In the process of constructing deep natural gas wells in Sichuan and Chongqing, gas wells encounter various technical challenges such as high temperature, high pressure, and a corrosive environment containing H₂S and CO₂. The corrosion of rubber materials in these acidic environments can easily lead to seal failure in downhole tools. To better investigate the corrosion resistance of rubber materials in acidic environments, we utilized a dynamic cyclic corrosion experimental device capable of simulating the service conditions experienced by downhole tools under high-temperature, high-pressure multiphase flow. Corrosion-resistance tests were conducted on fluororubbers (FKM) 1, 2, 3, and HNBR (hydrogenated nitrile-butadiene rubber) under acidic conditions (80 °C and 160 °C), along with sealing corrosion tests on O-rings. These tests aimed to analyze the mechanical properties, hardness, and corrosion resistance before and after exposure to acid media as well as the sealing performance of O-rings. Ultimately, our goal was to identify suitable rubber materials for acidic pressure environments. Experimental results revealed that all four types of rubber exhibited decreased elongation at break after undergoing corrosion testing; however, fluororubber 3 demonstrated significant susceptibility to temperature effects while the other three types showed minimal impact from temperature variations. Fluororubber 1 and fluororubber 3 displayed substantial deformation levels whereas mechanical properties greatly deteriorated for fluororubber 2. Overall, HNBR showcased superior comprehensive performance.

This study conducts weight loss corrosion experiments by a high-temperature autoclave to investigate the corrosion behaviours and the damage rules of mechanical properties of P110 tubing under coupling working conditions of multiple factors (temperature 50–155 °C, CO₂ content 1%–2%, Cl⁻ content 10,000–20,000 mg/L). It analyses the characteristics of corrosion products of P110 steel using X-ray diffraction, scanning electron microscopy, and energy dispersive spectroscopy (EDS). In addition, the 3D morphology and size of local corrosion pits are measured microscopically. The mechanical properties’ damage behaviours at different tubing positions are analysed by constant-load tensile stress corrosion tests. The results showed that the average corrosion rate of the tubing reaches the maximum value of 1.627 mm/a at the middle section of the shale gas well. With an increase in temperature and CO₂ partial pressure, the depth of the local corrosion pits on the tubing rises from 3.8 to 25.0 μm. The yield strength and tensile strength of the tubing at the bottom-hole section reduced by less than 8%, and the coupling damage effect of stress and corrosive mediums is serious. The tubing shows a sensitivity to stress corrosion cracking at the bottom-hole section. It was recommended that corrosion inhibitors should be cyclically added to inhibit CO₂ corrosion to control the corrosion rate of the tubing within the range of medium-degree corrosion, thus ensuring that the strength reduction of P110 tubing under the corrosion working conditions containing CO₂ and sulphate-reducing bacteria coupled with tensile stress is within the controllable range of safety factor.