Changing Your Crude Slate?

Changing Your Crude Slate?

Changing Your Crude Slate? You Need to Consider More Than Just Naphthenic Acid Corrosion and High Temperature Sulfidation.

Refiners are constantly evaluating their crude slates in an effort to maximize profits. It involves a continuous effort in trying to get the most product value from the lowest cost crudes. Generating a $1.00 per barrel margin on a crude slate, taking into consideration both product value and cost of the crudes in the slate, can create more than an 100M$ advantage over the course of a year for a refinery processing 300,000 barrels a day. This large advantage can be turned into a large loss with a single related equipment failure which results in weeks of unit shutdown.

Typically, when a refiner evaluates a crude change the primary considerations from an equipment reliability and safety standpoint are naphthenic acid corrosion and high temperature sulfidation. Many studies have been conducted that evaluate the effect higher TAN and sulfur crudes have on the corrosion experienced by equipment in crude and other downstream units. However, these are not the only forms of corrosion or damage that can be experienced by equipment as the result of a crude change. This article presents several examples of how a change in crude slate can have other adverse effects on equipment reliability and safety. These examples include the following:

Sulfidation from Light Crudes and Condensates

New light crudes and condensates from the Middle East and the countries on the Caspian Sea contain higher levels of lighter sulfur compounds such as mercaptans and disulfides. The corrosion rates caused by these lighter sulfur compounds are not accurately predicted by conventional high temperature sulfidation corrosion curves such as the McConomy curves. When these lighter crudes and condensates are added to a crude slate they do not significantly increase the overall weight percent sulfur in the crude slate; however, these lighter sulfur compounds concentrate in the lower boiling temperature naphtha fraction and significantly affect sulfidation observed in the naphtha stream when heated in a naphtha hydrotreating unit. Sulfidation can be particularly aggressive in 5 Cr tubes in the convection section of a naphtha hydrotreating furnace at a location in the coil where the naphtha completely vaporizes.

Desalting Difficulties

New crudes can frequently introduce desalter operating difficulties. Recent experience has shown that heavy high TAN crudes tend to form strong emulsions in desalters that require enhanced chemical additions and modifications to the desalter operation in order to avoid carryover that causes increased pre-heat train fouling, furnace coking and overhead corrosion. Additionally, some of the new crudes also have higher fine particulate levels that can be difficult to remove/reduce in a desalter. The particulates have caused increased fouling in equipment processing bottom streams.

Corrosion in Vacuum Overhead Circuits

Experience has shown that higher TAN levels in the feed to vacuum crude units promote the hydrolysis of inorganic salts, like sodium chloride, in the furnace to form HCl that promotes overhead corrosion. In the past, when running low TAN crude slates, salts in the vacuum unit feed did not hydrolyze to form HCl and overhead corrosion was not a concern. It was common that chloride levels in the overhead water of a vacuum unit were below 5 ppm. Today, it is common that the overhead water has chloride levels exceeding 50 ppm requiring corrosion control measures similar to the measures to control corrosion in the atmospheric crude unit overhead. These measures include neutralizer and corrosion inhibitor addition, water injection and selective use of alloy.

Increased Corrosion in Amine Treating Units

Naphthenic acid decomposes into carbon dioxide (CO2) and water in a hydrotreating unit reactor. In some refineries that have increased their TAN levels in the crude slate, this has caused increased CO2 levels in the hydrogen treat gas. When the hydrogen treat gas with elevated levels of CO2 is processed in the amine treating unit, the increased levels of CO2 in the rich amine stream and the regenerator overhead circuit have resulted in an increase in the observed corrosion in these circuits.

Increased Wet H2S Cracking

A refinery recently backed out a heavy high sulfur crude from its slate and replaced it with a heavy low sulfur high TAN crude. At the same time they noticed a dramatic increase in wet H2S cracking damage (hydrogen blistering and through wall HIC damage) of equipment in the cat light ends unit. This same refinery had previously discontinued ammonium polysulfide (APS) injection into the cat light ends feed stream because they found when processing the high sulfur crude it was not needed. However, when substituting the heavy low sulfur high TAN crude for the heavy high sulfur crude, there was inadequate sulfur present without APS injection to maintain the protective sulfide scale on equipment surfaces to protect it from wet H2S cracking in this high cyanide (CN) environment.

These examples demonstrate that when evaluating a new crude slate it is necessary to consider all possible damage mechanisms that can affect equipment. It is not just a matter of evaluating naphthenic acid corrosion and high temperature sulfidation. These damage mechanisms are important but they are not the only damage mechanisms that can affect equipment reliability and safety when changing a crude slate.

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About The Author

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Jim McLaughlin has over 30 years experience in materials engineering in the petroleum industry working with Chevron, Exxon and ExxonMobil.  He has been involved in all aspects of materials engineering including corrosion prevention, failure analysis, fire damage assessment and fitness-for-service assessments in the entire range of equipment in refineries, petrochemical units and upstream facilities. In addition to serving as a lead technical expert in areas of crude corrosion, high temperature corrosion, fitness-for-service (including high temperature remaining life assessments), risk-based inspection and metallurgy, Mr. McLaughlin has conducted research on and evaluated the effects of harsh environments at high temperatures involving such phenomenon as carburization, metal dusting and sulfidation in reducing conditions.

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