Analysis of Corrosion Failure of TP90H Gas Injection Tubing for Heavy Oil Fire-Flooding in Xinjiang Oilfield

The adaptability of the TP90H gas injection tubing in Xinjiang Oilfield fire flooding pilot test area, which has been operational for 10 years, remains uncertain. To address this issue, researchers conducted a comprehensive analysis of a typical TP90H gas injection tubing in a gas injection well. They examined its chemical composition and metallographic structure, and analyzed the macroscopic corrosion morphology. The depth of corrosion pits was measured using a laser confocal microscope. Additionally, the phases of corrosion products were investigated using a scanning electron microscope (SEM), energy dispersive spectrometer (EDS), and X-ray diffractometer (XRD). The results revealed that the chemical composition of the TP90H gas injection tubing complies with relevant industry standard, and its metallographic structure is normal. The primary corrosion product on the outer wall was identified as Fe3O4, while the inner wall corrosion products mainly consisted of Fe2O3 and FeCr2O4. By analyzing the on-site gas injection conditions during the fire flooding phase, it was determined that the main cause of tubing corrosion is electrochemical corrosion. Although the TP90H material gas injection tubing is suitable for the heavy oil fireflood conditions in Xinjiang Oilfield, it still poses a risk of corrosion failure. Therefore, it is recommended to enhance corrosion monitoring to ensure the normal operation of the gas injection wells. This proactive approach will help maintain the integrity and longevity of the TP90H gas injection tubings, reducing potential downtime and costs associated with corrosion-related issues.