In this paper, we analyze the potential factors affecting the hydrogen sulfide type of stress corrosion cracking in C110 casing pipes. In order to further study these cracking factors, the methods of material property testing, scanning electron microscopy, XRD, TEM, and 3D ultra-depth-of-field were applied in the experiments. Besides that, an HTHP autoclave was independently designed by the laboratory to simulate the actual corrosion environment, and the potential factors affecting the stress corrosion cracking of C110 casing pipes were determined. The test results showed that the chemical composition, metallographic structure, hardness, and non-metallic inclusions of the two types of C110 casing pipes were all qualified. In fact, there remains a risk of stress corrosion cracking when the two kinds of C110 casing pipes serve under long-term field-working conditions. It is considered in this paper that the precipitates on the material surface, stress damage, and pitting corrosion are all critical factors affecting the stress corrosion cracking of casing pipes.

In order to solve the corrosion problem of production string in the process of acidizing for the purpose of production, a new water-based annular protective fluid suitable for HTHP acid gas, including H₂S-CO₂ wells, was developed. Firstly, an appropriate deoxidizer, bactericide, and corrosion inhibitor shall be selected according to the production string of acid gas. In addition, the synergism between additives is evaluated. Then, by designing the additive ratio, the optimal formulation of the water-based annular protective fluid is determined. Finally, a high-temperature autoclave was used to evaluate the protective performance of the water-based annular protective liquid. The results showed that it is recommended to use water-based annular protective liquids prepared with clear water that comes easily from nature (rivers, etc.), which consist of a corrosion inhibitor, CT2-19C (30,000 ppm), BN-45 bactericide (2 g/L), and anhydrous sodium sulfite (3 g/L). The density of the water-based annulus protection liquid is 1.02 g/cm³, and the freezing point is −2.01 °C. The dissolved oxygen content of water-based annulus protection fluids prepared with clear water in formation water shall be controlled within 0.3 ppm. The corrosion inhibition rate of water-based annular protective fluid in the liquid phase is higher than 90%, and the corrosion rate of P110SS steel in the gas–liquid phase is lower than the oilfield corrosion control index (0.076 mm/y).

During the drilling operations of a shale gas well in Central China, a severe failure occurred in the pressure-resistant cylinder of the measurement while drilling (MWD) tool, with numerous microcracks observed on the outer surface of the cylinder. This significantly compromised the safety of the MWD tool and the reliability of the logging data. To determine the cause of the failure, macroscopic morphology analysis and physicochemical performance tests were conducted on the failed pressure-resistant cylinder, which is made of Cr20Ni11 (UNS 308) austenitic stainless steel. Additionally, scanning electron microscopy, X-ray energy dispersive spectroscopy, white light interferometry, and X-ray photoelectron spectroscopy were employed to analyze the morphology and chemical composition of the corrosion products and cracks, thereby identifying the cause of the corrosion failure. It is demonstrated that the physicochemical properties of the pressure-resistant cylinder comply with the specifications of relevant standards. Nevertheless, the size of non-metallic inclusions in the material reaches 100 μm, which significantly enhances the material’s susceptibility to stress corrosion cracking (SCC). Meanwhile, solid particles and high-concentration Cl⁻ present in the drilling fluid deteriorate the passive film formed on the substrate surface. EDS analysis reveals that the Cl⁻ content is measured to be 4.09 wt%, which induces pitting on the substrate with a maximum pitting depth of 13.5556 μm. Under the synergistic effect of stress and corrosion, the pressure-resistant cylinder experiences SCC failure initiated by Cl⁻; specifically, cracks nucleate at the bottom of the pitting pits and propagate along the radial direction.

This study investigates the causes and mechanisms of a corrosion-induced perforation failure in P110 tubing from a nitrogen injection well in the Tahe Oilfield. A comprehensive analysis was performed using macroscopic examination, mechanical and chemical property testing, characterization of corrosion product morphology and composition, and electrochemical measurements. The results show that the tubing material met all relevant standard requirements, ruling out intrinsic material defects as a contributing factor. The primary cause of failure was the breakdown of the internal coating. Poor coating adhesion in the older tubing from the shallow section, combined with the tensile stress from the tubing’s suspended weight and the acidic service environment, led to coating blistering and disbondment, thereby exposing the underlying steel. In the presence of H₂S, CO₂, and O₂, severe electrochemical corrosion developed on the exposed metal surface. The process was further accelerated by a high concentration of Cl⁻, which promoted rapid localized corrosion and ultimately resulted in perforation. Based on these findings, several targeted mitigation strategies are proposed. These include optimizing the coating process to improve adhesion and modifying the corrosive environment. The recommendations provide practical guidance for corrosion control in similar oil and gas well applications.

Cracking occurred in the surface coating of a screw rotor during shale gas well operations. To determine whether the coating cracks could contribute to the failure of the 42CrMo substrate, the microstructure and morphology of surface cracks and local corrosion pits were examined and analyzed using a metallographic microscope, an SEM, and an EDS. To investigate the cross-sectional morphology and elemental distribution of corrosion pits, EDS mapping was performed. The composition of the corrosion products was characterized using Raman spectroscopy and XPS. In addition, four-point bend stress corrosion tests were conducted on screw rotor specimens under simulated service conditions. The results indicate that the P and S contents in the screw rotor substrate exceeded the specified limits, whereas its tensile and impact strengths satisfied the standard requirements. The microstructure consisted of tempered sorbite and ferrite, along with a small amount of sulfide inclusions. The corrosion products on the fracture surface were primarily identified as FeOOH, Fe₃O₄, and Cr(OH)₃. All specimens failed during the four-point bend tests. The chlorine (Cl) content in the corroded regions reached up to 8.05%. These findings demonstrate that the crack resistance of the 42CrMo screw rotor was markedly reduced under the simulated service conditions of 130 °C in a saturated, oxygenated 25% CaCl₂ solution. The study concludes that stress concentration induced by sulfide inclusions in the screw rotor, together with the combined effects of chloride ions, dissolved oxygen, and applied load, promotes the initiation and propagation of stress corrosion cracking. Therefore, it is recommended to strictly control the chemical composition and inclusion content of the screw rotor material and to reduce the oxygen content of the drilling fluid, thereby mitigating the risk of corrosion-induced cracking of the rotor.

Axial cracking in threaded joints of rotary steerable tools is a critical but under-investigated failure mode that can severely disrupt shale gas drilling operations. Understanding its root cause is essential for prevention. This study aims to determine the cause of an axial cracking failure in an S35150 austenitic stainless steel threaded joint from a field operation. A comprehensive analysis was conducted, integrating physicochemical characterization of the failed joint. The stress corrosion behavior of the threaded joint in a simulated corrosive environment was evaluated via four-point bend (FPB) and double cantilever beam (DCB) stress corrosion tests. The results showed that the material exhibited high susceptibility factors: a hardness of 38.5 HRC, a yield-to-tensile ratio near 1, and a P content exceeding the standard. Fracture surface analysis revealed an intergranular morphology with substantial chlorine (0.78%) and sulfur (0.93%) contents, indicative of stress corrosion cracking (SCC). The laboratory tests results demonstrated that the threaded joint had poor crack resistance: the fracture toughness value of the specimen measured by the DCB test was 24.14 MPa·m^0.5, and all specimens fractured during the FPB.