The study aims to explore the corrosion behaviors of tubings of different materials under the injection condition of sulfur-containing purification exhaust gas buried storage well and select a proper steel. A high-temperature and high-pressure autoclave was used to simulate the injection condition of sulfurcontaining purification exhaust gas and carry out corrosion weight loss tests on N80 carbon steel, 13Cr stainless steel, and 825 nickel-based alloy steel under two different partial pressures of CO2 (2 and 5 MPa). Corrosion rate, the morphology of corrosion products, the morphology of cross-section of corrosion products, and local corrosion depth were explored and the corrosion life prediction and economic evaluation of tubings were performed. Under the simulated conditions, with the increase in CO2 partial pressure, the corrosion rates of N80 carbon steel, 13Cr stainless steel, and 825 nickel-based alloy steel increased from 0.0548 mm/a, 0.0172 mm/a, and 0.0013 mm/a to 0.102 mm/a, 0.025 mm/a, and 0.0034 mm/a. The corrosion products of the three steels were mainly FeCO3 and FeS and gradually increased with the increase in CO2 partial pressure. However, the connection among corrosion products was not dense and cracks and holes were observed in the corrosion product film. N80 steel mainly exhibited the uniform corrosion and its residual tensile strength and tensile safety factor decreased with the increase in service life. Safe service life decreased from 48a to 26a with the increase in CO2 partial pressure. Pitting corrosion occurred in 13Cr steel and the ultimate perforation life decreased from 6.05a to 3.36a with the increase in CO2 partial pressure. Based on the consideration of economy and field applicability, N80/825 bimetal composite tubing is recommended as the material of tubings. (c) 2025 The Authors. Publishing services provided by Elsevier B.V. on behalf of KeAi Communication Co. Ltd. This is an open access article under the CC BY license (http://creativecommons.org/licenses/by/4.0/).

A corrosion failure of tubing often occurs during the production process of production wells in heavy oil fire-flooding blocks and thus affects service safety. In the study, the service information of tubings in fire-flooding blocks was analyzed and the physical and chemical properties of defunct tubings were determined. In addition, the causes for the failures of series tubings with wall thickness thinning and corrosion perforation were revealed by SEM, EDS, and XPS. The common corrosion types of tubings and the inducing factors of different failure forms were clarified and corresponding anti-corrosion suggestions were given. The material of defunct tubings was not the failure cause. When high-temperature gas channeling and unburned O2 occurred, corrosion was intensified by a high content of Cl-, thus resulting in the corrosion failure of series tubings with serious wall thickness thinning. When a high content of Ca2 + existed in formation water, a CaCO3 scale layer was formed to adhere to the outer wall of the tubing and aggravate local corrosion under the action of a high content of Cl-. This above process was the cause for corrosion perforation. CO2/H2S corrosion generally occurred in the tubings of fire-flooding production wells. The inducing factors of tubing failures included high-temperature gas channeling, unburned O2, a high content of Ca2 +, and a high content of Cl- . It is recommended to use imidazoline corrosion inhibitor XCN-ZO2 and annular outer wall aluminum-based sacrificial anode anti-corrosion short sections for corrosion protection.

To elucidate the effects of Cl-and Ca2+ on the corrosion and scale formation of 3Cr steel in CO2 flooding-produced fluid, corrosion weight loss experiments, and titration experiments were conducted. The resulting products were characterized using scanning electron microscopy (SEM), X-ray diffraction (XRD), and X-ray photoelectron spectroscopy (XPS). This study examined the corrosion and scaling behavior of 3Cr steel under the influence of Cl-and Ca2+. The results indicate that both Cl-and Ca2+ promote the corrosion of 3Cr steel. Notably, Cl-diminishes the promoting effect of Ca2+ on corrosion and inhibits scaling, revealing a mutual enhancement between corrosion and scaling. The mechanisms of localized corrosion under varying concentrations of Cl-and Ca2+ differ; under-scale corrosion occurs in environments with 5000 mg center dot L-1 Cl-, while Cl-induced corrosion is observed in 20000 mg center dot L-1 Cl-environments. This study highlights that under the synergistic effects of Cl-, Ca2+, and scaling processes, the protective product film dissolves, thereby influencing both corrosion and scaling processes. (c) 2025

In a vertical shell-and-tube heat exchanger of the nitrogen production system in an oilfield, perforation failure of the internal heat exchange tubes occurred after only one year of service. The corrosion morphology and chemical composition of the failed tube were analyzed by visual examination, scanning electron microscope (SEM), X-ray photoelectron spectroscopy (XPS), and X-ray diffraction (XRD). The influence of temperatures ranging from 30 degrees C to 90 degrees C on the corrosion behavior of T2 copper was investigated through potentiodynamic polarization (PDP) testing. The uniform corrosion and pitting corrosion behaviors of T2 copper under static and dynamic conditions were separately studied using a circulating flow autoclave. The results indicate that the thicknesses of the corrosion product films are 10.12 mu m in the splash zone and 105.8 mu m in the dynamic waterline zone, respectively. No significant signs of corrosion or scaling were observed in the immersion zone. Corrosion intensity increases with rising temperature, and corrosion is more severe under dynamic conditions than under static conditions. Under dynamic conditions, the pitting corrosion rate in the dynamic waterline zone reached as high as 1.666 mm/y, whereas almost no pitting corrosion took place in the immersion zone. In the splash and dynamic waterline zones, liquid films experience continuous cycles of formation and evaporation, resulting in increased concentrations of Ca2+, CO32-, and Cl-.These elevated ion concentrations promote the generation of loose and porous corrosion products such as CaCO3, Cu-2(OH)(3)Cl, and Cu-2(OH)(2)CO3, which facilitate underdeposit corrosion. Furthermore, circulating water disturbances in the dynamic waterline area cause frequent detachment of corrosion products, ultimately leading to perforation due to localized corrosion.

Casing corrosion often occurs in CCUS injection wells and affects its safe service life. In a HTHP kettle, corrosion experiments on the inner and outer walls of N80 and L80-13Cr casing were carried out under different CO2 partial pressures in order to reveal the microscopic corrosion mechanism with characterization methods. Based on the weight-loss corrosion rate, local corrosion rate, collapse resistance strength, residual tensile strength, internal compressive strength and cost of casings, a hierarchical material selection model was established to evaluate the suitability of N80 and L80-13Cr steels and the results for the rational selection of materials. The corrosion rate of casings increased with the increase in CO2 partial pressure. In a simulated pore environment, CaCO3 and SiO2 formed a passivation film to alleviate uniform corrosion. In addition, loose CaCO3 scale caused the uneven product film, thus intensifying local corrosion. Cr element in L80-13Cr steel repaired the product film and reduced the corrosion rate, thus showing the stronger pitting corrosion sensitivity. It was recommended that N80 steel could meet the corrosion resistance requirements of oil casings in CCUS injection wells.

In order to study the problem of obvious wall thinning in the wellbore caused by proppant backflow and sand production under throttling conditions in tight gas wells. Based on the gas-phase control equation, particle motion equation, and erosion model, the wellbore erosion model is established. The distribution law of pressure, temperature, and velocity trace fields under throttling conditions is analyzed, and the influences of different throttling pressures, particle diameters, and particle mass flows on wellbore erosion are analyzed. The flow field at the nozzle changes drastically, and there is an obvious pressure drop, temperature drop, and velocity rise. When the surrounding gas is completely mixed, the physical quantity gradually stabilizes. The erosion shape of the wellbore outlet wall has a point-like distribution. The closer to the throttle valve outlet, the more intense the erosion point distribution is. Increasing the inlet pressure and particle mass flow rate will increase the maximum erosion rate, and increasing the particle diameter will reduce the maximum erosion rate. The particle mass flow rate has the greatest impact on the maximum erosion rate, followed by the particle diameter. The erosion trend was predicted using multiple regression model fitting of the linear interaction term. The research results can provide a reference for the application of downhole throttling technology and wellbore integrity in tight gas exploitation.

With the continuous rise in global energy demands, the exploration and development of oil and gas resources are increasingly moving into more challenging environments. These conditions pose significant corrosion and wear threats to oil country tubular goods (OCTG). In the oil and gas industry, tribo-corrosion often coexist in a complex manner, driven by both mechanical and chemical factors. However, the detailed interaction between them remains unclear. This paper first defines corrosion and friction, then reviews various tribo-corrosion models and commonly used testing standards and apparatuses. It also summarizes recent research on OCTG tribo-corrosion, covering key parameters such as material properties (microstructure, corrosion resistance, and surface roughness), electrochemical factors (solution properties and additives), and mechanical factors (sliding speed, contact load, and frequency). Finally, the paper statistically analyzes the existing research, identifies current challenges, and suggests future research directions.

In the construction of offshore oil and gas projects, the selection of pipeline materials is significant and challenging. In the complex marine environment, it is difficult to ensure the safe service life of oil and gas pipelines selected only based on the consideration of the corrosion resistance of materials. Therefore, multiple performance indicators should be comprehensively considered in the material selection. The partial pressure of H2S and CO2 in the oil and gas of an offshore block was as high as 2 MPa and the temperature of the transported fluid was up to 70 degrees C. Rock particles were carried in the fluid. In this study, TA3, TA10, and TA36 titanium alloy materials to be used in this block were evaluated through various tests, including physical and chemical tests (tensile test, impact test, bending test, and hardness test), friction wear test, gas-solid erosion test, corrosion test, and corrosion wear test. In this paper, based on the consideration of the performance indicators and expert knowledge corresponding to the above tests, a material selection method based on analytic hierarchy process was proposed and the priority in the material selection of marine pipelines was studied. In addition, the microstructures and element distributions of the tensile and impact fractures, erosion pits, and friction traces of the materials were studied by a scanning electron microscope, an energy dispersive spectroscope, and a laser confocal microscope. The results of hierarchical analysis showed that the selection priority of TA3, TA10, and TA36 titanium alloys was TA10 < TA3 < TA36. TA36 titanium alloy was the best material choice for the submarine pipeline system in the target area and the corresponding weight was 0.60121. The results provided the basis for the selection of the best material alternative for the construction of submarine pipelines in this block.

Confronting the ever more stringent demands for oil and gas transportation, the development and application of non-metallic pipes have become increasingly crucial and of strategic importance. In this study, a new carbon fiber-reinforced bismaleimide resin composite pipe with winding angles of [+/- 85 degrees/+/- 20 degrees/+/- 85 degrees]11 was prepared. The corrosion behaviors and aging mechanisms of CFRP pipe were analyzed and discussed by simulating harsh wellbore environments. After exposure to single working conditions, the resin matrix exhibits no significant degradation, the fiber-resin interfaces remain intact without debonding, and the glass transition temperatures (Tg) of the CFRP pipes remain above 230 degrees C. Following corrosion under continuous alternating condition, the propagation of microcracks and micropores leads to an increase in porosity from 0.78% to 0.96%. However, the internal structure of the CFRP pipe remains intact, the fiber-resin interfaces show no signs of debonding, and the degradation of resin matrix reduces the Tg to 221 degrees C. Furthermore, the moisture diffusion coefficient of the CFRP pipe in the 150 degrees C hot and humid environment is 7.22 x 10-11 m2/s. The results indicate that the resistance of the CFRP pipe to corrosion damage dominated by physical damage with chemical damage playing a secondary role determines its service performance.

Summary During pressure-preserved coring (PPC) retrieval, the core barrel’s pressure preservation performance is crucial for accurately assessing deep oil and gas resources. By accounting for the thermodynamic properties of the core, drilling fluid, and the variation in the core barrel’s working volume, we developed a thermodynamic model to predict temperature and pressure changes and to investigate the variation of thermodynamic parameters within the core barrel. A digital solution framework for the model was established using a fully implicit difference algorithm. Introducing the pressure preservation performance coefficient allowed us to evaluate the influence of key parameters—such as core length, drilling fluid density, and the core barrel’s height/diameter ratio—on pressure preservation. The model accurately predicts the thermal evolution during core retrieval and assesses the core barrel’s pressure preservation performance. Model predictions showed a relative error of less than 2.79% compared with laboratory measurements and less than 4.03% compared with field-collected data. During coring, the volumes of the core, drilling fluid, and core barrel increased by maximum values of 0.21%, 1.95%, and 1.00%, respectively. When ambient temperatures were high, adjusting the core length could improve pressure preservation. Given that various parameters affect core barrel design, it is recommended to increase the drilling fluid density, increase the height/diameter ratio of the core barrel, and keep the core barrel’s working volume below 20 L.

Steel-reinforced thermoplastic pipe is widely used for water transportation in sour gas fields. However, under the combined effects of corrosive media, internal high pressure, and long-term environmental aging, premature failures such as leakage and bursting often occur. To clarify the failure causes and primary contributing factors of the composite pipes, this study conducted a comprehensive analysis through microscopic morphology examination of different typical failure cases, differential scanning calorimetry, Fourier transform infrared spectroscopy, and mechanical property testing. The main failure mechanisms were investigated, and targeted protective measures are proposed. Key findings reveal that the typical failure modes are ductile cracking, aging-induced brittle cracking, and aging creep cracking. These failures follow a mechanism of degradation of the inner and outer polyethylene protective layers, penetration of the medium and corrosion of the steel wires, reduction in pressure-bearing capacity, and eventual structural damage or leakage propagation through the pipe wall. Notably, oxidation induction time values dropped as low as 1.4-17 min-far below the standard requirement of >20 min-indicating severe antioxidant depletion and material aging. The main controlling factors are poor material quality, external stress or mechanical damage, and long-term aging. The polyethylene used for the inner and outer protective layers is critical to the overall pipe performance; therefore, emphasis should be placed on evaluating its anti-aging properties and on protecting the pipe body during installation to ensure the long-term safety and stable operation of the pipeline system.

Repairing drilling tools with laser cladding technology becomes a meaningful way to reduce costs and increase efficiency. The relationship between the wear/wear corrosion mechanism and micromechanics of laser -repaired Ni-WC coating was investigated. It is found that the received NiWC coating is mainly composed of gamma -Ni, WC, W 2 C, and a small amount of CrC and MoC. In dry environment, the surface fatigue crack gradually propagates and develops along the surface as the load increases, forming a peeling phenomenon on the surface. Conversely, the water film was formed as lubrication to reducing the formation of peeling in wet environment. It is found that the wear and damage of the laser -repaired Ni-WC coating in wet environment is lower than that in dry environment. The effect of water film and water cooling on wear of the laser -repaired Ni-WC coating is higher than that of corrosion. In addition, a thin oxide interfacial layer is found under dry sliding at the boundary of WC particle with the maximum width of about 3 mu m, leading to low microhardness (H) / elastic modulus (E) of the oxide interfacial layer, which weakens the wear resistance of WC particles in laser -repaired Ni-WC coating.

The study combined experimental and numerical simulation methods to investigate the distribution of residual stress in laser composite welding of dissimilar aluminum alloys 6063 and 5083. Using the Simufact Welding simulation software and a combined volume heat source, the distribution patterns of transverse and longitudinal residual stress fields at different welding speeds were analyzed. The blind hole method was used to test the residual stress after welding. The results showed that the use of a combined volume heat source model for heat source calibration yielded ideal results, and the thermal cycle curve was basically consistent with the simulation and experimental results of residual stress. As the welding speed decreased, the longitudinal residual stress of the parent material on both sides significantly decreased, while the transverse residual stress increased. The majority of tensile and compressive stresses on both sides of the 5083 and 6063 aluminum alloys decreased with a decrease in welding speed. The Von Mises equivalent stress indicated that the cooling process is the main stage for residual stress generation. When the welding speed decreased, the peak value of longitudinal residual stress on the 6063 aluminum alloy side decreased from 230 to 90 MPa, while that on the 5083 aluminum alloy side decreased from 304 to 150 MPa. These findings provide an important basis for controlling and reducing the residual stress and deformation of dissimilar aluminum alloy laser arc composite welded components.

In order to improve the corrosion resistance of welded joints, X90 pipeline steel joints were subjected to post-weld heat treatment at 610 C-degrees, 640(degrees)C, and 670(degrees)C (holding time was 1 h). Through electrochemical corrosion and full immersion corrosion experiments, the corrosion resistance of welded joints under various conditions was tested, and the surface morphology and corrosion products of the corroded samples were analyzed by scanning electron microscopy and X-ray diffraction analysis. The experimental results show that the corrosion products of X90 pipeline steel welded joints in simulated soil solution mainly include Fe(OH)(3), gamma-FeOOH, alpha-Fe2O3, gamma-Fe2O3, and a small amount of Fe3O4, FeCl3 and Fe. After heat treatment at 610 C-degrees, the corrosion current density of the parent metal, heat-affected zone, and weld metal of the joint changes from 1.081, 2.889, 2.079 (x10(-5) A cm(-2)) to 0.977, 2.211, 1.810 (x10(-5 )A cm(-2)), respectively, the corrosion resistance is improved.

In order to explore the corrosion failure mechanism of an aluminum heat exchanger in the Yakela Gas Processing Plant, operating conditions, metallographic structure, mechanical properties, and macroscopic and microscopic corrosion characteristics of the heat exchanger were analyzed. The phase analysis of corrosion products was performed with a scanning electron microscope, an energy-dispersive spectrometer, and an X-ray photoelectron spectroscopy (XPS). The physicochemical properties of the aluminum alloy heat exchanger still met the performance requirements in related standards after 18 years of service. However, localized corrosion occurred at the bottom of the exchanger and corrosion pit depth was up to 18.75 µm. Corrosion products were identified as Al(OH)3 and contained 1.46

Large-displacement high-intensity sanding hydraulic fracturing operations often cause casing perforation erosion and thus temporary plugging failures, exacerbate the unevenness of fracture initiation and expansion, and induce casing damage. In order to clarify the dynamic evolution of perforation erosion and predict perforation diameter, the effects of different types of proppants, the viscosity of sand-carrying liquids, and large sand-passing quantities on perforation erosion rate were experimentally explored in the study. The evolution of perforation erosion and the particle size distribution of quartz sand and ceramsite were analyzed in the experiment and a prediction model for perforation erosion under various fracturing parameters was established. Compared to ceramsite, quartz sand had the more significant effect on perforation erosion and the more serious particle abrasion and fragmentation under the same sand-passing quantity. Increasing the viscosity of the sand-carrying liquid slowed down perforation erosion and made the edge of perforation entrance more uniform. As the sand-passing quantity through the perforation increased, perforation erosion in the initial stage was concentrated at the perforation edge. Then, the inner wall of the perforation was also eroded, but the average erosion rate was reduced. A prediction model of perforation erosion considering multiple fracturing parameters was established based on the principle of fluid similarity. The errors between predicted values and downhole eagle-eye observation values were less than 15%. The model provides an important basis for the optimization of fracturing parameters and downhole casing strength design.

The paper focuses on the excellent chemical inertness characteristics of nonmetallic materials and evaluates the performance of three types of new carbon fiber-reinforced resin-based composites under various simulated corrosion conditions in wellbores. Through comprehensive analysis of macro and micromorphology, moisture absorption performance, strength performance, and molecular structure, the damage characteristics and applicability of carbon fiber composites in oil and gas wellbore conditions were clarified. T700/epoxy and T300/epoxy composites experienced damage dominated by physical effects such as moisture absorption and wet thermal stress, manifested as swelling, deformation, and cracking at the macro level, and pore formation and delamination cracking at the micro level. After continuous corrosion tests, the tensile strength of T700/bismaleimide composite (913 MPa) was higher than that of T700/epoxy composite (814 MPa) and T300/epoxy composite (636 MPa), with reductions of 12.4%, 14.3%, and 19.5% respectively. The research results showed T700 carbon fiber/bismaleimide resin composites had the best mechanical and chemical stability.

A theoretical foundation for selecting corrosion-resistant materials is necessary to address the corrosion risks in complex oil and gas fields and tubing for CO2 capture, utilization, and storage (CCUS). To achieve this, experiments were conducted using actual oilfield simulated formation water as the corrosive medium. Weight-loss corrosion tests and surface analysis methods were employed to investigate and compare the corrosion of four steel materials (C110, 3Cr, 5Cr, and 9Cr) in high mineralization, CO2, and trace H2S coexistence environments. The results show that all materials experience CO2-dominated corrosion under CO2 and trace H2S conditions, with corrosion rates exceeding the controlled limit for oilfields (0.076 mm/y). The corrosion severity is classified as extremely severe, and the corrosion products mainly comprise a mixed carbonate of FeCO3 and CaCO3. Both uniform and localized corrosion rates decrease gradually with increasing chromium content in the materials. The experimental study demonstrates that chromium has good corrosion resistance. The morphology of the corrosion product film transitions from irregular particles to rhombohedral blocks or flakes with increased chromium content. Carbon steel primarily forms FexCa1-xCO3 corrosion products with a small amount of Fe2O3 inclusion, while corrosion products in chromium-containing steel include Cr2O3, Cr(OH)3, FexCa1-xCO3, and Fe2O3. As the chromium content in the steel material increases, the content of Ca and Cl elements in the corrosion product film gradually decreases. These findings provide valuable insights into the corrosion behavior of different steel materials under the challenging conditions of high mineralization, CO2-rich, and trace H2S environments. They contribute to the theoretical basis for selecting suitable corrosion-resistant tubing materials for oil and gas operations, including CCUS, enabling the industry to mitigate corrosion risks effectively.

为解决玛湖油田非金属管的结垢问题,通过结垢试验、接触角测量等研究了温度、CO2 分压、Ca2+含量和矿化度对玻璃钢管、热塑性塑料内衬玻璃钢管、柔性复合管结垢的影响,并优选出适用于玛湖油田现场工况的阻垢剂.结果表明:相同条件下,柔性复合管的结垢速率远高于其他两种材料;几种因素对非金属管材结垢影响的显著性排序为温度>矿化度>CO2 分压>Ca2+含量;有机膦酸阻垢剂(MQ2)的阻垢效果最优,推荐加注量为 60 mg/L;现场应用效果表明,降低运行温度并加注MQ2 可使非金属管的结垢现象得到良好控制.