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Stress corrosion cracking (SCC) of Type 304 stainless steel (304 SS) in elevated temperature (288 °C) high purity water is typically an intergranular (IG) process with cracks propagating along grain boundaries, which are mesoscopic entities relevant on the grain scale. It follows then that the nature of the grain boundaries plays a significant role in SCC. In fact, for IG SCC to occur three things must be present: 1) stress; 2) a corrosive environment; and 3) susceptible grain boundaries. SCC growth rate (SCCGR) equations for 304SS in high temperature, high purity water, test orientation, temperature, material composition, and sensitization.
The life of corrosion protection coating systems very often will not meet the design life of the steel structures they are supposed to protect. Decisions about corrosion protection coating selection are usually focusing on the costs for the initial application, ignoring the certain future maintenance costs. However, repeated maintenance operations, and resulting downtime, can add significantly to the total cost of ownership.
Hydrofluoric acid (HF) is used as a catalyst in the alkylation process to react isobutane with olefin feeds to manufacture a high octane alkylate product used in gasoline blending. The HF catalyst is added in its anhydrous liquid form (< 400 ppmw H2O) but as it circulates in the reaction system, residual water in the Paper No. 17520 liquid hydrocarbon feed is absorbed by the acid such that the circulating reaction acid builds up a small percentage (0.5 to 2.0 mass%) of water. This water/HF mixture is also referred to as rich HF (RHF). In addition, the alkylation reactions also will generate fluorocarbons and acid soluble oils (ASOs).
According to the Petroleum Safety Authority (PSA) in Norway, corrosion under insulation (CUI) caused about 50% of all hydrocarbon leaks at onshore plants. In the case of Alberta’s oil sands, CUI has also been observed in thermal operations in above ground assets carrying emulsions, steam, hot water and/or warm water that are externally insulated to ensure safe and energy efficient operations. CUI has also been observed in oil sands mining operations in various piping systems and in tanks and vessels on structural supports and insulated support rings that are frequently in contact with soil or standing groundwater.
Intergranular Stress Corrosion Cracking (IG-SCC) plays an important role as one of the most recognized degradation phenomena in Nuclear Power Plants (NPP). SCC is both multi-disciplinary with many parameters that are dependent on each other. This study was based on developing a multi-physics finite element model for IG-SCC prediction in unirradiated structural materials for non-pressure vessel components in NPPs. The environment considered was boiling water reactor (BWR) with normal water chemistry (NWC), containing approx. 200ppb oxidant (O2 + H2O2) and varying aggressive ions Cl-. The model was focused on the slip-oxidation model, where a crack is advancing by anodic dissolution, passivation, and oxide rupture at the crack tip. The rupture of the oxide film is due to the constant stresses applied creating slips in the bulk material which fractures the oxide.
Surface layers often form on carbon steel surfaces in carbon dioxide (CO2) saturated environments and under certain conditions can offer corrosion protection to the underlying steel. One such layer, magnetite (Fe3O4) is a semiconductor, having a reported electrical resistivity of the order of 10-2 to 10-1 Ω∙cm and band gap of 0.1 eV. The conductive properties of Fe3O4 are of significant importance when understanding the corrosion behaviour of carbon steel, as Fe3O4 can readily establish a galvanic couple with the steel surface upon which it has formed.
Thermally insulated pipelines have wide networks globally that are used to transport various chemicals, hydrocarbons as well as steam. CUI (corrosion under insulation), external SCC (stress corrosion cracking) and corrosion fatigue are some of the prominent damage mechanisms which may occur on the external surface of insulated pipes/ pipelines that in turn jeopardize the long-term integrity and operations. The moisture is undoubtedly the key contributor behind the above said external degradations of metallic surfaces and can come under thermal insulations via seepage and/ or condensation. Various factors that influence the extent of moisture intrusion are the design of insulated system(s), type and age of insulation, operating temperature of pipeline(s) as well as environmental and neighborhood conditions.
Microbiologically influenced corrosion (MIC) is a key oilfield problem associated with microbial activity, and can be described as the accelerated corrosion of surfaces (usually concrete or iron/steel) by the biological action of naturally present or externally introduced microorganisms. MIC incidents can occur anywhere that a system is exposed to the environment, where microorganisms can enter often via fluid flow and colonize various surfaces for their own growth. MIC is a persistent concern in practically any upstream, midstream, or downstream system where water could be present for microorganism colonization, including topside, subsurface, aerobic (with oxygen), anaerobic (without oxygen), and at extreme temperatures and salinities.
There are mainly two commonly adopted criteria for controlling CP. One is the polarized potential criterion and the other one is the polarization shift criterion1. These criteria are not the true criterion for cathodic protection; they are the surrogate criteria (see below). The polarized potential criterion is to control the instant-off structure-to-electrolyte potential within a specified range. For example, the instant-off potential should be between -0.85 and -1.2 V vs Cu/CuSO4 (VCSE) for pipelines buried in soil. The polarization shift criterion is to control the polarization of a CP-protected structure to a given minimum value and this minimum value is usually 100 mV. The polarization is determined either by the difference between the corrosion potential of the structure measured before CP is applied and the instant-off structure-to-electrolyte potential, or by the difference between the depolarized potential of the structure and the instant-off structure-to-electrolyte potential.
In previous years, we have explored the use of electrochemical sensors for humidity and corrosion measurements inside of natural gas pipelines. Designed to operate in systems where a conductive aqueous phase is intermittent or unavailable, these membrane-based sensors utilize electrochemical techniques such as linear polarization resistance and electrochemical impedance spectroscopy to determine the environment’s corrosivity to the pipeline material. We now aim to explore this sensor’s performance and capabilities in more complex systems, specifically in environments that promote localized corrosion. Using the aforementioned electrochemical techniques, along with electrochemical noise and cyclic voltammetry, we probe and monitor localized corrosion and general corrosion of X65 steel in the presence of inorganic pitting agents. Experiments are conducted in both aqueous and nonaqueous environments. The additional functionality increases the quantity and quality of corrosion data from these sensors, offering to internal corrosion-monitoring programs a more complete picture of real-time corrosion within their natural gas pipelines.