and Gorman for determining the corrosion rates in hydrocarbon-free and hydrocarbon-containing environments is utilized (see Appendix C), along with the SH/T3096-2001 Guidelines for Material Selection in the Design of Key Equipment for Processing High-Sulfur Crude Oil, and the SH/T3129-2002 Guidelines for Material Selection in the Design of Key Pipelines for Processing High-Sulfur Crude Oil. IV. Corrosion by hydrofluoric acid (HF): Concentrated hydrofluoric acid is commonly used in alkylation units where acid serves as a catalyst. Alkanes (usually isobutane) and olefins (butene, propylene, pentene) undergo alkylation reactions in an environment with acid as a catalyst. Both solutions and vapors of hydrofluoric acid pose serious threats to human health. Once it overflows, it will form dense, low-lying, highly toxic clouds. Therefore, special care must be taken when using hydrofluoric acid. The corrosion caused by hydrofluoric acid is mainly related to its concentration and temperature. Other factors such as flow velocity, turbulence, oxygen content, and impurities also have a significant impact on corrosion. Some materials form a fluoride protective film on their surface; once this protective layer is lost, corrosion is likely to accelerate, especially under conditions of high flow or turbulence. When the concentration of hydrofluoric acid exceeds 80%, its corrosive effect is attributed to anhydrous hydrofluoric acid (AHF, 0.5%). When the flow rate is below 1.5–3.05 m/s or above 7.62 m/s, Monel high-alloy material should be used. The tube bundles in domestic high-pressure air coolers are all made of carbon steel. Due to changes in the properties of the raw materials, the concentrations of corrosive substances such as H2S, NH3, and NH4HS have increased significantly, accelerating corrosion of the tube bundles. The corrosion rate is 0.5–0.6 mm/year. It is not certain that these coolers can handle high-sulfur crude oil; after all, the characteristic corrosion mechanism in reaction distillate air coolers is corrosion caused by NH4HS, which is formed as a result of reactions between H2S and NH3 present in the fluid. Therefore, the main factors affecting corrosion are the concentrations of H2S and NH3. According to the patterns identified by the American Society of Corrosion Engineers in a survey of numerous such air coolers conducted in 1975, the product of the molar concentrations of H2S and NH3 in the feed to the air cooler is defined as the Kp value; when Kp