Comparative study on CO2 corrosion behavior of N80, P110, X52 and 13Cr pipe lines in simulated stratum water

Abstract

To better understand the carbon dioxide (CO2) corrosion behavior of carbon steel and its influence on petroleum development (including drilling, production and transportation) in the Daqing Oilfield, CO2 corrosion behaviors of N80, P110, X52 and 13Cr pipe lines in simulated solution at high temperature and high pressure condition are investigated by dynamic corrosion experiments, scanning electron microscope (SEM) and energy dispersive X-ray spectroscopy (EDS) analyses. Results show that the corrosion rate of all pipe lines increases quickly when CO2 partial pressure increases from 0.5 to 1.5 MPa, but it slows down when CO2 partial pressure further increases from 1.5 to 4.5 MPa, during which localized corrosion is prevailing. When the experimental temperature ranges from 60 to 120°C, localized corrosion prevails. The corrosion rate of all pipe lines decreases sharply when the temperature changes from 60 to 100°C, and it becomes stable after the temperature is higher than 100°C. When the flow rate is in the range of 0–1.5 m/s, the corrosion rate of sample X52 remains unchanged, but localized corrosion gradually becomes very serious when the flow rate further increases. By analyzing the corrosion product scales of sample 13Cr, some remarkable phenomena are observed. At the temperature range of 60–100°C, the corrosion product scales are loose and thick, but become very compact when the temperature increases above 100°C. In the later case, localized corrosion is prevailing. The main components of the corrosion product scales are FeCO3 and Cr2O3.