Is this hydrogen sulfide corrosion?
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The top of Tower No. 1 in my condensate separation unit produces LPG products in the C3–C4 range, which also contain trace amounts of C2 and hydrogen sulfide. This unit came online in 2012; this year, thickness measurements were taken during maintenance work, and it was found that there was significant thinning at the inlet of the air-cooled finned tubes. The designed thickness of these tubes is 2.5 mm, with a corrosion allowance of 0.05 mm. The average thickness at the inlet, as determined by these measurements, was 2.19 mm, with the lowest value being 2.12 mm. In contrast, the thickness of the tubes at the outlet of the finned tubes showed almost no reduction. Air cooling operating parameters: pressure of 1.0 MPa, with a tolerance of ±0.05 MPa; inlet temperature of 73°C, with a tolerance of ±3°C; outlet temperature of 52°C, with a tolerance of ±2°C. The tube bundle is made of hydrogen-resistant steel. My preliminary analysis suggests that this is due to the air-cooling inlet being the phase transition zone where liquefied gas changes from a gaseous state to a liquid state. Since the phase transition parameters for hydrogen sulfide gas differ from those of liquefied gas, this gas accumulates in this area, leading to corrosion of the tube bundle. But there is no professional theoretical support for this; I asked the material specialist, who said that theoretically, hydrogen-resistant steel should not be corroded by hydrogen sulfide so quickly. I would appreciate it if experts could explain the reason. .
Other types of corrosion, such as chlorine corrosion, also need to be considered.
It is likely caused by multiple factors. The temperature at which low-temperature sulfur corrosion occurs is generally below 120°C, and since the mixture at the top of the tower consists of oil and gas, the corrosion is most severe in the areas where phase transformation takes place, that is, at the dew point. Compare your process to see if the phase transformation area is located at the inlet; I think it’s likely a combination of low-temperature sulfur corrosion, dew point corrosion, and abrasion.
The overhead distillation line of our tower is equipped with a corrosion inhibitor, but for some time the dehydration pack in the tower’s overhead reflux tank kept getting clogged by black flocculent substances; analyses performed on them did not yield any results. .
So you can ask the corrosion inhibitor manufacturer what the components of the corrosion inhibitor are, and whether it contains chlorides
By testing the water from the dehydration pack in the reflux tank, it was found that chlorine ions were present in it, with levels varying from time to time; however, the iron ion levels generally did not exceed the acceptable limits. It’s unclear what is causing this situation. Corrosion inhibitors were purchased from different manufacturers, some of which contain chloride ions.
1. The operating environment contains water vapor, solid particles, chloride ions, and hydrogen sulfide, and the temperature is lower than that at the top of a normal-pressure tower. Although corrosion is still severe, the corrosion rate is much lower compared to that in a normal-pressure tower. 2. This corrosion environment is a typical wet corrosion environment of low-temperature hydrogen sulfide + chloride ions + water. Solid particles, together with the fluid, enter the tube sheet, which accelerates erosion corrosion; therefore, corrosion is much more severe in the inlet section than in the outlet section. There will also be signs of corrosion on the row of tubes beneath the tube sheet in the outlet section; it’s just that you haven’t noticed it. Since water vapor condenses into water at the inlet, this water flows out at the outlet end of the lowest row of tubes. As a result, the welds between the tubes and the tube sheet in the outlet section are prone to corrosion, and the tubes themselves also become thinner. 3. What material is the hydrogen-resistant steel you mentioned? Just because it is hydrogen-resistant does not mean it can resist corrosion caused by hydrogen sulfide and chloride ions; for example, Q345R (HIC) has an even lower sulfur content, but it cannot withstand uniform corrosion, pitting corrosion, or erosion corrosion! There’s also something called 10 (HSC); it works on the same principle. These two steel grades are simply two types of carbon steel.
What is the iron ion content, and what is the sulfur content in the effluent?
This corrosion environment is a typical wet corrosion environment of low-temperature hydrogen sulfide + chloride ions + water, and the corrosion becomes even more severe, especially during phase transitions.
I am processing condensate oil; there is corrosion at the very bottom of the floating head of the primary heat exchanger, as well as corrosion at the bottom of the straight section of the pipe connected to the secondary control valve