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There are hundreds of kilometers of above-ground carbon steel pipelines located in 32 in-situ oilsands facilities operated by 18 producers in Alberta Canada, with a total thermal oilsands capacity (operating) of 1.8 million barrels per day. A typical in-situ oilsands operation is for recovering bitumen located 75 meters or more below the surface, by the injection of steam.
There has been multiple reported and documented external stress corrosion cracking (SCC) of above-ground carbon steel pipelines within the past 5 years for a number of in-situ oilsands operators. Majority of these failures were on pipeline carbon steel grades API 5L or Z245.1 with specified minimum yield strength (SMYS) 52 ksi or higher, but there were also reports of external SCC on A106 Gr B and A234 WPB steel grades. All the cracks manifested on the bare (uncoated) Outside Diameter (OD) surface of the pipe, and all were associated with wet mineral wool insulation. Common features include operating temperature between 70°C and 160°C, intergranular cracking morphology, and exposed to wet mineral wool insulation with vintage post 2005.
Previously, SCC of carbon steel pipelines has been commonly reported and investigated for buried pipelines. There is limited information in the industry however on SCC of above ground carbon steel pipelines. Extensive field and lab tests were performed to understand the mechanism, in conjunction with technical studies/ literature reviews. This paper provides a summary aimed at increasing the awareness of the industry with this new damage mechanism, and improve public safety.
Major manufacturers of protective coatings, steel fabricators, painting contractors, galvanizers, and end users, were surveyed to identify surface preparation and coating application costs, coating material costs, typical industrial environments and available generic coatings for use within those environments, and expected coating service lives (practical maintenance time).
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High flow velocity can have negative impact on the integrity of the oil and gas production equipment. This negative impact can manifest by the reduction of Corrosion Inhibitor (CI) efficiency: the higher the flow velocity, the lower the CI efficiency. The negative impact can also manifest by the occurrence of liquid erosion corrosion phenomena.
H2S corrosion, also known as sour corrosion, is one of the most researched types of metal degradation in oil and gas transmission pipelines requiring a wide range of environmental conditions and detailed surface analysis techniques. This is because localized or pitting corrosion is known to be the main type of corrosion failure in sour environments which caused 12% of all oilfield corrosion incidents according to a report from 1996. Therefore, control and reduction of this type of corrosion could prevent such failures in oil and gas industries, and significantly enhance asset integrity while reducing maintenance costs as well as eliminating environmental damage.