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CO₂ corrosion rate prediction is regarded as the backbone of materials selection in upstream hydrocarbon industry. This study aims to identify common types of errors in CO₂ rate calculation and to give guidelines on how to avoid them.

For the purpose of this study, 15 different “corrosion study and materials selection reports” carried out previously in upstream hydrocarbon industry were selected, and their predicted CO₂ corrosion rates were evaluated using various corrosion models. Errors captured in the original materials selection reports were categorized based on their type and nature.

The errors identified in the present study are classified into the following four main types: using inadequate or false data as the input to the model, failing to address factors which may have significant influence on corrosion rate, utilizing corrosion models beyond their validity range and utilizing a corrosion model for a specific set of input, where the model is considered to be inaccurate even though the input lies within the software’s range of validity.

This study is mainly based on the use of various corrosion models, and except few cases for which some actual field corrosion monitoring data were available, no laboratory tests were performed to verify the predicted data.

The paper provides a checklist of common types of errors in CO₂ corrosion rate prediction and the guidelines on how to avoid them.

CO₂ corrosion rate calculation is regarded as the backbone of materials selection in hydrocarbon industry. In this work, the source of errors in terms of corrosion modeling tool and human factors were identified.

This paper aims to study the effect of chloride ions concentration on the corrosion behavior of carbon steel in methyldiethanolamine (MDEA) aqueous solution in the sight of different process parameters of purification plant.

Due to the decrease of filtration efficiency and separation efficiency, the chloride ion in the desulfurization solution is enriched. The corrosion behavior of carbon steel under chloride ion enrichment environment was studied by weight-loss method, electrochemical impedance spectroscopy, cyclic polarization curve, X-ray photoelectron spectroscopy and scanning electron microscopy.

The results show that temperature and hydrogen sulfide loads are the main factors of corrosion in CO2-MDEA-H2O-H2S environment. The enrichment of chloride ions reduces the corrosion rate at low temperature but promotes the corrosion rate at high temperature. The chloride concentration should be controlled below 3000 mg/L, and no pitting corrosion was found under the experimental conditions.

The effect of chloride ion enrichment on MDEA solution corrosion shows that at low temperature, the increase of chloride ion will reduce the acid gas load and increase the density of corrosion products, so as to reduce the corrosion; on the contrary, at high temperature, the density of corrosion products will decrease and the corrosion will be intensified as well. It is believed that the chloride ion should be controlled below 3000 mg/L according to the results of the tests.

The paper aims to study the effect of liquid flow velocity on corrosion behavior of 20# steel at initial stage under (CO2/aqueous solution) gas–liquid two-phase plug flow conditions.

Weight loss, scanning electron microscopy, energy-dispersive X-ray spectroscopy and XPS methods were used in this study.

The corrosion rate increased with the increasing liquid flow velocity at any different corrosion time. The corrosion rate decreased with the extension of corrosion time at the same liquid flow velocity. There was no continuous corrosion products film on the whole pipe wall at any different corrosion time. The macroscopic brown-yellow corrosion products on the pipe wall surface decreased with the increasing liquid flow velocity and the loose floccus corrosion products decreased gradually until these products were transformed into un-continuous needle-like dense products with the increasing liquid velocity. The main elements among the products film were Fe, C and O, and the main phases of products film on the pipe wall were Fe3C, FeCO3, FeOOH and Fe3O4. When the corrosion time was 1 h under different liquid–velocity condition, the thickness of local corrosion products film was from 3.5 to 3.8 µm.

The ion mass transfer model of corrosion process in pipe was put forward under gas–liquid two-phase plug flow condition. The total thickness of diffusion sublayer and turbulence sublayer decreased as well as the turbulence propagation coefficient increased with the increasing liquid velocity, which led to the increasing velocity of ion transfer during corrosion process. This was the fundamental reason for the increase of corrosion rate with the increasing liquid velocity.

This paper aims to explore the influence of CO₂ partial pressure, flow rate and water cut on N80 steel corrosion behaviors in the displacement process of oil in glutenite reservoir by CO₂ injection.

A self-made 3 L high-temperature and high-pressure autoclave was used to conduct corrosion simulation experiments of N80 steel in different CO₂ partial pressures, flow rates and water cut (the independently developed oil and water mixing approach can ensure the uniform mixing of oil and water in experiments). Techniques like weight loss and surface analysis were used to analyze the corrosion behaviors of N80 steel under different conditions.

Results showed that the average corrosion rate of N80 steel accelerated at varying degrees with the increase of CO₂ partial pressure, flow rate and water cut. Excluding that the samples showed uniform corrosion under the two conditions of 0.5MPa CO₂ partial pressure and static corrosion, they displayed mesa attack corrosion under other conditions. Besides, with the increase of CO₂ partial pressure, the pH value of solution dropped and the matrix corrosion speed rose, hence leading to the increased Fe²⁺ and CO₃²⁻ concentration. Meanwhile, a lowered pH value improved the FeCO₃ critical supersaturation, thereby leading to an increased nucleation rate/growth rate and ultimately causing the decrease of the dimension of FeCO₃ crystallites formed on the surface of the samples.

The results can be helpful in targeted anti-corrosion measures for CO₂/oil/water corrosive environment.

Cations such as Cu2+, Co2+, Ni2+, Zn2+ or Ba2+ increases the corrosion rate of aluminium in 2 mol.L−1 HCI. This corrosion rate could be decreased by the addition of inhibitors which may form complexes with the cation used. Measurements of the corrosion rate of aluminium in 2 mol.L−1 HCI with and without addition of aliphatic substituted P‐hydroxy acetophenone hydrazone derivatives (10−4 — 10−5 mol.L−1) has been studied by weight loss and galvanostatic polarization methods. The same inhibition efficiency of the compounds has been found using either of the methods. In general, the efficiency of the inhibitors increases with an increase in aliphatic chain length. Activation energies in the presence and in the absence of inhibitors has been evaluated. Galvanostatic polarization data indicate that all these compounds are predominantly cathodic inhibitors. The rate of corrosion increases with increase in temperature together with a decrease in protection efficiency indicating that inhibition occurs through adsorption of the additives.

Sour water condensates are aqueous condensates which contain different concentrations of aggressive compounds such as HCl, H2S, CO2, NH3, cyanides, etc. These condensates which can be fairly corrosive are encountered in a variety of refinery processes ranging from atmospheric distillation units to hydrodesulphurisers and sour water strippers. This paper deals with the mechanism of corrosion by these condensates and the factors influencing corrosion in several typical refinery units. In addition, methods for corrosion prevention and control are also discussed.

Recently acquired quantitative data on the initial corrosion rate of steel vs. the Ryznar index of natural waters are given as a basis of provision of overall service life of steel piping. In the light of the available fundamental knowledge of aqueous corrosion, the mechanism of high‐rate localised attack of coated steel piping from carbonated waters is outlined. A representative case history of multiple perforation of bitumen‐coated steel piping from localised corrosion is reported for a municipal potable water distribution system. Practical protective measures and corrosion monitoring techniques are considered in relation to the most aggressive waters.

The work described in this paper is part of a current programme that has two objects: (1) to investigate further the reasons for the different scaling behaviour of steel in steam and carbon dioxide, although these gases have similar oxygen potentials; (2) to provide background information for an investigation into the effect of variations in re‐heating furnace atmospheres upon scaling and scale adhesion.

This paper presents a brief summary of the stress corrosion cracking experience of carbon steel in amine acid gas scrubbing units. In addition, it discusses the current views of the most probable mechanism of cracking of carbon steel equipment in amine acid gas scrubbing units and the probable role of the nature of the amine molecule.