Internal Corrosion of Pipelines Carrying Crude Oil
Crude oil is highly complex, which makes the corrosion of the pipelines carrying it complex as well.
Crude oils are a highly complex combination of hydrocarbons, heterocyclic compounds of nitrogen, oxygen, sulphur, organometallic compounds (any member of a class of substances containing at least one metal-to-carbon bond in which the carbon is part of an organic group), inorganic sediment, and water. More than 600 different hydrocarbons have been positively identified in crude oil, and possibly thousands of compounds occur, many of which will never be identified.
Usually, crude oil is separated into three categories based on the API gravity scale. They are light crude, medium crude and heavy crude. Specific gravity and API gravity evolve in opposite directions. Therefore, the smaller the API number, the heavier the fluid.
Read: An Intro to Pipeline Corrosion and Protection Methods
The Main Types of Corrosion Found in Pipelines Carrying Crude Oil
There are millions of kilometres of pipelines carrying crude oil in the world. The integrity of these pipelines is of utmost importance. The rupture or leak of a pipeline could have dire consequences to the environment, humanity and production loss. Corrosion is certainly one factor that can cause pipeline failure. Here are some of the main types of corrosion that cause it.
Carbon Dioxide (CO2) or Sweet Corrosion
Carbon dioxide corrosion - also known as sweet corrosion - is a type of corrosion that typically occurs in pipelines when dissolved CO2 gases in the crude oil react with water to form carbonic acid. This eventually corrodes the internal surface of the pipe. CO2 corrosion increases in the presence of both oxygen and organic acids, which can dissolve iron carbonate scale and prevent further scaling. When CO2 presents, there are various types of corrosion mechanisms that could take place. The main ones are pitting corrosion, uniform corrosion, wormhole attack, ringworm corrosion, erosion corrosion and mesa attack.
CO2 corrosion of steels usually occurs as shallow pits and grooves, which sometimes overlap. While some surfaces may remain unaffected, the corrosion is often remarkably uniform in the attacked areas, leading to so-called "mesa-corrosion," a characteristic of CO2 corrosion. In carbon steels, localized general thining and pitting corrosion are possible as well.
Possible Locations Where CO2 Corrosion May Be Found
CO2 corrosion damage related to fluid flow is primarily associated with the separation and accumulation of a water phase. Therefore, longitudinal corrosion grooving ("6 o'clock corrosion") is the primary concern in stratified gas/liquid flow wet gas pipelines.
CO2 corrosion predominantly occurs at surfaces freely exposed to the corrosive environment, for example shielded areas such as narrow crevice arcs are not attacked even though they may be "wetted" by the fluid. Corrosion may occur along the bottom surface of a pipe if there is a separate water phase or along the top surface of a pipe if condensation in wet gas systems occurs.
How to Mitigate CO2 Corrosion Damage
- Use effective pigging and chemical inhibition programs.
- Control process parameters such as pH, temperature and the pressure of the pipeline.
Hydrogen Sulphide (H2S) or Sour Corrosion
Hydrogen sulphide gases are produced in the crude oil, which comes from the reservoir or wells. The deterioration of metal due to contact with hydrogen sulphide (H2S) and moisture is called sour corrosion, which is the most damaging to drill pipe. Although H2S is not corrosive by itself, it becomes a severely corrosive agent in the presence of water, leading to pipeline embrittlement (loss of toughness).
When dissolved in water, hydrogen sulphide tends to form a weak acid. As such, it is a source of hydrogen ions and is corrosive. The corrosion products are iron sulphides and hydrogen. Iron sulphides form a scale that, at low temperature, can act as a barrier to slow corrosion. The forms of sour corrosion are uniform, pitting and stepwise cracking.
The Appearance of Wet H2S Damage
The appearance of corrosion damage from sour water corrosion is usually general thinning. However, localized corrosion or localized under-deposit attack can occur when air or oxygen is present.
Possible Locations Where Sour Corrosion Can Be Found
H2S in crude oil interacts with water, and interior pipe walls could form many types of sour corrosion. Depending on the type of corrosion mechanism, it can be found in various locations in the pipeline, as shown below.
How to Mitigate H2S Corrosion Damage
There are some key ways to minimize H2S corrosion damage in pipelines. They include:
- Use normalized electric resistance welding (ERW) line pipe that meets the industrial steel selection code requirements.
- Conduct periodic pigging of pipeline segments to remove liquids, solids and debris. Pigging is one of the most effective methods of internal corrosion control, and selection of pig type and sizing is essential.
- Periodically apply a batch corrosion inhibitor to provide a protective barrier on the inside surface of the pipe.
Microbiological Induced Corrosion (MIC)
MIC is not a form of corrosion but rather a process that can influence and even initiate corrosion. MIC in itself is not a unique corrosion mechanism; instead, it produces conditions that increase the susceptibility of materials to corrosion processes such as pitting, embrittlement and under deposit corrosion (UDC).
If unfamiliar with MIC, corrosion problems may be misdiagnosed as conventional chloride-induced corrosion or CO2 corrosion. One prominent indicator of MIC is a higher rate of attack than one would generally expect. MIC is corrosion affected by microorganisms' presence or activity (or both) in biofilms on the corroding material's surface. Many materials, including most metals and some nonmetals, can be degraded in this manner. MIC can result from microorganisms' activities, including bacteria, Archaea, and fungi in biofilms or the local environment directly connected with the corroding material. Depending on the environment, these microbes may include metal-oxidizing bacteria, sulphate-reducing bacteria (SRB), prokaryotes (SRP), acid-producing bacteria (APB) and metal-reducing bacteria (MRB).
The Appearance of Damage from Microbiological Induced Corrosion
Damage is often characterized by cup-shaped pits within pits (halo effect) in carbon steel or subsurface cavities in stainless steel. However, these pits are often indistinguishable from under-deposit corrosion in carbon steel and chloride pitting in stainless steel. Therefore, pit morphology alone may not be a reliable indicator of the cause of MIC corrosion.
Read: Testing for Microbiologically Influenced Corrosion in Pipelines
There are a few key ways to mitigate MIC. These include:
- If a biofilm is formed inside the pipeline, pigging can scrape it out. However, it cannot remove the entire bacterial colonization, and the bacteria may grow and develop the biofilm again.
- Biocides are the most effective chemicals used to terminate microbiologically influenced corrosion. They are chemical compounds that kill living microorganisms, and are of two types - oxidizing biocides and non-oxidizing biocides.
- It is also essential to have a continuous protective coating that can tolerate aggressive chemicals such as sulfuric acid and acetic acid produced by some acid-producing bacteria as part of the corrosion attack.
- The most recent scheme for mitigating microbiologically influenced corrosion using biological treatments uses different types of bacteria against the primary bacteria responsible for MIC in a specific industrial environment.
Oxygen can cause corrosion. Oxygen can enter a pipeline through seals on the suction side of pumps and storage tanks if the oil is exposed to the air (for example, floating roof tanks). Generally, the concentration of oxygen in the crude oil will be low because there is sufficient dissolved gas in the oil at equilibrium to prevent a high concentration of oxygen dissolving in the crude oil: this is because carbon dioxide and hydrogen sulphide are more soluble in crude oil and water than oxygen. If there is any trace of hydrogen sulphide present, this will react with the oxygen.
Corrosion by oxygen will typically occur at the inlet of the pipeline and reduce further downstream as the oxygen concentration is depleted. The ingress of oxygen will be low, and the oxygen will be dispersed into the oil stream. Oxygen is more soluble in oil than in water. Consequently, a slight ingress of oxygen will not necessarily result in a high corrosion rate because the oxygen in the water will be low. If the water that entered the pipeline were saturated with oxygen at eight ppm (the saturation concentration of oxygen in water at ambient temperature), the concentration in the 0.5% water phase in a crude oil pipeline would be below 40 parts per billion.
The appearance of the oxygen corrosion damage is pitting or general corrosion.
The use gas blanketing, vacuum deaeration, and oxygen scavengers can help mitigate oxygen corrosion in pipelines.
On numerous occasions during my failure investigation work I have encountered this type of damage mechanism in pipelines. The erosion corrosion mechanism increases the corrosion reaction rate by continuously removing the passive layer of corrosion products from the pipe wall. The passive layer is a thin film of corrosion products that stabilizes the corrosion reaction and slows it down. As a result of the turbulence and high shear stress in the line, this passive layer can be removed, causing the corrosion rate to increase. Erosion corrosion is always experienced with a high turbulence flow regime with a significantly higher corrosion rate and depends on fluid flow rate and the density and morphology of solids present in the fluid. High velocities and the presence of abrasive suspended material and the corrodents in drilling and produced fluids contribute to this destructive process. This form of corrosion is often overlooked or recognized as being caused by wear.
There are a few key methods for mitigating erosion corrosion. They include:
- Increasing the pipe diameter to reduce velocity, streamlining bends to reduce impingement, and using replaceable impingement baffles.
- Erosion corrosion is best mitigated by using more corrosion-resistant alloys or altering the process environment to reduce corrosivity, such as by deaeration, condensate injection, or adding inhibitors, as applicable.
Crevice corrosion is usually localized corrosion taking place in the narrow clearances or crevices in the metal and the fluid getting stagnant in the gap. This is caused by concentration differences of corrodents over a metal surface. Electrochemical potential differences result in selective crevice or pitting corrosion attacks. Oxygen dissolved in drilling fluid promotes crevice and pitting attacks of metal in the shielded areas of the drill string and is the common cause of washouts and destruction under rubber pipe protectors.
Crevice corrosion is a form of localized corrosion that occurs at, or immediately adjacent to, discrete sites where free access to the bulk environment is restricted. This form of corrosion, normally, can be identified visually and is recognized by the pitting or etching near or adjacent to locations of restricted flow. Common sites for crevice corrosion are under loose-fitting washers, flanges, or gaskets. However, this form of corrosion is not limited to crevices formed by mated surfaces of metal assemblies. Crevice corrosion can also occur under scale and surface deposits (termed "under deposit" corrosion).
There are a few key ways to mitigate crevice corrosion. They include:
- Do not form crevices. Use alternative joining techniques such as welding or brazing.
- Use sealants to avoid moisture penetrating the crevice.
- Design to remove stagnant areas where moisture and deposits can collect.
- Increase maintenance to include removal of deposits by high-pressure washing.
Written by Dennis Jayasinghe | Principal/Chief Technical Officer, Corr-Met Inspection & Consulting Inc.
Dennis Jayasinghe is a Senior Corrosion Engineer with over 15 years of combined experience in industry and research. Dennis brings substantial experience in corrosion failure analysis, corrosion mitigation and monitoring methods, corrosion inspection, design improvement against corrosion, corrosion risk assessment, development of corrosion management programs, and proper material selection for a specific environment. Additionally, he is an expert in solving quality-related issues of steel, stainless steel and galvanizing. After holding senior engineering positions in various manufacturing companies in Canada, he established CorrMet Inspection & Consulting, where he served as Principal. Dennis is a registered and active professional engineer in Alberta and Saskatchewan provinces in Canada and a full NACE member.