This paper presents the failure analysis of the crack and leakage accident of a crude oil pipeline under CO₂-steam flooding in the western oilfield of China. To analyze the failure behavior and cause, different testing, including nondestructive testing, chemical composition analysis, tensile property testing, metallographic analysis, and microanalysis of fracture and chloride stress corrosion cracking (SCC) testing, are applied in the present study. The obtained results showed that the pipeline under the insulation layer of high humidity, high oxygen content, and high Cl⁻ environment occurred pit corrosion, and the stress concentration area at the bottom of the corrosion pit sprouted cracks. Besides, it is demonstrated that the cracks were much branched, mostly through the crystal, and the fracture showed brittle, which is consistent with the typical characteristics of chloride SCC. Meanwhile, the insufficient Ni content of the pipeline material promoted the process of chloride SCC, and the high-temperature working conditions also aggravated the rate of chloride SCC. In addition, efficient precautions were provided to avoid fracture.

The response surface methodology (RSM) is utilized to construct a corrosion prediction model for steel pipelines for underground gas storage (UGS). Four key corrosion-influencing factors—the CO₂ partial pressure, Cl⁻ concentration, temperature, and flow rate—are identified by investigating the operating parameters of 14 UGS extracted pipelines (Nos. S1–S14) in China. Based on the operating parameters, 29 sets of high-temperature and high-pressure autoclave corrosion tests are designed and carried out. A quadratic regression equation model for corrosion rate prediction is fitted using the data from the corrosion test results. The p-values of the model’s four influencing factors are <0.01, indicating that the influencing factors are significant and reasonable. The F-value of the model is greater than the critical value, and the noise probability p-value is <0.01, indicating that the model has good fitness. The determination coefficient R² of the model is 0.9753, which is close to 1. Therefore, the observed value and the response value of the model are obviously correlated: i.e., the model has a high degree of truth. The model is used to predict the corrosion rate of 14 UGS pipelines: S3 and S14 are severely corroded, while the others are moderately corroded.

A firefighting pipeline failure accident occurred in a large high-rise office building. To investigate the cause of the accident, a series of tests were conducted, including material, physical and chemical property tests, full-scale hydrostatic and burst testing, and microcharacterization tests. The results indicated that the chemical composition, metallographic structure, hardness, and tensile properties of the pipeline body all met the requirements for Q275 material specified in the GB/T 3091-2015 standard. The hydrostatic test and hydrostatic burst test for the same batch of pipeline also comply with the relevant requirements of GB/T 3091-2015. However, the wall thickness and outer diameter of the pipeline failed to conform to the requirements for the DN150 specification. Additionally, the firefighting pipeline fractured circumferentially along the bottom of the groove. The fracture surface is flat and without obvious plastic deformation, showing a quasi-cleavage morphology. The groove rolling process resulted in an asymmetric structural mutation at the groove and also caused work hardening and deformation of the structural flow lines. Ultimately, under the action of loads such as internal pressure, water flow impact, and uneven torque, a sudden brittle fracture occurred at the root of the groove.

Aiming at the erosion failure risk of key elbow components in the process system of underground gas storage (UGS), numerical simulation was adopted to investigate the erosion behavior and mechanism of elbows under the following three typical working conditions: gas injection, gas production, and wastewater treatment. The results show that the elbow in the gas injection system is under gas–solid two-phase flow, and the most severely eroded area is located at 45–50° on the outer arc side of the elbow. Small particles have stronger flow-following ability than large particles and collide with the wall more sufficiently, resulting in a higher erosion rate. For the tandem elbows in the gas production system, affected by centrifugal force and secondary flow, the outer arc side shows high pressure while the inner arc side shows low pressure. As the particle size increases, the erosion rates of both elbows decrease, with a larger reduction for the second elbow. The most severely eroded positions of the first and second elbows are at 50–55° and 40–45° on the outer arc side, respectively. The elbow in the wastewater treatment system has relatively slight erosion with a symmetrical distribution, but a small amount of natural gas accumulated on the inner side easily induces cavitation corrosion.