Abstract: CO₂-assisted steam flooding is a novel method for heavy oil production. However, studies on CO₂ corrosion of downhole pipe in a high-temperature steam environment are relatively scarce. Therefore, in this study, the CO₂ corrosion behavior of oilfield pipe casing steel in a high-temperature steam environment was investigated using four types of oilfield pipe casing steel. A high-temperature, high-pressure autoclave was used to simulate the operating conditions during CO₂-assisted wellbore steam flooding. With a CO₂ partial pressure of 2 MPa and an operating temperature of 240℃, a weight loss coupon corrosion test was performed on four types of oilfield pipe casing steel, and the corrosion rates of the pipeline materials under the simulated operating conditions were obtained. Scanning electron microscopy, energy dispersive x-ray spectrometry, and x-ray diffraction were used to determine the morphology and composition of the corrosion products. The results show that under the experimental conditions, the uniform corrosion rates of the four types of materials were lower than the allowable corrosion rate for oil fields (0.076 mm/a). The corrosion morphology of N80 steel was uniform corrosion, while that of 3Cr, 9Cr, and 13CR steel were localized corrosion. The corrosion rates of all four steel materials met the corrosion control requirements for CO₂-assisted wellbore steam flooding.

Key words: CO₂-assisted steam flooding, CO₂ corrosion, downhole pipe, corrosion rate, corrosion morphology