Limiting corrosion in oilfield tubulars

Corrosion damage

Due to recent challenges in the oil and gas industry, it is critical for specifiers to choose the best products for an application, ensuring the long-term success of the project. Specifically, products in highly corrosive environments must be safeguarded to ensure reliable service life, thereby helping to ensure return-on-investment.

The fight against corrosion is an ongoing, costly battle that must be fought in nearly all oil and gas productions operations where water or corrosive elements such as carbon dioxide (CO2) and hydrogen sulfide (H2S) are present. Each year, corrosion damage results in reduced operating profit, causing oil and gas companies to lose, literally, billions of dollars.

In the course of this article, specifiers from oil and gas companies will gain knowledge about corrosion, especially as it relates to the protection of steel tubulars, and how to reduce corrosion by properly specifying the best available prevention methods.

For corrosion to occur in oilfield applications there has to be water in contact with the metal surface. In the oil and gas production industries, the major forms of corrosion include sweet corrosion, sour corrosion, oxygen corrosion, galvanic corrosion, crevice corrosion, erosion corrosion, microbiologically induced corrosion, and stress corrosion cracking.

Oilfield corrosion is often ‘sweet’ or ‘sour’ due to impact from oxygen. Oxygen is introduced in several oilfield applications such as water flooding, maintenance of pressure, gas lifting or completion fluids.

  • 'Sweet’ corrosion from dissolution of COin the produced brine. CO2 corrosion can influenced by temperature, an increase in pH value, composition of the water, presence of non-aqueous phases, flow condition, and more. Sweet corrosion is the common corrosion found in oil and gas production. Typically, pitting or material loss will occur to the tubular steel.
  • ‘Sour’ corrosion is caused from H2S. H2S is not corrosive alone; it becomes a corrosive agent with exposure to water. The tubular material will fail at stress levels below their normal yield strength as a result of degradation.
  • Galvanic corrosion is caused by the pairing of corrosive and noncorrosive metal in the presence of a corrosive agent.
  • Oxygen corrosion typically occurs from the oxygen dissolved in produced fluids. Even small amounts of oxygen, mixed with water and chlorides, can corrode tubing quickly.

“There is no corrosion mechanism more damaging on a concentration basis than oxygen – small amounts of oxygen, water and chlorides can ruin a chrome tubing completion in a few months. Injection wells are the most severely affected – minimise oxygen and don’t use chrome pipe in injectors.” George E. King, Engineering,

  • Crevice corrosion occurs in crevices in the metal where fluid becomes trapped.
  • Erosion corrosion caused by abrasion of metal surfaces by particles such as sand, shown in the photo below.
  • Bacterial Corrosion produces CO2, H2S, and acids that corrode the pipes and can cause plugging problems in injector wells.
  • Stress corrosion occurs when metal is in tension and exposed to H2S and water. Tensile stress can occur within a range of velocities from 3 to 10 mm/h.

Specifying the proper corrosion prevention solution for oilfield tubulars increases reliability, efficiency and overall production capacity. A high-performance product will not only protect tubulars from corrosion, but will lower overall expenditure and reduce maintenance costs. Here are a few key points to know for making a proper specification:

  • Begin with a basic knowledge of corrosion resistant alloys (CRA), internal coatings, and internal liners, in order to know which will perform best in a specific application.
  • Investigate the environment in which the tubulars will operate—more demanding environments usually require durable liners, and for extreme temperatures, GRE liner can be the best option.
  • Investigate routine operational practices the tubulars will be subject to—use of wireline or coil tubing will cause damage to coatings and therefore requires a liner.
  • Pay attention to key differences in liner options. Know that GRE liners have generally outperformed other polymer options, with a history of effective corrosion protection for over 30 years.
  • Look at the liner smoothness, as it increases overall production rates, and prevents particle buildup and unnecessary maintenance costs caused by friction inside the tubulars.

Corrosion resistant alloys

The compositions of corrosion-resistant alloys (CRAs) typically include ferrous stainless steels, nonferrous nickel, and cobalt alloys. CRAs provide more corrosion resistance than carbon steel, and therefore have been specified for applications in which carbon steel is not enough. For example, many specifiers have used carbon steel materials for oil and gas production applications and have found the need to switch to CRAs for deepwater applications. However, there are two downsides to this choice.

One is that there are various CRAs—different blends of metals—and selecting the right CRA for the environment can be complex. If mistakes are made, it can be costly. Another issue is that CRAs are significantly higher in price than other corrosion prevention options, and require a much longer delivery time. Consequently, specifiers have begun to explore alternatives such as internal coatings and liners.

Internal coatings

While intact, powder coatings effectively protect against corrosion, but they are thin and rather susceptible to damage. Often the thickness of powder coatings is not consistent, and the adhesion of the coating to the pipe is not strong. Eventually the thinnest areas of the coating begin to deteriorate and chip off, exposing the pipe and resulting in localised corrosion. These deteriorated areas grow, potentially leading to tubing failure and costly system shutdown.Many powder coatings have improved over the years, though it is essential to understand how the environmental conditions and operational practices of the application will affect the success of the product. For example, high temperature applications will likely cause a faster rate of adhesion failure, and coatings that will be potentially exposed to wireline tools and coil-tubing operations are highly susceptible to damage. In general, coatings are less durable than other corrosion prevention options, such as internal liners.

Internal liners

While liners are generally more durable than powder coatings, there are differences between liner options that will need to be considered according to the environmental conditions of the application. A complete evaluation of environmental factors, such as potential temperatures and pressures, is necessary to know which kind of liner will work for your application.

Polyvinyl chloride (PVC) liners are commonly used for corrosion prevention and perform effectively in lower-to-average temperature applications. Thermoset glass-reinforced epoxy (GRE) liners are designed for more demanding applications and are capable of withstanding higher temperatures. Available in various levels of chemical resistance, all with the ability to perform reliably in high temperatures, GREs have become an ideal solution for a wide range of applications.

Overall, GRE liners have solved challenges more reliably and efficiently than other tubular corrosion control options. The stability and consistent strength of GREs resists deterioration, even in high temperature applications, and prevents exposure of the steel pipe to corrosive fluids. GRE lining systems have proven to have long-lasting, reliable performance in applications such as water injection, CO2 injection, gas production, gas-lifted oil production, environments containing H2S, as well as onshore and offshore chemical disposal wells.To learn more how liners have been used for brine water and chemical disposal applications click here.

One manufacturer of high-quality GRE liners with a track record of solid performance in the field is Duoline® Technologies. These products are manufactured with an innovative process of wound fibres that undergo a high-temperature cure process. This advanced process, which cures liners from the inside-out, guarantees consistent strength and stability of the material. As well, the unprecedented manufacturing techniques produce the smoothest lining option available—another extremely important factor to consider when choosing an internal liner.A smoother internal surface eliminates setbacks that can be caused by friction, and increases efficiency of production. Understanding a few key points about the benefits of a smoother internal surface will make a big difference in specifying the best lining option for a corrosive environment.


Understanding the types of corrosion of tubulars for oilfield applications is critical for choosing the best prevention methods. Properly specifying the best available prevention method for the application will result in the overall reduction of tubular corrosion. Thus, a reduction in the high cost of corrosion found in the oil and gas industry will occur, along with the long-term success of the project in the field.

Sourced from: Duoline Technologies, David Marshall


Published on 11/08/2015

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