Carbon dioxide corrosion presents a significant challenge in the oil and gas field. This study simulates the corrosive environment characteristics of oil and gas fields to investigate the corrosion inhibition properties of three triphenylmethane dyes. The inhibitive performance and mechanisms of these dyes were analyzed through weight loss and electrochemical testing, revealing that crystal violet (CV) exhibited a superior inhibition effectiveness over malachite green (MG) and Fuchsine basic (FB). At a concentration of 150 ppm in a CO₂-saturated 5% NaCl solution at 25 °C, CV achieved an impressive maximum inhibition efficiency of 94.89%. With the increase in temperature, the corrosion rate slightly decreased, and the corrosion rate was 92.94% at 60 °C. The investigated CV acted as a mixed-type corrosion inhibitor and its protection obeyed the Langmuir adsorption isotherm. The corrosion morphology was characterized by scanning electron microscopy (SEM), X-ray photoelectron spectroscopy (XPS), and confocal laser scanning microscopy (CLMS). Quantum chemical calculations and molecular dynamics simulations were employed to validate the corrosion inhibition mechanisms, providing guidance for the further application of these dyes in corrosion control.

Titanium alloys are applied in oil and gas development and transportation to improve conditions because of their high specific strength and corrosion resistance. However, the disadvantage of poor wear resistance has become an obstacle to developing titanium alloys. The friction and wear properties of pure titanium TA3 and titanium alloy TA10 were tested under different loads and different friction forms using a reciprocating friction and wear tester. Moreover, the erosion resistance of pure titanium TA3 and titanium alloy TA10 was studied using a gas–solid erosion tester. The results show that the wear rate of TA3 and titanium alloy TA10 increases with increasing friction load. Under a load of 50 N, the mass losses of TA3 under dry friction and wet friction were 0.0013 g and 0.0045 g, respectively, while the mass losses of TA10 were 0.0033 g and 0.0046 g, respectively. While the load increased to 70 N, the mass loss of TA3 was even greater, reaching 0.0065 g, and the mass loss of TA10 was 0.0058 g. The wear forms of TA3 and TA10 include abrasive wear, adhesive wear and oxidation wear. The joint action of various friction forms leads to the loss of materials. Under the simulated working conditions, the erosion rates of TA3 and TA10 were 1.01 × 10⁻³ g/s and 0.94 × 10⁻³ g/s. The erosion mechanism is the same, including plowing, indentation and cracking.

The corrosion of steel caused by sulfate-reducing bacteria (SRB) has been a big trouble resulting in the service failure of engineering equipment, and SRB biofilm is the direct reason leading to the corrosion acceleration. In this work, SRB biofilms formed on N80 carbon steel in an artificial shale gas field produced water with different test conditions were characterized carefully by scanning electron microscopy (SEM), energy dispersive X-ray spectroscopy (EDS), fluorescence microscope, and three-dimensional stereoscopic microscope. Results demonstrate that test time, temperature, and initial SRB cell concentration can influence the growth and surface morphology of biofilm, and test time and temperature are primary factors. There is a highest corrosion rate of 0.100 ± 0.005 mm/y on the seventh day due to the high biological activity, and then corrosion rates gradually decline with time. The formed biofilms at different time have a similar morphology and the contents of elemental S in biofilms are high also suggesting SRB corrosion. Temperature can influence the biological activity of SRB, and then affect the formation of SRB biofilms. SRB has a higher biological activity at 20 and 37 °C than that of at 60 and 80 °C. The influence of initial SRB cell count differences on biofilm is weak.

The erosion of surface pipelines induced by proppant flowback during shale gas production is significant. The surface pipelines in a shale gas field in the Sichuan Basin experienced perforation failures after only five months of service. To investigate the erosion features of L360N, coatings, and ceramics and optimize the selection of two protective materials, a gas–solid two-phase flow jet erosion experimental device was used to explore the erosion resistance of L360N, coatings, and ceramics under different impact velocities (15 m/s, 20 m/s, and 30 m/s). An energy dispersive spectroscope, a scanning electron microscope, and a laser confocal microscope were employed to analyze erosion morphologies. With the increase in flow velocity, the erosion depth and erosion rate of L360N, coating, and ceramic increased and peaked under an impact velocity of 30 m/s. The maximum erosion rate and maximum erosion depth of L360N were, respectively, 0.0350 mg/g and 37.5365 µm. Its primary material removal mechanism was the plowing of solid particles, and microcracks were distributed on the material surface under high flow velocities. The maximum erosion rate and maximum erosion depth of the coating were, respectively, 0.0217 mg/g and 18.9964 µm. The detachment of matrix caused by plowing is the main material removal mechanism. The maximum erosion rate and maximum erosion depth of ceramics were, respectively, 0.0108 mg/g and 12.4856 µm. The erosion mechanisms were micro-cutting and plowing. Under different particle impact velocities, different erosion morphologies were observed, but the primary erosion mechanism was the same. The erosion resistance of the ceramics was higher than that of the coatings. Therefore, ceramic lining materials could be used to protect the easily eroded parts, such as pipeline bends and tees, and reduce the failure rate by more than 93%. The study provided the data and theoretical basis for the theoretical study on oil and gas pipeline erosion and pipeline material selection.

The combined effect of sulfate-reducing bacteria (SRB) and a microstructure on the stress corrosion behavior of heat-affected zones (HAZs) in pipeline steel for shale gas field applications was investigated. The results show that when the peak heating temperature reached 1020 °C, a coarse microstructure formed during multiple thermal cycles (MTCs), and Widmanstätten structures appeared in the HAZ. In the simulated environment, SRB intensified localized pitting corrosion of both the base metal and the HAZ. The welding HAZ was softened by the MTCs, and significant microcrack growth was observed in the presence of SRB. Among all subzones, the coarse-grained HAZ (CGHAZ) was the most susceptible to stress corrosion cracking (SCC) under shale gas service conditions. Cracks initiated at the metal surface and propagated vertically into the material. SRB activity further increased the SCC sensitivity of the CGHAZ.