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Carbon and low alloy steels (CS and LAS, respectively) used for exploration and production in the oil and gas (O&G) industry are normally exposed to environments that may contain H2S in a wide range of concentrations. In aqueous solutions, H2S acts as a cathodic poison.1,2 A cathodic poison inhibits the recombination of atomic hydrogen to H2, and as a result, favors its absorption by the metal.1,2 In the presence of a susceptible microstructure and the simultaneous effect of applied or residual tensile stress, a crack can nucleate and propagate, when a critical concentration of hydrogen is reached in the metal.3 This environmentally assisted cracking (EAC) phenomenon is known as Sulfide Stress Cracking (SSC).2 SSC is commonly addressed as a case of hydrogen embrittlement (HE) damage.2
Surface trenches are described as elongated pits or blunt cracks with a large depth (d) to width (a) ratio that occur as the result of an environmentally and stress-assisted damage. Trenches may represent a transition from pits to cracks in stressed carbon and low alloy steels specimens when exposed to H2Scontaining solutions under certain experimental conditions. In the literature, surface trenches are also known as deep or sharp pits, small blunt cracks, stress-induced microgrooves, fissures, cracklets, or microcracks. Since these features were first presented in 1977 by Dunlop, many authors have typically reported their depth while others have included the shape aspect ratio (d/a) for a more consistent characterization. In 2000, Pargeter published a flowchart to distinguish pits from cracks based on the microscopy analysis of the cross-sections of tested samples. In the absence of detrimental phases such as hard microstructures, and for indications with a depth higher than 250 µm, Pargeter classified cracks as features that presented sharp tips and parallel sides. However, indications with depths below the 250 µm limit reported in the literature remain unclassified according to Pargeter’s guidelines. In recent years, efforts have been made to clarify the limits between trenches with respect to pits and cracks.
As oilfield technologies have advanced, they have made high temperature (HT) reservoirs more accessible. HTs make the application of chemical more difficult because chemical instability at HT restricts what intermediates will work in these environments and the safety and complexity of HT testing further adds to the challenge.
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The aim of this work is to identify an approach to materials selection and corrosion control that can address the specific requirements of a Carbon Capture and Storage (CCS) project. This work is largely based on the accumulated knowledge and expertise that has been published. Besides the direct guidance from this document, specific topics may require more detail that can be found in the references.
Precipitation and deposition of wax or asphaltenes is a commonly encountered issue in the oilfield, causing flow restrictions, compromising the integrity and performance of equipment (some safety critical), limiting access during well interventions, causing “fill” in vessels, stabilizing emulsions and sometimes enhancing corrosion due to under-deposit corrosion and increased biofouling. Developing an effective management strategy that minimizes the total cost associated with these threats requires reliable prediction of whether they will occur, their severity and their location within the production system. Such prediction typically combines the use of compositional data and phase behaviour (typically referred to as “PVT data) with Equation of State (EoS) modelling plus the experimental measurement of key parameters specific to each issue.