Yinping Cao

Staged fracturing of horizontal wells is a core process in the development of unconventional shale oil and gas. Erosion damage to casing perforation holes caused by high-velocity, sand-laden fracturing fluid can easily lead to flow distribution imbalances in the perforation clusters and insufficient fracture propagation in the reservoir. These erosion patterns also affect the interpretation of microseismic events in the geophysical monitoring of hydraulic fractures. Currently, there remains a lack of systematic research on the mechanisms of casing perforation hole erosion, particularly regarding the influence of perforation angles on erosion patterns. Based on two-phase flow theory, this study employs a coupled CFD-DPM numerical method, combining the RNG k-ε turbulence model with the Oka erosion model to establish a numerical model of casing perforation hole erosion. It systematically analyzes the influence of perforation angle, fluid velocity, sand content, and proppant particle size on the erosion characteristics of the perforation holes. The results indicate that perforation hole erosion damage is concentrated on the wall surfaces on both sides of the main flow direction; the erosion rate exhibits an approximately linear increase with rising flow velocity and sand content; it shows an asymmetric ‘tooth-like’ variation with perforation angle, with the most severe erosion occurring at 30° and 150° and the least severe at 90°. These findings provide a theoretical basis for optimizing shale gas horizontal well fracturing operations and designing casing protection.

This study experimentally investigates the evolution of natural frequencies of premium threaded connections under varying interface contact stiffness, aiming to establish a non-destructive vibration-based method for evaluating sealing contact conditions. The sealing interface features a sphere-on-cone configuration, and Hertzian contact theory is used to derive the contact pressure distribution, which shows a nonlinear increase in peak pressure with increasing normal load. Modal experiments were conducted under free–free boundary conditions using an impact hammer on a Φ88.9 mm × 6.45 mm P110 premium threaded connection. Three make-up torque levels (4081 N·m, 4393 N·m and 4691 N·m) were applied to create distinct contact states, and the first five orders of natural frequencies were extracted from the measured acceleration responses, using frequency response function (FRF) analysis with peak-picking identification. The results demonstrate that natural frequencies increase significantly with make-up torque, following a power-law relationship f = αT^β with R² > 0.97 for the first three modes. A critical torque range of 4200–4400 N·m is identified, below which frequencies rise sharply and above which the increase slows due to contact stiffness saturation. Lower-order modes are more sensitive to contact stiffness variations than higher-order modes. The findings confirm that natural frequency can serve as an effective non-destructive indicator for assessing tightening quality and detecting loosening in premium threaded connections, offering practical guidance for torque optimisation and structural health monitoring in oilfield operations. Although only three torque levels are used, the observed trend is physically consistent with contact mechanics theory and widely reported joint stiffening behavior. Therefore, the fitted relationship should be interpreted as a physically guided empirical model rather than a purely statistical fit.

During gas storage injection and production operations, high-speed gas flow continuously impacts the completion string, easily triggering strong vibrations and leading to fatigue failure, which seriously threatens downhole safety and production continuity. To address this issue, this study establishes a transient finite element model of a 30 m section of Φ88.9×6.45 mm P110 tubing under 40 MPa high-pressure conditions based on two-way fluid-structure interaction (FSI) theory, and systematically conducts a detailed finite element simulation analysis of the string’s vibration characteristics. Finite element calculation results indicate that fluid pressure is the dominant factor causing significant radial expansion in the central section of the string, while wellhead and wellbottom constraints lead to high-risk stress concentration at the ends. Under thin-wall conditions, finite element simulations show that deformation and stress increase by 53% and 51%, respectively, compared to standard conditions. Under thin-walled, high-pressure conditions at 60 MPa, finite element method simulations reveal that deformation and stress increase by 53% and 51%, respectively, compared to the 40 MPa condition. Under the same high-pressure environment, two-way FSI consistently results in higher radial deformation and stress values in the tubular string compared to one-way FSI. Based on these finite element numerical results, the study provides critical theoretical support for the safety design and risk mitigation of gas storage tubular strings.

In CO₂ flooding technology, the injection tubing string is prone to intense fluid–structure interaction (FSI) vibrations and water hammer effects during transient start-up and shutdown processes, which seriously threaten injection safety. This study is based on a four-equation FSI model and employs the method of characteristics (MOC) and numerical simulations to analyze the dynamic responses of fluid velocity, pressure, axial vibration velocity, and additional stress in the tubing string during start-up and shutdown processes. The results indicate that the most severe vibrations occur within 12 s after pump start-up, with a significant increase in the amplitude of axial additional stress. Increasing the injection rate leads to a notable rise in the peak water hammer pressure. Extending the shutdown time effectively reduces impact loads. This research provides an important theoretical basis for the safe design and operational control of the CO₂ injection wells. It is recommended to adopt operational strategies such as low rate, slow start-up, and reasonably extended shutdown times to mitigate vibration hazards.

To address wellbore integrity issues (especially casing strength concerns) of oil and gas wells threatened by overburden movement in coal mine goafs, this study takes a gas well in the goaf of Yanchang Gas Field as the research object. Using FLAC^3D 7.0 software, a 3D coupling model of “casing-cement sheath-formation-goaf” is established to systematically analyze the effects of goaf presence, convergence criteria, casing wall thickness/layer count, and cement slurry density on casing stress while conducting wellbore structure optimization. Key research results are as follows: (1) Overburden movement concentrates the maximum casing stress near the goaf, with the surface casing stress being 7–8 times higher than that in the absence of a goaf, serving as the core object of stress control; (2) A convergence criterion of 10⁻⁴ balances calculation accuracy and efficiency, where the maximum Von Mises equivalent stress of the surface casing differs by only 0.98% compared with that under a convergence criterion of 10⁻⁶; (3) Increasing casing layers is more effective than thickening walls or upgrading steel grade: three-layer casing reduces surface casing stress by 23.4% compared with two-layer casing, and all casing safety factors meet the standards; (4) The casing stress is minimized when the cement slurry density is 1800–1900 kg/m³ (with a minimum of 325.79 MPa), while excessively low or high density will lead to increased stress. The optimized wellbore structure provides key references for the design of gas wells in goaf areas.

A study was conducted on the mechanical behavi or of the completion string in a 10,000 m ultra-deep well from western China’s oilfields to identify the causes of plastic failure in the string. This article analyzes the interaction between fluid and tubing in high-pressure and high-production gas wells by establishing a fluid structure coupling four-equation model. Through fatigue tests, it was found that P110 tubing material has a stress amplitude related ratchet effect, revealing the softening characteristics of tubing material. Through case analysis, the fatigue of the entire wellbore was analyzed, and it was shown that the fatigue hotspot is concentrated near the neutralization point, and stress concentration under high-production and low-production conditions leads to the degradation of tubing material performance under fatigue load. After continuous service for 30 days under high-production and low-production conditions, the entire wellbore section exhibited a softening phenomenon, and the yield strength began to decrease below 4349 m and 4324 m well depths, respectively. The safety factor of the entire wellbore section decreased. Within 284 days of production, the fatigue damage of the entire wellbore section was less than 5%, and the remaining yield change and material softening of the tubing string were negligible. However, there was an impact load during the lifecycle, which caused severe fluctuations in the wellbore safety factor and was the main cause of tubing string fracture. Subsequent research should integrate diverse well cases exhibiting varying production parameters to establish a statistically robust predictive framework for safety factor variations.

Tubular string temperature and pressure are important parameters in string mechanics analysis. Thus, accurately calculating temperature and pressure in the injection process is fundamental for analyzing the tubular string mechanics of CO₂ injection wells. Based on the S-W equation of state and Vesovic models, we modeled the physical properties of CO₂. Then, based on the physical properties of CO₂, combined with the theory of heat transfer and three conservation laws, a temperature–pressure coupling model of a tubular string was established. Lastly, the temperature and pressure field distributions of the G66X1 well were determined using the alternating iteration method. According to a comparison of the established model and the actual data, the maximum error in predicting temperature was 4.1% and the maximum error in predicting pressure was 2.3%; thus, the model exhibits a high level of accuracy. In the final section, the model was used to study the influence of injection temperature on the tubular string temperature and pressure field distribution. Next, we studied the influence of the injection time, displacement, and pressure on the bottom hole temperature. This study provides a reference for predicting the wellbore temperature and pressure in CO₂ injection wells.

To investigate corrosion and resulting changes in the sealing performance of premium connections in corrosive CO₂ environments, we carried out a simulation analysis of their secondary current distribution and structural mechanics based on multi-physics field coupling. A finite element calculation model of Ф88.9 mm × 6.45 mm taper–taper premium connections (steel grade P110) was established using COMSOL6.0 general software. By analyzing corrosion laws under different environmental parameters, five internal pressures and tensile displacements were set. We simulated premium connections under different operating conditions using a secondary current distribution module. To investigate the distribution of the corrosion current density in premium connections under different operating conditions, the sealing performance before and after corrosion was quantitatively evaluated using a seal strength index. The results show that the current density is higher at the torque shoulder of the premium connections, which is more susceptible to damage. As the internal pressure increases, the current density in the inner wall of the column increases, and on the threads, the current density is highest at the rounded corners of the root of the thread, which is also more likely to be damaged. Under different internal pressures, although the sealing strength of the premium connections meets the sealing criterion, the corroded ones show a significant reduction in sealing performance. The results of this study provide a reliable theoretical basis for research on sealing premium connections in corrosive environments.

The premium connection is an important section of the tubing column. Under intricate downhole conditions, axial vibration generates alternating loads that cause energy dissipation between the sealing surfaces of the premium connection, reducing sealing performance. To investigate this issue, the mutual conversion process of sticking, slipping, and macroscopic slipping stages between the sealing surfaces of the premium connection under axial loads must be assessed. In this study, a finite element analysis model of a taper–taper Φ88.9 mm × 6.45 mm P110 premium connection is developed based on the discrete Iwan model’s ontological relationship, and the sealing surface’s force–displacement hysteresis curve is obtained. The equivalent Iwan model for this particular premium connection is constructed by discretizing the hysteresis curve and identifying the model’s four sets of parameters. The correctness of the parameter identification method of the equivalent Iwan model is verified by comparing and analyzing the similarity of the two models. The energy dissipation in the sealing surfaces of the premium connection for different working conditions under dynamic loading is analyzed. This study reveals that the area similarity of the hysteresis curves of the two models is more than 92%, while the positional error is less than 2%. The sealing surface displacement amplitude of the premium connection is between 0.04 mm and 0.07 mm, while the sealing surface energy dissipation increases linearly, which may lead to a decline in sealing performance.

Coiled tubing has been widely used in oilfield development because it can significantly improve oil well productivity and recovery efficiency. However, with the increase in fracturing, drilling, and sand-washing operations, the erosion of coiled tubing walls caused by solid particles has become one of the main failure modes. To accurately predict the erosion rate of coiled tubing, this study studied the influence law of erosion rate through experiments, screened the main influencing factors of erosion rate by grey relational analysis (GRA), and established a back-propagation neural network (BPNN) model optimized by the sparrow search algorithm (SSA) to predict the erosion rate. The results show that the main influencing factors for coiled tubing erosion rate are impact velocity, impact angle, and sand concentration. In addition, the SSA-BPNN model shows a high goodness of fit (R) and a good fit with the experimental data. The SSA-BPNN model underwent standard statistical validation tests, effectively predicting the erosion rate of coiled tubing with a high coefficient of determination and low errors, demonstrating a robust consistency between predicted and actual values. This study is of great significance to oilfield engineers, pipeline designers, and oilfield developers, and provides effective support for optimizing oilfield development and pipeline maintenance. The main users include oil companies, engineering consulting institutions and related industry personnel, and may also attract the interest of scientific research institutions and academia, providing a useful reference for the technological progress of the oil industry.