High-temperature naphthenic acid corrosion in atmospheric and vacuum distillation units

My equipment is relatively old; over the past two years, corrosion has been detected in the bottom reduction pipeline (20#). The naphthenic acid-induced corrosion is a type of localized corrosion that progresses very rapidly. The bottom reduction pipeline has thinned out significantly in those areas, resulting in three leaks that nearly led to serious consequences.

Naphthenic acid corrosion is primarily a form of localized corrosion, with the corrosion occurring mainly in the vacuum furnace, the vacuum oil transfer line, and areas below the feed section of the vacuum tower; the atmospheric furnace system is affected to a lesser extent. The corrosion morphology of naphthenic acids consists of pits and grooves with sharp edges. In addition to the naphthenic acid concentration (acid value greater than 0.5 mgKOH/g) and temperature (two ranges of 270–280°C and 350–400°C), the flow rate also affects the impact of naphthenic acid corrosion. The corrosion sites of naphthenic acids are all concentrated in areas with high flow rates; as the flow rate increases, the corrosion rate also increases. For naphthenic acid corrosion, it is necessary to select a cost-effective and corrosion-resistant material based on the temperature, flow rate, and flow pattern of the medium; the main materials used are those of the 0Cr18Ni10Ti series, as well as 316L and 317L. The corrosion products of metal materials, which contain large amounts of metal elements (especially iron), can have a severe negative impact on the processes used in secondary processing equipment as well as on catalysts; under permissible conditions, higher-grade materials should be selected. The reduction bottom pipeline (20#) mentioned on the 2nd floor is corroded; it is not necessarily due to naphthenic acid corrosion – high-temperature sulfur corrosion could also be the cause. First, examine the materials and corrosion conditions in other parts of the vacuum distillation tower (such as the corrosion inside the tower below the second vacuum line as well as on the side lines). Naphthenic acid corrosion is not only a type of localized corrosion; moreover, its pattern is easy to observe, appearing as grooves.

Naphthenic acid corrosion is primarily concentrated in the reduced-pressure side streams, such as those at the second and third reduction stages. The main cause of reduction is high-temperature sulfur corrosion; Cr5Mo steel should be used.

Cr5Mo steel offers some resistance to high-temperature sulfur corrosion, but it is completely ineffective against naphthenic acid corrosion; at least 304 or 321 stainless steel is required, with 316 or 316L being the preferred choices

How many filling points are there for high-temperature corrosion inhibitors in the vacuum unit? Is it necessary to add fluid after the vacuum furnace?

As the quality of crude oil used in processing deteriorates, on the one hand, the materials of equipment are upgraded by replacing vacuum distillation columns with composite materials and pipelines with high-grade materials such as Cr5Mo; on the other hand, corrosion monitoring is intensified, and high-temperature corrosion inhibitors are used for prevention.

In our plant, a short circuit in one of the residue oil heat exchangers caused leakage due to erosion; the heat exchanger’s casing was made of grade 20 steel, while the pipelines were made of chromium-molybdenum alloy.

Our institute now uses 316L for all areas subject to corrosion caused by highly acidic crude oil. Research has shown that using larger pipe diameters along with lower flow rates is the ideal approach

We don’t encounter naphthenic acid corrosion very often; it’s sulfur corrosion that we deal with mainly

In the heavy furnace pitch unit, gasoline is transported through stainless steel pipelines

There is also a reduction in the bottom line, but this poses a problem: a stress issue, with cracks appearing at the flange connections

Special attention should be paid to the elbows, flanges, pressure gauge leads, and instrument thermocouples in areas subject to high temperatures; ring acid corrosion usually manifests first in these areas. The methods we commonly use now include injecting ammonia, corrosion inhibitors, alkaline water, as well as high-temperature corrosion inhibitors at the bottom of the initial distillation tower and atmospheric pressure towers! It is also necessary to conduct regular anti-corrosion inspections to monitor the extent of corrosion, and make corresponding adjustments to the injected substances. If possible, it is best to replace the equipment and pipelines with materials of grade 316 or higher! :(

To address the corrosion of high-acid crude oil, especially in high-temperature areas, in addition to using 316L material of a higher grade, when domestic materials are employed, an additional requirement must be imposed: the Mo content should be increased (to a minimum of 2.0%) to achieve better results.

The most fundamental solution to high-temperature corrosion is material upgrading; from the perspective of process-based corrosion prevention, adding high-temperature corrosion inhibitors is another approach

It is also necessary to consider the total acid value of crude oil, as this can lead to an increase in pressure drop across the catalyst bed during subsequent processing steps such as hydrocracking!

There is corrosion in the weld at the interface where the outlet transfer line of our atmospheric pressure furnace connects to the atmospheric pressure tower; the material used is DN530/Cr5Mo. The most serious issue was a perforation in the 4-inch diameter φ273*9 elbow pipe running from the furnace outlet to the transfer line, which occurred in May 2007. Fortunately, it was detected in time, preventing any accidents. After monitoring, the thinnest part was 1.9 mm and the thickest part was 6.2 mm, mainly concentrated on the outer side of the bent tube. We believe that naphthenic acid corrosion is mainly closely related to flow rate. As the flow rate doubles, it increases at a geometric rate. Moreover, there are gas-phase components in this area, resulting in a higher flow velocity.

Corrosion is severe in the high-temperature areas; the elbow from the atmospheric furnace to the atmospheric tower has suffered severe erosion. Adding a corrosion inhibitor has a significant effect.

Corrosion is severe in the high-temperature areas; the elbow from the atmospheric furnace to the atmospheric tower has suffered severe erosion. Adding a corrosion inhibitor has a significant effect.

The main component of naphthenic acid is pentacyclic carboxylic acid, which is a widely used chemical product.

Naphthenic acid corrosion is a common problem in the petroleum processing industry. As crude oil becomes of lower quality, an increasing amount of crude oil with high acid values is reaching refineries. The issue of naphthenic acid corrosion receives widespread attention. As is well known, there are two solutions: 1. Replace the material – molybdenum-containing steels can resist naphthenic acids; grades such as 316, 316L, and 317 all contain a high level of molybdenum. However, even these grades of molybdenum steel cannot withstand high temperatures, and steels with an even higher molybdenum content, such as 254SMO, are required to handle such conditions. These materials should be used in the areas from the second to the third stage of the vacuum distillation tower ； At higher temperatures, the corrosion caused by naphthenic acids is reduced; therefore, relatively common materials can be used for the stripping section and the bottom of the tower. When using high-grade materials, it is important to apply them where they are most needed. I recommend visiting a lubricant refining demonstration facility in the United States that deals with oils with high acid values; there, the material of the heating furnace tubes changes from ordinary stainless steel to 316 as the temperature rises, and finally to 254SMO. The pipeline leading to the bottom of the solvent recovery tower is quite short, which seems to not provide enough safety distance. Another method is to inject high-temperature corrosion inhibitors into the relevant trays; organic amine salts of phosphoric acid polyalcohol esters are commonly used (as already suggested by others). What I want to say is that these corrosion inhibitors are of the \"film-forming\" type, and they exert their best effect before corrosion occurs in the equipment ； Furthermore, when first using it, a slightly higher dose should be applied to form a film; the dose should then be adjusted by observing changes in the trace iron content of the sample, in order to achieve an appropriate injection level. The above opinions are for reference only.