Oil-water Two-phase Flow Research Articles

Molecular Simulation Study and Analytical Model for Oil–Water Two-Phase Fluid Transport in Shale Inorganic Nanopores

Shale reservoirs contain omnipresent nanopores. The fluid transport phenomena on the nanoscale are significantly different from that on the macroscale. The understandings of fluid transport behavior, especially multiphase flow, are still ambiguous on the nanoscale and the traditional hydrodynamic models are insufficient to describe the fluid flow in shale. In this work, we firstly use a molecular dynamics simulation to study the oil–water two-phase flow in shale inorganic quartz nanopores and investigated the unique interfacial phenomena and their influences on fluid transport in a confined nanospace. The results of the molecular simulation revealed that the water-oil-water layered structure was formed in quartz nanopores. There is no-slip boundary condition between water and quartz surface. The density dip and the extremely low apparent viscosity of the oil–water interface region were observed. The liquid–liquid slip effect happened at the oil–water interface. Based on the nano-effects obtained by the molecular simulation, two mathematical models were proposed to describe the nanoscale oil–water two-phase flow, considering both the solid–liquid and liquid–liquid interfacial phenomena, and the performances of two mathematical models were validated. This study shed light on the flow behaviors of oil and water on the nanoscale, and provides the theoretical basis for scale-upgrading, from the nanoscale to the macroscale.

Numerical quasi-three dimensional modeling of stratified oil-water flow in horizontal circular pipe

The stratified oil-water two-phase flow is commonly encountered in offshore oil production systems, and is considered to be among the fundamental flow configuration in two-phase systems. A numerical quasi-three dimensional model for the calculations of the axial pressure gradient, interface height, water holdup, and the flow field in a fully developed oil-water two-phase stratified pipe flow has been developed. The oil-water curved interface configuration is predicted by using minimum energy model. The model solves the governing equations of the steady axial momentum and mass conservation equations together with a low Reynolds number k～ε model of turbulence for the eddy viscosity, performed in the bipolar coordinate system, for convenient describing the curved interface and mapping of the physical domain. The predicted dynamic parameters, such as interface height of close to the pipe wall and in the middle of the pipe cross-section, water holdup, pressure gradient and flow filed are compared with the experiments. At the same time, this model is utilized to study the variation of these dynamic parameters with increasing superficial oil and water velocities. In addition, the numerical model with concave oil-water interface gives more accurate results than a flat interface. It indicates that the interfacial configuration effects are significant.

Data-Driven Methodology for the Prediction of Fluid Flow in Ultrasonic Production Logging Data Processing

A new method for the determination of oil and water flow rates in vertical upward oil-water two-phase pipe flows has been proposed. This method consists of an application of machine learning techniques on the probability density function (PDF) and the power spectral density (PSD) of the power spectrum output of an ultrasonic Doppler sensor in the pipe. The power spectrum characteristic parameters of the two-phase flow are first determined by the probability density function (PDF) method. Then, the transducer signal is preprocessed by distance correlation analysis (DCA), and independent features are extracted by principal component analysis (PCA). The extracted features are used as input to a least-squares fit, which gave the oil flow rates as output. In the same way, the transducer signal is also preprocessed by partial correlation analysis (PCA), and independent features were extracted using independent component analysis (ICA). The extracted features were used as inputs to multilayer back-propagation neural networks, which water cuts as output. The present method was used to calibrate an ultrasonic Doppler sensor to estimate the flow rates of both phases in oil–water flow in a vertical pipe of diameter 159 mm. Predictions of the present method were in good agreement with direct flow rate measurements. Compared to previously used methods of feature extraction from the ultrasonic Doppler power spectrum signals, the present method provides a theoretical basis for the interpretation of ultrasonic multiphase flow logging data. Ultrasonic multiphase flow logging has potential application value in the production profile logging and interpretation evaluation of production wells with low fluid production and high water cut.

A fractal physics-based data-driven model for water-flooding reservoir (FlowNet-fractal)

This paper proposed a fractal physics-based data-driven framework for reservoir simulation (name as FlowNet-fractal) by integrating physics-based data-driven model with fractal theory. FlowNet-fractal enables fast history matching and production prediction of water flooding reservoirs by considering the fractal characteristics of reservoir permeability and porosity. Details of FlowNet-fractal calculation were given with an oil-water two-phase flow example. In the FlowNet-fractal, transmissibility, control pore volumes (PVs), fractal mass dimension and fractal index were separately defined in each one-dimensional connection element to map reservoir properties, which more specifically reflected reservoir heterogeneity than the traditional FlowNet method. In this paper, an example of simple heterogeneous reservoir model and two actual water-flooding reservoir cases with different scales were given. The calculation results showed that the FlowNet-fractal method outperformed the FlowNet method in both the convergence speed and the accuracy of history matching. Moreover, the heterogeneity of the reservoir model was also defined by the inversed fractal mass dimension and the fractal index. • An integrated fractal-physics-based data-driven model and fractal theory are proposed in this research as the FlowNet-fractal framework for reservoir simulation. • The FlowNet-fractal approach beats the FlowNet method in terms of computing correctness, convergence speed, and historical matching effect. • Using the fractal mass dimension and fractal index, FlowNet-fractal may not only highlight reservoir heterogeneity but also significantly boost calculation rate.

Oil-water separation in a cylindrical cyclone with vortex finder

Cylindrical cyclones are always used in the petroleum industry to separate the oil-water two-phase mixtures or treatment the waste water. Here, we use dimensional analysis and multiphase flow numerical simulation to analyze the separation process in a cylindrical cyclone with a vortex finder to better understand the theory and characteristics of separation. In the dimensional analysis, we consider all structural, flow, and operating parameters. A multiphase mixture model is used to simulate oil-water two-phase flow and separation in a cylindrical cyclone. There is a vortex in the core of the cylinder, and its structure is influenced by the diameter of the overflow pipe, the inlet velocity, and the flow split ratio. However, the influence of these three factors on the equivalent diameter of the vortex core can be ignored. Moreover, the inlet velocity has little influence on the equivalent length of the vortex core. Therefore, the structure of the vortex core can be calculated from the diameter and flow split ratio of the up-outlet of the cylindrical cyclone. Oil-water separation increases as the diameter of the oil droplet increases. The separation efficiency of the cylindrical cyclone with vortex can reach 80% if the inlet dispersion droplet diameter is larger than 1 mm. The oil volume fractions in the up- and down-outlets decrease as the overflow split ratio increases. The flow split ratio is the only operating parameter to consider to obtain the best separation results for a cylindrical cyclone with a fixed inlet oil-water mixture.

Effect of Temperature on Oil-Water Separations Using Membranes in Horizontal Separators.

The effect of temperature on oil–water separations is studied in this paper, focusing on the changed penetration velocities of water droplets on the separation membrane in a horizontal separator. A compact numerical scheme is developed based on the phase-field model, and the temperature effect is first theoretically analyzed regarding the key thermodynamic properties that may affect the separation performance. The computational scenario is designed based on practical horizontal separators in the oil field, and the droplet motions in the oil–water two-phase flow are simulated using our scheme under various operation conditions. It was found that a higher temperature may result in a faster penetration of the water droplets, and a larger density difference in the oil–water system is also preferred to accelerate the separation using membranes. Furthermore, increasing the operation temperature is proved to benefit the separation of water and heavy oil.

Measurement of high-water-content oil-water two-phase flow by electromagnetic flowmeter and differential pressure based on phase-isolation

When the oil field has been exploited by long-term water-flooding, it will be in high water-content stage of production. However, it is a great challenge for high-water-content measurement due to oil droplets extremely dispersed in the water. In this paper, we developed a phase-isolation based method for high-water-content oil-water two-phase flow measurement. Phase-isolation was realized by axial-flow swirler to concentrate scattered and random oil droplets into the pipe center and change the inlet flow pattern into a particular annular flow before measuring. Owing to the axisymmetric velocity and phase distribution, the electromagnetic flow meter avoided the effect of random distribution of insulating phase, and then had a good measurement performance for total volume flow rate. Furthermore, we respectively studied using axial pressure drop, radial pressure drop and the ratio of the two pressure drops to measure water content. The results showed that the ratio of the two pressure drops not only improves the resolution of oil and water, but also effectively reduces the impact of error transfer. In the dual-parameter measurement experiment, the relative errors of total volume flow rate and water content were almost within ±5%.

Prediction of split-phase flow of low-velocity oil-water two-phase flow based on PLS-SVR algorithm

In the middle and late stages of water flooding development in oil fields, oil wells will have the characteristics of low production fluid and high water cut content, making traditional production profile combination instruments unable to meet field needs. In order to accurately obtain the flow rate of each phase of the oil-water two-phase flow under the condition of low velocity, this paper proposes a new production profile logging method that combines an ultrasonic Doppler logging tool and a combined annulus logging tool. The measurement characteristics are verified by simulation experiments. Through frequency spectrum transformation of the original ultrasonic logging data, the power spectrum curve of the oil-water two-phase flow is obtained, the oil frequency, oil amplitude and other parameters are obtained by Gaussian fitting, and the distance analysis of the obtained experimental data is performed to obtain the correlation between the variables. Finally, the PLS-SVR algorithm is used to predict the oil and water flow. The mean absolute percentage error of oil flow is 7.96%, and the mean absolute percentage error of water flow is 9.4%. The prediction results show that the proposed low-velocity oil-water two-phase split-phase flow prediction model can meet actual needs, and has higher accuracy than support vector regression (SVR) and back propagation (BP) neural network prediction models, which can provide a new theoretical support for logging interpretation of production profiles.

Pore network modeling of oil and water transport in nanoporous shale with mixed wettability

Hydraulic fracturing is an effective means for the economic development of shale oil reservoirs. A large volume of water is introduced into the shale matrix during hydraulic fracturing, which leads to the subsequent oil-water two-phase flow in the shale reservoir. The fluid flow behaviors in shale are still ambiguous due to the nonnegligible nanoconfinement effect caused by the omnipresent nanoscale pores and the heterogeneities of mineral types, pore size and wettability of shale. In this study, both the single-phase and oil-water two-phase flow behaviors at pore-scale considering nanoconfinement effects, dual-wettability and pore space characteristic of shale reservoir were investigated using the pore network modeling (PNM) method. We constructed the three-dimension shale digital rock based on scanning electron microscope (SEM) images and extracted the pore network model. The modified single nanotube flow equations considering the adsorption and slip effects were incorporated with the shale pore network model to investigate the single-phase flow at different volumetric total organic content (TOC). Oil-water two-phase flow and relative permeability at different TOC in volume were computed by quasi-static method with consideration of nanoconfinement effect. Results indicated that the TOC and wettability are the primary factors affecting the single-phase flow in shale. Slip effect enhanced the flow capacities of both single-phase water and oil. The wettability effect on two-phase relative permeability curve was not as notable as that on single-phase flow. Oil-water two-phase relative permeability curves were significantly affected by TOC. The two-phase flow region narrows down with the increase of volume TOC, indicating more oil is trapped and thus cannot be displaced. This work provided important insights on pore-scale fluid transport behaviors in shale.

Experimental Study of the Flow Mechanism of Deep Lacustrine Carbonate Reservoirs in the Yingxi Area of the Qaidam Basin

Many of the exploration and development theories derived for conventional clastic rock reservoirs are not applicable to pore-fracture lacustrine carbonate reservoirs. The fluid flow mechanisms under reservoir conditions are still unclear. Therefore, in this study, the rock samples were characterized using X-ray diffraction (XRD), porosity-permeability analysis, scanning electron microscopy (SEM), plain thin sections, and casting thin sections. The core samples were classified into two types (fractures and matrix pores) based on their reservoir spaces. The core flow experiments were performed under reservoir conditions using reservoir core plugs. The experimental results demonstrate that the cores, especially the fractured cores, have a strong stress sensitivity. The oil phase flow in the core has the characteristics of non-Darcy flow, and the threshold pressure gradient is 0.01–0.003 MPa/m. Additionally, for the oil-water two-phase flow in the fractured core, the water phase relative permeability of the residual oil is high. In contrast, the water phase relative permeability of the matrix core is less than 0.2. The nuclear magnetic resonance (NMR) transverse relaxation time ( T 2 ) spectra were used to analyze the differences between the water flooding characteristics of the two pore structures. The experimental results show that the peaks of the T 2 spectra after water flooding are lower than those before water flooding, and the matrix cores have a better oil displacement effect. The relaxation time of 0.1–10 ms makes the greatest contribution to the water flooding efficiency. The micropores smaller than 10 μm in diameter play an important role in the water flooding of the matrix core. These results will provide theoretical basis for solving the difficult problems of developing deep lacustrine carbonate reservoirs.

Measurement of Water Holdup in Vertical Upward Oil-Water Two-Phase Flow Pipes Using a Helical Capacitance Sensor.

Oil–water two-phase flows widely exist in industrial production, especially in the petroleum industry. The liquid holdup is significant for understanding reservoir production characteristics and improving oil recovery. This paper focuses on the helical capacitance sensor for the measurement of water holdup of oil–water two-phase flows. A new double helix capacitance sensor with an electrode rotation angle of 360° is designed. The sensitivity field distribution of the sensor with different parameters is simulated by the finite element analysis method, and the optimal geometric size of the sensor is obtained. The measurement characteristics of the sensor under different flow conditions are investigated by dynamical experiments of vertical oil–water flows. By analyzing the response signal of the helical capacitance sensor, the flow pattern can be identified, and the apparent water holdup can be calculated. The results show that the proposed sensor is suitable to measure the water holdup in a wide range of water cuts. Even in flow conditions of a high water cut, the sensor still retains good resolution in the D O/W flow pattern. This study expands the water holdup measurement of a capacitance sensor in the case of an oil–water two-phase flow with a high water cut.

Multiscale Voltage Reconstruction With Attention-Based Network for Volume Fraction Prediction of Industrial Oil–Water Two-Phase Flow by EIT

Oil-water two-phase flow as a typical two-phase flow type widely exists in various industrial processes and the accurate measurement of oil volume fraction plays a significant role in transporting and separating oil-water mixture in the processes. Electrical Impedance Tomography (EIT) as a merging technology with the advantages of non-invasive, low cost and real-time measurement is widely applied in the industrial field to measure the volume fraction for different types of two-phase flows. However, the measurement process of taking homogeneous reference voltages is time-consuming and costly. To cope with the problem, in the paper, by establishing an end-to-end mapping between measurement voltages and volume fraction, we propose an Attention UNet-Fully Connected (AU-FC) architecture. Relying on the attention mechanism, the reconstructed voltages having a strong correlation or a weak correlation with volume fraction are highlighted or suppressed respectively. Oil-water two-phase flow experiment was conducted in the NEL facility to collect EIT voltage data. Compared with six state-of-the-art and existing machine learning methods, the proposed method performs better in predicting volume fraction. The results indicate that the proposed AU-FC architecture can accurately and real-time predict the volume fraction of oil-water two-phase flow, which improves the application potential of EIT combined with deep learning method in the industrial field.

Flow Loop Study of ECT-Based Volume Fraction Monitoring in Oil–Water Two-Phase Flows

Measurement of phase volume fractions in water-containing multiphase flows is necessary for the optimization of a host of industrial flow processes. Many water-containing multiphase flows can be classified as either water-dispersed or water-continuous mixtures. A recently developed approach based on Hanai’s mixture formula and utilizing electrical capacitance tomography (ECT) sensors have shown good potential for obtaining water volume fraction estimates in two-phase water-containing flows with different water salinity levels. However, the proposed approach was investigated via controlled experiments restricted to static configurations while, in practice, multiphase flows can be dynamic and unpredictable. In this work, we perform a flow loop study of the proposed ECT-based method for volume fraction estimation in oil-water two-phase flows. We evaluate the performance of the proposed method in both water-dispersed and water-continuous flow regimes by employing different types of capacitive sensors in cylindrical arrangements and in parallel-plate rectangular arrangements.

A Modified Adaptive Cross Correlation Method for Flow Rate Measurement of High-Water-Cut Oil-Water Flow Using Planar Flowmeter

This article proposed a modified adaptive (MA) cross correlation method to measure the flow rate of high-water-cut oil-water two-phase flow. It asynchronously commences the acquisitions of the upstream and downstream signals for cross correlation according to the flow rate, enhancing the degree of correlation between them, thus a higher measurement accuracy of transition time can be obtained. By limiting the searching scope of the correlogram’s peak value in a transition time-related observation window, the calculation process is kept steady and divergence due to the outliers is effectively avoided. A planar flowmeter is adopted for high-water-cut flow rate measurement, and the advantages in axial resolution and sensitivity are analyzed. Experiments are conducted in 90% water cut oil-water flow in a practical vertical well. Results show that compared to the conventional (C) one, the MA method is capable of fast and reliable capture of the transition time from the upstream to the downstream sensors in a much wider flow rate range, with much lower deviation and a higher degree of correlation. Finally, the flow rates and their uncertainties are calculated from the measured transition time to validate the measurement stability.

Two Phase Flow Simulation of Fractal Oil Reservoir Based on Meshless Method

The reservoir is the networked rock skeleton of an oil and gas trap, as well as the generic term for the fluid contained within pore fractures and karst caves. Heterogeneity and a complex internal pore structure characterize the reservoir rock. By introducing the fractal permeability formula, this paper establishes a fractal mathematical model of oil-water two-phase flow in an oil reservoir with heterogeneity characteristics and numerically solves the mathematical model using the weighted least squares meshless method. Additionally, the method’s correctness is verified by comparison to the exact solution. The numerical results demonstrate that the fractal oil-water two-phase flow mathematical model developed using the meshless method is capable of more accurately and efficiently describing the flow characteristics of the oil-water two-phase migration process. In comparison to the conventional numerical model, this method achieves a greater degree of convergence and stability. This paper examines the effect of varying the initial viscosity of the oil, the initial formation pressure, and the production and injection ratios on daily oil production per well, water cut in the block, and accumulated oil in the block. For 10 and 60 cp initial crude oil viscosities, the water cut can be 0.62 and 0.80, with 3100 and 1900 m3 cumulative oil production. Initial pressures have little effect on production. In this case, the daily oil production of well PRO1 is 1.7 m3 at 7 and 10 MPa initial pressure. Block cumulative oil production is 3465.4 and 2149.9 m3 when the production injection ratio is 1.4 and 0.8. The two-phase meshless method described in this paper is essential for a rational and effective study of production dynamics patterns in complex reservoirs and the development of reservoir simulations of oil-water flow in heterogeneous reservoirs.

Oil–Water Two-Phase Flow Volume Fraction Measurement Based on Nonlinear Ultrasound Technique

Ultrasonic techniques have been widely used to determine the volume fractions of liquid components in oil–water two-phase flow. The two major ultrasonic interactions amenable to volume fraction estimation are the sound speed and attenuation. Instead of using these two linear ultrasound parameters, this study explores the use of ultrasound nonlinear parameter to measure the volume fraction of oil–water two-phase flow. Based on the theoretical modeling of ultrasound nonlinear propagation and nonlinearity measurement principle using finite amplitude insertion substitution (FAIS), we established a relationship between volume fraction and the amplitude of the second harmonic components in the received ultrasound waveform. With the use of high-intensity ultrasonic excitation, two-end calibration, and second harmonic amplitude extraction, the volume fraction of water can be calculated. The performance of the proposed method is validated by the numerical simulations and experimental studies in a lab-scale flow loop. Good qualitative agreement between the model and results shows that the nonlinear ultrasonic measurement technique has good quantitative accuracy and high measurement sensitivity, which make it well suited for industrial applications.

A novel semi-analytical model for oil-water two-phase flow of a fractured vertical well in triple media carbonate reservoir

A novel semi-analytical model for oil-water two-phase flow of a fractured vertical well in triple media carbonate reservoir

Effect of Viscosity Action and Capillarity on Pore-Scale Oil–Water Flowing Behaviors in a Low-Permeability Sandstone Waterflood

Water flooding technology is an important measure to enhance oil recovery in oilfields. Understanding the pore-scale flow mechanism in the water flooding process is of great significance for the optimization of water flooding development schemes. Viscous action and capillarity are crucial factors in the determination of the oil recovery rate of water flooding. In this paper, a direct numerical simulation (DNS) method based on a Navier–Stokes equation and a volume of fluid (VOF) method is employed to investigate the dynamic behavior of the oil–water flow in the pore structure of a low-permeability sandstone reservoir in depth, and the influencing mechanism of viscous action and capillarity on the oil–water flow is explored. The results show that the inhomogeneity variation of viscous action resulted from the viscosity difference of oil and water, and the complex pore-scale oil–water two-phase flow dynamic behaviors exhibited by capillarity play a decisive role in determining the spatial sweep region and the final oil recovery rate. The larger the viscosity ratio is, the stronger the dynamic inhomogeneity will be as the displacement process proceeds, and the greater the difference in distribution of the volumetric flow rate in different channels, which will lead to the formation of a growing viscous fingering phenomenon, thus lowering the oil recovery rate. Under the same viscosity ratio, the absolute viscosity of the oil and water will also have an essential impact on the oil recovery rate by adjusting the relative importance between viscous action and capillarity. Capillarity is the direct cause of the rapid change of the flow velocity, the flow path diversion, and the formation of residual oil in the pore space. Furthermore, influenced by the wettability of the channel and the pore structure’s characteristics, the pore-scale behaviors of capillary force—including the capillary barrier induced by the abrupt change of pore channel positions, the inhibiting effect of capillary imbibition on the flow of parallel channels, and the blockage effect induced by the newly formed oil–water interface—play a vital role in determining the pore-scale oil–water flow dynamics, and influence the final oil recovery rate of the water flooding.

A pressure drop model of post-fracturing shut-in considering the effect of fracturing-fluid imbibition and oil replacement

Since the production regime of shut-in after fracturing is generally adopted for wells in shale oil reservoir, a shut-in pressure drop model coupling wellbore-fracture network-reservoir oil-water two-phase flow has been proposed. The model takes into account the effects of wellbore afterflow, fracture network channeling, and matrix imbibition and oil exchange after stop of pumping. The simulated log-log curve of pressure-drop derivative by the model presents W-shape, reflecting the oil-water displacement law between wellbore, fracture network and matrix, and is divided into eight main control flow stages according to the soaking time. In the initial stage of pressure drop, the afterflow dominates; in the early stage, the pressure drop is controlled by the cross-flow and leakoff of the fracture system, and the fractures close gradually; in the middle stage of pressure drop, matrix imbibition and oil exchange take dominance, and the fracturing fluid loss basically balances with oil replaced from matrix; the late stage of pressure drop is the reservoir boundary control stage, and the leakoff rate of fracturing-fluid and oil exchange rate decrease synchronously till zero. Finally, the fracture network parameters such as half-length of main fracture, main fracture conductivity and secondary fracture density were inversed by fitting the pressure drop data of five wells in Jimsar shale oil reservoir, and the water imbibition volume of matrix and the oil replacement volume in fracture were calculated by this model. The study results provide a theoretical basis for comprehensively evaluating the fracturing effect of shale oil horizontal wells and understanding the oil-water exchange law of shale reservoir after fracturing.

Effect of rubber particles on water flow behavior in fractured-vuggy reservoirs

The presence of the large channel in fractured-vuggy reservoirs diminishes the sweep efficiency of any water, gas or polymer flooding. This paper presents a novel type of rubber particle for water shutoff agent and the flow direction of water is adjusted by plugging the large channel. Simultaneously, through the microscopic displacement experiment of the organic glass etching model, the water flow behavior and injection parameters optimization are studied. The results show that the resistance of solid media to fluid flow is almost zero when the oil-water two-phase flow occurs, and the gravity action is prominent. Therefore, there are still a lot of residual oil of karst cave, flow around oil and attic oil with poor connectivity after the fractured-vuggy reservoir is displaced by injected water. In addition, the rubber particles can form a temporary plugging zone by migration – accumulation – bridging under formation conditions, resulting in the flow direction of subsequent injection water changes from the large channel to the small channel, thereby reducing water content and increasing oil production. By optimizing the injection parameters of rubber particles, the optimal injection volume, particle size and injection speed are obtained, which are 0.02PV, 0–1 mm, 2–4 mm and 25 mL/min, respectively.