Treatment of overhead gas from high-sulfur crude oil processing plants and anti-corrosion methods

The gas at the top of the tower is sent for gas desulfurization, while the water is sent to a wastewater treatment plant.

The injection point has been changed to a nozzle injection, improving the atomization effect of the liquid injected; this ensures thorough contact between gas and liquid, allowing for the effective removal of acidic gases from the oil and gas, thereby enhancing the anti-corrosion effect.

The oil and gas pipelines at the top of the tower can be filled with corrosion inhibitors to protect the equipment and pipelines, but high sulfur content can cause corrosion in the upper part of the atmospheric pressure tower. If the material used for the tower is not resistant to high-sulfur corrosion, it can lead to severe corrosion of the upper trays; in extreme cases, the trays may even collapse, which is something we have encountered before.

Generally speaking, the cause of corrosion at the top of the tower is dew point corrosion caused by HCL-H2S-H2O.

Although injecting a corrosion inhibitor at the top of the tower can have some effect, since the inhibitor cannot mix evenly with the oil and gas, it cannot be distributed uniformly across the wall of the vessel, and thus the desired corrosion-inhibiting effect is not achieved. As long as water can be injected for dilution before the oil and gas dew point is reached, it is ensured that no acidic substances will form to corrode the equipment. Of course, upgrading the material at the top of the tower is also a way to address corrosion, but it is costly and does not solve the underlying problem.

High-sulfur crude oil is characterized by a high sulfur content. Apart from the processing units that come later, there are two types of corrosion in atmospheric and vacuum distillation units: low-temperature corrosion and high-temperature corrosion. (1) Low-temperature corrosion is mainly caused by HCl-H2S-H2O in the tower tops; HCl is the main factor contributing to severe corrosion, including in areas where condensation occurs as well as in subsequent sections. If organic amines are added and the pH is kept low (not exceeding 7.5), the H2S content in the water will not be very high, and its impact on corrosion will be minimal. The problem can be resolved by using appropriate neutralizing agents and corrosion inhibitors； However, a high sulfur content increases the likelihood of FeS precipitation; therefore, it is recommended to add organic amines to high-sulfur crude oils, and keep the pH of the condensate between 6.0 and 7.0 to prevent under-scale corrosion. (2) High-temperature corrosion mainly occurs in areas with temperatures above 220°C; however, if the acid value of the crude oil is not high and the material used for the equipment meets the required standards, high-temperature sulfur corrosion is not severe, as the FeS formed has a certain anti-corrosive effect ； If the acid value of crude oil is high, FeS can be dissolved by naphthenic acids; an increased sulfur content will instead promote corrosion in high-temperature areas. Therefore, it is necessary to upgrade the material used in the equipment and also use qualified high-temperature corrosion inhibitors to mitigate corrosion in those areas. Therefore, for high-sulfur crude oil, corrosion protection is not a major concern; it is only when the crude oil also has a high acid value that higher requirements are placed on equipment corrosion protection.

We turned on the heat recovery, but the effect isn’t very good

What was said on the 8th floor is correct; a qualified high-temperature corrosion inhibitor is very important

Use corrosion inhibitors for compatibility, as well as ammonia water or liquid ammonia; in addition, upgrade the materials of the tower top lines and high-temperature pipelines to 316L, and enhance inspection routines