In recent years, the research on super 13Cr corrosion at home and abroad mainly focuses on uniform corrosion in formation fluid environment and H2S stress corrosion cracking in annulus protection fluid, but rarely considers pitting corrosion failure in annulus protection fluid. At home and abroad, there are few cases of short-term pitting corrosion perforation failures of super 13Cr pipes in annulus protection fluid. This paper aims to study the pitting corrosion failure mechanism of super 13Cr pipes in the service environment of oil and gas wells, and analyze the pitting corrosion failure behaviors of super 13Cr martensitic stainless steel in the environment of high temperature, high chloride-containing annulus protection fluid and supercritical H2S/CO2 to make clear the applicability of super 13Cr tubing and put forward corrosion protection measures. Based on the analysis of the macro and micro structure, corrosion morphology and corrosion products of the failed tubing, the failure reason of super 13Cr tubing was determined. Combined with high temperature and high pressure reactors, the downhole corrosion environment was simulated, the mechanism of pitting corrosion loss of super 13Cr tubing was revealed from the aspects of average corrosion rate and pitting corrosion rate. The results showed that the super 13Cr tubing in the failed well had pitting perforation failure in the environment of H2S/CO2 polluted annulus protection fluid. Field failure tubing showed that in the environment of high chloride-containing annulus protection fluid polluted by corrosive gas, obvious local corrosion occurred on the outer wall of tubing, and the corrosion expanded from the outer wall of tubing to the inner wall, resulting in pitting corrosion perforation. The failed tubing had certain H2S stress corrosion cracking (SCC) characteristics. There were Cr, O, Cl and S ions on the surface of the failed tubing, and the corrosion was jointly controlled by CO2-H2S. The simulated corrosion test results showed that the super 13Cr tubing was sensitive to pitting corrosion under the environment of seawater annulus protection fluid polluted by corrosive gas. The pit depth was 80.346 μm and the pitting corrosion rate was 10.34 mm/a. It was considered that the corrosion failure of super 13Cr tubing in this well was controlled by CO2-H2S and extended from annulus to tubing. Serious pitting corrosion failure occurred under high chloride-containing annulus protection fluid containing CO2/H2S corrosive gas. Super 13Cr tubing had good uniform corrosion resistance in the annulus protection fluid, but it had obvious tendency of pitting corrosion in the environment of high chloride-containing annulus protection fluid polluted by H2S/CO2. The super 13Cr tubing without removing the oxide skin would aggravate the damage of the passivation film, form local corrosion sensitive areas, induce local pitting corrosion initiation, and increase the diffusion rate of medium and corrosion rate in the environment of seawater base annulus protection fluid polluted by corrosive gas. It is recommended that in the process of offshore oilfield development and production, attention should be paid to the deoxygenation process of annulus protection fluid, and the base fluid configured with annulus protection fluid should be changed from seawater filtration to fresh water. At the same time, the match between annulus protection fluid and the material of the used pipe string should be fully considered in the design stage, so as to fundamentally solve the pitting corrosion failure of super 13Cr tubing in the downhole. The research in this paper can provide help for casing material selection and corrosion control in the development of such offshore oilfield.