Process corrosion protection for atmospheric and vacuum distillation units

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Process anti-corrosion for atmospheric and vacuum distillation units 1 Introduction In recent years, the volume of crude oil processed and the amount of crude oil imported by Sinopec have increased rapidly. To reduce the cost of crude oil procurement, refineries are increasing their purchases of crude oils with high sulfur and acid content, such as those with a sulfur content of 1%–2% or an acid value (KOH) of 0.5–1.0 mg/g. The new problems arising from the deterioration of crude oil properties are first and foremost reflected in atmospheric and vacuum distillation units, severely affecting their production, safety, and equipment corrosion protection, as well as having an adverse impact on downstream units as well. Based on recent field investigations at enterprises, the current corrosion issues in atmospheric and vacuum distillation units have been analyzed and summarized, along with some measures and recommendations proposed. 2 The hazards of corrosion: It is reported that in industrialized countries, the economic losses caused by corrosion damage account for approximately 3% to 5% of the Gross National Product (GNP). In the United States, at 1995 price levels, the economic losses caused by corrosion each year amount to approximately 300 billion dollars. A 1978 research report used a carefully designed model that took into account more than 130 economic factors, and found that metal corrosion caused the United States to suffer economic losses of $82 billion in 1975, accounting for approximately 4.9% of that year’s GNP. The report states that 60% of the economic losses were inevitable, while the remaining 40% could have been avoided had the best anti-corrosion measures been used at the time. Despite differences in the properties of the crude oil processed by various refineries, as well as in the design of their facilities and operating conditions, the 9 units at the 5 companies surveyed in 2004 experienced severe problems related to low-temperature corrosion, including corrosion and perforation of the \"three top pipelines,\" internal and external leaks in heat exchangers and air coolers, and cracks in certain areas. In November 2003, a leak was detected at the weld of the gauge connection for a heavy oil high-temperature pipeline in Unit 3’s pressure reduction device at a certain enterprise ； Further inspection revealed that the thickening of most atmospheric-pressure heavy oil high-temperature pipelines was extremely severe. The pipeline was in operation for only 18 months from its commissioning until a leak occurred, with an average thinning of 3–5 mm ； The thinnest part of the radiation outlet pipeline in the atmospheric pressure furnace is only 3 mm. In another plant, its 5,000 kt/a atmospheric and vacuum distillation unit had been in operation for over a year after maintenance when a fire broke out due to corrosion and perforation of the collector pipe at the outlet of the atmospheric furnace. The unit was kept running by applying a cladding solution; thickness measurements revealed significant thinning in the high-temperature heavy oil lines, with an average thinning of 3–4 mm. In another company, the internal components of the vacuum tower in Unit III of its atmospheric and vacuum distillation unit – namely the girders, liquid drop trays, and packing – suffered severe damage, posing a significant threat to production. 3 Discussion on corrosion mechanisms 3.1 Low-temperature corrosion The corrosive agents involved in low-temperature corrosion are mainly HCl-H2S-H2O; the areas affected by this corrosion are the initial distillation tower, atmospheric tower, and vacuum tower of the atmospheric and vacuum distillation unit, as well as the condensation and cooling systems at the top of these towers. The cause of corrosion is the presence of certain amounts of chlorides in crude oil; even after desalination, trace amounts of magnesium salts, calcium salts, and even sodium salts remain. MgCl2 and CaCl2 begin to hydrolyze at temperatures below 200°C, while NaCl starts to hydrolyze at 300°C, producing hydrogen chloride. In the presence of liquid water, hydrochloric acid is formed, which causes severe corrosion: Fe + 2HCl → FeCl2 + H2. When hydrogen sulfide is present, the following reactions occur: FeCl2 + H2S → FeS↓ + HCl; Fe + H2S → FeS↓ + H2; FeS + 2HCl → FeCl2 + H2S. These reactions create a cycle that exacerbates corrosion. Corrosion in the low-temperature sections of atmospheric and vacuum distillation is mainly caused by the hydrolysis of inorganic salts present in the crude oil, and it has little to do with whether the crude oil contains acids or sulfur. Studies show that the salt content in crude oil is generally proportional to the corrosion rate of equipment, as shown in Figure 1. It can be seen that salt content in crude oil is the fundamental cause of corrosion. 3.2 High-temperature corrosion: High-temperature corrosion is mainly caused by active sulfur and naphthenic acids. High-temperature sulfur corrosion is primarily caused by hydrogen sulfide, thiol compounds, and elemental sulfur; these substances can undergo chemical reactions with metals at temperatures around 350–400°C: H2S + Fe → FeS + H2; RCH2CH2SH + Fe → FeS + RCH=CH + H2. Hydrogen sulfide decomposes at 340–400°C according to the following equations: H2S → S + H2; S + Fe → FeS. Thioethers and disulfides decompose at around 240°C, turning into thiol compounds, sulfur, and hydrogen sulfide. For example, thioethers decompose at high temperatures to yield elemental sulfur and hydrogen sulfide: RCH2CH2S—SCH2CH2R → RCH2CH2SH + RCH2CH2S + H2; RCH2CH2S—SCH2CH2R → RCH=CH-S-CH2CH3 + H2S + 2H2. When the acid value (KOH) of naphthenic acid is greater than 0.5 mg/g, corrosion caused by naphthenic acid is most severe at temperatures of 270–280°C and 350–400°C. Naphthenic acid does not cause corrosion at low temperatures; corrosion is most severe near its boiling point, especially in an anhydrous environment. The reactions are as follows: 2RCOOH + Fe → Fe(RCOO)2 + H2; FeS + 2RCOOH → Fe(RCOO)2 + H2S. Cycloanoic acid reacts with iron to form oil-soluble iron cycloanoate, which physically adsorbs on the metal surface; however, it does not easily form a protective layer. As the oil flows, the active metal surface remains exposed. Especially when the flow rate increases, impurities in the oil scour the metal surface, resulting in groove-like corrosion. The corrosivity of naphthenic acids is related to their molecular weight, with lower-molecular-weight naphthenic acids being the most corrosive. At temperatures below 220°C, naphthenic acid causes little corrosion. As the temperature rises, the corrosivity increases gradually, reaching its highest level at 270–280°C. As the temperature rises further, the naphthenic acid partially vaporizes without condensing, and the concentration of naphthenic acid in the liquid phase decreases, thus reducing its corrosivity again. At around 350°C, the vaporization rate of naphthenic acids increases, the velocity of the gas phase rises, and corrosion intensifies. By around 425°C, almost all of the naphthenic acids in the crude oil have vaporized, and no further corrosion occurs in the high-temperature parts of the equipment. 4 Analysis of Existing Problems and Countermeasures 4.1 Corrosion in Low-Temperature Areas and Protection Measures Although the salt content in the effluent from the vacuum distillation units of most companies is generally below 3 mg/L, there are still some companies where this value is extremely high, even exceeding 10 mg/L ； Even though the salt content after desalination generally meets the requirement of below 3 mg/L, the iron ion concentration in the initial, normal, and reduced-pressure condensate water from many units still reaches 5 mg/L, or even exceeds 10 mg/L, indicating severe corrosion. Therefore, it is essential to operate electrodialysis properly and ensure effective “one removal and three injections”. (1) The main reasons for the high salt content after electrodialysis desalination are as follows: 1) The properties of crude oil vary greatly; the selection of demulsifiers and the monitoring of their effectiveness are not carried out in a timely manner, resulting in suboptimal performance despite the use of demulsifiers at concentrations of 20–70 mg/L, which leads to poor desalination results ； 2) The operating temperature for electrodesalination is relatively low, typically only 110–120°C, and it is not adjusted according to the properties of the oil. 3) Poor quality of water used for injection: Some companies use fresh water with a high content of impurities for electrodialysis processes, while other companies employ wastewater that has been purified by steam stripping; however, the quality of this water is still poor. In some cases, the NH3-N concentration is as high as 400 mg/L, the H2S concentration is 200 mg/L, and the pH value is as high as 9 ； To address these issues, the following measures are recommended: 1) Start from the source by stabilizing the types and mixing ratios of crude oil, in order to maintain consistency in the properties of the crude oil fed into the vacuum distillation units and avoid significant fluctuations in those properties. Carefully select demulsifiers with good adaptability, high demulsification efficiency, and low dosage, and strictly control their usage amount. Strictly control the quality of demulsifiers entering the factory; do not use demulsifiers that fail to meet technical, quality, or performance standards ； 2) Depending on the properties of the crude oil, adjust the operating temperature of electrodesalting to 130–140°C, and adjust the intensity of oil-water mixing ； 3) Ensure the quality of water used for electrodesalination. For issues that cannot be resolved immediately, steam condensate or other low-salinity water can be used, and the secondary water can be reinjected back into the primary system ； 4) For plants that process crude oils with significant differences in their intermittent processing properties, different demulsifiers can be used depending on the characteristics of each crude oil, along with appropriate operating conditions, and these can be established as standard procedures. Adjust the oil level properly and make timely adjustments to the operation. (2) Ammonia injection, water injection, and corrosion inhibitor injection: Injecting ammonia into the overhead distillation line of the fractionation tower is an effective measure for preventing corrosion in low-temperature areas. Ammonia neutralizes HCl and H2S, adjusts the pH value of the condensation and cooling system, reduces corrosion, and ensures the effectiveness of the corrosion inhibitors. Corrosion inhibitors contain polar groups within their molecules, which allow them to adsorb onto the metal surface and form a protective film that prevents corrosive agents from coming into contact with the metal surface, thereby providing protection. Water injection can shift the dew point forward to protect the equipment, and it can also dissolve NH4Cl for washing. At present, the facilities and management related to the \"three injection\" processes have the following issues: 1) The ammonia injection systems in some units are not well-designed, which prevents uniform and adequate injection of ammonia; as a result, the pH value of the condensate water at the top of the tower fluctuates greatly, making it impossible to effectively neutralize HCl and H2S, and this also affects the effectiveness of the corrosion inhibitors ； 2) In some units, the water injection at the top of the tower does not operate properly, or the amount of water injected is too low (or none at all), resulting in the desired effect not being achieved ； 3) Improper selection and use of corrosion inhibitors. As a result, even with usage levels as high as 15–20 mg/L, it is not possible to achieve an inhibition rate of over 90%. Some corrosion inhibitors are not suitable for the corrosion prevention of sulfur-containing or high-sulfur crude oils ； The effective concentration of some corrosion inhibitors is low, requiring high doses for use ； The performance of corrosion inhibitors is unstable, resulting in different effects for the same amount ； The injection volume distribution is not entirely reasonable; the distribution of the three types of corrosion inhibitors does not match the level of corrosion at those three locations. The following measures are recommended to strengthen the management of the \"three injections\": 1) Improve the facilities for ammonia injection, water injection, and corrosion inhibitor injection, so as to ensure uniform distribution, multi-point injection, and adjustable functionality, thereby maintaining an alkaline corrosion-inhibiting environment throughout the entire low-temperature system from the top of the tower to the point where condensation is completed ； 2) Improve the analysis, monitoring, and control management system for post-distillation salt content, Fe2+ and Cl- levels at the tower top, as well as pH value. It is recommended to analyze the salt content after desalination, as well as Fe2+ and Cl- levels at the tower top, once a day; the pH value should be checked once per shift. This provides accurate, comprehensive, and reliable data support for optimizing operational procedures and assessing the effectiveness of corrosion inhibitors ； 3) Select appropriate corrosion inhibitors and strictly control the quality of materials entering the factory. The oil-phase corrosion inhibitors can be reused through top reflux, resulting in minimal losses, while the water-phase corrosion inhibitors are discharged along with the condensate; therefore, using oil-soluble corrosion inhibitors is more economical ； 4) The corrosion inhibitor should be injected at multiple points in a uniform manner to maintain a stable concentration of the inhibitor. The injection amount should be adjusted according to the Fe2+ content, in order to prevent the protective film from being repeatedly damaged and repaired, which could affect its effectiveness. For low-temperature corrosion in atmospheric and vacuum distillation processes, anti-corrosion measures primarily rely on the \"one removal and three injections\" process, with material selection for equipment serving as a supplementary measure. The process parameters to be maintained after applying the \"one removal and three injections\" approach are as follows: the salt content in the crude oil after desalination should be less than 3 mg/L (it can be less than 5 mg/L in cases where no further processing is carried out); the Fe2+ content in the condensate water should be less than 1 mg/L; the chloride ion content in the condensate water should be less than 20 mg/L; and the pH value should be kept between 7.5 and 8.5. 4.2 Corrosion and Protection in High-Temperature Areas There are many factors that affect corrosion in high-temperature areas, such as temperature, the content of active sulfur, fluid flow rate, material type, and the content of naphthenic acids. Regarding corrosion in high-temperature areas, the following problems exist: (1) The sulfur or acid content in the crude oil processed by some companies exceeds the values permitted by design. Due to a shortage of crude oil resources, it is necessary to process crude oil of lower quality. These companies lack experience in processing high-sulfur, high-acid crude oil as well as an understanding of the severity of corrosion; they also fail to take appropriate measures, which leads to increased corrosion of the equipment. The corrosion and perforation of the collector pipe at the outlet of the atmospheric furnace, which resulted in a fire accident, falls into this category ； (2) The technical evaluation of the materials selected is not thorough enough; in particular, there is insufficient assessment of the properties of the process media and the potential problems that may arise. Additionally, although the chemical properties of the selected materials meet the design requirements, their mechanical properties may be poor, and the corrosion margin designed for the components inside the tower might be too small. The severe failures of the beams, liquid drop trays, and packing in the vacuum distillation tower mentioned earlier fall into this category ； (3) New circumstances have arisen. In the No. 3 atmospheric and vacuum distillation unit of a certain plant, corrosion and perforation as well as thinning in the area handling high-temperature heavy oil occurred because the unit continuously processed crude oil with an acid value (KOH) of around 0.3–0.5 mg/g and a sulfur content of 0.23%–0.46% for over 130 days; as a result, corrosion worsened gradually, at a rate of 2–3 mm per year. Observation of the removed furnace tubes, pipelines, etc. suggests that the corrosion was primarily acid-induced, with corrosion patterns in the form of pits and grooves. The preliminary analysis of the reasons is as follows: when the acid value of crude oil (KOH) exceeds 0.3 mg/g, and as the sulfur content increases beyond this value (sulfur content greater than 0.3%), the corrosion products are mainly ferrous sulfide, with very little ferrocyclohexanecarboxylate being formed, resulting in mild corrosion. If the sulfur content increases further, the resulting ferrous sulfide protective layer becomes thick but not dense, and it is relatively brittle, prone to peeling off, which in turn exacerbates corrosion. When the acid content increases further while the sulfur content falls below the value corresponding to the acid number, the entire system exhibits severe naphthenic acid corrosion ； (4) In terms of equipment monitoring, there is a problem of insufficient connection and coordination between process management and equipment management. Monitoring and identifying the causes are carried out only after corrosion occurs as a result of changes in the properties of the crude oil ； During the cause analysis process, there was insufficient communication among specialists, and fault diagnosis was not carried out in a timely manner ； (5) In the process monitoring method, some aspects are not thorough enough, and the accuracy and comparability of the data are poor. Some units don’t even have monitoring facilities and rely solely on experience for estimation. 5 Main countermeasures (1) Raise awareness of the severity of corrosion in the equipment. Senior corporate management and those responsible for crude oil planning must have a clear understanding of the suitability of crude oil for the company’s processing facilities; by addressing this issue at its source, they should make every effort to ensure that crude oil suitable for processing is supplied to the plant. Due to objective constraints, once low-quality crude oil enters the plant, it is necessary to make full use of the existing inventory for blending, improve the management of processes and equipment, and take appropriate measures to reduce the degree of corrosion and keep it under control. (2) For plants that process low-sulfur crude oil and whose equipment has not been upgraded, they can draw on the monitoring practices of companies that have encountered problems: comparative monitoring, residual life assessment, adjustment of production load, and adjustment of the acid-sulfur ratio of the crude oil fed into the plant ； A special monitoring team composed of process and equipment management personnel was established to enhance oversight, thereby alleviating the high corrosion rate. If the headquarters has planned to downgrade the quality of crude oil varieties, material upgrades should be carried out as soon as possible based on the actual situation, and care should be taken to avoid the aforementioned issues when selecting materials. (3) Conduct necessary research on the ratio of oil types, particularly carrying out in-depth studies on the corrosion effects resulting from the combined influence of factors such as acid value, sulfur content, and medium flow rate. Identify theoretical foundations to guide the blending of crude oil, production processes, and equipment management, and improve and revise the established SH/T 3096-2001 \"Guidelines for Design and Material Selection of Key Equipment in Facilities Processing High-Sulfur Crude Oil\". (4) Strengthen the integration of planning, process, and equipment management. The types of crude oil planned to be purchased must be approved by process engineers; information and resources related to process management should be shared with equipment management. Equipment management departments should proactively communicate with process management departments to keep track of changes in the properties of crude oil, provide timely recommendations, and predict potential problems. (5) Conduct a comprehensive inspection of the installations, equipment, and auxiliary systems that may experience increased corrosion due to the deterioration of crude oil, and establish relevant inspection rules and requirements to ensure the reliability, accuracy, and comparability of the inspection results. 6 Conclusions (1) As crude oil resources become scarce and its quality deteriorates, many new problems and challenges arise in terms of corrosion prevention in atmospheric and vacuum distillation units, which require close attention. (2) For low-temperature corrosion protection, the \"one removal and three injections\" process should be the primary method, with material selection for equipment serving as a supplementary measure. The proper selection of demulsifiers and corrosion inhibitors has a significant impact on the efficiency of the “one removal and three injections” process ； For ammonia injection, water injection, and corrosion inhibitor injection, it is necessary to ensure uniformity, multiple injection points, and adjustability, while adjusting the injection volume according to the total iron content. The recommended process parameters after the \"one desalting and three injections\" process are as follows: the salt content in the crude oil after desalting should be less than 3 mg/L (it can be less than 5 mg/L in the case of no further processing), the Fe2+ content in the condensate water should be less than 1 mg/L, the chloride ion content in the condensate water should be less than 20 mg/L, and the pH value should range from 7.5 to 8.5. Enterprises must strictly implement the management regulations regarding “one separation and three injections” and put all relevant requirements into practice. (3) For high-temperature corrosion, material selection for corrosion resistance in equipment should be the primary approach, with process-based corrosion protection serving as a supplementary measure. Material selection must strictly comply with SH/T3096-2001 \"Guidelines for Design and Material Selection of Key Equipment in Plants Processing High-Sulfur Crude Oil\"; high-temperature corrosion inhibitors may be used as a last resort. (4) Strengthen the integration of planning, process, and equipment management, achieving a combination of change approval, information sharing, joint oversight, mutual promotion, and technical problem-solving. (5) For the plants, equipment, and auxiliary systems where the deterioration of crude oil may lead to increased corrosion, it is necessary to conduct a thorough inspection and implement corresponding measures. Appendix: Corrosion conditions of the second distillation unit in Maoming 1. Corrosion conditions of Tower 1 1.1 Initial distillation tower: The inner wall of the tower shell is intact, with no obvious signs of corrosion. The tray plates are in good condition; there is slight leakage from some floating valves and the tray clamps are loose, which are normal phenomena. 1.2 Atmospheric pressure tower: There are obvious bulging areas and weld cracks in the OCr13 lining of the tower wall. There are 3 weld cracks at the top of the tower; the longest one is 1 meter long and 0.3 mm deep, while the others are 0.5 meters long and 0.1 mm deep. There are also 3 bulging areas with an area of approximately 0.2 m² and a height of about 1.5 mm ； The tower feed section has 4 weld cracks, each 0.5 m long and 0.1 mm deep, as well as 5 bulges; one of these bulges is 1.3 m long, 0.4 m wide, and 3 mm high, while the remaining bulges have an area of about 0.2 m² and a height of about 1.5 mm ； There are 5 weld cracks at the bottom of the tower; the longest ones are 0.5 m long and 0.3 mm deep. There are 4 bulges with an area of approximately 0.2 m² and a height of about 1.5 mm. No bulges or weld cracks were found in other areas. On the top tray of the tower, one 1Cr18Ni9Ti tray is broken, and most of the floating baffles have fallen off due to deformation. The liquid drop plates (made of A3F material) have suffered corrosion-induced perforations. In the remaining trays, there are a small number of floating baffles and loose clamps. The welds on the pipeline leading out from the top of the tower have corrosion pits, with a depth of 5 mm. 1.3 Atmospheric stripping towers and vacuum stripping towers: No significant signs of corrosion were observed. 1.4 Vacuum tower: There are 5 bulges on the OCr13 lining at the bottom of the tower, with a height of about 1.5 mm and an area of 0.25 m². There are also 4 weld cracks, each 0.5 m long and 0.3 mm deep. One piece of lining measuring 0.2 m² has fallen off. Five of the stainless steel large floating baffle trays in layers 1 to 4 have been blown away. Layers 5 and 6, along with their main and secondary beams, have all been knocked down. Layers 7 to 17 show obvious grooved corrosion on their vertical surfaces. The main and secondary beams in layers 9 and 10 were replaced during repairs carried out in 1999 when the plant was shut down for maintenance. The foam arresters and supports in layers 7 to 17 have become deformed and fallen off. Multiple holes have appeared in the foam breaking mesh on layer 8, and there is a layer of brown rust on the surface of the foam breaking mesh at the top of the tower. 2 Corrosion status of containers 2.1 Demulsifier tank: The steel plate surrounding the bottom of the tank has thinned due to prolonged use, resulting in multiple perforations. 2.2 Two electrodialysis tanks: Cross-weld cracks were detected during inspections during the major repair in 1995; these tanks were classified as pressure vessels of grade 4. A thorough inspection was carried out during this repair to eliminate potential hazards. 2.3 Other containers: No significant signs of corrosion were found, and thickness measurements showed no abnormalities. 3 Corrosion status of heat exchange equipment 3.1 Coolers at the top of the three towers: Cracks were found in the welds of the cold-1/4 and cold-1/5 shell sections of the primary coolers. Yellowish-white powder was present around the cracks. In the cold-2/2 tube bundle of the primary cooler, 36 tubes were blocked. 3.2 Heat exchanger in line 3 (exchange-7/4): There were many blocked tubes. 4 Corrosion status of heating furnaces 4.1 Furnace radiant section tubes: Except for furnace-3, where 14 tubes were replaced in 1999 due to excessive hardness and carbonization of the tubes, no significant thinning was observed in the furnace radiant section tubes during this repair. 4.2 Furnace insulation lining: The insulation nails (made of 1Cr18Ni9Ti material) in the radiant sections of furnaces-1 and 3 had corroded at their roots and broken apart. For the convection section tubes of furnaces-1, 2, and 3, the softening water pipes were perforated, and the cold feed tubes in the convection sections of furnaces-1 and 2 were also perforated. 5 Corrosion status of process pipelines: The atmospheric oil transfer lines and vacuum oil transfer lines in our plant were replaced with 20G+316L material in 1990 and 1988 respectively, and no significant corrosion was observed. Similarly, no significant thinning was detected in the three vaporization lines. The pipelines with the most severe corrosion include the following: 5.1 Residue oil line: Originally made of 20# steel, this line was replaced with Cr5Mo material in August 1998 due to corrosion-induced perforations in sections from pump-29, 30, 31 to exchange-11/1ABCD. In May 1999, it was again replaced with Cr5Mo material due to thinning in the section from the bottom of the vacuum tower to the inlets of pumps 29, 30, 31. During this repair, it was found that the pipeline between the first set of heat exchangers and the second set of heat exchangers in the residue oil line (from exchange-11/1ABCD to exchange-11/1ABCD) had thinned, with the thickness decreasing from δ=7 mm to δ=4.1 mm over the past 5 years. The rate of thinning was 0.58 mm/year. Additionally, the fuel oil line carrying residue oil to the furnace also thinned, with its thickness decreasing from δ=5 mm to δ=3.2 mm over the same period, at a rate of 0.36 mm/year. 2.5.2 Line 5: Due to its short operating time and incomplete purging, line 5 suffered severe corrosion beneath the scale. The flanges of this line had deep corrosion pits, with a depth of 1.2 mm. 2.5.3 Line 4: The temperature of the fluid in line 4 exceeded 280 degrees Celsius, resulting in severe corrosion. The thickness of this line decreased from δ=6 mm to δ=4.3 mm over the past 5 years, with a rate of thinning of 0.34 mm/year. 2.5.4 Secondary water pipes: These are buried pipes that have suffered severe soil corrosion over time, resulting in multiple perforations.