Liguo Zhong

High-temperature steam flow in unconsolidated sandstone triggers complex coupling among hydrodynamic motion, interfacial mass transfer, and mineral dissolution, which further reshapes pore networks and alters fluid transport properties. However, the reactive–seepage coupling mechanism governing mineral dissolution-induced pore network evolution under high-temperature steam flow remains poorly understood. This work conducts sand-packed flow simulation experiments under formation compaction conditions with varied particle geometric features and steam parameters. Scanning electron microscopy and energy-dispersive x-ray spectroscopy were used to characterize microscale grain and pore variations. The results show that grain evolution is jointly controlled by hydrodynamic shear and thermal stress. The overall dissolution rate depends on both particle and flow conditions, while the maximum dimensionless dissolution amount is governed solely by particle geometry, reaching a peak of 4.10% at a grain size of 0.10 mm. A predictive model combining boundary-layer mass transfer theory and Noyes–Whitney kinetics is established, with a high fitting accuracy of R2≥0.97. This work reveals the fundamental coupling rules of flow, mass transfer, and solid reaction in granular porous media and provides theoretical support for evaluating pore evolution during high-temperature fluid displacement.

Hydraulic sand-jetting perforation is widely employed in oil and gas reservoir stimulation and downhole operations, where the nozzle profile design is crucial for enhancing jet energy utilization and improving perforation quality. However, traditional nozzle design often relies on empirical methods and trial-and-error approaches, making it challenging to achieve an optimal contour that balances high efficiency and low energy loss. Against this background, this study focuses on the working conditions of hydraulic sand-jetting perforation and utilizes the Euler–Lagrange (EL) model in combination with the Shooting method to theoretically model and numerically solve for the optimal converging nozzle profile. By formulating a variational optimization problem and incorporating comparisons of turbulent kinetic energy, analyses of pressure and velocity distributions, as well as comparative simulations of different nozzle contours (including a straight conical nozzle, a hyperbolic nozzle, a Vitoshinsky-profiled nozzle, and the EL-based nozzle), the results show that the Vitoshinsky and hyperbolic nozzles achieve increases in outlet velocity of approximately 6.81% and 5.48%, respectively, compared to the straight conical nozzle. In contrast, due to its initial expansion followed by contraction, the EL nozzle experiences a slight reduction in outlet velocity (around 5.82%) while maintaining a more stable internal flow field and a shortened local acceleration zone. This configuration facilitates more rational energy distribution and reduces turbulence-induced losses. The findings provide feasible theoretical and engineering guidance for nozzle profile optimization, laying a foundation for improving the efficiency of hydraulic sand-jetting perforation and advancing nozzle design.

Hydraulic sandblasting perforation guns play a critical role in well completion and productivity enhancement operations in oil and gas wells, as their performance and service life directly affect perforation efficiency, reservoir integrity, and downhole operational safety. Drawing on a comprehensive review of the existing literature, this paper systematically summarizes recent research progress on surface erosion, high-pressure leakage, and vibration-induced fatigue in perforation guns. Regarding erosion wear, we discuss the mechanisms and preventive strategies influenced by abrasive particle flow characteristics, material selection, and coating applications. In the field of high-pressure leakage, we analyze the key factors of seal failure, structural deformation, and material degradation that contribute to leakage formation, and we provide improvement measures involving seal structure optimization, enhanced material properties, and real-time monitoring technologies. Concerning vibration and fatigue, we elucidate the multi-factor coupling mechanisms of failure—encompassing fluid–solid interactions, cavitation impacts, and stress concentration—and outline mitigation strategies through structural redesign, material reinforcement, and fluid dynamic control. Furthermore, the paper anticipates the future trends of intelligent fault diagnosis and predictive maintenance, including multi-sensor data fusion, AI-driven predictive models, and digital twin technologies. Overall, the integrated application of precision design, dynamic optimization, and intelligent control across the entire service life of perforation guns is poised to guide forthcoming research and engineering practices, driving hydraulic sandblasting perforation technology toward greater efficiency, reliability, and intelligence.

In the fields of oil and gas, aerospace, and marine engineering, elliptical pipes are utilized for optimizing space usage, reducing aerodynamic drag, and enhancing structural resilience against bending and torsional forces. Predicting and optimizing fluid dynamics within such configurations remains challenging due to complex velocity distributions impacting kinetic energy calculations. This study explores the interaction between the kinetic energy correction factor and velocity distribution in elliptical pipes by uniquely solving the Navier–Stokes equations in an elliptical coordinate system. We begin by deriving transformation relationships between elliptical and Cartesian coordinates and defining gradient and Laplacian operators to express fundamental fluid dynamics quantities such as velocity vectors and pressure distributions. After analyzing the steady-state Navier–Stokes equations, we establish a set of partial differential equations that describe fluid velocity and pressure. Employing the method of separation of variables and linearizing into an eigenvalue problem, we analytically solve these equations. To confirm the validity of our theoretical models, we utilize computational fluid dynamics with the Wray–Agarwal turbulence model, alongside physical experiments with Preston tubes, which corroborate the predicted velocity distributions in elliptical pipes. Comparative analysis with experimental data using the root mean square error (RMSE) and Bland–Altman methods demonstrates that RMSE values are less than 0.05 and all differences fall within the 95% confidence interval. This level of precision significantly improves the reliability of kinetic energy correction factor predictions and supports the design and study of fluid dynamics in elliptical pipes.

There are occurrences of crude oil emulsification following the fracturing shut-in wells in the Jimushar, but the emulsification characteristics and mechanism remain unclear. In this study, the low-field nuclear magnetic resonance technique and visual microdisplacement tests are employed to investigate the emulsification characteristics of crude oil, along with its emulsification mechanism in porous media. Experimental results revealed that the heavy components (asphaltene and resin) enhance crude oil emulsification by increasing the viscous force of water droplets in the oil phase, affecting the size and stability of small water droplets in the oil phase. In the process of flowing through pore throats, emulsions are formed primarily by stretching and snap-off action, with stretching preferring to form smaller droplet-size emulsions, while snap-off results in the division of larger oil droplets into two smaller ones. The primary factors causing a large oil droplet to be stretched into smaller droplets include changes in the composition of the oil droplet, external tension, and the duration of these forces acting on the droplet. Capillary forces can emulsify crude oil and water at the pore scale, resulting in a reduction of the absorption rate. However, this rate can be restored when the capillary forces are strong enough for the water phase to penetrate and break through the emulsified layer. This study offers valuable insights into understanding the adaptability of the emulsification flooding mechanism.

The water quality of the injection–production systems deteriorates as the water flooding oilfields are developed more deeply, and the content of sulfate-reducing bacteria (SRB) increases. Accordingly, hydrogen sulfide (H2S) emission related to SRB is intensified, which will arise safety and health problems. In order to investigate the effect of SRB on H2S emission in the water flooding oilfield, the contents of SRB and sulfide of the different nodes of a typical injection–production system of Daqing Oilfield were measured first, and then, H2S emission from water was simulated under different conditions. Consequently, a H2S emission prediction model was established based on Henry coefficient and the correlation between sulfide content and SRB content in the water. The measured sulfide contents were ranging from 0.25 to 6.34 mg/l, and the SRB contents were from 2.5 to 25 000 pcs/ml, and the highest SRB and sulfide contents were found in the settling tank. The correlation between sulfide content and SRB content was much remarkable, and the R2 value of the correlation analysis was 0.94. Henry coefficient of H2S emission was obtained from the simulated experiments under varied conditions such as sulfate content, oil content, and temperature. The established H2S emission prediction model was much reliable for predicting H2S emission for water flooding injection–production system, and the accuracy of the predicted H2S emission of four nodes of the injection–production system was larger than 95% compared to the measured results. This study provides theoretical guidance for predicting H2S emission risks in water flooding injection–production systems.

Due to damage caused by fracturing fluid invasion, tight oil reservoirs exhibit slow post-hydraulic fracturing production recovery and low productivity. This study investigates the impact of a nanoclay-based active agent system on oil–water two-phase flow during and after fracturing fluid invasion, emphasizing its potential for enhancing recovery in tight oil reservoirs. Laboratory experiments using crude oil and natural core samples analyze the mechanism of how nanofluids affect oil–water distribution and flow characteristics during fracturing fluid invasion and oil recovery stages. Results show that nanofluids rapidly disrupt the emulsified state of “water-in-oil” emulsions, reducing emulsion viscosity by 84.19% and oil–water interfacial tension by two orders of magnitude, facilitating oil droplet dispersion and deformation and altering the wettability of oil-wet rock surfaces to aid crude oil detachment. Nanofluids increase the accessible volume of the water phase in pores and throats, enlarging flow paths for fracturing fluid flowback and oil recovery. The oil recovery process post-fracturing fluid invasion is delineated into three stages: substantial fracturing fluid flowback in the first stage, with nanofluids reducing the fluid return rate by 11.08% upon crude oil breakthrough; emulsion droplets occupying pores and throats in the second stage, with nanofluids reducing additional resistance during emulsion flow; and continuous oil production in the third stage, with nanofluids consistently and stably altering rock surface wettability to reduce invaded rock matrix resistance to oil flow. The findings of this study hold potential value in mitigating damage from fracturing fluid invasion in tight oil reservoirs.

In urban water supply and drainage systems, rainwater channels or pipes are rectangular in design to help control the flow rate and adapt well to limited space. When the Bernoulli equation in fluid mechanics is used to solve the head loss of rectangular pipelines, the velocity parameter used in the kinetic energy term is usually the instantaneous or average velocity of the section at a certain point. Given that this velocity parameter is in exponential form, the smaller the error is, the greater the impact on the result will be. Thus, the kinetic energy term must be corrected. This study focuses on establishing a cross section velocity distribution model in a rectangular pipe and deriving the kinetic energy correction coefficient through the velocity distribution. Based on the Navier–Stokes equation, the partial differential equation describing the velocity distribution is further refined and simplified. Combined with the boundary conditions of the pipeline, the method of separating variables and Fourier transform are used to solve the equation. An example shows how to establish the velocity distribution model and find the analytical solution. Finally, the analytical formula of the kinetic energy correction factor of different cross section parameters and fluid properties is derived. To verify the accuracy of the analytical formula, the Fluent numerical simulation software is used for empirical verification, and then the Deming regression method is used to analyze the error between the theoretical and experimental values. The regression results of the kinetic energy correction coefficient prediction model established in this study are consistent with the actual values, and the confidence interval reaches 95%. This work provides strong guidance for the prediction of the kinetic energy correction coefficient in fluid mechanics and has an important theoretical and practical value.

The main objective of this study is to put forward effective schemes for alleviating reservoir choke caused by emulsification or Jamin’s effect using the dilution method by light crude oil, as well as sharply increased viscosity. In this study, water-in-heavy-oil (W/O) emulsions with varying water fractions were prepared with heavy oil from Bohai Bay, China. Mixtures of W/O emulsions and light crude oil samples (light oil and light heavy oil) with varied dilution ratio (1:9, 2:8, 3:7) are tested, respectively by the electron microscope and by the rheometer. W/O droplets’ distribution and viscosity variations are obtained to evaluate the emulsion stability and viscosity reduction effects by dilution. Results show that W/O droplets^, size distribution range increases with the increase of water fractions. W/O droplets with larger size tend to be broken first in the dilution process. Light oil could reduce emulsions’ viscosity more effectively than light heavy oil. Viscosity reduction mechanisms by dilution could be concluded as the synergistic effects of dissolving heavy components and weakening oil–water film stability. Therefore, light oil is suggested as the optimal one for solving formation plugging. The poor performance of Richardson model is related to the re-emulsification between free water and crude oil favored by light heavy oil, and demulsification favored by light oil. The modified model shows a significant improvement in prediction accuracy, especially for W/O emulsions with large water fractions. This study demonstrates a promising and practical strategy of solving heavy oil well shutdown problems and viscosity increasing by injecting light crude oil in the thermal stimulation.

This study carried out interfacial tension (IFT) test, sand surface element analysis and scanning electron microscope (SEM) image, rock-oil-emulsification system interaction test, microstructure, droplet size distribution and stability of oil in water (O/W) emulsion to clarify the porous media flooding mechanism of hydrophilic Nano-SiO₂ enhanced emulsification system. Results shows that by adding small amount of Nano-SiO₂ (0.01 wt.%) into anionic surfactant fatty alcohol polyoxyethylene ether sodium hydroxypropyl sulfonate (AEOSHS) solution (0.5 wt.%), the IFT of oil-water effectively reduced, the adsorption loss of AEOSHS on the formation sand surface was reduced by more than 70%, the droplet size of formed O/W emulsion reduced by 50%. This greatly improves the effective concentration of AEOSHS and emulsify heavy oil ability in formation away from injection well. Moreover, the spreading ability of oil on core surface is greatly reduced, and the width of diffusion zone is narrowed. Meanwhile, a very clear dividing line of oil can be seen which shows that the wettability of core has changed to water wet. The stability of formed O/W emulsion was further enhanced, and the coalescence and migration process of droplet is extremely slow. The oil recovery of AEOSHS+ Nano-SiO₂ system can effectively increase 21.95% of original oil in place (OOIP). Both the sand-packed tube experiment and the microscopic visual oil flooding experiment show that the system can not only expand the sweep volume, but also improve the oil displacement efficiency, which means that the combination system can significantly improve the oil displacement effect.