Oil-Gas-Water Three-Phase Slug Flow Liquid Holdup Model in Horizontal Pipeline

2006 ◽  
Author(s):  
Jing Mei Zhao ◽  
Jing Gong ◽  
Da Yu
Keyword(s):  
Slug Flow ◽  
Water Film ◽  
Mineral Oil ◽  
Superficial Velocity ◽  
Oil Viscosity ◽  
Liquid Holdup ◽  
Three Phase ◽  
Water Based ◽  
Water Cut ◽  
Oil Gas

According to experiments and relational documents, slug regime, appeared in this experiment, can be divided into the following flow regimes: oil-based separated slug, oil-based dispersed slug, water-based separated and water-based dispersed slug. Experiments for oil-gas-water three-phase flow in a stainless steel pipe loop (25.7mm inner diameter, 52m long) are conducted. Compressed air, mineral oil and water are used as experiment medium. Mineral oil Viscosity is 64.5mPa.s at 20°C. Gas superficial velocity, liquid superficial velocity and water cut ranges are 0.5∼15 m/s, 0.05∼0.5 m/s and 0∼100% respectively. There are some strange observed in this experiment. At the very low gas superficial velocity less than 1m/s, the average liquid holdup of low liquid superficial velocity was larger than that of higher liquid superficial velocity especially in higher inlet water cut experiments. This is because at very low gas superficial velocity, the regime is separated slug flow which has water film below their liquid film zone, velocity difference between oil film and water film will affect the average liquid holdup greatly. With the increase of gas and liquid superficial velocity, the regime becomes dispersed slug flow which oil and water are homogeneous. It will be more obvious with the increasing of water cut for the thicker water film. A new liquid holdup model of oil-based and water-based separated slug has been developed. Based on statistical analysis, it is observed that the new model gives excellent results against the experimental data.

A Case Study in Oil-Gas Transportation through Subsea Pipeline in Liaohe Tanhai Oilfield

2011 ◽  
Vol 317-319 ◽  
pp. 2239-2243
Author(s):  
Yang Liu ◽  
Zhi Hua Wang ◽  
Li Xin Wei ◽  
Ren Shan Pang
Keyword(s):  
Freezing Point ◽  
Self Control ◽  
Outlet Temperature ◽  
Oil Viscosity ◽  
Long Distance ◽  
Pump System ◽  
Public Projects ◽  
Well Production ◽  
Water Cut ◽  
Oil Gas

The crude oil in Kuidong region of Liaohe Tanhai Oilfield is characterized by high oil viscosity, high density, high content of colloid asphalt, low content of wax and low freezing point. In the shallow region, the large current, high content of silt, long-distance subsea buried pipeline and drift ice in winter have brought great challenge to offshore construction and oil-gas transportation. In this paper, the investigations of offshore construction project and platform process are shown. Based on the well production rate, gas-oil ratio, water cut, wellhead back pressure and outlet temperature, the range of daily transportation volume was acquired, as well as the maximum inlet pressure and pressure difference of the pump. The paper also selected technically and economically feasible pumps, then designed the public projects, corresponding electric power and self-control facilities. The selected skidded twin screw multiphase pump system can smoothly transport produced liquid to the terminal systems onshore without any effect on the daily output.

Pressure Effects on Low-Liquid-Loading Oil/Gas Flow in Slightly Upward Inclined Pipes: Flow Pattern, Pressure Gradient, and Liquid Holdup

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2221-2238 ◽  
Author(s):  
Hendy T. Rodrigues ◽  
Eduardo Pereyra ◽  
Cem Sarica
Keyword(s):  
Pressure Gradient ◽  
Flow Pattern ◽  
Slug Flow ◽  
Annular Flow ◽  
Flow Patterns ◽  
Pressure Effects ◽  
Liquid Holdup ◽  
Liquid Loading ◽  
Interfacial Roughness ◽  
Oil Gas

Summary This paper studied the effects of system pressure on oil/gas low–liquid–loading flow in a slightly upward inclined pipe configuration using new experimental data acquired in a high–pressure flow loop. Flow rates are representative of the flow in wet–gas transport pipelines. Results for flow pattern observations, pressure gradient, liquid holdup, and interfacial–roughness measurements were calculated and compared to available predictive models. The experiments were carried out at three system pressures (1.48, 2.17, and 2.86 MPa) in a 0.155–m–inside diameter (ID) pipe inclined at 2° from the horizontal. Isopar™ L oil and nitrogen gas were the working fluids. Liquid superficial velocities ranged from 0.01 to 0.05 m/s, while gas superficial velocities ranged from 1.5 to 16 m/s. Measurements included pressure gradient and liquid holdup. Flow visualization and wire–mesh–sensor (WMS) data were used to identify the flow patterns. Interfacial roughness was obtained from the WMS data. Three flow patterns were observed: pseudo-slug, stratified, and annular. Pseudo-slug is characterized as an intermittent flow where the liquid does not occupy the whole pipe cross section as does a traditional slug flow. In the annular flow pattern, the bulk of the liquid was observed to flow at the pipe bottom in a stratified configuration; however, a thin liquid film covered the whole pipe circumference. In both stratified and annular flow patterns, the interface between the gas core and the bottom liquid film presented a flat shape. The superficial gas Froude number, FrSg, was found to be an important dimensionless parameter to scale the pressure effects on the measured parameters. In the pseudo-slug flow pattern, the flow is gravity–dominated. Pressure gradient is a function of FrSg and liquid superficial velocity, vSL. Liquid holdup is independent of vSL and a function of FrSg. In the stratified and annular flow patterns, the flow is friction–dominated. Both pressure gradient and liquid holdup are functions of FrSg and vSL. Interfacial–roughness measurements showed a small variation in the stratified and annular flow patterns. Model comparison produced mixed results, depending on the specific flow conditions. A relation between the measured interfacial roughness and the interfacial friction factor was proposed, and the results agreed with the existing measurements.

scholarly journals CNN-Based Volume Flow Rate Prediction of Oil–Gas–Water Three-Phase Intermittent Flow from Multiple Sensors

Sensors ◽  
2021 ◽  
Vol 21 (4) ◽  
pp. 1245
Author(s):  
Jinku Li ◽  
Delin Hu ◽  
Wei Chen ◽  
Yi Li ◽  
Maomao Zhang ◽  
...  
Keyword(s):  
Deep Learning ◽  
Volume Flow ◽  
Superficial Velocity ◽  
Intermittent Flow ◽  
Horizontal Pipe ◽  
Flow Rates ◽  
Multiple Sensors ◽  
Three Phase ◽  
Test Loop ◽  
Oil Gas

In this paper, we propose a deep-learning-based method using a convolutional neural network (CNN) to predict the volume flow rates of individual phases in the oil–gas–water three-phase intermittent flow simultaneously by analyzing the measurement data from multiple sensors, including a temperature sensor, a pressure sensor, a Venturi tube and a microwave sensor. To build datasets, a series of experiments for the oil–gas–water three-phase intermittent flow in a horizontal pipe, in which gas volume fraction and water-in-liquid ratio ranges are 23.77–94.45% and 14.95–86.97%, respectively, and gas flow superficial velocity and liquid flow superficial velocity ranges are 0.66–5.23 and 0.27–2.14 m/s, respectively, have been carried out on a test loop pipeline. The preliminary results indicate that the model can provide relative prediction errors on the testing-1 dataset for the volume flow rates of oil-phase, gas-phase and water-phase within ±10% with 94.49%, 92.56% and 95.71% confidence levels, respectively. Additionally, the prediction results on the testing-2 dataset also demonstrate the generalization ability of the model. The consuming time of a prediction with one sample is 0.43 s on an Intel Xeon CPU E5-2678 v3, and 0.01 s on an NVIDIA GeForce GTX 1080 Ti GPU. Hence, the proposed CNN-based prediction model, which can fulfill the real-time application requirements in the petroleum industry, reveals the potential of using deep learning to obtain accurate results in the multiphase flow measurement field.

Simplified Stochastic Modelling of the Force on a Pipe Bend Due to Two-Phase Slug Flow

2021 ◽  
Author(s):  
Arnout M. Klinkenberg ◽  
Arris S. Tijsseling
Keyword(s):  
Fluid Dynamics ◽  
Computational Fluid Dynamics ◽  
Flow Pattern ◽  
Slug Flow ◽  
Oil And Gas ◽  
Length Distribution ◽  
Momentum Balance ◽  
Oil Viscosity ◽  
Liquid Holdup ◽  
Pipe Bend

Abstract Slug flow, a flow pattern with alternating aerated liquid pockets (slugs) and large gas bubbles, is a commonly observed flow pattern in oil and gas pipelines. Due to its unsteady character, the force on a pipe bend is fluctuating which results in unacceptable motions when the piping is insufficiently supported. To investigate the risk of fatigue failure of the system, finite-element models are used to predict the dynamic stresses required to estimate the fatigue life of the system. The excitation force of the slug flow is the essential input required for accurate fatigue damage predictions. A new, simplified model of slug forces on a bend is proposed. The model is calculating the slug force by solving the momentum balance over the pipe bend using slug flow properties as liquid holdup and phase velocities. Average properties predicted by a unit slug model cannot predict the stochastic force variations caused by the slug flow. The new approach introduces the stochastic character of slug flow in the force calculations via a log-normal slug length distribution. A Lagrangian slug tracking method is used to solve the governing equations. The modelled liquid holdup, pressure and predicted forces are compared with available measurements and Computational Fluid Dynamics calculations. The measurements were done under atmospheric conditions and the fluids used were air and water. Whether these measurements are representative for high-pressure oil and gas slug flow is unknown. By using a mechanistic approach where the main equations are based on physical laws instead of fitted measured data, the model is applicable for different fluids and operational conditions. To validate the model for oil and gas flows, the results are compared with Computational Fluid Dynamics calculations done with high gas density and typical oil viscosity.

scholarly journals The Performance of Drag Reducing Agent in Three Phase Slug Flow and Annular Flow

2000 ◽  
Author(s):  
C. Kang ◽  
D. Vedapuri ◽  
W. P. Jepson
Keyword(s):  
Pressure Drop ◽  
Slug Flow ◽  
Annular Flow ◽  
Maximum Pressure ◽  
Average Pressure ◽  
Effective Height ◽  
Pressure Drops ◽  
Three Phase ◽  
Water Cut ◽  
Maximum Pressure Drop

Experiments have been carried out in a 36-m long, 10-cm diameter multiphase horizontal flow system to examine the effect of drag reducing agents (DRA) on average pressure drop, maximum pressure drop and slug characteristics with the presence of water. Superficial liquid velocities between 0.5 and 1.5 m/s and superficial gas velocities between 2 and 14 m/s were investigated. Oil with a viscosity of 2.5 cP at 25 °C was used for the study. ASTM salt was used as a substitute for seawater and carbon dioxide was used as the gas. Water cut was 50%. Temperature and pressure were maintained at 25 °C and 0.13 MPa. The DRA concentrations of 0, 20 and 50 ppm were used in this study. The results show that the average pressure drop in both slug flow and annular flow decreased significantly with addition of DRA. Under special conditions, it was found that DRA changed the flow pattern from pseudo-slug to annular resulting in a 74% reduction in pressure drop. For annular flow, the average pressure drop reduction of up to 53% was achieved. The maximum pressure drop across the slug also decreased with the presence of DRA. The average and maximum pressure drops at a DRA concentration of 50 ppm were more effective than 20 ppm for all cases. The slug frequency and effective height of the liquid film decreased significantly when DRA concentrations were added. This led to a decrease in the average pressure drop. However, the slug translational velocity did not change significantly with addition of DRA.

scholarly journals Decoupling of Mechanical and Transport Properties in Organogels via Solvent Variation

Gels ◽  
2021 ◽  
Vol 7 (2) ◽  
pp. 61
Author(s):  
Kenneth P. Mineart ◽  
Cameron Hong ◽  
Lucas A. Rankin
Keyword(s):  
Mechanical Properties ◽  
Mechanical Behavior ◽  
Transdermal Drug Delivery ◽  
Triblock Copolymer ◽  
Polymer Concentration ◽  
Mineral Oil ◽  
Solute Diffusion ◽  
Oil Viscosity ◽  
Chain Entanglement ◽  
Mineral Oils

Organogels have recently been considered as materials for transdermal drug delivery media, wherein their transport and mechanical properties are among the most important considerations. Transport through organogels has only recently been investigated and findings highlight an inextricable link between gels’ transport and mechanical properties based upon the formulated polymer concentration. Here, organogels composed of styrenic triblock copolymer and different aliphatic mineral oils, each with a unique dynamic viscosity, are characterized in terms of their quasi-static uniaxial mechanical behavior and the internal diffusion of two unique solute penetrants. Mechanical testing results indicate that variation of mineral oil viscosity does not affect gel mechanical behavior. This likely stems from negligible changes in the interactions between mineral oils and the block copolymer, which leads to consistent crosslinked network structure and chain entanglement (at a fixed polymer concentration). Conversely, results from diffusion experiments highlight that two penetrants—oleic acid (OA) and aggregated aerosol-OT (AOT)—diffuse through gels at a rate inversely proportional to mineral oil viscosity. The inverse dependence is theoretically supported by the hydrodynamic model of solute diffusion through gels. Collectively, our results show that organogel solvent variation can be used as a design parameter to tailor solute transport through gels while maintaining fixed mechanical properties.

Image Fusion of ECT/ERT for Oil-Gas-Water Three-Phase Flow

2011 ◽  
Vol 3 (2) ◽  
pp. 29-34 ◽  
Author(s):  
Lifeng Zhang
Keyword(s):  
Image Fusion ◽  
Electrical Capacitance Tomography ◽  
Phase Flow ◽  
Electrical Capacitance ◽  
Cross Sectional ◽  
Three Phase ◽  
Three Phase Flow ◽  
Capacitance Tomography ◽  
Oil Gas ◽  
Image Fusion Method

The tomographic imaging of process parameters for oil-gas-water three-phase flow can be obtained through different sensing modalities, such as electrical resistance tomography (ERT) and electrical capacitance tomography (ECT), both of which are sensitive to specific properties of the objects to be imaged. However, it is hard to discriminate oil, gas and water phases merely from reconstructed images of ERT or ECT. In this paper, the feasibility of image fusion based on ERT and ECT reconstructed images was investigated for oil-gas-water three-phase flow. Two cases were discussed and pixel-based image fusion method was presented. Simulation results showed that the cross-sectional reconstruction images of oil-gas-water three-phase flow can be obtained using the presented methods.

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