How To Optimize Tubing Material Selections Using the PREN Value

Despite its inherent resistance to corrosion, stainless steel tubing installed in a marine environment suffers from different types of corrosion throughout its expected lifetime. Such corrosion can lead to fugitive emissions, lost product, and potential risks. Offshore platform owners and operators can reduce corrosion risks at the outset by specifying more robust tubing materials that offer better corrosion resistance. Later, they must remain vigilant in their inspections of chemical injection, hydraulic, and impulse lines, as well as process instrumentation and sensing equipment, to ensure corrosion isn’t threatening the integrity of the installed tubing and impacting safety.

Localized corrosion can be found on tubing in many platforms, ships, vessels, and offshore facilities. Such corrosion may be in the form of pitting or crevice corrosion, either of which could eat through the tubing’s wall and lead to a release of fluids.

The risk of corrosion is greater when the operating temperatures of the application are elevated. Heat can accelerate the breakdown of the tubing’s protective outer passive oxide film, encouraging pitting to form.

Unfortunately, localized pitting and crevice corrosion can be difficult to detect, making these types of corrosion more challenging to identify, predict, and design against. In light of these risks, platform owners, operators, and specifiers should exercise proper diligence when selecting the optimal tubing material for their application. Material selection is their first line of defense against corrosion, so it is important to get it right. Fortunately, they can use a very simple, yet highly effective, measure of resistance to localized corrosion known as the Pitting Resistance Equivalent Number (PREN) to make their selections. The higher the PREN value of the metal, the higher its resistance to localized corrosion.

This article will review how to recognize pitting and crevice corrosion, as well as how to optimize tubing material selections for marine oil and gas applications based on the material’s PREN value.

Recognizing Localized Pitting and Crevice Corrosion

Localized corrosion appears in small areas compared to general corrosion, which is more uniform across a metal’s surface. Both pitting and crevice corrosion begin to form on 316 stainless steel tubing when the metal’s exterior, chromium-rich passive oxide film breaks down due to exposure to corrosive fluids, including salt water. Chloride-rich offshore and onshore marine environments, as well as elevated temperatures and even contamination on the tubing surface, increase the likelihood for this passive film to deteriorate.

Pitting Corrosion. When the passive film on a piece of tubing is breached, pitting corrosion can take hold, forming small cavities, or pits, in the tubing’s surface. Such pits will likely grow as electrochemical reactions take place, causing iron in the metal to dissolve into a solution within the bottom of the pit. The dissolved iron will then diffuse toward the top of the pit and oxidize to create iron oxide or rust. As a pit deepens, the electrochemical reaction accelerates, increasing corrosion and potentially leading to the tubing walls perforating and causing leaks.

Tubing is more susceptible to pitting corrosion when its exterior surface is contaminated (Fig. 1). For example, contamination from welding and grinding operations can interrupt the tubing’s passive oxide layer, enabling pitting corrosion to form and accelerate. The same is true for contamination from simply handling the tubing. In addition, moist salt crystals that form on tubing when saltwater droplets evaporate have the same effect on the protective oxide layer and can lead to pitting corrosion. To guard against these types of contamination, keep tubing clean by rinsing it periodically with fresh water.

Fig. 1—316/316L stainless steel tubing contaminated by acids, salt water, and other deposits is highly susceptible to forming pitting corrosion.

Crevice Corrosion. In most cases, operators can readily recognize pitting corrosion. However, crevice corrosion is not easily detectable, which poses a greater risk to operations and personnel. It’s commonly found on tubing that has tight spaces between surrounding materials, such as tubing held in place by clamps or tubing runs installed closely side by side. When salt water wicks into crevices, a chemically aggressive acidified ferric chloride (FeCl₃) solution can form in this area over time and cause accelerated crevice corrosion (Fig. 2). Because the crevice itself increases the risk of corrosion, crevice corrosion can occur at far lower temperatures than pitting corrosion.

Fig. 2—Crevice corrosion is likely to form between tubing and tubing supports (top), as well as when tubing is installed close to other surfaces (bottom), due to the formation of a chemically aggressive acidified ferric chloride solution in the crevice.

In the crevice formed between a piece of tubing and a tube support clamp, crevice corrosion will typically emulate pitting corrosion at first. However, the initially shallow pits will grow larger and deeper until they cover the whole crevice due to an increase in the Fe++ concentration in the fluid within the crevice. Eventually, the crevice corrosion may perforate the tubing.

Tight crevices pose the greatest risk for corrosion to occur. Therefore, tubing clamps that wrap around much of the tubing’s circumference tend to pose a greater risk than more open-style clamps that enable minimal contact surface between the tubing and the clamp. Maintenance technicians can help reduce the likelihood of crevice corrosion resulting in damage or failures by regularly opening clamps and inspecting tubing surfaces for corrosion.

Both pitting and crevice corrosion are best prevented by selecting the proper metal alloys for the application. Specifiers should exercise due diligence to choose the optimal tubing material to minimize the risk of corrosion based on the operating environment, process conditions, and other variables.

Selecting Tubing Alloys Based on PREN Calculations

To help specifiers optimize material selections, they can compare the PREN values of the metals to determine their resistance to localized corrosion. The PREN can be calculated based on the chemical composition of the alloy, including its chromium (Cr), molybdenum (Mo), and nitrogen (N) content, as follows:

PREN = %Cr + 3.3x%Mo + 16x%N

The PREN increases with higher levels of the anti-corrosive elements chromium, molybdenum, and nitrogen in the alloy. The PREN relationship is based on the Critical Pitting Temperature (CPT) – the minimum temperature at which pitting corrosion is observed – of various stainless steels related to their chemical composition. In essence, PREN is proportional to CPT. Therefore, higher PREN values indicate greater pitting corrosion resistance. As one compares alloys, a small increase in PREN equates to only a small increase in CPT, while a large increase in PREN indicates a more substantial performance improvement to a significantly higher CPT.

Table 1 provides a comparison of PREN values for various alloys typically specified for marine oil and gas applications. It demonstrates how significantly specifiers can enhance corrosion resistance by selecting a higher-grade tubing alloy. When transitioning from 316 to 317 stainless steel, the PREN increases by only a small amount. To realize a significant performance increase, one would ideally use 6-moly super austenitic stainless steel or 2507 super duplex stainless steel.

Table 1—PREN values for different alloys.

Higher concentrations of nickel (Ni) in stainless steels also enhance corrosion resistance. However, the nickel content of stainless steel is not part of the PREN equation. Regardless, it is often beneficial to specify stainless steels with higher nickel concentrations, as the element facilitates the re-passivation of surfaces that show signs of localized corrosion. Nickel stabilizes austenite against the formation of martensite during tube bending or cold-drawing of 1/8-hard tubing. Martensite is an undesirable crystalline phase within the metal that reduces the resistance of stainless steels to localized corrosion, as well as chloride-induced stress cracking. A higher nickel content of at least 12% in 316/316L is also desirable for applications involving high-pressure gaseous hydrogen. The minimum required nickel concentration in the ASTM standard specifications for 316/316L stainless steel is 10%.

Optimizing Material Selections To Minimize Corrosion

Localized corrosion can occur anywhere on a piece of tubing used in a marine environment. However, pitting corrosion is more likely to form on areas that have been contaminated, and crevice corrosion is more likely to occur in areas featuring narrow gaps between tubing and mounting hardware. Using the PREN as a basis, specifiers can select the optimal tubing alloy to minimize the risk of either type of localized corrosion.

However, remember that there are other variables that affect corrosion risk. For example, temperature affects the pitting corrosion resistance of stainless steels. For hot marine climates, 6-moly super austenitic or 2507 super duplex stainless steel tubing should be seriously considered, as these materials offer excellent resistance to localized corrosion and chloride stress cracking. For colder climates, 316/316L tubing may be adequate, especially if a successful history of use has been established.

Offshore platform owners and operators can also take steps to minimize corrosion risks after installing tubing. They should keep the tubing clean, rinsing it periodically with fresh water to reduce the risk of pitting corrosion. They should also have maintenance technicians open up tubing clamps during routine inspections to look for the presence of crevice corrosion.

Following the above steps, platform owners and operators can reduce their risk of tubing corrosion and associated leaks in marine environments, enhancing safety and efficiency, while also decreasing the chance of losing product or releasing fugitive emissions.

Brad Bollinger is market manager, oil and gas, at Swagelok Co. He can be reached at bradley.bollinger@swagelok.com.