The review presented herein is regarding the stress corrosion cracking (SCC) phenomena of carbon steel pipelines affected by the corrosive electrolytes that comes from external (E) and internal (I) environments, as well as the susceptibility and tensile stress on the SCC. Some useful tools are presented including essential aspects for determining and describing the E-SCC and I-SCC in oil and gas pipelines. Therefore, this study aims to present a comprehensive and critical review of a brief experimental summary, and a comparison of physicochemical, mechanical, and electrochemical data affecting external and internal SCC in carbon steel pipelines exposed to corrosive media have been conducted. The SCC, hydrogen-induced cracking (HIC), hydrogen embrittlement, and sulfide stress cracking (SSC) are attributed to the pH, and to hydrogen becoming more corrosive by combining external and internal sources promoting cracking, such as sulfide compounds, acidic soils, acidic atmospheric compounds, hydrochloric acid, sulfuric acid, sodium hydroxide, organic acids (acetic acid, mainly), bacteria induced corrosion, cathodic polarization, among others. SCC growth is a reaction between the microstructural, chemical, and mechanical effects and it depends on the external and internal environmental sources promoting unpredictable cracks and fractures. In some cases, E-SCC could be initiated by hydrogen that comes from the over-voltage during the cathodic protection processes. I-SCC could be activated by over-operating pressure and temperature at flowing media during the production, gathering, storage and transportation of wet hydrocarbons through pipelines. The mechanical properties related to I-SCC were higher in comparison with those reviewed by E-SCC, suggesting that pipelines suffer more susceptibility to I-SCC. When a pipeline is designed, the internal fluid being transported (changes of environments) and the external environment concerning SCC should be considered. This review offers a good starting point for newcomers into the field, it is written as a tutorial, and covers a large number of basic standards in the area.

Purpose: The purpose of this paper was to study the corrosion process of API X52, X60, X65, X70 and X80 steels exposed to two clay soils collected in two states of Mexico (Tabasco and Campeche). To saturate the soils, 60 mL of deionized water was added to simulate the conditions for dry and wet season, due to in field, the climate change could modifies the physicochemical properties of the soils for each season of the year and this generate a variable environment, which affect the electrochemical responses on steel–soil interface. Design/methodology/approach: The corrosion evaluation was carried out simulating the conditions of deteriorated coating (bare steel); this includes steel surface exposed to clay soil affected by seasonal fluctuations in a tropical zone. These soils were characterized, without any further treatment as were found in the field (dry season). Moreover, some samples were taken and prepared to analyze in laboratory. For each soil sample, 60 mL of deionized water was added to simulate the rainy season (saturated soils). Electrochemical evaluations were carried out after 3 h of exposure time at room temperature. Because soil is a system with high resistivity and impedance, it is necessary to carry out IR-drop compensation using two platinum rods that were used as an auxiliary electrode. In addition, the IR-drop correction obtained from the experimental potentiodynamic curves was investigated. Findings: In clay from Campeche (Clay-C), the more susceptible steel to corrosion was X65, whereas in clay from Tabasco (Clay-T), the more susceptible steel to corrosion was X80 steel. Electrochemical results show that despite higher-degree steels providing higher strength and hardness, the order of corrosion susceptibility is random, which can be attributed to different microstructures in the steels. The complexity of the corrosion process on five steels was evident when steel samples were exposed to different soils. The higher corrosion rate was obtained in X65 steel (0.5 mm/year). Practical implications: The paper clearly identifies any implication for the research. Originality/value: The electrochemical responses of different steels exposed in two types of clay soil explained the corrosion complexity that can be attributed to changes in physicochemical properties of the soils, which are because of changes in seasons (dry and rainy) and the microstructure of each steel related to the process of fabrication. Suggesting that the increase in mechanical properties such as hardness and resistance of the pipeline steels could not be associated with its corrosion resistance, the corrosion susceptibility is more dependent on the microstructure of the steels.

Purpose: The purpose of this research is to study different extra-heavy crude oil-in-water emulsions that can be found in practice for corrosion process of X52 steel adding 60 mg.L-1 of non-ionic surfactant and a corrosion inhibitor (CI). Electrochemical impedance spectroscopy and Tafel plots are carried out. Thus, Bode-modulus and Bode-phase angle plots are discussed. Adsorption isotherms obtained from corrosion rate (CR) values are taken into account.Design/methodology/approach: Two-electrode arrangement is used to characterize the pseudo-capacitance values for X52 steel exposed to water and crude oil phases, mainly. Electrochemical evaluations for X52 steel exposed to extra-heavy crude oil-in-water emulsions are recorded in a conventional three-electrode cell to study the corrosion process as was documented in detail by Quej-Ake et al. (2015). Therefore, all electrodes are placed as close as possible to eliminate the iR-drop.Findings: Pseudo-capacitance analysis shows that X52 steel immersed in oilfield produced water was more susceptible to corrosion than that immersed in ocean water solution and extra-heavy crude oil phase. After being analyzed, the X52 steel surface coverage and adsorption process for surfactant and CI could be concluded that surfactant could protect the metal surface. In a coalescence extra-heavy crude oil-in-water emulsion, the water medium generated a new solution that was more corrosive than the original water phase. Wash crude oil process was provoked in emulsion systems to sweep up the salts, mainly. Thus, corrosive species that can be recovered inside extra-heavy crude oil may appear, and in turn a new more corrosive solution could be obtained. Taking into account the straight line obtained in Bode-modulus plot for X52 exposed to extra-heavy crude oil, it is possible to point out that the negative value of the slope orR²can be related to a coefficient (Jorcin et al., 2006). It is important to mention that electrochemical responses for X52 steel exposed to extra-heavy crude oil-in-water under coalescence emulsions revealed that corrosion and diffusion processes exist. Therefore, a possible good inhibitor is surfactant in emulsion systems.Originality/value: CR and anodic and cathodic slopes suggest that the surfactant acted as mixed CI. Of these, susceptible anodic (MnS and perlite or cementite) and cathodic (ferrite) sites on steel surface could be affected, due to which physicochemical adsorption could happen by using electrochemical parameters analysis. Thus, no stable emulsions should be taken into account for extra-heavy crude oil transportation, because corrosion problems in atmospheric distillation process of the crude oil due to stable emulsion cannot be easily separated. In this manner, coalescent emulsions are more adequate for transporting extra-heavy crude oil because low energy to separate the water media is required.

Purpose: The purpose of this paper is to study the susceptibility to corrosion processes of X60, X65 and X70 steels immersed in sand-clay soil with pH 3.0, using electrochemical techniques, scanning electron microscopy (SEM), energy dispersive spectroscopy and X-ray diffraction (XRD). Design/methodology/approach: Natural acidic soil sample was collected as close as possible to buried pipes (1.2 m in depth) in a Right of Way from south of Mexico. Both steels and soil were characterized through SEM and XRD. Then, open circuit potential was recorded for all steels exposed to soil at different exposure times. Thus, the electrochemical impedance spectroscopy (EIS) was traced, and anodic polarization curves were obtained. Findings: The steel corrosion processes started when the active sites were exposed to natural acidic soil. However, corrosion rates decreased for three steels as immersion time increased, obtaining the highest corrosion rate for X60 steel (0.46 mm/year for 5 h). This behavior could be attributed to corrosion products obtained at different exposure times. While, 5 h after removing corrosion products, X65 steel was more susceptible to corrosion (1.29 mm/year), which was corroborated with EIS analysis. Thus, corrosion products for the three steels exposed to natural acidic soil depended on different microstructures, percentage of pearlite and ferrite phases, in which different corrosion processes could occur. Therefore, the active sites for carbon steel surfaces could be passivated with corrosion products. Practical implications: The paper identifies the any implication for the research. Originality/value: Some anodic peaks could be caused by metallic dissolution and was recorded using high positive polarization (high field of perturbation). In addition, the inductive effects and diffusion process were interpreted at low frequency ranges using EIS. According to X-ray diffraction (XRD), acidic soil had Muscovite containing aluminum and iron phases that were able to generate hydrogen proton at the presence of water; it might be promoted at the beginning of deterioration on low carbon steels. Steel surface cleaning after removing corrosion products was considered to study the possible diffusion phenomena on damaged steel surfaces using EIS.

An electrochemical study of three API steels: X52, X65, and X80, exposed to seawater and sediment from seabed is presented. Two seabed samples were collect

The work introduces a numerical external damage prediction method for buried pipelines. The external pitting initiation and corrosion rate of oil or gas pipelines are affected by pipeline age, physicochemical properties of soils and cathodic protection performance as well as coating conditions. Before developing the damage prediction model, the influencing factors were weighed by grey relational analysis, and then the relationship among the pitting depth and the influencing factors of external corrosion was established for corrosion damage prediction through artificial neural network (ANN). Subsequently, the established ANN was applied to predict corrosion damage and corrosion rate for some selected cases, and the neural network prediction model was analyzed and compared to another corrosion rate prediction models. Through the analysis and comparison, a few opinions were proposed on the external corrosion damage prediction and pipeline integrity management.