Xuanpeng Li

The corrosion behavior of P110 tubing in a supercritical CO₂/oil/water environment (20 MPa, 90 °C) was investigated over a test duration of 168 h by means of weight loss testing and corrosion scale analysis. The results reveal a significant transition at 50% water cut, where the uniform corrosion rate surged by approximately two orders of magnitude, while the localized corrosion rate exhibited a distinct convex trend, peaking at this threshold due to inhomogeneous wetting dynamics. The corrosion scales were identified as Calcium-substituted Iron Carbonate solid solutions (Fe_xCa_1−xCO₃). Based on the competitive crystallization between corrosion-derived Fe²⁺ and bulk Ca²⁺, a mechanism for scale morphological evolution is proposed. This model explains the structural transition of the scale from a heterogeneous multi-layered film at a low water cut (30%) to a kinetic-controlled single layer at the critical water cut (50%), and finally, to a diffusion-controlled tri-layer gradient structure under fully water-wetted conditions (100%).

Carbon dioxide capture, utilization, and storage for enhanced oil recovery (CCUS-EOR) represents an effective strategy for reducing CO₂ emissions while improving oil recovery efficiency. However, harsh environmental conditions during the process can induce a supercritical state in captured CO₂, which may undermine the structural integrity of tubular components through corrosion. This study systematically investigated the corrosion behaviors of two tubing steels (P110 and Super 13Cr) in 20 MPa supercritical CO₂ containing trace H₂S/O₂ impurities at 60–120 °C using weight loss tests and surface analysis. The results demonstrate that in water-unsaturated supercritical CO₂ with ≤500 ppmv H₂S, both steels exhibited low general corrosion rates (P110: 0.03 mm/y; S13Cr: 0.01 mm/y), with incomplete surface films partially covering grinding traces. However, S13Cr suffered pitting corrosion at >500 ppmv H₂S. Oxygen introduction triggered severe general/localized corrosion characterized by cracked, non-protective surface films. Reducing O₂ to 500 ppm yielded thin, continuous protective films, eliminating pitting. Temperature critically influenced S13Cr corrosion: decreasing from 120 °C to 60 °C increased the corrosion rates from 0.0031 mm/y to 0.08 mm/y due to enhanced water precipitation and impurity gas dissolution. These findings establish impurity thresholds to ensure acceptable corrosion performance.

In order to solve the problem of external corrosion of deep well casing in oil and gas fields, a new type of high-temperature-resistant zinc alloy sacrificial anode material was used. The temperature and corrosion resistance of the new anode material and TP140 casing were investigated by simulating the high-temperature working conditions of a deep well in an oil field using high-temperature and high-pressure corrosion tests and electrochemical tests. The results showed that at 100–120 °C, the corrosion rate of TP140 protected by a sacrificial anode was only one-tenth of that under unprotected conditions, and the minimum corrosion rate of TP140 protected by a sacrificial anode at 100 °C was 0.0089 mm/a. The results of the dynamic potential polarization curve showed that the corresponding corrosion current density of TP140 first increased and then decreased with the increase in temperature. The self-corrosion potential in sacrificial anode materials first increased and then decreased with the increase in temperature, and the potential difference with TP140 gradually decreased.