The corrosion behavior of a 15Cr-6Ni-2Mo martensitic stainless steel (15Cr stainless steel) in a CO₂/H₂S environment was investigated by conducting high-temperature/high-pressure immersion tests combined with scanning electron microscopy and metallographic microscopy. The presence of H₂S decreased the corrosion resistance of the 15Cr tubing steel. The critical H₂S partial pressure (P_H2S) for stress corrosion cracking in the 15Cr tubing steel in the simulated oil field environment with a CO₂ partial pressure of 4 MPa and an applied stress of 80% σ_s was identified. The 15Cr tubing steel mainly suffered uniform corrosion with no pitting and cracking when the P_H2S was below 0.5 MPa. When the P_H2S increased to 1 MPa and the test temperature was 150 °C, the pitting and cracking sensitivity increased. The stress corrosion cracking at a higher P_H2S is attributed to the sulfide-induced brittle fracture.

In order to clarify the difference in corrosion performance between low Cr-containing (3Cr, 5Cr, and 9Cr) tubing material and carbon steel N80 in the Carbon dioxide (CO₂) flooding injection and production environment and the range of adaptation, corrosion tests and analysis were carried out in simulated working conditions. In this paper, the electrochemical potentiodynamic testing technology and the weight loss method were used to comparatively analyze the corrosion performance and variation law of three types of tubing materials with different Cr contents in a simulated CO₂ flooding-produced water environment under different partial pressure conditions. Additionally, scanning electron microscopy and Energy Dispersive Spectrometer (EDS) analysis were conducted to examine the surface corrosion morphology characteristics and elemental composition of material films under various conditions. The results indicate that the open circuit potentials of 3Cr, 5Cr, and carbon steel N80 were similar under the same experimental conditions. However, the open circuit potentials of 9Cr were relatively high and there was an obvious passivation zone in anodic polarization. Nevertheless, compared to that of 13Cr, the passivation state was unstable, and pitting corrosion continued to expand once it formed. This demonstrates that the corrosion resistance of the material can be effectively enhanced and a stable passivation state can be achieved in the anodic polarization region when the Cr content of the material reaches at least 13%. The service life of materials can be predicted based on their corrosion rate under high temperature and pressure simulation environments. We found that 9Cr materials exhibited good adaptability while 3Cr and 5Cr materials showed poor adaptability. Therefore, it was not recommended to use 3Cr and 5Cr materials. Therefore, 3Cr, 5Cr, and N80 materials will be used at lower partial pressure levels of CO₂ (<0.2 MPa).

The purpose of this paper is to reveal the corrosion behavior of J55 and N80 carbon steels in formation water under oil wells at different partial pressures, explore the formation process of corrosion product films under supercritical CO₂ conditions, and analyze the reasons why the microstructure of carbon steel affects the corrosion behavior. The results show that the corrosion rate gradually increases with the increase in CO₂ partial pressure. When the pressure exceeds 10 MPa, the corrosion rate of J55 increases slightly, and that of N80 decreases slightly. Under different partial pressures, the surface composition of the corrosion product film of J55 steel is FeCO₃, and that of N80 steel is FeCO₃ with a small amount of Fe₃C. The analysis shows that the corrosion product films of two kinds of carbon steels can be divided into three layers under the condition of supercritical CO₂. There are holes in the middle layer, which are formed first, and then the inner layer and the outer layer are formed at the same time. It is believed that the difference in the morphology and distribution of Fe₃C is the reason why the corrosion rate of J55 steel is lower than that of N80 steel. Fe₃C in J55 steel is lamellar, which can anchor FeCO₃, promote the formation of corrosion product films, and improve the compactness of corrosion product films. However, the Fe₃C in N80 is granular and dispersed in the ferrite matrix, which makes it easy to fall off the surface, form pits, and destroy the integrity of the corrosion product film.

To clarify the corrosion behavior of P110SS material under the synergistic action of multiple factors such as a CO₂/H₂S coexistence environment, a high temperature, and high-salinity formation water, a series of simulation tests and analyses were carried out in this paper. High-temperature high-pressure autoclaves, scanning electron microscopy, and a three-dimensional microscope were used to analyze and evaluate the changing trend of the corrosion performance of P110SS tubing material under different temperatures and a H₂S/CO₂ partial pressure ratio in a high-salinity formation water environment, and the corrosion cracking sensitivity and pitting sensitivity of the material with stress were compared and analyzed. The results indicate that the average corrosion rate of P110SS material without stress increases with the rising test temperature, and the corrosion damage worsens with an increase in the H₂S: CO₂ partial pressure ratio. The highest corrosion rate for P110SS material is 0.99 mm/a. When the test temperature varies from 80 °C to 180 °C and PH₂S:PCO₂ = 0.53:0.17, the P110SS material with a loading stress of 85% YS_min is not susceptible to stress corrosion cracking (SCC). Although surface pitting nucleation is evident at a high temperature of 180 °C, no expansion-induced cracking or fracture phenomena occur.

The gathering and transportation pipeline experienced corrosion cracking failure after 2 years of operation. This paper conducted an analysis on the reasons for the pipeline failure by integrating background information on its usage, as well as observations, analyses, and detection of the morphology of failure samples. The results indicated that the fracture originated from the inner wall of the pipeline and extended to the outer wall along the wall thickness until complete fracture occurred. Based on microstructure analysis of the fracture and original microcracks at the top of the pipeline, it was determined that the fracture was a multi-source brittle fracture, spreading in both inter-granular and trans-granular forms with obvious radial quasi-cleavage fractures accompanied by secondary cracks. EDS analysis revealed that the element S was present in all zones related to fracture initiation, spreading, and transient zones. XRD analysis showed that corrosion products on the fracture surface were mainly composed of FeS, indicating the presence of H₂S in the service environment leading to sulfide stress corrosion cracking characteristics in line with pipeline failure. It is recommended to confirm the source of H₂S in the service medium and test residual stress within the same pipeline for potential risk assessment regarding cracking in other areas.

The release rate of liquid core material from microcapsules is crucial for the surface properties of self-protective metal/liquid microcapsule composite plating coating. However, there is no method to accurately predict the release rate of microcapsules. In this paper, the permeability experiments of different shell membranes and core materials were carried out using the weight loss method, and the permeability model of liquid microcapsules was studied based on a multiple linear regression method. The results show that three-variable mathematical model C, including membrane porosity, the viscosity of core material, and membrane thickness is suitable to describe permeability, and the membrane thickness is the most significant influence factor. Additionally, the accuracy of model C was experimentally verified, and the error of the permeation rate is about 2.06% between predictive and experimental values.