Search Results (84)

Tight sandstone gas is currently one of the largest unconventional oil and gas resources being developed. In actual reservoir development, the complex pore structure affects the distribution of residual gas and water during the displacement process. However, there is still a lack of experimental research on the multi-scale visualization of pore structures in high-water-content tight gas reservoirs. Therefore, based on the porosity and permeability properties of reservoir cores and the micropore throat structural characteristics, this study designs and prepares three micro-physical models with different permeability ranges. Through micro-experiments and visualization techniques, the microscopic flow phenomena and gas–water distribution in the pore medium are observed. When the water–gas ratio exceeds 5, the produced water type is free water; when the water–gas ratio is between 2 and 5, the produced water type is weak capillary water; and when the water–gas ratio is less than 2, the produced water type is strong capillary water. The latter two types are collectively referred to as capillary water. In the Jin 30 well area, the main types of produced water are first free water, followed by capillary water, accounting for 58.5%. The experimental results of the micro-physical models with different permeability levels show that the production pattern of formation water varies due to differences in pore connectivity. In the low-permeability model, the high proportion of nano-pores and small pore throats requires a large pressure difference to mobilize capillary water, resulting in a higher proportion of residual water. Although the pores in the medium-permeability model are larger, the poor connectivity of nano-pores leads to local water phase retention. In the high-permeability model, micro-fractures and micropores are highly developed with good connectivity, allowing for rapid mobilization of multi-scale water phases under low pressure. The connectivity of nano-pores directly impacts the mobilization of formation water in micron-scale fractures, and poor pore connectivity significantly increases the difficulty of capillary water mobilization, thus changing the production mechanism of formation water at different scales. Full article

As information and sensor technologies advance swiftly, data-driven approaches have emerged as a dominant paradigm in scientific research. In the petroleum industry, precise forecasting of patterns of two-phase flow involving oil and water is essential for enhancing production efficiency and ensuring safety. This study investigates the application of Kolmogorov–Arnold Networks (KAN) for predicting patterns of two-phase flow involving oil and water and compares it with the conventional Multi-Layer Perceptron (MLP) neural network. To obtain real physical data, we conducted the experimental section to simulate the patterns of two-phase flow involving oil and water under various well angles, flow rates, and water cuts at the Key Laboratory of Oil and Gas Resources Exploration Technology of the Ministry of Education, Yangtze University. These data were standardized and used to train both KAN and MLP models. The findings indicate that KAN outperforms the MLP network, achieving 50% faster convergence and 22.2% higher accuracy in prediction. Moreover, the KAN model features a more streamlined structure and requires fewer neurons to attain comparable or superior performance to MLP. This research offers a highly effective and dependable method for predicting patterns of two-phase flow involving oil and water in the dynamic monitoring of production wells. It highlights the potential of KAN to boost the performance of energy systems, particularly in the context of intelligent transformation. Full article

To enhance the steam parameters of steam injection boilers during the thermal recovery of heavy oil while ensuring the safe and stable operation of boiler pipelines, this study conducted two-phase flow boiling numerical simulations in a horizontal heated tube with an inner diameter of 65 mm, using water and water vapor as working fluids. The analysis focused on the gas–liquid phase distribution, temperature profiles, near-wall fluid velocity, and pressure drop along both the axial and radial directions of the tube. Furthermore, the effects of heat flux density, mass flow rate, and inlet subcooling on these parameters were systematically investigated. The results reveal that higher heat fluxes intensify the velocity difference between the upper and lower tube walls and enlarge the temperature gradient across the wall surface. A reduction in mass flow rate increases the gas phase fraction within the tube and causes the occurrence of identical flow patterns at earlier axial positions. Additionally, the onset of nucleate boiling shifts upstream, accompanied by an increase and upstream movement of the wall’s maximum temperature. An increase in inlet subcooling prolongs the time required for the working fluid mixture to reach saturation, thereby decreasing the gas phase fraction and delaying the appearance of the same flow patterns. Finally, preventive and control strategies for ensuring the safe operation of steam injection boiler pipelines during heavy oil recovery are proposed from the perspective of flow pattern regulation. Full article

The thermal development in heavy oil reservoirs with edge and bottom water is poor, while gas huff-n-puff development shows a high recovery and strong adaptability. The formation of foamy oil during gas huff-n-puff is one of the reasons for the high recovery. In order to determine the factors affecting the foamy oil flow during gas huff-n-puff, experiments using a one-dimensional sandpack were conducted. The influences of drawdown pressure and cycle number were analyzed. The formation conditions of foamy oil were preliminarily clarified, and the enhanced oil recovery (EOR) mechanism of foamy oil was revealed. The experimental results show that the drawdown pressure and cycle number are two important factors affecting the formation of foamy oil. Foamy oil flow is prone to forming under a moderate drawdown pressure of 0.5–0.75 MPa, and being too small or too large is unfavorable. Foamy oil is more likely to form in the first two cycles, and it becomes increasingly challenging with the increase in the cycle number. These two factors reflect two necessary conditions for the formation of foamy oil during gas huff-n-puff: one is allowing the oil and gas to flow adequately to provide the shear and mixing for the generation of micro-bubbles, and the other is that the oil content should not be too small to avoid the inability to disperse and stabilize bubbles. The formation of foamy oil, on the one hand, increases the volume of the oil phase, and on the other hand, it reduces the mobility of the gas phase and slows down the pressure decline rate in the core, thereby enhancing the driving force for oil displacement. So, under the influence of the foamy oil, the gas production volume in a cycle declined by about 26%, and the average oil recovery increased by 4.5–6.9%. Full article

During natural gas development, the gas–water two-phase flows in upward and horizontal wellbores are complex and variable. The accurate calculation of the water holdup in each production layer using appropriate methods based on the logging data collected by fluid identification instruments can enable the precise identification of primary oil-producing and water-producing layers and facilitate subsequent water shutoff operations. In this study, we first investigated the measurement techniques and calculation methods for gas–water two-phase holdups both in China and internationally. Second, we conducted gas–water two-phase simulation experiments in upward and horizontal large-diameter wellbores using a Triangular Arm Array Imager (TAAI) equipped with six fiber-optic probes in a multiphase flow simulation laboratory. We then categorized the flow patterns observed in the physical simulation experiments based on typical theoretical classifications of gas–water two-phase flow patterns. Subsequently, we calculated the spatial positions of the fiber-optic probes and the local water holdup in the wellbore cross-section from the data collected by TAAI and compared the results obtained by Gaussian radial basis function (GRBF) or inverse distance weighted (IDW) interpolation algorithms. We processed the experimental data and found significant discrepancies between the holdup calculated by the two algorithms and the actual wellbore holdup. Therefore, we applied the Levenberg–Marquardt (L-M) algorithm to optimize these interpolation algorithms and discovered that the holdup obtained from the optimized algorithms aligned more closely with the actual wellbore holdup with reduced errors. Finally, we applied the optimized algorithms to the processing of measured data from a gas–water two-phase horizontal well. The results indicate that the L-M algorithm can improve the accuracy of 4–5% of holdup calculations. In the actual production process, the output situation of each production layer can be more accurately judged to provide important opinions for the subsequent actual production by this study. Full article

Understanding the structural evolution of two-phase fluid flow in fractured rock is of great significance for related rock engineering, including underground oil and gas extraction, contaminant storage and leakage, etc. Considering that rock fracture is the fundamental element of fractured rock, we conduct a series of numerical simulations to investigate the role of fracture aperture, surface roughness and shear displacement in the transition of two-phase fluid flow. The roughness fracture surfaces were generated by a MATLAB code we developed according to successive random addition algorithms. The level set method was applied to describe two-phase fluid flow and the numerical solution of the governing equations in COMSOL 6.2, and its effectiveness was verified by comparing it with the results of previous experiments. Numerical simulation results indicated the following: the water saturation (S_w) in the fracture decreases with an increase in the gas–water flow rate ratio; with an increase in roughness, the water saturation contained within the fracture gradually increases; the effect of fracture roughness on the two-phase fluid flow structure is enhanced; with an increase in dislocations, the water saturation in the low-roughness fracture increases, and the water saturation in the high-roughness fracture first increases and then decreases. The results of this study can provide reference significance for the study of gas–water two-phase fluid flow and provide theoretical guidance in related engineering. Full article

The oil field enters a low-production liquid and high-water-cut stage, where the oil–water two-phase flow becomes increasingly complex and diverse. Traditional production profile logging interpretation methods often face significant errors and limitations. To improve interpretation accuracy, this study begins by examining the impact of flow rate and water cut on the oil–water two-phase flow pattern (defined as the characteristic distribution and movement of oil and water phases in the flow, which varies depending on flow conditions such as flow rate and water cut) through numerical simulations and surface experimental observations. The flow characteristics of the oil–water two-phase flow are clarified. Next, the data from surface experiments are collected using a multi-component logging tool, and artificial intelligence algorithms are employed to identify flow patterns and provide data support for production profile interpretation. The genetic algorithm–backpropagation (GA-BP) algorithm is used for flow type classification, with the flow pattern recognition accuracy reaching 93.75% when compared to the experimental results. Finally, the surface experimental data and flow patterns are input into the grey wolf and falcon optimization algorithm–radial basis function (GHOA-RBF) algorithm for training and prediction. The results show that the GHOA-RBF algorithm, incorporating flow patterns, exhibits superior prediction accuracy. Specifically, the coefficient of determination (R²) for oil flow is 0.996, and for water flow, it is 0.993, outperforming traditional RBF neural networks and the GHOA-RBF algorithm without flow pattern incorporation. This demonstrates that this study provides new theoretical support for production profile logging interpretation, with significant practical implications. However, limitations include the reliance on experimental data, which may not fully capture all field conditions, and the computational efficiency of the algorithm, which may need optimization for large-scale applications. Full article

Background/Objectives: Chitosan–alginate microcapsules were produced to encapsulate bioactive compounds from Artemisia annua L. extract (apigenin, luteolin) and cannabidiol (CBD). The study aimed to optimize emulsion composition and encapsulation parameters for potential applications in food supplements and pharmaceuticals. Methods: A water-in-oil-in-water (W/O/W) emulsion and a modified coacervation extrusion technique were employed. The study was conducted in two phases using response surface methodology. Key metrics included encapsulation efficiency (EE), yield (EY), cumulative release in vitro, and physicochemical and morphological properties, analyzed via scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FT-IR), high-performance liquid chromatography with a diode array detector (HPLC-DAD), and gas chromatography with flame ionization detection (GC-FID). Results: The optimal conditions were identified as 0.1% Tween 20, 3.8% Span 80, 3.8% CBD, 19.9% A. annua L. extract, 1.5% outer-phase Tween 20, 48.5% sodium alginate, 200 rpm stirring for 30 min, and a 0.05 mL/min flow rate. The EE values were 80.32 ± 4.11% for CBD, 88.13 ± 3.13% for apigenin, and 88.41 ± 4.17% for luteolin, with respective cumulative releases of 77.18 ± 4.4%, 75.12 ± 4.81%, and 75.32 ± 4.53%. Conclusions: The developed microcapsules demonstrated high encapsulation efficiency and controlled release, highlighting their potential for further development in food supplements and pharmaceuticals. Future studies should focus on refining the formulation for improved bioavailability and stability. Full article

Understanding the flow behaviors of two-phase fluids in rock mass fractures holds significant importance for the exploitation of oil and gas resources. This paper takes rock fractures with different surface roughness characteristics as its research object and conducts experiments on the gas–water seepage laws of fractures under various confining pressures and shear displacements. The results indicate that the higher the fracture surface roughness, the larger the equivalent fracture width and the higher the single-phase permeability of gas/water in the fractures. During gas–water two-phase flow, when the water phase split flow rate is high, the influence of the confining pressure and fracture surface morphology on the water phase is significantly higher than that on the gas phase. The relative permeability at the isosmotic point of the fractures increases with the increase in confining pressure and decreases with the increase in roughness. After the dislocation of shale fractures, the interphase resistance within the fractures reduces. The relative permeability of the water phase increases more significantly compared to that of the gas phase. The water phase split flow rate at the isosmotic point does not change significantly, and the relative permeability at the isosmotic point increases. This research is helpful for guiding the protection based on the conductivity capacity of the rock mass fracture network. Full article

Gas reservoirs play an increasingly important role in oil and gas consumption and safety in China. To study the problem of erosion and wear caused by gas-carrying particles in the process of gas extraction from gas storage reservoirs, a mathematical model of gas–liquid–solid three-phase erosion of gas storage reservoir columns was established through theories of multiphase flow and particle motion. Based on this model, the effects of the water volume fraction, gas extraction rate, particle mass flow rate, particle size, and bending angle on the erosion location and rate of the pipe columns were investigated. The findings indicate that when the water content volume fraction is low, the water production volume minimally affects the maximum erosion rate of pipe columns. Conversely, the gas extraction rate exerted the most significant influence on the column erosion, showing a power function relationship between the two. When gas extraction volume exceeds 60 × 10⁴ m³/d, the maximum erosion rate surpasses the critical erosion rate of 0.076 mm/a. This coincided with the increased sand mass flow rate, although the maximum erosion rate of the pipe columns remained relatively steady. The salt mass flow rate demonstrated a linear relationship with the erosion rate, with the maximum erosion rate exceeding the critical erosion rate of 0.076 mm/a. The maximum erosion rate of the pipe columns increased, stabilized with larger sand and salt particle sizes, and exhibited an increasing trend with the bending angle. For gas extraction volumes exceeding 46.4 × 10⁴ m³/d and salt mass flow rates exceeding 22 kg/d, the maximum erosion rate of pipe columns exceeds the critical erosion rate of 0.076 mm/a. The conclusions of this study are of some importance for the clarification of the influencing law of pipe column erosion under high temperature and high pressure in gas storage reservoirs and for the formulation of measures for the prevention and control of pipe column erosion in gas storage reservoirs. Full article

With the increasing demand for oil and gas, the depth of some vertical gas wells can reach 6000 m. At this time, the downhole fluid is in a state of high temperature and pressure, and interpretation of the production logging output profile faces the problem of inaccurate production calculations and difficulty judging the water-producing layer. The drift-flux model is usually used to calculate the gas–water two-phase flow. The drift-flux model is widely used to describe the two-phase flow in pipelines and wells because of its accuracy and simplicity. The constitutive correlations used in drift-flux models, which specify the relative motion between phases, have been extensively studied. However, most of the correlations are only extended by laboratory data of small pipe diameters at standard temperature and pressure and do not apply to high-temperature and high-pressure large-diameter gas wells. Therefore, we improved the distribution coefficient and drift velocity of drift-flux correlations in this study for high-temperature and high-pressure gas wells with large pipe diameters. Therefore, this study improved the distribution coefficient and drift velocity of the drift-flux correlations for high-temperature and high-pressure gas wells with large pipe diameters. In practical application, the coincidence rates of gas production and water production calculated by the new drift-flux model were 12.68% and 19.39%, respectively. For high-temperature and high-pressure deep wells, the measurement errors of production logging instruments are significant, and surface laboratory pipelines are challenging to configure and equip with actual high-temperature and high-pressure conditions. Therefore, this study used the method of numerical simulation to study the flow characteristics of the two phases of high-temperature and high-pressure gas and water to provide a basis for identifying the water layer. Combined with the proposed drift-flux correlations and the new method of determining the water-producing layer, a new method of production profile interpretation of high-temperature and high-pressure gas wells is obtained. Full article

Unconventional oil and gas reservoirs are frequently developed using inclined and horizontal wells, leading to intricate multiphase flow patterns due to spatial asymmetry surrounding the wellbore and gravitational differentiation effects. Through the examination of water holdup imaging, the spatial arrangement of oil and water phases within the wellbore may be clearly depicted, yielding critical information for precisely assessing the ratios of oil and gas. This study employed No. 10 industrial white oil and tap water as fluid media, with measurements obtained using a resistive ring array tool (RAT) to evaluate its response properties over the wellbore cross-section. The data gathered throughout the trials were analyzed by two-dimensional interpolation imaging utilizing 2020 version MATLAB software. To enhance the analysis of water holdup distribution in the wellbore, three interpolation algorithms were utilized: Simple Linear Interpolation (SLI), Inverse Distance Weighting Interpolation (IDWI), and Ordinary Kriging Interpolation (OKI). The results indicated that RAT operates effectively in medium and low flow circumstances, correctly representing the real distribution of oil and water phases while yielding more dependable water holdup data. The SLI algorithm effectively delineates the oil-water interface during stratified flow of oil and water phases, rendering it the optimal algorithm for determining water holdup in standard flow patterns. Under DW/O&W and DO/W&W flow patterns, SLI continues to perform well; however, the accuracy of IDWI and OKI markedly enhances, with IDWI more effectively delineating the attributes of intricate mixed flow and more precisely representing the dynamic fluid distribution. Under DW/O and DO/W flow patterns, the OKI algorithm exhibits optimal performance in these intricate dispersed flow patterns. OKI more precisely represents the dynamic distribution of dispersed oil and water due to its capacity to simulate the spatial correlation of both phases, surpassing both SLI and IDWI. Full article

The Longwangmiao Formation gas reservoir in the Moxi block of the Sichuan Basin is a complex carbonate reservoir characterized by a low porosity and permeability, strong heterogeneity, developed natural fractures, and active water bodies. The existence of natural fractures allows water bodies to easily channel along these fractures, resulting in a more complicated mechanism and dynamic law of gas-well water production, which seriously impacts reservoir development. Therefore, a core-based simulation experiment was designed for oil–water two-phase flow. Three main factors influencing the water production of the gas reservoir, namely fracture permeability, fracture penetration, and water volume multiple, were analyzed using the orthogonal test method. The experimental results showed that the influences of the experimental parameters on the recovery factor and average water production can be ranked as water volume multiple > fracture penetration > fracture permeability, with the influence of the water volume multiple being slightly greater than that of the other two parameters. It provides a certain theoretical basis for water control of the gas reservoir. Full article

Light non-aqueous phase liquids (LNAPLs), which include various petroleum products, are a significant source of groundwater contamination globally. Once introduced into the subsurface, these contaminants tend to accumulate in the vadose zone, causing chronic soil and water pollution. The vadose zone often contains lens-shaped bodies with diverse properties that can significantly influence the migration and distribution of LNAPLs. Understanding the interaction between LNAPLs and these lens-shaped bodies is crucial for developing effective environmental management and remediation strategies. Prior research has primarily focused on LNAPL behavior in homogeneous media, with less emphasis on the impact of heterogeneous conditions introduced by lens-shaped bodies. To investigate the impact of lens-shaped structures on the migration of LNAPLs and to assess the specific effects of different types of lens-shaped structures on the distribution characteristics of LNAPL migration, this study simulates the LNAPL leakage process using an indoor two-dimensional sandbox. Three distinct test groups were conducted: one with no lens-shaped aquifer, one with a low-permeability lens, and one with a high-permeability lens. This study employs a combination of oil front curve mapping and high-density resistivity imaging techniques to systematically evaluate how the presence of lens-shaped structures affects the migration behavior, distribution patterns, and corresponding resistivity anomalies of LNAPLs. The results indicate that the migration rate and distribution characteristics of LNAPLs are influenced by the presence of a lens in the gas band of the envelope. The maximum vertical migration distances of the LNAPL are as follows: high-permeability lens (45 cm), no lens-shaped aquifer (40 cm), and low-permeability lens (35 cm). Horizontally, the maximum migration distances of the LNAPL to the upper part of the lens body decreases in the order of low-permeability lens, high-permeability lens, and no lens-shaped aquifer. The low-permeability lens impedes the vertical migration of the LNAPL, significantly affecting its migration path. It creates a flow around effect, hindering the downward migration of the LNAPL. In contrast, the high-permeability lens has a weaker retention effect and creates preferential flow paths, promoting the downward migration of the LNAPL. Under conditions with no lens-shaped aquifer and a high-permeability lens, the region of positive resistivity change rate is symmetrical around the axis where the injection point is located. Future research should explore the impact of various LNAPL types, lens geometries, and water table fluctuations on migration patterns. Incorporating numerical simulations could provide deeper insights into the mechanisms controlling LNAPL migration in heterogeneous subsurface environments. Full article

The sensitivity of gas and water phases to DAS acoustic frequency bands can be used to interpret the production profile of horizontal wells. DAS typically collects acoustic signals in the kilohertz range, presenting a key challenge in identifying the sensitive frequency bands of the gas and water phases in the production well for accurate interpretation. In this study, a gas–water two-phase flow–acoustic coupling model for a horizontal well is developed by integrating a gas–water separation flow model with a pipeline acoustic model. The model simulates the sound pressure level (SPL) and amplitude variations of acoustic waves under different flow patterns, spatial locations, and gas–water ratio schemes. The results demonstrate that within the same flow pattern, an increase in the gas–water ratio significantly elevates acoustic amplitude and SPL peaks within the 5–50 Hz frequency band. Analysis of oil field DAS data reveals that the amplitude response range for stages with a lower gas–water ratio falls within 5–10 Hz, whereas stages with a higher gas–water ratio exhibit an amplitude response range of 10–50 Hz. Full article