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This paper aims to establish the downhole CO₂ partial pressure profile calculating method and then to make an economical oil country tubular goods (OCTG) anti-corrosion design. CO₂ partial pressure is the most important parameter to the oil and gas corrosion research for these wells which contain sweet gas of CO₂. However, till now, there has not been a recognized method for calculating this important value. Especially in oil well, CO₂ partial pressure calculation seems more complicated. Based on Dolton partial pressure law and oil gas separation process, CO₂ partial pressure profile calculating method in oil well is proposed. A case study was presented according to the new method, and two kinds of corrosion environment were determined. An experimental research was conducted on N80, 3Cr-L80 and 13Cr-L80 material. Based on the test results, 3Cr-L80 was recommended for downhole tubing. Combined with the field application practice, 3Cr-L80 was proved as a safety and economy anti-corrosion tubing material in this oil field. A proper corrosion parameter (mainly refers to CO₂ partial pressure and temperature) can ensure a safety and economy downhole tubing anti-corrosion design.

Based on Dolton partial pressure law and oil gas separation process, CO₂ partial pressure profile calculating method in oil well is proposed. An experimental research was conducted on N80, 3Cr-L80 and 13Cr-L80 material. A field application practice was used.

It is necessary to calculate the CO₂ partial pressure properly to ensure a safety and economy downhole tubing (or casing) anti-corrosion design.

The gas and oil separation theory and corrosion theory are combined together to give a useful method in downhole tubing anti-corrosion design method.

The purpose of this study is to investigate the corrosion behaviour of X70 steel in the presence and absence of various concentrations of inhibitor N-(2-o-Tolyl azophenyl)-acetamide (NTAA) in a CO₂ environment.

The temperature was set at 80°C, and the flow velocity was 1.5 m/s. The inhibitor concentrations were 10, 20, 30, 60 and 80 ppm, and the CO₂ partial pressure was 0.8 MPa. Weight loss method, pitting depth measurement, scanning electron microscopy and electrochemical techniques were used to investigate the inhibitory effects of the inhibitor NTAA.

The results showed that a small peak emerged in the curve of the corrosion rate versus inhibitor concentration plot at 20-30 ppm. Polarisation studies revealed that the anodic Tafel slopes changed greatly in the presence of an inhibitor; NTAA behaved as an anode-type inhibitor. At concentrations of 20-30 ppm, the incomplete coverage of the metal surface by inhibitor molecules resulted in macroscopic galvanic corrosion.

Corrosion behaviour of X70 steel in the presence and absence of various concentrations of an anode-type inhibitor was assessed. Cathodic Tafel slopes are almost unchanged, while the anodic Tafel slopes change significantly with the increase in inhibitor concentration. The corrosion rates of 20 and 30 ppm are almost three times of that of 10 ppm, which is because of the macroscopic galvanic corrosion caused by the inadequate coverage of inhibitor on steel surface.

This paper aims to report an experimental investigation of the galvanic corrosion that occurs between the base metal and the welds in X52 carbon steel petroleum pipelines when exposed in carbon dioxide (CO₂)-containing saltwater at pH 4 at room temperature. The pipeline was fabricated by electric resistance welding (ERW).

The experimental setup was a closed glass cell equipped with a silver/silver chloride (Ag/AgCl) reference electrode, two working electrodes (the weld metal and the parent steel specimens) and a gas bubbler. The corrosion potential and polarization resistance of the base metal and the weld were determined using electrochemical testing methods: potentiodynamic polarization scans and linear polarization resistance measurement. The galvanic currents of the base metal when coupled to the weld metal were measured using zero resistance ammetry.

The weld metal was the anode of the couple for a very short time at the beginning of the experiment and then became the cathode until the end of the experiment. This indicates that electric resistance welded X52 steel pipe is a promising material to be operated in CO₂-containing saltwater at pH 4 and 25°C because the weld area is cathodic to the parent metal, the value of the galvanic current is very low (in the order of nanoamps) and the area of the anode (i.e. the parent metal) is significantly larger than that of the cathode (weld metal).

Further experimental research could be performed to investigate the galvanic corrosion behavior between the parent metal and the weld area of X52 carbon steel petroleum pipelines in CO₂-containing saltwater at different pH values, temperature and velocity.

Electric resistance welded X52 steel pipe is a promising material for use with CO₂-containing saltwater environments at pH 4 and 25°C.

The new information presented in the paper is the galvanic corrosion behavior between the parent metal and the ERW weld metal of X52 carbon steel in CO₂-containing solutions. The paper should be useful to researchers working in the field of oil industry corrosion.

Among the many influencing effects that the medium has on the CO₂ corrosion of carbon steel, flow is one of the most important because it can determine the formation of corrosion product scales and its stabilisation, thus influencing the attack morphology and corrosion rate. This paper aims to summarise some factors affecting aqueous CO₂ corrosion and the laboratory methodologies to evaluate one of the most important, the flow, with an emphasis on less costly rotating cage (RC) laboratory methodology.

Regarding the key factors affecting CO₂ corrosion, both well-established factors and some not well addressed in current corrosion prediction models are presented. The wall shear stress (WSS) values that can be obtained by laboratory flow simulation methodologies in pipelines and its effects over iron carbonate (FeCO₃) scales or inhibition films are discussed. In addition, promising applications of electrochemical techniques coupled to RC methodology under mild or harsh conditions are presented.

More studies could be addressed that also consider both the salting-out effects and the presence of oxygen in CO₂ corrosion. The RC methodology may be appropriate to simulate a WSS close to that obtained by laboratory flow loops, especially when using only water as the corrosive medium.

The WSS generated by the RC methodology might not be able to cause destruction of protective FeCO₃ scales or inhibition films. However, this may be an issue even when using methodologies that allow high-magnitude hydrodynamic stresses.

This paper is by no means intended to cover the whole problem signified by the title. Efforts at a solution are world wide and have been attended by slow improvement rather than complete success. The sole intention is to convey the results of some objective tests which have been designed to prove or disprove the worth of certain protective processes in preventing corrosion of steel in the salt atmosphere of Sydney. The individual must draw his own conclusions. It is hoped that he may at least discover certain things he should not do.

This paper aims to provide an insight into the main parameters that govern corrosion mechanisms in production tubing of oil and gas wells.

Corrosion has been an old concern for the oil industry. None of the three major sectors of the oil industry, namely, upstream, midstream and downstream, are immune of corrosion attacks. However, the upstream sector (oil and gas production facilities) is more vulnerable to corrosion because of its extreme conditions such as high temperature and pressure, multiphase flow, complicated water chemistry, presence of acidic gases, etc. This paper is a general review of the influence of such parameters on corrosion mechanisms of oil and gas wells.

In recent years, many technical papers have been published in this area. However, none of them provide a general review of the all contributing parameters on corrosion under field conditions.

Modeling and corrosion mitigating processes under downhole conditions require a thorough understanding of the influencing parameters. This paper aims to provide an insight into the main parameters that govern corrosion mechanisms in production tubing of oil and gas wells.

This paper aims to analyze a failure case of a P110 tube in a CO₂ flooding well.

The chemical composition, microstructure and mechanical properties of the failed P110 tubing steel were tested, and met the API Spec 5CT standard. The fractures were investigated by scanning electron microscopy and energy dispersive spectroscopy.

Fracture was induced by stress corrosion cracking (SCC) and that the stress concentration caused by the mechanical damage played an important role in the failure. The failure case is a SCC failure affected by mechanical damage and galvanic corrosion.

The effect of the infiltration of groundwater was studied in the failure case. The stress concentration caused by the mechanical damage played an important role in the failure.

The purpose of this paper is to solve the tubing corrosion problem of B Block on the Right Bank of Amu Darya river sour gas field.

By using four-point-bending method, the tubing’s ability to resist sulfide-stress cracking was tested. Simulating the wellbore corrosive environment, the corrosion inhibitor which was suitable for gas filed had been screened. According to the characteristic of Amu Darya river gas field, the corrosion monitor system had been designed.

From the feedback of wellbore corrosion monitor result, the corrosion rate was lower than 0.076 mm/a.

This anti-corrosion technique provides security for the development of gas field.

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.