Yujie Bai

Sucker rods operate under long-term cyclic loading while being exposed to produced fluids, making corrosion–fatigue damage an important integrity concern in rod-pumped wells. This study applied a field-scale multi-source evidence framework to produced-fluid samples from 16 sucker-rod failure wells and 16 corresponding failed rods from a Daqing oil production plant. Ionic-composition analysis, SEM/EDS, bulk chemical analysis, metallography, axial tensile testing, exploratory fatigue testing, and field rod-string load analysis were integrated. The produced fluids exhibited an HCO₃⁻-dominated ionic background, with average HCO₃⁻, Cl⁻, and SO₄²⁻ concentrations of 345.7, 0.129, and 2.55 mg/L, respectively. Representative fracture surfaces contained corrosion pits, corrosion products, secondary cracks, and lamellar or step-like features, while local EDS analyses showed substantial O, together with detectable Cl and S. Residual tensile strength varied markedly among rods with different service histories. The exploratory fatigue dataset exhibited a non-monotonic stress–life response and, with only one specimen per source-rod/loading-level combination, was insufficient to establish a conventional S–N relationship or fatigue limit. For well X9-D2-149, the actual fracture location did not coincide with the position of maximum calculated nominal axial stress. Integration of the field, microstructural, fractographic, mechanical, and loading evidence supports a representative damage pathway from localized corrosion and pit formation to crack initiation, cyclic propagation, crack coalescence, and final rapid fracture.

Gas-lift deliquification in multiphase wells can be hindered by wall-adhered droplets and persistent liquid films, increasing hydraulic resistance and reducing liquid transport. Here, a SiO2/epoxy superamphiphobic coating was developed to regulate the phase-specific near-wall transport of water and crude-oil droplets under upward gas flow. PFOTS 1H,1H,2H,2H-perfluorooctyltrichlorosilane (PFOTS) reduced surface energy, while 3-glycidoxypropyltrimethoxysilane (KH-560) promoted interfacial coupling between SiO2 particles and the epoxy matrix, producing a hierarchical fluorinated surface. The coating exhibited static contact angles of 155° for water and 153° for crude oil, with contact-angle hysteresis below 9°. Experimentally measured advancing and receding contact angles were incorporated into the level set wall-wetting condition to represent macroscopic contact-angle hysteresis. Shear-rate-dependent constitutive models were further introduced for heavy and extra-heavy crude oils to account for non-Newtonian rheology. Simulations showed that the normalized near-wall migration metric for water increased from 1.22% on bare steel to 1.87% on the coated surface, while the recalculated values for heavy and extra-heavy crude oils were 0.98% and 0.81%, respectively. The results indicate that reduced interfacial retention promotes droplet migration, whereas shear-rate-dependent rheological resistance becomes increasingly important in high-viscosity oils. These findings highlight the coupled roles of wall wettability and liquid rheology in near-wall droplet transport. Simultaneous oil–water coexistence, competitive wetting, and emulsification remain outside the present scope.

With the continuous decline in easily recoverable reserves of conventional oil and gas, the focus of oil and gas exploration and development has gradually shifted toward complex reservoirs, such as low-permeability, tight, high-temperature and high-pressure (HTHP), and strongly heterogeneous reservoirs. Such reservoirs are characterized by complex pore–throat structures, poor seepage capacity, extreme temperature and pressure conditions, and strong heterogeneity. Traditional acidizing technologies face multiple challenges, including short effective penetration distances, system instability at high temperatures, uneven stimulation, and a tendency to induce secondary formation damage, making it difficult to meet the requirements for highly efficient reservoir stimulation. This paper systematically analyzes the petrophysical properties and acidizing challenges of four typical types of complex reservoirs. It reviews the reaction mechanisms, research and development progress, and reservoir adaptability principles of six acid systems, and elaborates on the application value of molecular simulation technology in acid–rock reaction analysis, formulation optimization, and injection regulation. The review indicates that, under extreme operating conditions, existing technologies still suffer from inadequate system stability, limited deep mass transfer, and environmental concerns. Future research should deepen the understanding of multi-scale acid–rock reaction mechanisms, develop composite acid systems tolerant to extreme conditions, and drive the development of acidizing technologies toward refinement and intelligentization.

Sucker rods operate under long-term cyclic loading while exposed to corrosive produced fluids, making corrosion–fatigue damage a major integrity concern. This study examined produced-fluid samples from 16 wells with sucker-rod failures and 16 corresponding failed rods from a Daqing oil production plant using ionic-composition analysis, SEM/EDS, bulk chemical analysis, metallography, axial tensile tests, exploratory fatigue tests, and field load analysis. The fluids were HCO₃⁻-dominated, with average HCO₃⁻, Cl⁻, and SO₄²⁻ concentrations of 345.7, 0.129, and 2.55 mg/L, respectively. Representative fracture surfaces showed corrosion pits, corrosion products, secondary cracks, and lamellar or step-like morphologies, while corroded microregions were enriched in O and contained detectable Cl and S. Local discontinuities, including decarburization, inclusions, and scratches, were also observed. Residual tensile strength varied substantially with service history, and exploratory fatigue results showed considerable scatter. The actual field fracture location did not coincide with the maximum nominal axial stress. The combined evidence supports a representative sequence of localized corrosion and pit formation, crack-susceptible region development, microcrack initiation, cyclic crack propagation, crack coalescence, loss of effective load-bearing area, and final rapid fracture.

The phase behavior regulation of microemulsions is crucial for enhancing oil recovery (EOR) efficiency. This study aims to investigate the effects of surfactant incorporation on oil-water interfacial properties, interfacial thickness, microscopic adsorption, and emulsion stability. Focusing on the interfacial region of microemulsions, we characterized the emulsification behavior, water separation rate, and the evolution of the interfacial microstructure for different systems. The results indicate that under the experimental conditions, System #3 (heavy alkylbenzene sulfonate: hydroxysultaine = 7:3) exhibits the optimal emulsification efficiency and stability, characterized by minimal water separation and the formation of densely packed spherical oil droplets at the interface. Microscopic analysis reveals that System #3 significantly enhances the mechanical strength of the interfacial film by strengthening interfacial adsorption, inhibiting molecular diffusion, and broadening the interfacial transition zone. Simulation results demonstrate that emulsification performance is comprehensively regulated by crude oil composition, surfactant concentration, and temperature. Within a specific concentration range, longer alkane carbon chains and higher temperatures contribute to superior emulsification effects. This study elucidates the dynamic evolution mechanism of the emulsification process at the molecular level, providing theoretical support for the optimization and molecular design of surfactant systems for EOR.

Acid flowback fluids impose substantial economic burdens and severe secondary pollution risks, while conventional nanofluid-based enhanced oil recovery (EOR) systems are plagued by prohibitive preparation costs and inherent scalability bottlenecks. Herein, a novel cost-effective synergistic nano-surfactant oil displacement system is constructed by extracting nanoscale fluorosilicate particles directly from oil well acid flowback fluids. The synergistic effects of these nanoparticles with anionic, nonionic, and zwitterionic surfactants were systematically evaluated. It was found that weakly positively charged fluorosilicate nanoparticles form composite interfacial films composed of a surfactant monolayer and solid particles via electrostatic adsorption with negatively charged anionic surfactants (SDBS, petroleum sulfonate). These composite films reduce the oil-water interfacial tension by one order of magnitude and significantly enhance emulsion stability. Microscopic visualization experiments confirmed that the formulated system effectively overcomes capillary resistance in porous media and displaces residual oil trapped in micropores through the dual mechanisms of elastic compression and interfacial shear. Core flooding experiments further demonstrated that the irreversible adsorption of nanoparticles at the oil-water interface induces a sustained Jamin effect in emulsion droplets, which effectively blocks preferential water flow channels, redirects displacing fluids into low-permeability zones, and results in an 8.3% increase in oil recovery factor. In contrast, nonionic surfactants exhibited no significant synergistic effects with the nanoparticles, while zwitterionic surfactants even deteriorated the oil displacement performance.

As oil and gas development increasingly targets low and ultra-low permeability reservoirs, conventional recovery techniques often prove insufficient for mobilizing residual oil. Surfactant flooding, a key chemical enhanced oil recovery (EOR) technology, thus requires careful system optimization and mechanistic investigation. This study focuses on low-permeability reservoirs in the Changqing Oilfield, evaluating three surfactant systems—YHS-Z1 (a 7:3 mass ratio blend of hydroxypropyl sulfobetaine and cocamide), YHS-Z2 (a polyether carboxylate, a nonionic-anionic composite) and a middle-phase microemulsion system (Heavy alkylbenzene sulfonate and hydroxysulfobetaine were combined with a mass ratio of 7:3)—through a series of experiments including interfacial tension measurement, contact angle analysis, static and dynamic oil displacement tests, as well as emulsion transport/retention index assessments, to comprehensively characterize their oil displacement properties. Based on the experimental data, this study constructed four classical regression models: Ridge Regression, Random Forest (RF), Gradient Boosting Regression (GBR), and Support Vector Regression (SVR), and conducted a comparative analysis of their predictive performance. The results demonstrate that the Random Forest (RF) model achieved the optimal prediction performance, with a Mean Absolute Error (MAE) of 1.8245, a Mean Absolute Percentage Error (MAPE) of 4.78%, and a coefficient of determination (R²) of 0.9428 on the training set. Further analysis using the SHapley Additive exPlanations (SHAP) algorithm revealed that the retention index is the primary global factor (accounting for 49.79% of the variance), while significant intergroup differences exist in the primary factors across different surfactant systems. Concurrently, single-factor and multi-factor sensitivity analyses were conducted to elucidate synergistic effects and threshold behaviors among parameters. The optimal parameter combination, identified via a random search method, achieved a predicted recovery factor of 45.61%, representing a 6.57% improvement over the highest experimental value. This study demonstrates that machine learning methods can effectively identify the dominant factors in oil displacement and enable synergistic parameter optimization, thereby providing a theoretical foundation for the efficient development of surfactant flooding in low-permeability reservoirs.

The wetting behavior of multiphase fluids in reservoir rocks significantly affects the recovery efficiency of shale reservoirs. This study systematically investigated the mechanisms by which multiple gases influence shale wettability. The results showed that HF and HCl dissolve in water to form an acidic environment, which erodes the rock surface and exposes polar hydrophilic sites, thereby significantly enhancing hydrophilicity. CH4 and H2S reduce interfacial tension through adsorption onto the rock surface, thereby improving shale hydrophilicity. However, H2S also reacts with iron-bearing minerals in the rock to form hydrophobic FeS, which weakens hydrophilicity. CO2 generates a hydrophilic surface via hydrolysis; whereas, in the oil–water coexisting systems, its miscibility increases hydrocarbon activity, raises the water–phase contact angle, and consequently reduces hydrophilicity. All five gases increase the wetting angle of the oil phase significantly. In a single oil–phase system, the degree of influence from largest to smallest is HF, HCl, CH4, CO2, and H2S. In the oil–water coexisting system, due to the difference in water solubility, the degree of influence decreases from largest to smallest, which is HF, H2S, HCl, CH4, and CO2. Elevated temperatures generally increase the oil–phase contact angle. Increased pressures strengthen the gas–phase impact on contact angles primarily by enhancing gas molecule density and promoting dissolution and adsorption processes.