Desalting heavy Canadian crudes

Effective desalting requires large desalters and attention to all variables associated with good desalter performance

Tom Collins, Forum Energy Technologies
Tony Barletta, Process Consulting Services

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Article Summary

Heavy Canadian crudes from Alberta and Saskatchewan are some of the most challenging crudes to desalt because of their oil properties, composition and contaminants. The geographic location of the producing basin and, to some extent, the production method determine the degree of desalting difficulty due to variability in filterable solids, viscosity, “cutterstock” composition, asphaltene content, naphthenic acid content and other contaminants. Even though many of these crudes are between 18.5-22° API gravity, their desalting characteristics are not the same. For example, heavy Canadian crudes such as Cold Lake or Lloydminster B are easier to desalt than bitumen-derived blends from Northern Alberta. Heavy Canadian crude production is increasing, so more refiners will be exposed to increasing volumes of these crudes.

The purpose of the desalter is to remove contaminants and chlorides from the raw crude oil. The reduction in chlorides reduces corrosion and thereby improves reliability and run length. Most refiners target a four-to-six-year run length between maintenance turnarounds on their crude units. Crude and vacuum unit (CDU/VDU) run length has been materially reduced when processing large percentages of crudes derived from heavy Canadian bitumen, especially from Northern Alberta. Poor desalter performance is one of the major contributors to the shortened run length. This article presents an overview of critical desalter design and operating considerations for heavy Canadian crude processing, focusing on salt removal. These same design and operating requirements apply to other heavy opportunity crudes.

Heavy Canadian crudes
For many years, US refiners have processed heavy conventional crudes or heavy synthetic crudes from Venezuela. BCF 17 is an example of conventional crude, whereas Merey is a blend of light crude and Orinoco bitumen. Examples of Venezuelan synthetic heavy crudes are PetroZuata and Hamaca, which are blends of coker products (sometimes hydrotreated) and Orinoco bitumen. Heavy Canadian crudes are similar to the Venezuelan crudes with respect to desalting difficulty, with the added challenge of high filterable solids. Two types of heavy Canadian crudes are encountered. They are:
• Conventional heavy crudes, such as Bow River and Lloydminster B
• Bitumens, diluted with synthetic crudes produced from cokers and resid hydrocrackers or diluted with condensate.

Bitumens are produced in the Cold Lake, Peace River and Athabasca regions, with the majority of future production by steam-assisted gravity drainage (SAGD) methods. Heavy Canadian crudes contain varying amounts of filterable solids, hard-to-remove chlorides, amines and H2S scavengers from the production process. The filterable solids are iron oxides, iron sulphides, sand and clay.

By definition, bitumens contain high asphaltene concentrations, which present problems when they precipitate from the crude oil either in the desalter or the preheat train. Bitumens mixed with paraffinic condensates and other paraffinic- type crudes increase the likelihood of asphaltene precipitation and stable rag layer formation in the desalter.

A significant problem with desalting heavy Canadian crude is the generation of a stable emulsion. Large amounts of solids, H2S scavengers and tramp amines stabilise the emulsion.

Consequences of poor desalting
Desalter performance is generally considered good when desalted crude salt content is less than one pound of salt per thousand barrels (ptb) of crude. When large percentages of heavy Canadian crude are processed, desalted crude salt content can be chronically high (3-5 ptb) or the desalter can have periodic upsets, leading to extremely high salt content for short intervals. In either case, a high salt content in desalted crude significantly increases crude unit corrosion. Additionally, some heavy Canadian and other opportunity crudes contain difficult-to-remove organic and inorganic chlorides, requiring special treating chemistry.

A portion of the salt leaving the desalter hydrolyses to HCl in the atmospheric and vacuum heaters. The amount of hydrolysis depends on the heater temperature, the type of salt and the presence of other compounds such as naphthenic acids contained in the crude. Many refiners inject caustic downstream of the desalter to convert chlorides that hydrolyse to more stable sodium chloride (NaCl), to reduce the HCl level in the crude overhead system. This practice helps reduce chlorides. However, if the desalted crude salt content is in the 3-6 ptb range, even additional caustic will not materially improve reliability.

A portion of the thermally stable NaCl remaining in the desalted crude, which does not hydrolyse in the atmospheric heater, will break down to HCl in the vacuum heater. Hence, corrosion rates and fouling in the vacuum column overhead system can be very high relative to conventional crudes. Corrosion in the vacuum column overhead system and salt laydown in the top of the vacuum column have become much more common with heavy Canadian crude processing. This same problem is also common with heavy Venezuelan and other opportunity crudes.

Poor desalting generally leads to a very high corrosion rate in the atmospheric crude and vacuum column overhead systems. It is not uncommon for the top of the columns to experience corrosion and/or salting. Peripheral equipment such as top pumparounds and product rundown systems have experienced fouling and corrosion, too. Piping, exchangers, ejector equipment and drums have all been severely corroded, with loss of containment occurring in several instances. Rapid laydown of amine chloride salts in the top of the atmospheric crude column is relatively common and, increasingly, the internals in the top of vacuum columns foul with chloride salts. Atmospheric crude columns with top pumparounds can have very high corrosion rates in the piping, pumps, exchangers and control valves.

Vacuum column light vacuum gas oil pumparounds (LVGO) and vacuum preflash column top pumparounds have shown a high metal loss. These chlorides eventually make their way to downstream hydrotreating equipment, where higher corrosion rates have also been observed. Other consequences of poor desalting include severe exchanger fouling from poor filterable solids removal in conjunction with poor exchanger design.

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