Shunbei Oilfield is a fractured carbonate reservoir with complex geological structures that are influenced by fault movements and prone to collapse and leak incidents. Precisely predicting leakage pressure is crucial for conducting fracturing operations in the later stages of production. However, current fracture-related leakage pressure prediction models mostly rely on statistical and mechanical methods, which require the consideration of factors such as fracture aperture and parameter selection, thereby leading to limitations in prediction efficiency and accuracy. To enhance the accuracy of reservoir leakage pressure prediction, this study leverages the advantages of artificial intelligence methods in dealing with complex nonlinear problems and proposes an optimized Long Short-Term Memory (LSTM) neural network prediction approach using the Particle Swarm Optimization (PSO) algorithm. Firstly, the Spearman correlation coefficient is used to evaluate the correlation between nine parameter features and leakage pressure. Subsequently, an LSTM network framework is constructed, and the PSO algorithm is applied to optimize its hyper-parameters, establishing an optimal model for leakage pressure prediction. Finally, the model’s performance is evaluated using the Coefficient of Determination ($R^2$), Root Mean Squared Error ($RMSE$), and Mean Absolute Percentage Error ($MAPE$). The evaluation results demonstrate that the PSO-optimized LSTM model achieved an $R^2$ of 0.828, $RMSE$ of 0.049, and $MAPE$ of 3.2, all of which outperformed the original model. The optimized LSTM model showed an average accuracy approximately 12.8% higher than that of the single LSTM model, indicating its higher prediction accuracy. The verification results from multiple development wells in this block further confirmed that the deep learning model established in this study surpassed traditional methods in prediction accuracy. Consequently, this approach is beneficial for drilling engineers and decision-makers to plan drilling operations more effectively and achieve accurate risk avoidance during the drilling process.

High-speed fluid-carried sand particles pose a significant challenge to oil well screen pipes, leading to sand control failure and adversely affecting the well's production and recovery rates. This research targets the commonly used metal mesh screen pipe in oil well sand production and establishes a full-sized three-dimensional structure model. A fluid-solid coupling of discrete particle flow numerical simulation algorithm is incorporated to formulate a novel method for predicting the screen pipe's erosion life. This method provides a solution to the complex task of predicting the pipe's lifespan under oil sand fluid erosion. The analysis elucidates the impact of sand particles on the velocity distribution and erosion rate of the metal mesh at varying velocities, facilitating the prediction of the mesh screen pipe's erosion life. Key findings reveal that the velocity and erosion rate vary across the different layers. The first layer screen experiences velocity and erosion rates that are 3.6-3.76 times and 2.45-2.50 times, respectively, higher than those at the inlet. The second layer screen undergoes velocity and erosion rates 2.32-2.43 times and 1.04-1.06 times, respectively, higher than those at the inlet. Erosion failure primarily occurs in the first layer screen due to velocity expansion instigated by the screen tube's structure. The discrete flow numerical simulation method proves valuable in predicting the mesh screen's erosion life at different flow rates, with a maximum error of 6.38% when compared with field monitoring life values. This method introduces a new technical approach to predicting the life span of metal mesh screens in oil wells. The study concludes by suggesting measures to extend the screen pipe's lifespan, thereby enhancing oil recovery.

Advancements in drilling technology are pivotal to optimizing the production and sustainability of oil and gas wells. One of the emerging innovations is the application of a specialized fluid known as “Fuzzy-ball” fluid. This paper comprehensively reviews the historical evolution and advancements in the utilization of fuzzy-ball fluid in drilling and well-repair processes. Fuzzy-ball fluid has been discovered to bolster a formation’s pressure-bearing capabilities and systematically augment resistance against oil, gas, and water flow. These attributes have been instrumental in the phased integration of fuzzy-ball fluid into procedures aiming to enhance production in oil and gas wells. This paper bridges the knowledge gap in the industry regarding the application of fuzzy-ball fluid, thereby circumventing the challenges of inadequate understanding and suboptimal designs. However, the study acknowledges the potential limitation of information loss despite the extensive data collection from diverse sources, such as articles, patents, and reports. As a future direction, this paper emphasizes the need for a more encompassing and critical evaluation of fuzzy-ball fluid’s performance and applications. This will enable a more informed decision-making process, fostering the expanded use and understanding of this fluid’s mechanism within the industry.

To meet the escalating demand for oil and gas exploration in microporous reservoirs, it has become increasingly crucial to develop high-performance plugging materials. Through free radical grafting polymerization technology, a carboxymethyl chitosan grafted poly (oligoethylene glycol) methyl ether methyl methacrylate acrylic acid copolymer (CCMMA) was successfully synthesized. The resulting CCMMA exhibited thermoresponsive self-assembling behavior. When the temperature was above its lower critical solution temperature (LCST), the nanomicelles began to aggregate, forming mesoporous aggregated structures. Additionally, the electrostatic repulsion of AA chains increased the value of LCST. By precisely adjusting the content of AA, the LCST of CCMMA could be raised from 84.7 to 122.9 °C. The rheology and filtration experiments revealed that when the temperature surpassed the switching point, CCMMA exhibited a noteworthy plugging effect on low-permeability cores. Furthermore, it could be partially released as the temperature decreased, exhibiting temperature-switchable and self-adaptive plugging properties. Meanwhile, CCMMA aggregates retained their reversibility, along with thermal thickening behavior in the pores. However, more detailed experiments and analysis are needed to validate these claims, such as a comprehensive study of the CCMMA copolymer’s physical properties, its interaction with the reservoir environment, and its performance under various conditions. Additionally, further studies are required to optimize its synthesis process and improve its efficiency as a plugging material for oil and gas recovery in microporous reservoirs.

Offshore oil field loose sandstone reservoirs have high permeability. However, during the water injection process, water injection blockage occurs, causing an increase in injection pressure, making it impossible to continue injecting water on site. Current research mainly focuses on the factors causing water injection blockage, with less attention given to the blockage locations and the pressure increase caused by water injection. There is a lack of research on the change in the law of injection capacity. This paper establishes a simulation experiment for water injection blockage that can accommodate both homogeneous and heterogeneous cores. The experimental core is 1 m long and capable of simulating the blockage conditions in the near-well zone during water injection, thereby analyzing the core blockage position and blockage pressure. The study clarifies the influence of water quality indicators, heterogeneity, and core length on the blockage patterns in reservoirs during water injection. The research findings are as follows: I. The reservoir blockage samples were characterized using scanning electron microscopy (SEM), casting thin sections, and X-ray diffraction (XRD) analysis. The results indicate that the main factors causing blockage are clay, silt, and fine particulate suspensions, with the fine particles mainly consisting of hydrated silicates and alkali metal oxides. The primary cause of blockage in loose sandstone is identified as the mechanism of migration and accumulation of clay, fine rock particles, and suspended matter in the injected water. II. By monitoring pressure and permeability changes in the core flooding experiments, the impact of reservoir heterogeneity on water injection capacity was evaluated. The evaluation results show that the blockage locations and lengths in heterogeneous cores are twice those in homogeneous cores. III. For heterogeneous reservoirs, if the initial permeability at the inlet is lower than in other segments of the core, significant blockage resistance occurs, with the final resistance being 1.27 times that of homogeneous cores. If the initial permeability at the inlet is higher than in other parts, the final blockage resistance is close to that of homogeneous cores. This study provides theoretical support for the analysis of blockage locations and pressures in loose sandstone water injection and offers technical support for the design of unplugging ranges and pressures after blockage in heterogeneous formations. At the same time, it provides a theoretical basis for selecting the direction of acidizing after blockage occurs in loose sandstone.

During coalbed methane dewatering and production, variations in the dip angle of coal seam create uneven V-shaped grooves in horizontal wellbores. To investigate the critical velocity and transportation of coal particles under different pipeline structures and operating conditions, this study combines experiments to analyze pressure fluctuations and flow pattern changes in a gas–liquid–solid three-phase system during the early dewatering stage. The intrinsic transport mechanism and critical discharge velocity of coal particles are identified. Additionally, simulations are used to calculate the coal particle deposition thickness and transportation efficiency under various conditions, providing direct guidance for field operations. Results show that as the gas mass flow rate increases, the periodic pressure differential in the V-shaped pipe increases, and the flow pattern transitions from the slug flow to the intermittent flow. Changes in the inclination angle increase the critical velocity for coal particles and accelerate flow pattern transitions, with a direct shift to plug flow at 35°. A reduced fluid velocity and increased coal particle concentration significantly increase deposition thickness, particularly in pipes at 45°. Moreover, the transport efficiency at a velocity ratio of 0.4 is only 86%, increasing with velocity ratio in a power function while decreasing exponentially with inclination angle under certain conditions. Consequently, matching appropriate fluid velocity with the pipeline design and discharged coal particle concentration can effectively mitigate horizontal well blockage.