Condensate oil separation unit: corrosion at the inlet of the air cooler of Tower No. 1
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The top of Tower No. 1 in my condensate separation unit produces liquefied gas products in the C3–C4 range, with trace amounts of C2 and hydrogen sulfide. The 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. .
It is likely corrosion caused by H2S+H2O; it is recommended to vaporize a corrosion inhibitor and purified water at the top of the hydrogen sulfide removal stripping tower, which can effectively reduce corrosion in air-cooled systems. The most cost-effective method at present is to increase the water flow rate in order to dilute the H2S in the vapor line at the top of the tower, thereby reducing corrosion of the equipment and pipelines. There are also methods involving material upgrades or treatment of the inner surface of the tube bundles. Generally, for this area, if the material grade is to be upgraded, 09CrCb (a steel resistant to hydrogen sulfide corrosion at low temperatures and containing rare earth elements) can be used; as for surface treatment, nickel-phosphorus plating inside the air-cooled tubes or the use of coolant coatings inside the tubes can also be tried.
Can spectral testing be used to determine whether there is any cutting corners in the steel used for the tube bundles?
Increasing the water injection at the top of the tower seems feasible as it involves low costs, but are there any precedents of such improvement measures succeeding? In fact, the H2S content in the raw material is very low, and the product at the top of the tower consists of liquefied gas components in the C3–C4 range. Moreover, the corrosion occurred entirely at the inlet section of the air-cooled tube bundle, with no thinning observed at the outlet. (The tube bundle design thickness is 2.5 mm; the thickness measured at the inlet is 2.07 mm, while the thickness measured at the outlet is 2.53 mm.)
The manufacturer is Ha Air Conditioner; I called to inquire, and it should be fine.
Currently, at the catalytic unit’s distillation section, the acidic water is injected before cooling the top of the distillation tower； Before gas enrichment and air cooling of stable-position acidic water ； Pre-cooling injection of deionized water before air cooling in the stable operation section of the coking unit ； There are many examples. It has been in use ever since, and the results are good
Thank you so much! Then how is the water injection volume calculated? Is there an algorithm?