An oil spill accident will cause serious harm to marine ecology and the environment. Rapid response and effective prevention methods are required to minimize the damage of oil spill accidents. The critical problems that marine emergency rescue teams face are when the spilled oil reaches the sea surface, the extent of the spilled oil, and how far they are from the drilling platform. However, there is no reliable model to predict the diffusion distance of spilled oil. Accurately predicting the diffusion characteristics of underwater spilled oil can provide timely and accurate information for the treatment of oil spill accidents and guide the correct implementation of emergency treatment. In this paper, the computational fluid dynamics (CFD) method was used to establish a two-phase flow model for the diffusion of a submarine oil spill. The volume-of-fluid (VOF) technique was implemented to track the interface between oil–water phases. The effects of different parameters on leakage and diffusion characteristics were investigated by adjusting spilled oil velocity, ocean current velocity, crude oil density, and crude oil viscosity. The logarithmic velocity profile was adopted for ocean currents to conform to the actual flow near the sea surface. A user-defined function (UDF) was developed and applied for CFD modeling. The focus was on analyzing the diffusion range (rising height H_p and lateral migration distance W_p) from full-field data. The results indicate that the oil spill velocity, ocean current velocity, crude oil density, and crude oil viscosity impact the viscous shear force, the oil spill’s inertia force, and the current shear effect. The formula for calculating the lateral migration distance of spilled oil under different working conditions was obtained by fitting. The results of this study can provide a scientific basis for formulating an emergency treatment plan for offshore oil spill accidents and minimizing the harm to marine ecology and the environment.

Cement bond quality is critical to ensuring the long-term safety and structural integrity of oil and gas wells. However, due to the complex interdependencies among geological conditions, operational parameters, and fluid properties, accurately predicting cement bond quality remains a considerable challenge. To improve the accuracy and practical applicability of cement bond prediction, this study develops an intelligent prediction model. A Wide and Deep neural network architecture is adopted, into which two key parameters of the cement slurry’s power-law rheological model—the consistency coefficient and the flow behavior index—are embedded. A temperature correction mechanism is incorporated by integrating the correction equations directly into the network structure, allowing for a more realistic representation of the cement slurry’s behavior under downhole conditions. The proposed model is designed to simultaneously predict the bonding quality at both the casing–cement sheath and cement sheath–formation interfaces. It is trained on a field dataset comprising 30,000 samples from eight wells in an oilfield in western China. On the test set, the model achieved prediction accuracies of 87.29% and 87.49% at the two interfaces, respectively. Furthermore, field testing conducted during a third-stage cementing operation of a well demonstrated a prediction accuracy of approximately 90%, indicating strong adaptability to real-world engineering conditions. The results demonstrate that the temperature-corrected neural network effectively captures the flow characteristics of the cement slurry. The proposed model meets engineering application requirements and serves as a reliable, data-driven tool for optimizing cementing operations and enhancing well integrity.

To investigate the mitigation of high-pressure CO₂-induced degradation of wellbore cement sheath in Carbon Capture, Utilization, and Storage–Enhanced Oil Recovery applications (CCUS-EOR), conventional Class G oil well cement and modified cement systems incorporating graphene, waterborne epoxy resin, and a composite of waterborne epoxy resin with graphene were formulated. This study presents the original comparative investigation on the long-term carbonation resistance of graphene-modified, waterborne-epoxy-modified, and their composite-modified oil well cements under 130 °C and 7 MPa CO₂ partial pressure, filling the research gap of unclear synergistic effects of the two modifiers in high-temperature CCUS environments. The specimens were subjected to simulated downhole conditions, and key properties, including compressive strength and permeability, were evaluated. The underlying mechanisms were elucidated through material characterization techniques such as X-ray diffraction, X-ray computed tomography, and scanning electron microscopy. Results indicated that the waterborne epoxy resin–modified cement system exhibited superior long-term carbonation resistance, achieving a 90 d compressive strength retention rate of 84%. The graphene-modified cement showed a 90 d compressive strength retention rate of 65%, while the waterborne epoxy–graphene composite system only retained 39.7% of its compressive strength at 90 d due to negative synergistic effects. The enhanced durability of the waterborne-epoxy-modified cement is attributed to the formation of a continuous polymeric film, which acts as a protective barrier against CO₂ penetration. This study provides valuable insights for the design of CO₂-resistant cement systems in CCUS-EOR environments.

Neat well cement experience significant strength retrogression at high temperatures above 110 °C, especially at approximately 150 °C. To reveal the mechanism of performance degradation and guide the preparation of high-performance cement, we investigate the hydration process, mechanical behavior, and fracture process for well cement at the temperature of 150 °C based on molecular dynamics simulations and experiments. From triaxial pressure tests and Brazilian splitting tests, the strength, elastic modulus, and Poisson’s ratio of well cement decrease drastically with temperature increases from 80 °C to 150 °C. According to XRD, TG/DTG/DSC, and SEM, the hydration degree is insufficient, and larger pores exist in the microstructures. As the main binding phase of well cement, the mechanism of calcium silicate hydrates (C-S-H) influenced by curing temperatures is investigated through molecular dynamics simulations. C-S-H with calcium/silicon ratios (C/S) of 1.1 and 1.8 are simulated in the aqueous and solid states to investigate precipitation and mechanical behaviors. By reducing the C/S ratio to 1.1, the strength rebounds to a certain extent, and the adequacy of the hydration degree improved. It is found from the polymerization process that the increasing temperature promotes the polymerization rate, which is higher with C/S = 1.8 than that of 1.1. However, an increase in the C/S ratio will lead to a decrease in bridging oxygen content, thus a lower polymerization degree. The fracture simulations of C-S-H gels at different temperatures indicate that the failure of the C-S-H structure is mainly attributed to the disassembling of the calcium oxygen layers. With a higher temperature, there are fewer Ca-O bonds breaking, thus less strain energy consumed, resulting in worse performance. The elasticity of C-S-H, including Young’s and shear moduli, also exhibits certain degradations at a higher temperature. The elastic behavior of C-S-H with a low C/S ratio is generally higher than the high C/S.

Under the global carbon-neutrality target, the technology of carbon capture, utilization, and storage-enhanced oil recovery (CCUS-EOR) faces a severe challenge of carbonation-induced degradation of oil-well cement in harsh downhole environments. Traditional cement suffers serious structural failure under high-temperature and high-pressure CO₂ conditions, whereas single-nanoparticle or polymer modification cannot meet long-term safety requirements. Meanwhile, the comparative study between the “matrix modification strategy” and the “cement system replacement strategy” is still insufficient under real CCUS-EOR conditions. In this study, experimental investigations including macroscopic performance testing, phase analysis, and multi-scale microstructural characterization were conducted. This study systematically evaluates the carbonation resistance of polyaniline@titanium dioxide-modified cement (P@T) and calcium aluminate phosphate cement (CAP). The results show that the carbonation resistance follows the descending order: CAP > P@T > silica-fume-containing Class G oil-well cement (PT). CAP seems to demonstrate a potential “corrosion-induced densification” effect. After 90 days of corrosion, its compressive strength increases to 62.5 MPa, and its permeability decreases to 13.3% of the initial value, indicating continuously improved performance. P@T indicates the possible decoupling of high carbonation degree (CaCO₃ content of 25.26%) and microstructural stability through a structural regulation mechanism of “physical filling–homogeneous distribution of carbonation products”. In contrast, PT undergoes complete structural failure after 60 days. This study fills a gap in comparative evaluation between modification and replacement schemes, reveals the multi-scale structural regulatory effects of P@T and the intrinsic stability of CAP, and provides two reliable cement solutions—“modification enhancement” and “system replacement”—for CCUS-EOR environments. The scientific validity is demonstrated through multi-scale characterization, offering key theoretical and technical support for ensuring long-term wellbore integrity.

Carbon capture, utilization and storage (CCUS) is a key technology for carbon neutrality and efficient oilfield development. Oil well cement suffers serious carbonation degradation under high-temperature, high-pressure and high CO₂ partial pressure environments, leading to well cementing failure. In this study, TA@Gr-OTES (TGO) composite was prepared by surface grafting modification, and a hydrophobic oil well cement system suitable for CCUS was constructed. The anti-carbonation performance was tested under simulated formation conditions (130 °C, 25 MPa, CO₂ partial pressure 7 MPa). Results show that TGO-modified cement maintains stable hydrophobicity, with a 60-day compressive strength attenuation rate of only 6.7%, and its permeability and porosity are much lower than those of plain cement. TGO inhibits deep carbonation and corrosion product leaching, preserves hydration products, and reduces defect volume. The potential triple mechanisms of a hydrophobic barrier, graphene physical shielding and matrix densification effectively blocks CO₂ intrusion. This study provides theoretical and technical support for long-life cementing materials in CCUS wells.