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Field Testing of Self-Healing Metallic Coatings for Internal Corrosion Protection of Natural Gas Pipelines

Picture for Field Testing of Self-Healing Metallic Coatings for Internal Corrosion Protection of Natural Gas Pipelines
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Natural gas pipelines are subject to internal corrosion. Internal corrosion of steel pipelines can cause natural gas leakage, leading to wasted energy, explosion hazards, and methane emissions. The U.S. Department of Transport reported numerous case histories of corrosion problems and failures in wet gas pipelines. The National Energy Technology Laboratory (NETL) performed an incident survey from 2010 through 2018 and found that 112 (12%) of these incidents in the U.S. transmission lines were caused by internal corrosion.

Product Number: 51323-18857-SG
Author: Zineb Belarbi, Ömer N. Doğan, Patrick Carr, Richard E. Chinn, Julius Samson
Publication Date: 2023
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$20.00
$20.00

Internal corrosion occurs in natural gas pipelines primarily due to the presence of water, carbon dioxide, and hydrogen sulfide. Internal corrosion can eventually result in leakage, cracks, and rupture of the pipeline. The objective of this work is to mitigate internal corrosion in steel pipelines transporting natural gas using cold spray coatings. The corrosion behavior of carbon steel coated with self-healing ZnCr and ZnNb cold spray coatings was investigated in a natural gas environment. For comparison purposes, hot-dip galvanized steel (HDGS) was tested under the same conditions as cold spray coatings.
The field test was performed at the NW Natural gas storage facility in Mist, Oregon. The field test was conducted in a 6-inch diameter pipe transporting wet natural gas out of an underground storage well at 500 psi and 40o F. The coupons were tested for 15 and 32 days under stagnant and flow conditions, respectively. Weight loss method was used to measure corrosion rate of metallic coatings. Post-corrosion surface characterization was performed on the specimen using a scanning electron microscopy (SEM) equipped with energy dispersive X-ray spectroscopy (EDS). Crystalline phases were determined by X-ray diffraction (XRD). The field-test results confirm that the metallic coatings provide corrosion protection of carbon steel exposed to wet natural gas under stagnant and flow conditions. The formation of the ZnCO3 layer on top of ZnNb and ZnCr coatings led to passivation of the coatings which helps to reduce the self-corrosion. These layers form a barrier for diffusion of corrosive species to the surface.

Internal corrosion occurs in natural gas pipelines primarily due to the presence of water, carbon dioxide, and hydrogen sulfide. Internal corrosion can eventually result in leakage, cracks, and rupture of the pipeline. The objective of this work is to mitigate internal corrosion in steel pipelines transporting natural gas using cold spray coatings. The corrosion behavior of carbon steel coated with self-healing ZnCr and ZnNb cold spray coatings was investigated in a natural gas environment. For comparison purposes, hot-dip galvanized steel (HDGS) was tested under the same conditions as cold spray coatings.
The field test was performed at the NW Natural gas storage facility in Mist, Oregon. The field test was conducted in a 6-inch diameter pipe transporting wet natural gas out of an underground storage well at 500 psi and 40o F. The coupons were tested for 15 and 32 days under stagnant and flow conditions, respectively. Weight loss method was used to measure corrosion rate of metallic coatings. Post-corrosion surface characterization was performed on the specimen using a scanning electron microscopy (SEM) equipped with energy dispersive X-ray spectroscopy (EDS). Crystalline phases were determined by X-ray diffraction (XRD). The field-test results confirm that the metallic coatings provide corrosion protection of carbon steel exposed to wet natural gas under stagnant and flow conditions. The formation of the ZnCO3 layer on top of ZnNb and ZnCr coatings led to passivation of the coatings which helps to reduce the self-corrosion. These layers form a barrier for diffusion of corrosive species to the surface.

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Picture for Revisiting Alloy K-500 with Improved Performance Limits for Short and Long-Term Subterranean Applications
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Revisiting Alloy K-500 with Improved Performance Limits for Short and Long-Term Subterranean Applications

Product Number: 51323-18787-SG
Author: Manuel Marya
Publication Date: 2023
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Alloy K-500 (UNS N05500) is concomitantly a centurial material and the very first precipitation-strengthened nickel-based alloy, then developed in the 1920s by the newly-formed International Nickel Company, or Inco. 
Derived from Monel 400 (UNS N04400) that was invented in 1901, Alloy K-500 shares many of the same corrosion and tribological characteristics.  Being a pioneer alloy with so-called “stain-less” characteristics, Alloy
K-500 also established itself as the first high-strength oilfield nickel alloy, having survived sour service conditions exceeding the capabilities of the low-alloy steels of the time. From early naval propeller shaft applications to
general cross-industrial uses, Alloy K-500 has always been considered a corrosion-resistant alloy, or CRA. For instance, it has been included in the NACE MR1075 document right from the first 1975 edition. 
Picture for Investigation of the Pitting Corrosion Behavior of Austenitic Stainless Steel UNS S20910 Correlated to its Microstructural Condition
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Investigation of the Pitting Corrosion Behavior of Austenitic Stainless Steel UNS S20910 Correlated to its Microstructural Condition

Product Number: 51323-18877-SG
Author: Helmuth Sarmiento Klapper, Julia Ditmann, Clara Herrera, Merlin Seifert
Publication Date: 2023
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During drilling operations, the components in the drill string including the bottom hole assembly (BHA) remains in permanent contact with the drilling fluid. Therefore, besides non-magnetic properties and high strength the corrosion resistance of the materials utilized for the BHA plays a decisive role specially in applications involving harsh environments. In fact, strain-hardened CrMn-austenitic steels commonly used in directional drilling technology show a high susceptibility to pitting corrosion and environmentally assisted cracking in drilling fluids with a high chloride (Cl-) content at elevated temperatures.
Picture for Performing Corrosion Risks Assessments of Nuclear Waste Process Tanks Containing Variable Waste Chemistries
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Performing Corrosion Risks Assessments of Nuclear Waste Process Tanks Containing Variable Waste Chemistries

Product Number: 51323-18878-SG
Author: J.S. Page, S.T. Campbell, C.L. Girardot, J.R. Gunter
Publication Date: 2023
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The Hanford Site stores over 50 million gallons (190 million liters) of legacy nuclear process waste that was generated from plutonium separations and waste management processes. This waste, in the form of supernatant liquids, saltcakes, and sludges is contained in large underground storage tanks, up to a million gallons (3.78 million liters) in capacity and lined with carbon steel. The waste was made highly alkaline to ensure passivation of the carbon steel, but it also contains nitrate, in high concentrations, along with fluoride and chloride that poses risks for stress corrosion cracking and pitting corrosion.
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