Weekly Topic: Corrosion-prone areas of various devices and material selections, Issue 23, July 18–24, 2011
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This post was last edited by lijianhuai on 2011-7-17 09:40. The weekly topic discussion event in the refining area welcomes active participation from everyone; we also hope that participants will come up with more valuable topics, and the moderators will award rewards ranging from 5 to 20 wealth points. Those who post excellently will receive a reward of 10 to 50 Wealth or an equivalent amount of Charm. Please do not hide your responses to this topic. As the properties of oil products deteriorate and the sulfur content in the raw materials increases, corrosion of equipment and pipelines has become an urgent problem. People are trying to address this by upgrading the materials used and adjusting operating parameters, but they are still caught off guard by sudden accidents. We replaced the material used in the top circulation line; from the tower wall to the pump inlet, everything was upgraded to 316L material. (Although there have been no leaks or perforations in the pipes yet – they have only been in use for a year – when the pipes were removed, large amounts of ferrous sulfide caused multiple fires. Upon inspection, it was found that the thickness of the pipes had decreased by 2.8 mm, and a large amount of rust and ferrous sulfide mixture was present inside. It’s a pity no photos were taken at that time.) We also installed double valves at the tower wall. At one point, corrosion in the top circulation line led to a major fire that forced a shutdown. Since the inlet valves were corroded and the pumps broke down, it was not possible to remove the damaged parts for repair, so emergency measures had to be taken (similar to a shutdown). The losses and lessons learned from this incident were extremely severe ； Another example is a company where work was halted due to a high-pressure hydrogen exchange process; spontaneous combustion of ferrous sulfide caused by high-pressure air cooling led to a massive fire that destroyed numerous pieces of equipment ； Not long ago, I discovered a perforation at the liquid extraction outlet of the dry distillation unit (there are photos); it was shocking, as the unit had only been in operation for a year! ! ! I earnestly ask the experts to share information on the corrosion of their installations, including the specific areas affected and the materials used. For example: Device name, locations prone to corrosion, material before update, model before update, operating cycle, material after update, model, measures taken in response to changes in operating conditions
This post was last edited by lijianhuai on 2011-7-20 at 11:32. Device name: Atmospheric and Vacuum Distillation Unit. Corrosion-prone areas: the trays at the top of the atmospheric tower, a total of 8 trays from top to bottom. Model before material replacement: 0Cr18Ni10Ti; operating cycle before replacement: 2 months. Model after material replacement: 316L. Measures taken due to changes in operating conditions: Before the material was changed, the unit processed low-sulfur, high-acidity crude oil, with an acidity level of around 3; the pressure at the top of the tower was 0.03 Mp and the temperature was 115 degrees. After processing high-acidity crude oil for 2 months, problems such as poor separation between gasoline and diesel occurred, along with large fluctuations in the temperature at the top of the tower. Upon shutdown for inspection, it was found that the trays were severely corroded, and the upper three layers had their trays fall off due to severe corrosion； After changing the material, the unit was used to process low-sulfur, high-acid crude oil; the acidity of the crude oil was around 3.5, the top pressure of the tower was 0.03 Mp, and the temperature was 115 degrees. Upon inspection when the unit was shut down after 7 months of operation, no significant corrosion was found on the tower trays.
Device name: Delayed coking unit. Corrosion-prone area: Reboiler shell at the bottom of the desulfurization regeneration tower. Material before replacement: Tube/Shell 0Cr18Ni10Ti/20#. Operating cycle before replacement: 17 months. Material after replacement: Tube/Shell 0Cr18Ni10Ti/0Cr18Ni10Ti. Measures taken due to changes in operating conditions: Before the material was replaced, the liquid-rich stream obtained after desulfurization of the liquefied gas from the coking process flowed through the unit; the pressure at the top of the tower was 0.06 Mp, and the temperature of the liquid returning to the tower via the reboiler was 133 degrees. After 17 months of operation, leakage occurred at the welds connecting the outlet of the regenerator shell. Subsequently, leakage also appeared at other welds. Inspection revealed extensive corrosion and thinning in the upper middle part of the shell, especially in the area where the liquid returned to the tower and in the region of the small floating head； After the material of the casing was changed, it has been in operation for over 4 years without any corrosion or thinning
The corrosion in the constant-pressure system is relatively severe; the material used for the air coolers in the constant pressure and vacuum distillation units has been changed to 0Cr18Ni9Ti. No leaks have occurred over the 4 years since its installation
Let me add something: for corrosion resistance to naphthenic acids in foreign materials, 317 is recommended; its price is more than twice that of 316L, and 10 times that of ordinary carbon steel. For domestic use, choose 316L
Here’s another example: Device name: Catalytic unit. Parts prone to corrosion: Cooling coil at the top of the distillation tower. Model before material replacement: The air-cooling and water-cooling tube bundles were made of 10# steel. Operational life before replacement: Over 3 years; leaks occurred in both the air-cooling and water-cooling systems, and the corrosion of the cooling coil at the top of the distillation tower was caused by H2S+H2O corrosion. Model after material replacement: The tube bundles of the water-cooling coil at the top of the tower are made of 0Cr18Ni9 material, while the air-cooling tube bundles are protected against corrosion using PVA-C coating； Measures to address changes in operating conditions: Before changing the material, 30% slag was added to the high-sulfur wax oil used in the plant; the sulfur content in the wax oil was as high as 1%. The pressure at the top of the tower was 0.1 Mp, and the temperature was 123 degrees. After more than 3 years of operation, leaks occurred first in the air coolers, followed by leaks in the water coolers. Corrosion inhibitors and ammonia were injected at the top of the tower ； After the material was changed, the raw materials used for processing the unit retained essentially the same properties as before, and the operating conditions remained unchanged; no corrosion inhibitors were used, only ammonia was added. The unit has been in operation for over 7 years, and there have been no leaks in the cooling coil at the top of the distillation tower
Device name: Hydrogenation. Corrosion-prone area: Light gas cooler. Model before material replacement: Made of 20# carbon steel. Operating cycle before replacement: It had been in use for over 3 years; there were instances of light gas leakage as well as blockages caused by ammonium salts. Model after material replacement: No change in the material; enhanced water injection was implemented. Measures taken to address changes in operating conditions: Enhanced water injection and increased thickness monitoring, with prompt action taken whenever any thinning was detected.