Distillation Corrosion

During crude oil distillation, oxides and sulfides contained in crude oil undergo thermal decomposition or hydrolysis, generating corrosive media such as hydrogen chloride (HCl), hydrogen sulfide (H₂S), and organic acids, which cause corrosion of equipment and pipelines.

Distillation corrosion in atmospheric and vacuum distillation units is mainly driven by salt hydrolysis, HCl formation, and sulfur-containing compounds during crude oil processing.

The main chlorides include sodium chloride (NaCl), calcium chloride (CaCl₂), and magnesium chloride (MgCl₂). CaCl₂ and MgCl₂ begin to hydrolyze when heated to approximately 120 °C. As temperature increases, the degree of hydrolysis also rises. At an atmospheric furnace outlet temperature of around 360 °C, nearly 90% of MgCl₂ and about 16% of CaCl₂ are hydrolyzed.

MgCl₂ + 2H₂O → Mg(OH)₂ + 2HCl

CaCl₂ + 2H₂O → Ca(OH)₂ + 2HCl

When condensation first occurs in the overhead condensation and cooling system of the fractionation column, the HCl produced by hydrolysis is absorbed into the condensate, forming relatively concentrated hydrochloric acid, which causes severe corrosion to metal surfaces.

Fe + 2HCl → FeCl + H₂

HCl can also react with iron sulfide (FeS), which normally provides a protective film on the metal surface.

FeS + 2HCl → FeCl₂ + H₂S

The ferrous chloride formed is soluble in water, causing the metal to lose its protective film, while corrosive H₂S is released. The metal is then subjected again to H₂S corrosion. HCl strongly promotes low-temperature sulfur corrosion, significantly accelerating the overall corrosion rate.

Fe + H₂S → FeS + H₂

In the presence of water, HCl can also cause stress corrosion cracking of metals, particularly austenitic stainless steels.

Naphthenic acids are a general term for organic acids present in petroleum. At high temperatures, they react with metals to form naphthenates, and corrosion typically occurs in high-temperature zones such as furnace tubes, transfer lines, fractionator side draws, and column bottoms. Sulfides in petroleum—including hydrogen sulfide, mercaptans, and elemental sulfur—are classified as active sulfur. Sulfides such as thioethers, disulfides, and polysulfides are considered neutral sulfur compounds, which can decompose at high temperatures to form hydrogen sulfide and mercaptans, thereby exerting corrosive effects on metals.

An important process corrosion prevention measure for atmospheric and vacuum distillation units is the electrostatic-desalting-based “one desalting plus three injections” scheme, which includes crude oil electrostatic desalting, ammonia injection at the fractionator overhead, corrosion inhibitor injection, and wash water injection.

Desalting: The hydrolysis of salts contained in crude oil generates hydrogen chloride, which is a major cause of corrosion in the overhead sections of the primary distillation column, atmospheric column, vacuum column, and their associated condensation and cooling systems. Data show that the corrosion rate of equipment is directly proportional to the salt content of crude oil. If the salt content is reduced to 1% of its original level, the annual corrosion rate will also decrease to approximately 1% of its original value. Therefore, in order to prevent corrosion of equipment and pipelines, it is essential to remove salts from the crude oil. The salt content of desalted crude oil not only reflects the operating performance of the electrostatic desalting unit, but also constitutes a key corrosion control requirement of the process. Strictly controlling the salt content of crude oil after desalting to less than 3 mg/L has become an important performance indicator for atmospheric and vacuum distillation units.

Ammonia Injection: Injecting ammonia into the fractionator overhead distillate line is an effective corrosion prevention measure for low-temperature sections. Ammonia neutralizes HCl and H₂S, adjusts the pH of the condensation and cooling system, and, when used in conjunction with corrosion inhibitors, enhances their effectiveness. The ammonia injection rate should be sufficient to neutralize all HCl and 20%–30% of H₂S, maintaining the pH of the overhead condensate at 6–7. The injection point is located on the overhead distillate line and should be upstream of the corrosion inhibitor injection point.

NH₃ + HCl = NH₄Cl

Corrosion Inhibitor Injection: Corrosion inhibitors contain polar functional groups in their molecular structure, allowing them to adsorb onto metal surfaces and form a protective film that prevents corrosive media from contacting the metal, thereby providing protection. Low pH values (2–3) and high temperatures (>230 °C) can render corrosion inhibitors ineffective. Therefore, ammonia should be injected first to control the pH before inhibitor injection. Corrosion inhibitors are applied in low-temperature sections at the column overhead, and excessively high fluid line velocities can hinder the formation of the protective film. The typical injection rate of corrosion inhibitors is 10–20 μg/g.

Wash Water Injection: Wash water injection shifts the dew point forward and protects equipment. It also dissolves NH₄Cl formed by ammonia injection, preventing NH₄Cl deposition in the overhead condensation and cooling equipment, which could otherwise lead to fouling and blockage.