You are currently viewing: Articles



Mar-2018

Crude analysers in corrosion prevention

On-line salt-in-crude oil analysers and crude oil analysers are essential in protecting the CDU and other refinery process units from corrosion.

GREGORY SHAHNOVSKY, ARIEL KIGEL and RONNY MCMURRAY
Modcon-Systems Ltd
Viewed : 1977
Article Summary
Today’s strategy in the refinery industry forces refineries to change their crude oil sources towards those crude oils that can give maximum profit from distillates and refinery products with the minimum cost being paid for raw materials.

Alongside that, refineries also have to take into consideration ever-changing crude oil prices and instabilities in oil producing countries and may be forced to change their crude oil sources at any time. This results in the need for flexibility by refineries to respond to the conditions that are required for processing different crude oils.

The presence of corrosive substances in crude oil, such as naphthenic acid, H2S and mineral salts, will result in increased corrosion in refinery units when changing between different types of crude oils, especially from sweet to sour and heavy crudes.

There are two types of corrosion properties existing in crude oils:
1. Direct corrosion properties which are caused by acidic molecules such as asphaltic acids and H2S, which in general is expressed by the total acid number (TAN) of a crude oil.
2. Indirect corrosion properties which are caused by non-acidic substances in crude oil, such as mineral salts.

Corrosion caused by crude oil primarily affects atmospheric tower overhead condenser tubes and reflux drums, atmospheric tower fractionation trays, the vacuum tower, overhead condenser tubes and jet ejector bodies, and heat exchangers.

Various substances contribute to the direct corrosion properties of crude oils. Naphthenic acids cause aggravated equipment corrosion, especially at elevated temperatures between 200-400°C and when the TAN number is above 0.5 mg KOH/g of crude. A number of technologies have been explored to reduce the TAN value, for instance by removing naphthenic acids by chemical reactions, neutralisation with caustic, and so on. However, blending high TAN crudes with low TAN crudes is the most economical solution to reduce the content of naphthenic acid. H2S is highly corrosive too. Its removal requires the treatment of crude oil with scavenger chemicals.

Indirect corrosion is caused by the presence of mineral salts dissolved in an oil-water emulsion in crude oils. These salts do not directly corrode equipment but will lead to corrosive conditions during processing. About 70% of the salt content comprises sodium chloride, a relatively stable salt even at higher temperatures. Its impact is relatively mild compared to other salts such as calcium chloride (CaCl2) and magnesium chloride (MgCl2), which are also present in crude oil but are far less stable than sodium chloride. They easily decompose at lower temperatures and hydrolyse in the presence of moisture to form highly corrosive hydrochloric acid.

Magnesium chloride hydrolyses during preheating at about 120°C, while calcium chloride hydrolyses at 220°C, with the formation of hydrogen chloride (HCl) and precipitation of their relevant oxides:

MgCl2 + H2O →  MgO + 2 HCl
CaCl2 + H2O →  CaO + 2 HCl

These chloride salts melt in heaters where the temperature can reach as high as 300°C. In heat exchanger and heating furnaces, and with the evaporation of water, salts are deposited on tube walls. This decreases heat transfer efficiency and increases pressure drop. In a severe case, it will block a tube and cause a shutdown. In the presence of water in crude oil, hydrolysis of the salts will occur in a distillation tower’s preheater furnaces, resulting in fouling due to the precipitation of water insoluble calcium and magnesium oxides, and corrosion by HCl.

When the temperature cools below the dew point in the distillation tower, the effect of HCl will be strongest. The walls of the distillation tower react with HCl and H2S, especially where HCl dissolved in condensate accumulates to form iron sulphide and iron chlorides which coat the walls or cause fouling:

Fe + HCl  →  FeCl2 + H2
FeCl2 + H2S →  FeS + 2 HCl
Fe + H2S →  FeS + H2
FeS + 2HCl → FeCl2 + H2S
 
It is clear that acidity affects the overhead more than in the area of heavier distillates, which have distillation temperatures high enough to push HCl or water into higher sections of the distillation tower.

Salts that are not hydrolysed at the temperature of the bottom product in the crude atmospheric tower will find their way into the vacuum tower and to the FCC unit. They will hydrolyse and decompose, causing corrosion in the vacuum tower. HCl, H2S and resulting iron salts will find their way into downstream equipment such as the FCC unit and the hydrotreater and initiate the corrosion cycle. They also affect the catalyst, which results in more frequent need for catalyst change-out.

Preventative actions that are taken inside the distillation tower and in the overhead system do not replace the need to remove the maximum amount of salt content from the crude oil before it enters the crude distillation unit.

The salt content of crude oils varies with origin, the water content in the emulsion and the amount of emulsion-forming particles in the crude oils, like polar resins and asphaltenes. To prevent corrosion, it is essential to pre-process the crude oil in the desalter which breaks the oil/water emulsion, separating the water from the crude oil, and thus removing the salt.

To increase the refining margin, refineries purchase crude oils and crude blends at the lowest cost, often as heavy and sour opportunity crudes which are blended with other crude oils. Therefore the salt content and emulsion properties will frequently fluctuate according to the crude feed in the desalter. Some crudes are difficult to desalt, such as Venezuelan extra heavy crude, Doba crude and Canadian crudes, and form HCl in the preheater of the desalter.

High salt content in heavy and opportunity crudes also plays an important role in scale accumulation in heat exchanger tubes due to the formation of insoluble sulphide salts of magnesium and calcium, which results in:
• Reduced heat transfer in heaters, causing more fuel consumption and higher cost
• Hot spots in heating tubes, which reduces their operational life
• Reduced flow rates which overloads pumping units, making them less efficient
• Blockages in tubes which lowers their capacities and efficiencies.
Current Rating :  3

Add your rating:



Your rate: 1 2 3 4 5