Mitigating iron foulants in refinery processes

Purification systems are designed to remove iron based particles without detriment to a catalyst bed’s permeability.


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Article Summary

In order to ensure the smooth and uninterrupted flow of oil and gas into different refinery processes, one must understand oil impurities and the process for removing them. The primary impurities in refinery feedstock and processes are sulphur, nitrogen, and metal compounds. Of these, iron and related compounds constitute the most prevalent, causing corrosion within piping and equipment. This article provides a comprehensive review of how iron compounds enter into refinery processes, the detrimental effects that can result, and the mitigation of those effects in hydroprocessing reactors. Current mitigation methods utilising low cost, high efficiency technology will also be discussed.

Fouling, high pressure drop, loss of catalyst activity, and product contamination frequently cause unexpected shutdowns, often in hydroprocessing units. These problems are due to two predominant foulant types: inorganic, in which deposits mainly consist of iron and its compounds; and organic, in which asphaltenes and polymer precursors ultimately result in coke deposits. These two types of fouling often occur together, their magnitude depending on processing circumstances.

Considerable evidence of mixed organic and inorganic deposits exists in the literature, some examples of which are found in Table 1. For the crude oil CO-1 to CO-4, results were obtained in recirculation flow or stirred batch laboratory units. Temperatures were taken to reflect those in crude oil preheaters. For heavy oil fractions HF-1 and HF-2, results are from the tube side of an industrial bitumen processing unit.

When examining elements in refinery feedstock (see Table 1), it is important to remember the compounds associated with the elements found are either soluble or insoluble in oil. Soluble compounds pose a different threat than insoluble or solid compounds. Insoluble compounds found in deposits can, at times, be mistakenly identified as catalyst poisons. To understand the foulant composition, it is important to examine deposit or feed samples with a number of laboratory procedures that enable the interested engineer or scientist to correctly diagnose the source and probable chemistry of the problematic compounds. Crystaphase has built a laboratory in such a fashion to specifically examine and differentiate these types of compounds. In the case of iron, which can appear in refinery feedstock as a multitude of compounds, this capability and insight is vital to design a proper course of action to deal with such problems.

Iron found in refinery feedstock and processes generally has two sources. The first source, inherent iron, is flowing in concentrations from 0.04 to 120 ppm or, for heavy crudes or bitumens, in concentrations from 120 to 500 ppm, both soluble and insoluble. The second source is introduced via corrosion from upstream piping and process equipment during the upgrading process. This is largely due to acidic compounds in the feed that are not well matched with process metallurgy.

As an example, naphthenic acids are not just responsible for corrosion issues, but can result in particle generation inside the catalyst bed. The iron moves in a myriad of paths from pipe to feed to reactor. Ultimately, if these types of problems are not dealt with, the fouling particles can reduce cycle lengths, greatly impacting reactor profitability.

Shown below is the chemistry of how iron compounds are generated during the refining process and become entrained with the feed.

The formation of iron sulphide in a hot, flowing oil is believed to involve two processes:
I) The corrosion of iron by organic acids and sulphur compounds
II) The decomposition of soluble iron salts.

Two different mechanisms are considered for the reactions depending on the presence or absence of oxygen; here we consider only the latter case. Oxidative environments would require a completely different review and are not as applicable to the realm of hydroprocessing. The steps involved:

Reaction 1 Corrosion of iron by organic acids, which occurs on the walls of upstream piping and equipment:
Reaction 2 Thermal decomposition of acid salts:

Reaction 3 Iron oxide reacts with organic sulphur or hydrogen sulphide (H2S):

Soluble organic iron species such as iron carboxylates and iron naphthenates are likely to decompose at higher temperatures, reacting with organic sulphur or H2S to form FeS deposits on process equipment surfaces. Their decomposition temperature is >300°C. At 282°C, iron acetate decomposes iron carbonate to form iron oxide (FeO). Once decomposed to iron oxide, abundant sulphur in the hydroprocessing allows for the generation of FeS. As Figure 1 shows, these types of precipitation result in a beautiful, crystallographic agglomeration of iron sulphide. This crystal structure, known as pyrrhotite, is a wonderful morphological characteristic which can be sought to identify such problems.
The following are types of refinery corrosion, other than acidic, which result in the formation of iron compounds.

Water related corrosion
Crude oil desalting and distillation generates considerable wastewater. This water contains accelerative corrosive components such as hydrogen sulphide (H2S), carbon dioxide (CO2), chlorides, and 
high levels of dissolved solids. 
In addition to wastewater, water used in various cooling 
operations contains chlorides, oxygen, dissolved gases and microbes, which also contribute to corrosion, making iron species in process.

Process-related corrosion
The top section of the crude distillation unit is subjected to an array of corrosive species. This includes hydrochloric acid (HCl) formed from the hydrolysis of calcium and magnesium chloride, the principal strong acid responsible for corrosion. Carbon dioxide released from crudes also leads to corrosion, typically produced in CO2 flooded fields and crudes that contain a high content of naphthenic acid.

Low molecular weight fatty acids such as formic, acetic, propionic, and butanoic acids are released from crudes with a high content of naphthenic acid. Hydrogen sulphide released from sour crudes significantly increases the corrosion in the crude unit top section. Sulphuric and sulphurous acids, formed either by oxidation of H2S or direct condensation of SO2 and SO3, also increase corrosion and contribute to the formation of iron compounds in process.

High temperature crude corrosivity of distillation columns is a major concern in the refining industry. The presence of naphthenic acid and sulphur compounds considerably increases corrosion in the high temperature services occurring in parts of the distillation unit, crude feedstock heaters, furnaces, transfer lines, feed and reflux sections of atmospheric and vacuum columns, heat exchangers, and condensers.

Sulphur corrosion
After carbon and hydrogen, sulphur is the most abundant element in crude petroleum. It may be present as elemental sulphur, hydrogen sulphide, mercaptans, sulphides, and polysulphides. Sulphur at a level of 0.2% and greater is known to be corrosive to carbon and low alloy steels at temperatures from 230°C to 450°C.

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