CONTROLLING CORROSION: A NEW METHOD TO MEASURE THE TAN IN CRUDE OIL AND REFINERY DISTILLATION FRACTIONS


Many refi ners look at discounted opportunity crudes as a means to improve their margin spread. The growing varieties of discounted opportunity crudes on the market contain certain risks for the purchaser, such as high naphthenic acid or sulfur content. Sulfur compounds and naphthenic acids are among the many species that contribute to the corrosive nature of crude oils and refi ned fractions. Opportunity crudes with high naphthenic acid and sulfur content therefore come with an ongoing risk of increased corrosion. The refi ner must balance the cost benefi t versus the risk and the cost of corrosion control when processing these crudes.


Naphthenic acids: Occurrence


Naphthenic acids are found in many types of crude oil and can be present at varying concentrations. Their presence is found in crudes of diverse global origin including California, Venezuela, China, India, Mexico, Brazil, West Africa, North Sea, Western Canada, and other regions. Broader availability and higher volume of naphthenic-acid-containing crudes increase the risk of experiencing high-temperature corrosion of refi nery equipment in refi nery operations. The atmospheric and vacuum distillation columns, side strippers, furnaces, piping, and overhead systems are particularly at risk.


Naphthenic acid and sulfur corrosion who noted it was diffi cult to


content.5 Corrosion risk from naphthenic acids is greater at process temperatures over 200 °C.


At operating temperatures greater than 420 °C, naphthenic acids are believed to break down into shorter-chain organic acids. These can end up in distillation fractions, and there is concern about their corrosivity.6


As operating process temperature increases, so does the possibility of corrosion due to these short-chain organic acids.


The link between naphthenic acids and refi nery corrosion was established by W.A. Derungs,1


differentiate between sulfi de and naphthenic acid corrosion. Both produced high corrosion rates at elevated temperatures. The mechanism of corrosion from combined naphthenic acid and sulfur content has been described by the following chemical reactions.2, 3, 4


Physical parameters affecting corrosion Flow-induced wall shear stress can separately infl uence the corrosion by naphthenic acid and sulfur species. Refi nery units with process stream fl ow velocities greater than 2.7 m/s and areas of high turbulence are more susceptible to naphthenic acid corrosion. A thin fi lm of iron sulfi de – formed through the reaction of hydrogen sulfi de in crude and steel refi nery units – protects the steel from naphthenic acid attack. High-velocity fl ow and turbulence can, however, dissolve the sulfi de fi lm, leaving the metal vulnerable to attack by naphthenic acid.


Desalter upsets caused by naphthenic acids


In the fi rst reaction, iron naphthenates are formed from the reaction of naphthenic acids with steel. Being soluble in oil, the iron naphthenates are carried in the fl uid fl ow. Simultaneously, hydrogen sulfi de or other sulfi de-containing species react with the steel to form an iron sulfi de coating on the surface (Reaction 2). Hydrogen sulfi de reacts with the iron naphthenates to form iron sulfi de and liberate the naphthenic acids (Reaction 3).


While these three reactions form the recognized mechanism of naphthenic acid in sulfur-containing crudes, naphthenic acid corrosion is in fact more complex and affected by many factors such as temperature and velocity as well as acid and sulfur


PIN April / May 2022


In the crude oil desalter, naphthenic acids can cause upsets through the formation of emulsions: as the pH of the water inside a desalter increases, naphthenic acids can form very stable sodium naphthenate emulsions. Emulsions that are formed must be broken to restore the effi ciency of the desalter and reduce fouling.


Corrosion control: Monitoring the acid number


To control corrosion in the processing of crude oil, the acid number and sulfur content of the crude or refi nery fraction are measured. The acid


Figure 1. The 859 Titrotherm with magnetic stirrer, two Dosinos, and the tiamoTM This simple setup allows you to measure the acid number of crudes and refi nery fractions.


software:


number (AN) is defi ned as the total acidity, i.e., the amount of potassium hydroxide in milligrams required to neutralize one gram of sample. It is not uncommon to fi nd crude or traded fractions such as vacuum gas oil (VGO) with acid numbers up to 4 mg KOH/g. Most crude or refi nery fractions have an acid number of less than 1 mg KOH/g. Experience from refi neries and corrosion studies shows elevated corrosion risk when the naphthenic acid content is greater than 0.5 mg KOH/g in crude, and greater than 1.0 mg KOH/g in fractions. If the acid number of a crude or fraction exceeds these values it is considered to be a high-acid- number stream.


Until the release of acid number standard ASTM D8045, the acid number of crude oil and fractions was estimated by using potentiometric method ASTM D664. This test method was originally developed for the analysis of new and used lubricants and presents the analyst with a number of analytical challenges when applying it to crude oil and fractions. For example,


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