Search Results (195)

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

Pore-scale remediation investigation of oil-contaminated soil is important in several environmental and industrial applications, such as quick responses to sudden accidents. This work aims to investigate the oil pollutant removal process and optimize the oil-contaminated soil remediation performance at the pore scale to find the underlying mechanisms for oil removal from soil. The conservative forms of the phase-field model and the non-Newtonian power-law fluid model are employed to track the moving interface between two immiscible phases, and oil pollutant flushing removal process from soil pores is investigated. The effects of viscosity, interfacial tension, wettability, and flushing velocity on pore-scale oil pollutant removal regularity are explored. Then, the oil pollutant removal effects of two flushing agents (surfactant system and surfactant–polymer system) are compared using an oil content prediction curve based on UV-Visible transmittance. The results show that the optimal removal efficiency is obtained for a weak water-wetting system with a contact angle of 60° due to the stronger two-phase fluid interaction, deeper penetration, and more effective entrainment flow. On the basis of the dimensionless analysis, a relatively larger flushing velocity, resulting in a higher capillary number (Ca) in a certain range, can achieve rapid and efficient oil removal. In addition, an appropriately low interfacial tension, rather than ultra-low interfacial intension, contributes to strengthening the oil removal behavior. A reasonably high viscosity ratio (M) with a weak water-wetting state plays synergetic roles in the process of oil removal from the contaminated soil. In addition, the flushing agent combined with a surfactant and polymer can remarkably enhance the oil removal efficiency compared to the sole use of the surfactant, achieving a 2.5-fold increase in oil removal efficiency. This work provides new insights into the often-overlooked roles of the pore scale in fluid dynamics behind the remediation of oil-contaminated soil via flushing agent injection, which is of fundamental importance to the development of effective response strategies for soil contamination. Full article

In the process of reservoir water flooding development, the characteristics of underground seepage field have changed, resulting in increasingly complex oil–water distribution. The original understanding of reservoir physical property parameters based on the initial stage of development is insufficient to guide reservoir development efforts in the extra-high water cut stage. To deeply investigate the spatio-temporal evolution of heterogeneity in the internal seepage field of layered reservoirs during water flooding development, water–oil displacement experimental simulations were conducted based on layered, normally graded models. By combining CT scanning technology and two-phase seepage theory, the variation patterns of heterogeneity in the seepage field of medium-to-high permeability, normally graded reservoirs were analyzed. The results indicate that the effectiveness of water flooding development is doubly constrained by differences in oil–water seepage capacities and the heterogeneity of the seepage field. During the development process, both the reservoir’s flow capacity and the heterogeneity of the seepage field are in a state of continuous change. Influenced by the extra resistance brought about by multiphase flow, the reservoir’s flow capacity drops to 41.6% of the absolute permeability in the extra-high water cut stage. Based on differences in the variation amplitudes of oil–water-phase permeabilities, changes in the heterogeneity of the internal seepage field of the reservoir can be broadly divided into periods of drastic change and relative stability. During the drastic change stage, the fluctuation amplitude of the water-phase permeability variation coefficient is 114.5 times that of the relative stable phase, while the fluctuation amplitude of the oil-phase permeability variation coefficient is 5.2 times that of the stable stage. This study reveals the dynamic changes in reservoir seepage characteristics during the water injection process, providing guidance for water injection development in layered reservoirs. Full article

The aim of this study was to compare the functional properties of linseed oil powders made of three types of wall material (OSA starch + maltodextrin, OSA starch + nutriose, and OSA starch + inulin) and two types of emulsion phases (micro- and nanoemulsion). For these independent variables, the properties of the prepared emulsions (flow curves and viscosity) and the resulting powders (encapsulation efficiency, particle size distribution, water activity, bulk and tapped density, Carr’s index, color parameters, and thermal stability) were determined. The results showed that emulsion viscosity and most powder properties were affected by the emulsion type. All emulsions demonstrated Newtonian-like behavior, with viscosity values ranging from 29.07 to 48.26 mPa·s. The addition of nutriose induced the most significant variation in this parameter, with nanoemulsification leading to a 1.6-fold increase in viscosity compared to microemulsification. The application of nanoemulsification to prepare the emulsions prior to spray-drying resulted in powders with lower surface oil content (by 78.8–88.5%), tapped density (by 1.7–14.2%), and Carr’s index (by 7.6–14.0%), as well as higher encapsulation efficiency (by 5.9–17.0%). The decreased oxidative stability (by 30.9–51.1%) of powders obtained from nanoemulsified emulsions was related to 4.7–15.9-fold lower surface oil content. Powders produced using inulin as the wall material had the smallest and most uniform particle sizes, showing minimal variation between powders derived from nano- and microemulsified emulsions. 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

Ethanol production by fermentation results in obtaining, in addition to the main product, ethyl alcohol, by-products and secondary products, which include carbon dioxide, fusel oil, and ester–aldehyde cut. Fusel oil, despite its low yield and the large volume of ethanol production, accumulates at distilleries, which ultimately raises the question of its disposal or the rational use of this by-product. Fusel oil, being a complex mixture, can serve as a source of technical alcohols used in various sectors of the economy, including the food industry, pharmaceuticals, organic synthesis, perfume, and cosmetics industries, as well as the production of paints and varnishes. However, the complexity of using fusel oil lies in its difficult separation. The reason for this is the presence of water, which forms low-boiling azeotropes with aliphatic alcohols. Our study aimed to develop a process flow diagram (PFD) that allows individual components from fusel oil to be obtained without extraneous separating agents (not inherent in fusel oil). This condition is necessary to obtain products labeled as natural for further use in the food, perfume, cosmetic, and pharmaceutical industries. The distinctive feature of this work is that the target product is not only isoamyl alcohol but also all other alcohols present in the composition of fusel oil. To achieve this goal and create a mathematical model, the Aspen Plus V14 application, the Non-Random Two Liquid (NRTL) thermodynamic model, and the Vap-Liq/Liq-Liq phase equilibrium were used. Fusel oil separation was modeled using a continuous separation PFD to obtain ethanol, water, isoamyl alcohol, and raw propanol and butanol cuts. The Sorel and Barbet distillation technique was used to isolate ethanol. The isolation of isopropanol and 1-propanol, as well as isobutanol and 1-butanol, was modeled using the batch distillation method. The isolation of fusel oil components was based on their thermodynamic properties and the selection of appropriate techniques for their separation, such as extraction, distillation, pressure swing distillation, and decantation. The simulation of fusel oil separation PFD showed the possibility of obtaining the components of a complex mixture without separating agents, as discussed earlier. Ethanol corresponds to the quality of rectified ethyl alcohol, and 1-butanol and isoamyl alcohols to anhydrous alcohols, whereas isopropanol (which contains an admixture of ethanol), 1-propanol, and isobutanol are obtained as aqueous solutions of different concentrations of alcohols. However, due to a distillation boundary in the raw propanol and butanol cuts, these mixtures cannot be separated completely, which leads to the production of intermediate fractions. To eliminate intermediate fractions and obtain anhydrous isopropanol, 1-propanol, and isobutanol in the future, it is necessary to solve the dehydration problem of either fusel oil or the propanol–butanol mixture. Full article

A computational fluid dynamics study of the horizontal oil–water flow was performed using the Eulerian–Eulerian and mixture multiphase models in conjunction with the realizable k–ε turbulence model for the characterization of flow patterns. The experimental tests were carried out using water and mineral oil with a density of 880 kg/m³ and a viscosity of 180 cP, varying the superficial velocities of both fluids in ranges of 0.1–1.2 m/s and 0.1–0.5 m/s, respectively. The numerical model was defined under the same initial and boundary conditions as in the experiment. Moreover, the model is defined such that entering the fluids in a mixed state, the stratified pattern could form adequately with the two multiphase models. Although the Eulerian–Eulerian model, together with the geometric reconstruction scheme, allowed us to visualize the three-dimensional dispersed patterns in a very similar way to the experimental results, the mixture model did not exhibit such similarity, especially in the oil-in-water dispersions. Additionally, the Eulerian–Eulerian model was able to predict the experimental holdup values with an average error of 15.2%. 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

Owing to the limitations of physical experiments on heavy oil, this study establishes a mathematical model for heavy oil–water two-phase flow based on the theory of multiphase flow, considering factors such as heavy oil viscosity, mixed flow velocity, and inlet water cut. Through transient calculations of 650 groups of heavy oil–water two-phase flows based on this model, six typical heavy oil–water two-phase flow patterns were identified by monitoring flow pattern cloud images, liquid holdup, and the probability density function (PDF) of liquid holdup: water-in-oil bubble flow, transitional flow, water-in-oil slug flow, oil-in-water bubble flow, oil-in-water very fine dispersed flow, and water-in-oil core-annular flow. Five sets of flow pattern maps for a heavy oil–water two-phase flow with different viscosities were established based on the inlet water cut and mixed flow velocity. The results showed that different heavy oil viscosities lead to different oil–water two-phase flow patterns. When the heavy oil viscosity is 100 mPa·s, the flow patterns include water-in-oil bubble flow, transitional flow, water-in-oil slug flow, oil-in-water bubble flow, and oil-in-water very fine dispersed bubble flow. When the heavy oil viscosity reaches 600 mPa·s, a water-in-oil core-annular flow appears, and the oil-in-water very fine dispersed bubble flow disappears. After the heavy oil viscosity exceeds 1100 mPa·s, the oil-in-water bubble flow disappears. Among the different flow patterns, the range of the water-in-oil slug flow is most affected by the viscosity and flow velocity. The greater the heavy oil viscosity, the larger the range. When the viscosity remained constant, a larger flow velocity resulted in a smaller range. The accuracy of the flow pattern predictions in the maps was verified by comparing them with field production data, confirming that the research results can provide a theoretical basis for understanding oil–water two-phase flow patterns in heavy oil wellbores. Full article

This paper presents a study on heat transfer in two-phase mixtures (air–water and air–oil) flowing through heated horizontal channels filled with open-cell aluminum foams characterized by porosities of 92.9–94.3% and pore densities of 20, 30, and 40 PPI. The research included mass flux densities ranging from 2.82 to 284.7 kg/(m²·s) and heat flux densities from 5.3 to 35.7 kW/m². The analysis examined the effects of flow conditions, fluid properties, and foam geometry on the intensity of heat transfer from the heated walls of the channel to the fluid. Results indicate that the heat transfer coefficient in two-component non-boiling flow exceeds that of single-phase flow, primarily due to fluid properties and velocities, with minimal impact from flow structures or foam geometry. An assessment of existing methods for predicting heat transfer coefficients in gas–liquid and boiling flows revealed significant discrepancies—up to several hundred percent—between measured and predicted values. To address these issues, a novel computational method was developed to accurately predict heat transfer coefficients for two-component non-boiling flow through metal foams. Full article

A physics-informed convolutional neural network (PICNN) is proposed to simulate two-phase flow in porous media with time-varying well controls. While most PICNNs in the existing literature worked on parameter-to-state mapping, our proposed network parameterizes the solutions with time-varying controls to establish a control-to-state regression. Firstly, a finite volume scheme is adopted to discretize flow equations and formulate a loss function that respects mass conservation laws. Neumann boundary conditions are seamlessly incorporated into the semi-discretized equations so no additional loss term is needed. The network architecture comprises two parallel U-Net structures, with network inputs being well controls and outputs being the system states (e.g., oil pressure and water saturation). To capture the time-dependent relationship between inputs and outputs, the network is well designed to mimic discretized state-space equations. We train the network progressively for every time step, enabling it to simultaneously predict oil pressure and water saturation at each timestep. After training the network for one timestep, we leverage transfer learning techniques to expedite the training process for a subsequent time step. The proposed model is used to simulate oil–water porous flow scenarios with varying reservoir model dimensionality, and aspects including computation efficiency and accuracy are compared against corresponding numerical approaches. The comparison with numerical methods demonstrates that a PICNN is highly efficient yet preserves decent accuracy. Full article