In the environment of CO₂ enhanced recovery (CCS?EOR), the corrosion cracking behavior and mechanism of X70 pipeline steel under different CO₂ pressures were studied. The on?site environment was simulated by using a high?pressure reactor and a simulated produced aqueous solution; the corrosion rate and corrosion mechanism of X70 pipeline steel in the CCS?EOR environment were investigated by electrochemical experiments; the corrosion cracking behavior of X70 pipeline steel under simulated environment was investigated by slow strain rate tensile experiments; finally, the corrosion cracking behavior of X70 pipeline steel under different CO₂ pressure was analyzed by scanning electron microscope. The results show that the corrosion rate of X70 pipeline steel increases with the increase of CO₂ pressure; the corrosion product film produced on the surface of X70 pipeline steel can not protect the metal matrix, and intensify the local corrosion; under the influence of the corrosion product film, the increase of CO₂ pressure makes X70 pipeline steel stress corrosion susceptibility increases; and the corrosion cracking of X70 pipeline steel is also affected by the metal surface cracks.

Oil and gas pipelines (X52 steel) in the marine environment are highly susceptible to corrosion. The effects of different dissolved oxygen concentration, pH, and hydrostatic pressure on the corrosion behavior of X52 pipeline steel in the marine environment was analyzed using electrochemical testing technology and observation of corrosion morphology. The results show that the corrosion of the pipeline slowed down as the ambient pH increased, while the corrosion of the pipeline steel increased as the dissolved oxygen content and hydrostatic pressure increased. The corrosion behavior of pipeline steel under different conditions is controlled by anodic activation of dissolution, and all appear local pitting corrosion phenomenon.

At present, water injection is often used to extract oil, but CO₂ corrosion often occurs in water?bearing pipelines. Therefore, Computational Fluid Dynamics (CFD) was used to study the distribution of oil and water in straight pipes and bends at different water content (volume) and flow rates, to determine the conditions for the occurrence of CO₂ corrosion in oil pipelines, and the effect of flow rate and water content on the wall shear force was analyzed. The results show that the occurrence of CO₂ corrosion depends on the water content and flow rate in the pipeline. When the water content increases, oil infiltration in the inner wall of the pipe to prevent corrosion; when the water content decreases, the amount of water accumulation increases, resulting in serious CO₂ corrosion. When the flow rate increases, turbulence occurs in the pipeline, so it is difficult to form water accumulation, reducing the risk of corrosion. However, an increase in flow rate will lead to an increase in wall shear, which will destroy the corrosion product film and further accelerate the corrosion rate. In downward elbows, under the action of gravity, water often does not occur in the pipeline, and the risk of corrosion is low; in upward elbows, water is most likely to occur, and the risk of corrosion is high; affected by scouring, the elbow end is corroded seriously. The elbow end is susceptible to the interaction of corrosion and mechanics, so corrosion is serious. The research results have certain guiding significance for the safe operation of oilfield gathering pipelines.

When crude oil is extracted from oil wells, associated gas will be generated, and natural gas hydrates will be generated in high pressure and low temperature environments, which will block the transportation pipeline. Therefore, it is of great significance to study the hydrate formation in oil sand system (that is, the crude oil?containing system) and the pure quartz sand system (not including crude oil). The formation of methane hydrate and the final gas consumption in the oil sand system) and the pure quartz sand system were studied under the conditions of initial pressure of 4.00, 6.00, 8.00 MPa, quartz sand particle size of 20, 30, 60, 80 mesh, and constant temperature.The results show that in the oil sand system and under the same initial pressure conditions, the smaller the particle size of quartz sand, the shorter the induction period for hydrate formation, and the greater the rate of hydrate formation; the effect of particle size on the final gas consumption for hydrate formation It is found that as the particle size of the quartz sand decreases, the gas consumption first increases and then decreases. When the particle size of the quartz sand is 60 mesh, the gas consumption reaches the maximum, and its value is 0.19 mol. At the same time, the hydrate formation in the oil sand system and the pure quartz sand system was compared. The results show that, due to the presence of SDS (sodium dodecyl sulfate) solutions in the two systems, there is little difference in the formation rate of hydrates; the final gas consumption in the oil sand system is less than that in the quartz sand system under the same quartz sand particle size. This indicates that crude oil has an inhibitory effect on the formation of hydrates. In the oil sand system, it is found that the higher the pressure, the more favorable the formation of hydrates.