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In aqueous carbon dioxide (CO2)-saturated environments, such as those found in geothermal energy, oil and gas and carbon abatement industries, various naturally occurring layers can be found on the internal surface of carbon steel infrastructure, such as pipelines, as they corrode in the mildly acidic conditions. Amongst the most commonly found layers are iron carbonate (FeCO3), iron carbide (Fe3C) and magnetite (Fe3O4). FeCO3 can offer corrosion protection to the underlying steel when formed under certain conditions, as too can Fe3O4. Fe3C is typically associated with enhancement of electrochemical activity of carbon steel and is revealed due to preferential dissolution of ferrite in the steel microstructure – through the formation of a porous network at the steel surface. Each of these layers play a fundamental role in the uniform and localized corrosion of the underlying carbon steel.
Iron carbonate (FeCO3), magnetite (Fe3O4) and iron carbide (Fe3C) layers are able to form on carbon steel surfaces in aqueous carbon dioxide (CO2) environments, and suspected to play a critical role in uniform and localized corrosion of the underlying steel. Fe3C and Fe3O4 are known to establish micro-galvanic cells with uncovered regions of the steel surface, due to their conductive and semi-conductive nature respectively, enhancing corrosion rates. To evaluate the significance of the layers’ galvanic corrosion in an aqueous CO2 environment, layers of Fe3C, Fe3O4 and FeCO3 were formed on X65 carbon steel surfaces. The coupons were then galvanically coupled to a bare X65 carbon steel coupon at different area ratios (AR = 1 and 10) in a pH 5, 1 wt.% NaCl, CO2-saturated solution at 50°C. Galvanic currents were measured using zero resistance ammetry over 24 h, with similarly high galvanic currents measured for the Fe3C-bare steel and Fe3O4-bare steel couples, enhancing the bare steel corrosion rates. The galvanic current was significantly smaller and reversed for the FeCO3-bare steel couple, enhancing rather the corrosion rate of the FeCO3-covered coupon.
Hydrocarbon production currently occurs in a variety of onshore and offshore locations. Most offshore production in shallow water (< 500 m) has reached maturity, with most of the more accessible reserves having already been exploited. As a result, exploration and production in offshore environments has been extended to deeper water (> 500 m), which usually incurs more expense and overall project risk for operators and service providers. Production from deepwater oil fields is expected to grow by 40%, to 10 million bpd (10% of total global output), by 2025.
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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.