Pipelines have been installed and operated around the globe to transport oil and gas for decades. They are considered to be an effective, economic and safe means of transportation. The major concern in their operation is corrosion. Among the different forms of corrosion, stress corrosion cracking (SCC), which is caused by stresses induced by internal fluid flow or other external forces during the pipeline’s operation, in combined action with the presence of a corrosive medium, can lead to pipeline failure. In this paper, an extensive review of different factors affecting SCC of pipeline steels in various environmental conditions is carried out to understand their impact. Several factors such as temperature, presence of oxidizers (O2, CO2, H2S, etc.), composition and concentration of medium, pH, applied stress, and microstructure of the metal/alloy have been established to affect the SCC of pipeline steels. SCC susceptibility of a steel at a particular temperature strongly depends on the type and composition of the corrosive medium and microstructure. It was observed that pipeline steels with water quenched and quenched and tempered heat treatments, such as those that consist of acicular ferrite or bainitic ferrite grains, are more susceptible to SCC irrespective of solution type and composition. Applied stress, stress concentration and fluctuating stress facilitates SCC initiation and propagation. In general, the mechanisms for crack initiation and propagation in near-neutral solutions are anodic dissolution and hydrogen embrittlement.

Offshore pipelines are subjected to stresses (e.g., from fluid flow, mechanical vibration, and earth movement). These stresses, combined with corrosive environments and in the presence of trace gases (O2, CO2), can increase the pipeline’s corrosion rate and potentially lead to cracking. As such, the impact of trace gases such as CO2 (linked to enhanced oil recovery and carbon capture and sequestration) on corrosion is key to determining whether pipelines are at increased risk. American Petroleum Institute (API) 5L X70 and X100 were exposed as stressed C-rings (80% or 95 % of yield strength). The tests were conducted with either N2 (control) or CO2 bubbled through 3.5% NaCl, at either 5 °C or 25 °C. Linear polarization resistance was used to assess corrosion rate, while morphology and variation were determined using optical microscopy (generating metal loss distributions) and scanning electron microscopy. The control experiment (N2) showed that corrosion rates correlated with temperature and stress. In this low O2 environment, both alloys showed similar trends. Under CO2 exposure, all samples showed accelerated corrosion rates; furthermore, the morphologies generated were different for the two alloys: undercutting corrosion with discontinuous microcracks (X70) or deep, wide ellipses (X100). Understanding these changes in corrosion response is key when selecting materials for specific operational environments.