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Relevant bibliographies by topics / Liquid Holdup in Vertical Multiphase Flow

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Academic literature on the topic 'Liquid Holdup in Vertical Multiphase Flow'

Author: Grafiati

Published: 4 June 2021

Last updated: 1 February 2022

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Journal articles on the topic "Liquid Holdup in Vertical Multiphase Flow"

1

Wang, Dayang, Ningde Jin, Lusheng Zhai, and Yingyu Ren. "Salinity Independent Flow Measurement of Vertical Upward Gas-Liquid Flows in a Small Pipe Using Conductance Method." Sensors 20, no. 18 (September 15, 2020): 5263. http://dx.doi.org/10.3390/s20185263.

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Flow measurement in gas-liquid two-phase flow is always a challenging work, because of the non-uniform phase distribution, severe slippage effect between phases, and different flow structures. Furthermore, the variation of salinity changes the water conductivity, which brings more difficulties to multiphase flow measurement. In this study, a methodology for flow measurement using the conductance method in gas-liquid two-phase flow with salinity change is proposed. The methodology includes the suitable conductivity detection method, the strategy of using combined sensors, and the measurement models of flow parameters. A suitable conductivity detection method that can guarantee that the sensor output is linearly proportional to the conductivity is proposed. This conductivity detection method can ensure that the sensors have a high and constant resolution in the conductivity variation caused by water holdup under the conditions of water conductivity change. Afterward, a combined sensor system consisting of a water holdup sensor, velocity sensor, and water conductivity sensor is designed and experimentally evaluated in gas-water two-phase flow in a 20 mm inner diameter pipe. Considering the non-uniform phase distribution, severe slippage effect between phases, different flow structures, and the variation of salinity, a new water holdup measurement model and flow velocity measurement models are established to achieve salinity independent water holdup measurement and flow velocity measurement for the first time.

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2

Ren, Guishan, Dangke Ge, Peng Li, Xuemei Chen, Xuhui Zhang, Xiaobing Lu, Kai Sun, Rui Fang, Lifei Mi, and Feng Su. "The Flow Pattern Transition and Water Holdup of Gas–Liquid Flow in the Horizontal and Vertical Sections of a Continuous Transportation Pipe." Water 13, no. 15 (July 30, 2021): 2077. http://dx.doi.org/10.3390/w13152077.

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A series of experiments were conducted to investigate the flow pattern transitions and water holdup during oil–water–gas three-phase flow considering both a horizontal section and a vertical section of a transportation pipe simultaneously. The flowing media were white mineral oil, distilled water, and air. Dimensionless numbers controlling the multiphase flow were deduced to understand the scaling law of the flow process. The oil–water–gas three-phase flow was simplified as the two-phase flow of a gas and liquid mixture. Based on the experimental data, flow pattern maps were constructed in terms of the Reynolds number and the ratio of the superficial velocity of the gas to that of the liquid mixture for different Froude numbers. The original contributions of this work are that the relationship between the transient water holdup and the changes of the flow patterns in a transportation pipe with horizontal and vertical sections is established, providing a basis for judging the flow patterns in pipes in engineering practice. A dimensionless power-law correlation for the water holdup in the vertical section is presented based on the experimental data. The correlation can provide theoretical support for the design of oil and gas transport pipelines in industrial applications.

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Alamu, Mhunir Bayonle. "Gas-Well Liquid Loading Probed With Advanced Instrumentation." SPE Journal 17, no. 01 (January 16, 2012): 251–70. http://dx.doi.org/10.2118/153724-pa.

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Summary Drop size, liquid holdup, and pressure drop have been measured simultaneously in real time. This experiment was carried out with air/water to establish annular two-phase flow on a 0.019-m-internal-diameter vertical pipe (7-m-long multiphase-flow facility). Drop concentration, distribution, and sizes in the core flow were measured using Spraytec, a light-diffraction-based instrumentation. Liquid holdup was logged with pairs of flush-mounted ring-conductance probes at various positions within the test section. Pressure drop was monitored using a differential-pressure meter mounted between two pressure taps separated by a distance of 1.5 m. Subtle changes were observed in the characteristic drop diameters around gas superficial velocities of 21 and 30 m/s following progressive, systematic increase in gas and liquid superficial velocities. The gas superficial velocities at which these changes were observed have been linked with transition boundaries to cocurrent and mist annular flows, respectively. Corresponding similar pseudochanges, fingerprinted in the liquid-holdup and pressure-drop data at these transition boundaries, in addition to film and drop-flow reversals captured on video, make the evidence more compelling. Applicability of core-flow dynamic data to explain various physical processes associated with gas-well liquid loading has been demonstrated.

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Qi, Dan, Honglan Zou, Yunhong Ding, Wei Luo, and Junzheng Yang. "Engineering Simulation Tests on Multiphase Flow in Middle- and High-Yield Slanted Well Bores." Energies 11, no. 10 (September 28, 2018): 2591. http://dx.doi.org/10.3390/en11102591.

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Previous multiphase pipe flow tests have mainly been conducted in horizontal and vertical pipes, with few tests conducted on multiphase pipe flow under different inclined angles. In this study, in light of mid–high yield and highly deviated wells in the Middle East and on the basis of existent multiphase flow pressure research on well bores, multiphase pipe flow tests were conducted under different inclined angles, liquid rates, and gas rates. A pressure prediction model based on Mukherjee model, but with new coefficients and higher accuracy for well bores in the study block, was obtained. It was verified that the newly built pressure drawdown prediction model tallies better with experimental data, with an error of only 11.3%. The effect of inclination, output, and gas rate on the flow pattern, liquid holdup, and friction in the course of multiphase flow were analyzed comprehensively, and six kinds of classical flow regime maps were verified with this model. The results showed that for annular and slug flow, the Mukherjee flow pattern map had a higher accuracy of 100% and 80–100%, respectively. For transition flow, Duns and Ros flow pattern map had a higher accuracy of 46–66%.

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Wordu, David Nwobisi, Felix J. K. Ideriah, and Barinyima Nkoi. "A Study of Pressure Gradient in Multiphase Flow in Vertical Pipes." European Journal of Engineering Research and Science 4, no. 1 (January 23, 2019): 54–59. http://dx.doi.org/10.24018/ejers.2019.4.1.1090.

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The study of multiphase flow in vertical pipes is aimed at effective and accurate design of tubing, surface facilities and well performance optimization for the production of oil and gas in the petroleum industry by developing a better approach for predicting pressure gradient. In this study, field data was analyzed using mathematical model, multiphase flow correlations, statistical model, and computer programming to predict accurately the flow regime, liquid holdup and pressure drop gradient which are important in the optimization of well. A Computer programme was used to prediction pressure drop gradient. Four dimensionless parameters liquid velocity number (Nlv), gas velocity number (Ngv), pipe diameter number (Nd), liquid viscosity number (Nl), were chosen because they represent an integration of the two dominant components that influence pressure drop in pipes. These dominant component are flow channel/media and the flowing fluid. The model was found to give a fit of 100% to the selected data points. Hagedorn & Brown, Griffith &Wallis correlations and model were compared with field data and the overall pressure gradient for a total depth of 10000ft was predicted. The predicted pressure gradient measured was found to be 0.320778psi/ft, Graffith& Wallis gave 0.382649Psi/ft, Hagedorn & Brown gave 0.382649Psi/ft; whereas generated model gave 0.271514Psi/ft. These results indicate that the model equation generated is better and leads to a reasonably accurate prediction of pressure drop gradient according to measured pressure gradient.

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Shynybayeva, Amina, and Luis R. Rojas-Solórzano. "Eulerian–Eulerian Modeling of Multiphase Flow in Horizontal Annuli: Current Limitations and Challenges." Processes 8, no. 11 (November 9, 2020): 1426. http://dx.doi.org/10.3390/pr8111426.

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Multiphase flows are present in many natural phenomena, processing technologies, and industries. In the petroleum industry, the multiphase flow is highly relevant, and special attention is paid to the development of predictive tools that determine flow conditions to guarantee safe and economic hydrocarbon extraction and transportation. Hydrodynamic aspects such as pressure drop and holdup are of primary relevance for the field engineer in daily operations like pumping power calculation and equipment selection and control. Multiphase flow associated with oil production is usually a mixture of liquids and gas. The hydrodynamic behavior has been studied in different pipeline configurations (i.e., vertical ascending/descending and horizontal/inclined pipelines). However, the available information about flow patterns as well as the general conditions present in horizontal annuli is incomplete, even if they are of fundamental relevance in today’s horizontal drilling, production, and well intervention in many oil wells around the world. This review aims to present an in-depth revision of the existing models developed to predict two-phase flow patterns and hydrodynamic conditions in annuli flow, focusing mainly on, but not limited to, horizontal configuration. Key flow parameters and effects caused by annuli geometry and the physical properties of fluids are extensively discussed in the present paper. Different empirical correlations and mechanistic and numerical models on two-phase flow through horizontal/inclined pipelines and in both concentric and eccentric annuli are analyzed. Some of these models partially agree with experimental results and show acceptable predictions of frictional pressure loss and flow patterns. Limitations in current models and challenges to be faced in the next generation of models are also discussed.

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Al-Darmaki, Saeed, Gioia Falcone, Colin Hale, and Geoffrey Hewitt. "Experimental Investigation and Modeling of the Effects of Rising Gas Bubbles in a Closed Pipe." SPE Journal 13, no. 03 (September 1, 2008): 354–65. http://dx.doi.org/10.2118/103129-pa.

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Summary Transient multiphase flow in the wellbore causes problems in well-test interpretation when the well is shut in at surface and the pressure is measured downhole. Pressure-buildup data recorded during a test can be dominated by transient wellbore effects (i.e., phase change, flow reversal, and re-entry of the denser phase into the producing zone), making it difficult to distinguish between true reservoir features and transient wellbore artifacts (Gringarten et al. 2000). This paper is a follow-up to paper SPE 96587 (Ali et al. 2005), which presented experimental results of phase redistribution effects on pressure-buildup data. Though the results of the experiments were revealing, they are complex because they reflect the real well situation. To obtain results in which the phase redistribution in the well is studied independently of the interaction with the reservoir, a further set of experiments was carried out. In these experiments, the tube (simulating the well) was isolated at both the top and the bottom at the same time. The pressure distribution was measured during the transient following shut-in and for the steady-state final condition, in which there was a liquid-filled zone at the bottom of the test section and a gas-filled zone at the top. A substantial number of tests were conducted in the bubbly-flow region and could therefore be analyzed by a simple 1D model for bubbly flow. The results of the comparison between the model and the experimental data are presented in this paper. Introduction In the first study (Ali et al. 2005), experiments were carried out to investigate the effects of wellbore phase redistribution (WPR) and phase re-injection on pressure-buildup data. Single-phase- and two-phase-flow tests were conducted with air and water in the long-tube system (LOTUS) at Imperial College. The LOTUS test layout, as described in paper SPE 96587 (Alii et al. 2005), was designed to simulate a reservoir connected, by a resistance, to the base of a flowing well. The "reservoir" was recreated by a pressurized vessel, while the "well" was simulated by a 10.8-m -long, 32-mm-internal-diameter vertical pipe (i.e., the main LOTUS test section). The well was flowed at controlled rates to mimic those encountered in gas/condensate reservoirs. After steady-state conditions had been attained, the well was shut in at the top of the rig (i.e., at the surface) and the associated transient phenomena were monitored through distributed measurements of pressure, temperature, liquid holdup, and wall shear stress. Pressure-buildup data were interpreted with established well-test-analysis techniques. These initial experiments provided a qualitative and quantitative understanding of the effects of gas rates, liquid rates, and rising gas bubbles on WPR and phase re-injection. Gas flow rate was found to have a higher effect than water flow rate on WPR. This was most probably because of annular flow being the predominant flow regime for the experiments. Phase re-injection was simulated successfully. The lower the reservoir pressure, the higher the liquid re-injection, an analog to low-permeability reservoirs. For a closed system, WPR took place. Rising gas caused an increase in bottomhole pressure. The focus of the second study, presented here, was to investigate WPR independently of the interactions with the reservoir. The LOTUS tube was isolated at both the top and the bottom at the same time. The test section was again the LOTUS 10.8-m-long, 32-mm-internal-diameter vertical tube. A two-phase flow was set up with known air- and water-flow rates. The pressure distribution and void fraction were measured for the steady-state flow, and the flow subsequently was shut down by closing valves at the top and bottom of the test section simultaneously. Although the experiments covered a wide range of conditions, a substantial number of tests were conducted in the bubbly-flow regime. A simple, 1D model for bubbly flow was developed and implemented for comparison with the experimental data. Earlier efforts toward understanding the physics of gas-bubble migration in wells were carried out by Hasan and Kabir (1994; 1993) and Xiao et al. (1996). Aremu (2005) provided an overview of bubbly-flow models applied to the problem of gas kicks while drilling. A detailed review of previously published work on research into transient wellbore phenomena is presented by Falcone (2006). In recent years, much work has been carried out on the phenomena occurring in bubbly flows with a wide range of local measurements, and increasingly, many use computational methods to represent the detailed motions and interfacial deformations of the bubbles.

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Denney, Dennis. "Flow Regimes and Liquid Holdup in Horizontal Multiphase Flow." Journal of Petroleum Technology 53, no. 10 (October 1, 2001): 42. http://dx.doi.org/10.2118/1001-0042-jpt.

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Tromp, Rutger R., and Lucas M. C. Cerioni. "Multiphase Flow Regime Characterization and Liquid Flow Measurement Using Low-Field Magnetic Resonance Imaging." Molecules 26, no. 11 (June 2, 2021): 3349. http://dx.doi.org/10.3390/molecules26113349.

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Multiphase flow metering with operationally robust, low-cost real-time systems that provide accuracy across a broad range of produced volumes and fluid properties, is a requirement across a range of process industries, particularly those concerning petroleum. Especially the wide variety of multiphase flow profiles that can be encountered in the field provides challenges in terms of metering accuracy. Recently, low-field magnetic resonance (MR) measurement technology has been introduced as a feasible solution for the petroleum industry. In this work, we study two phase air-water horizontal flows using MR technology. We show that low-field MR technology applied to multiphase flow has the capability to measure the instantaneous liquid holdup and liquid flow velocity using a constant gradient low flip angle CPMG (LFA-CPMG) pulse sequence. LFA-CPMG allows representative sampling of the correlations between liquid holdup and liquid flow velocity, which allows multiphase flow profiles to be characterized. Flow measurements based on this method allow liquid flow rate determination with an accuracy that is independent of the multiphase flow profile observed in horizontal pipe flow for a wide dynamic range in terms of the average gas and liquid flow rates.

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Xipeng, Zheng, Wang Le, Jia Xiaoxuan, Xiang Wenchuan, and Yang Shunsheng. "Numerical Simulation of Gas-Liquid Flow in a Bubble Column by Intermittent Aeration in Newtonian Liquid/Non-Newtonian Liquid." International Journal of Chemical Engineering 2018 (November 6, 2018): 1–12. http://dx.doi.org/10.1155/2018/5254087.

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The dynamic behaviors of gas-liquid two-phase flow were simulated in a lab-scale intermittent bubble column by Euler-Euler two-fluid model coupled with the PBM (population balance model) using two different liquid phases, i.e., Newtonian fluid (water)/non-Newtonian fluid (activated sludge). When non-Newtonian fluid was used during intermittent aeration, some interesting results were obtained. Two symmetric vortexes existed in the time-averaged flow field; the vertical time-averaged velocity of the liquid phase decreased with increasing anaerobic time; the average gas holdup distribution was like a trapezoid with long upper side and short lower side and affected by the dynamic viscosity of the liquid phase. Compared with non-Newtonian fluid, the use of Newtonian fluid as the liquid phase led to a more complicated time-averaged flow field structure and vertical time-averaged velocity distribution, higher average gas holdup, and the asymmetric column-shaped gas holdup distribution with increasing anaerobic time. For different liquid phases, the instantaneous flow field, instantaneous vertical velocity, and instantaneous gas holdup distribution all periodically changed with anaerobic time; however, different from Newtonian liquid phase, non-Newtonian liquid phase had no periodic oscillating instantaneous horizontal velocity.

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Dissertations / Theses on the topic "Liquid Holdup in Vertical Multiphase Flow"

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Akor, Innocent Collins. "Liquid Holdup in Vertical Air/Water Multiphase Flow with Surfactant." University of Dayton / OhioLINK, 2013. http://rave.ohiolink.edu/etdc/view?acc_num=dayton1382076807.

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Maley, Lisa. "A study of slug flow characteristics in large diameter horizontal multiphase pipelines." Ohio : Ohio University, 1997. http://www.ohiolink.edu/etd/view.cgi?ohiou1177090588.

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Duran, Tibo. "Summary of Laboratory Multiphase Flow Studies in 2” Diameter Pipe at the University of Dayton and Comparison to OLGA Predictions." University of Dayton / OhioLINK, 2015. http://rave.ohiolink.edu/etdc/view?acc_num=dayton1430004871.

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4

Aliyu, A. M. "Vertical annular gas-liquid two-phase flow in large diameter pipes." Thesis, Cranfield University, 2015. http://dspace.lib.cranfield.ac.uk/handle/1826/9848.

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Gas-liquid annular two phase flow in pipes is important in the oil and gas, nuclear and the process industries. It has been identified as one of the most frequently encountered flow regimes and many models (empirical and theoretical) for the film flow and droplet behaviour for example have been developed since the 1950s. However, the behaviour in large pipes (those with diameter greater than 100 mm) has not been fully explored. As a result, the two- phase flow characteristics, data, and models specifically for such pipes are scarce or non-existent such that those from smaller pipes are extrapolated for use in design and operation. Many authors have cautioned against this approach since multiphase pipe flow behaviour is different between small and large pipes. For instance the typical slug flows seem not to occur in vertical upwards flows when the pipe diameter exceeds 100 mm. It is therefore imperative that theoretical models and empirical correlations for such large diameter pipes are specifically developed.

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5

Van, der Merwe Werner. "The Morphology of trickle flow liquid holdup." 2004. http://upetd.up.ac.za/thesis/available/etd-02162005-085324/.

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Book chapters on the topic "Liquid Holdup in Vertical Multiphase Flow"

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Lucas, D., M. Beyer, and L. Szalinski. "Experiments on Gas-Liquid Flow in Vertical Pipes." In Handbook of Multiphase Flow Science and Technology, 1–45. Singapore: Springer Singapore, 2016. http://dx.doi.org/10.1007/978-981-4585-86-6_15-1.

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Sakaguchi, T., H. Shakutsui, H. Minagawa, A. Tomiyama, and H. Takahashr. "Pressure Drop in Gas-Liquid-Solid Three Phase Bubbly Flow in Vertical Pipes." In Multiphase Flow 1995, 417–29. Elsevier, 1995. http://dx.doi.org/10.1016/b978-0-444-81811-9.50042-1.

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Ito, A., N. Masunaga, and K. Baba. "Marangoni Effects on Wave Structure and Liquid Film Breakdown along a Heated Vertical Tube." In Multiphase Flow 1995, 255–65. Elsevier, 1995. http://dx.doi.org/10.1016/b978-0-444-81811-9.50027-5.

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Founti, M. A., T. J. Achimastos, D. A. Dimopoulos, and A. S. Klipfel. "Experimental and Computational Investigation of Particle-particle Interactions in a Vertical, Sudden Expansion Liquid-solid Flow." In Multiphase Flow 1995, 47–62. Elsevier, 1995. http://dx.doi.org/10.1016/b978-0-444-81811-9.50009-3.

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Harvel, G. D., K. Hori, K. Kawanishi, and J. S. Chang. "Real-Time Cross-Sectional Averaged Void Fraction Measurements in Vertical Annulus Gas-Liquid Two-Phase Flow by Neutron Radiography and X-ray Tomography Techniques." In Multiphase Flow 1995, 781–92. Elsevier, 1995. http://dx.doi.org/10.1016/b978-0-444-81811-9.50074-3.

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Conference papers on the topic "Liquid Holdup in Vertical Multiphase Flow"

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Michel, Guillermo G., and Faruk Civan. "Accurate Well-Bore Hydraulics Simulation Considering Non-Isothermal and Liquid-Slippage Phenomena for Multiphase Flow in Oil and Gas Wells." In ASME 2009 28th International Conference on Ocean, Offshore and Arctic Engineering. ASMEDC, 2009. http://dx.doi.org/10.1115/omae2009-80068.

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A review of studies relevant to describing the non-ideal behavior encountered in oil and gas flow through wells is presented. The empirical prediction of liquid holdup and relaxation in time of gas separation from liquid phases are considered as mechanisms for explaining the nonideal behavior. Several features in modeling multiphase flow are discussed. The details of interest are elaborated for each reviewed approach and summarized. An application is presented in order to illustrate the holdup and relaxation profiles for vertical oil wells. The results are obtained by applying a novel formulation for liquid holdup modeling.

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Shirazi, Siamack A., and Brenton S. McLaury. "Predicting Solid Particle Erosion in Multiphase Flow: Challenges and Success Stories (Keynote Paper)." In ASME 2009 Fluids Engineering Division Summer Meeting. ASMEDC, 2009. http://dx.doi.org/10.1115/fedsm2009-78580.

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Solid particle erosion is a major problem in many industrial applications where solids are entrained in gas and/or liquid flows. For example, erosion of production equipment, well tubing and fittings is a major operating problem that costs the petroleum industry millions of dollars each year. Entrained sand particles in the oil/gas production fluid impinge on the inner surfaces of the pipes, fittings, and valves that result in solid particle erosion. In certain production situations with corrosive fluids, erosion is compounded with corrosion causing severe erosion-corrosion. Even in situations when sand control means are utilized such as gravel packing and sand screens, small sand particles can plug sand screens promoting higher flow velocities through other portions of the screens causing failure and allowing sand production. Erosion can cause severe damage to the piping and equipment wall, resulting in loss of equipment and production downtime. Solid particle erosion is a mechanical process by which material is removed gradually from a solid surface due to repeated impingement of small solid particles on the metal surface. The erosion phenomenon is highly complicated due to the number of parameters affecting the erosion severity, such as production flow rate, sand rate, fluid properties, flow regime, sand properties, sand shape and size, wall material of equipment, and geometry of the equipment. For ductile materials, erosion is caused by localized deformation and cutting action from repeated particle impacts. It is well known that solid particle erosion rates are a strong function of the impacting velocity of particles and also the mass of impacting particles. Predicting solid particle erosion in multiphase flow is a complex task due to existence of different flow patterns. The existence of different flow patterns and sand and liquid holdup in vertical and horizontal pipes means that a unique erosion model has to be developed for each flow regime if the model is to account for the number and velocity of impacting particles. The particle impact velocity is affected by the pipe geometry, carrying fluid properties and velocity, flow pattern, particle size and distribution in the flow. Among different multiphase flow patterns in horizontal and vertical flows, severe erosion damage can occur in annular and slug flows with high gas velocities and low liquid velocities. Although there is a lack of accurate mechanistic models to predict solid particle erosion, there is a need to develop engineering prediction models for multiphase flows. Earlier erosion calculation procedures in multiphase flow were primarily based on empirical data and the accuracy of those “empirical” models was limited to the flow conditions of the experiments. A framework for developing a model has been established for predicting erosion rates of elbows in multiphase flow. The model considers the effects of particle velocities in gas and liquid phases upstream of the elbow. Local fluid velocities in multiphase flow are used to determine representative particle impact velocities. Also based on data representing sand holdup for several flow regimes, the masses of impacting particles are estimated. Erosion experiments are also conducted on elbows in two-inch and three-inch large scale multiphase flow loops with gas, liquid and sand flowing in vertical and horizontal test sections. Based on the experimental data for different flow regimes including slug, wet gas and annular flow a method for improving a previous model is discussed and is being implemented to predict erosion rates in multiphase flow.

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Fazeli, Ahmad, and Ali Vatani. "Computer Programming Simulation of Two-Phase Flow Pipelines Using Mechanistic and Semi-Empirical Models." In 2006 International Pipeline Conference. ASMEDC, 2006. http://dx.doi.org/10.1115/ipc2006-10017.

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Two-phase flow pipelines are utilized in simultaneous transferring of liquid and gas from reservoir fields to production units and refineries. In order to obtain the hydraulic design of pipelines, pressure drop and liquid holdup were calculated following pipeline flow regime determination. Two semi-empirical and mechanistical models were used. Empirical models e.g. Beggs & Brill, 1973, are only applicable in certain situations were pipeline conditions are adaptable to the model; therefore we used the Taitel & Dukler, 1976, Baker et al., 1988, Petalas & Aziz, 1998, and Gomez et al., 1999, mechanistical models which are practical in more extensive conditions. The FLOPAT code was designed and utilized which is capable of the determining the physical properties of the fluid by either compositional or non-compositional (black oil) fluid models. It was challenged in various pipeline positions e. g. horizontal, vertical and inclined. Specification of the flow regime and also pressure drop and liquid holdup could precisely be calculated by mechanistical models. The flow regimes considered in the pipeline were: stratified, wavy & annular (Segregated Flow), plug & slug (Intermittent Flow) and bubble & mist (Distributive Flow). We also compared output results against the Stanford Multiphase Flow Database which were used by Petalas & Aziz, 1998, and the effect of the flow rate, pipeline diameter, inclination, temperature and pressure on the flow regime, liquid holdup and pressure drop were studied. The outputs (flow regime, pressure drop and liquid holdup) were comparable with the existing pipeline data. Moreover, by this comparison one may possibly suggest the more suitable model for usage in a certain pipeline.

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Ma, Bowen, and Narakorn Srinil. "Dynamic Characteristics of Deep-Water Risers Carrying Multiphase Flows." In ASME 2018 37th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2018. http://dx.doi.org/10.1115/omae2018-77381.

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Deep-water flexible risers conveying hydrocarbon oil and gas flows may be subject to internal dynamic fluctuations associated with the spatial variations of phase densities, velocities and pressure drops. Many studies have focused on single-phase flows in pipes whereas understanding of multiphase flow effects is lacking. This study aims to investigate the planar free-vibration characteristics of a long flexible catenary riser carrying the steady-state, multiphase slug oil-gas flows in order to understand how the inclination-dependent internal slug flows affect riser natural frequencies and modal shapes. The influence of slug characteristics such as phase velocities on the riser vibration is also studied. The catenary riser planar motions are mathematically described by a two-dimensional continuum model capturing coupled horizontal and vertical responses. Based on the selected two-phase flow rates at the wellhead, riser geometric configurations and specified slug unit lengths, a steady-state slug flow model is considered by taking into account several empirical closure correlations and riser mechanical properties, solving for the multiphase flow aspects including pressure, velocities, liquid holdup and gas fraction. By assigning an undamped free-vibration shape of an empty catenary riser as initial displacement conditions, the space-time numerical simulations are performed using a finite difference approach. Comparisons of oscillation frequencies, time histories, phase planes, time-space varying responses and dynamic stresses of catenary risers with and without slug flows are presented, identifying the dynamic modifications arising from the internal slug-induced mass momentum change and pressure loss. To understand the influence of slug flow properties, parametric studies are carried out with different gas velocities. Numerical results highlight the reduced riser tensions, decreased oscillation frequencies, multiple oscillation modes, amplified amplitudes and stresses. These key observations will be useful for the forced vibration analysis of catenary risers subject to combined internal (multiphase) and external (vortex-shedding) flow excitations.

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Girfoglio, M., F. De Rosa, G. Coppola, and L. de Luca. "Global eigenmodes of free-interface vertical liquid sheet flows." In MULTIPHASE FLOW 2013. Southampton, UK: WIT Press, 2013. http://dx.doi.org/10.2495/mpf130241.

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Ueyama, K. "Effect of relative motion between bubbles and surrounding liquid on the Reynolds stress as a mechanism controlling the radial gas holdup distribution." In MULTIPHASE FLOW 2009. Southampton, UK: WIT Press, 2009. http://dx.doi.org/10.2495/mpf090231.

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Sinkunas, S., J. Gylys, and A. Kiela. "Computational and experimental analyses of a liquid film flowing down a vertical surface." In MULTIPHASE FLOW 2007. Southampton, UK: WIT Press, 2007. http://dx.doi.org/10.2495/mpf070331.

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MUÑOZ-COBO, JOSÉ LUIS, SUSANA M. IGLESIAS, DANY S. DOMINGUEZ, ALBERTO ESCRIVÁ, and CÉSAR BERNA. "ANALYTICAL MODEL AND NUMERICAL STABILITY ANALYSIS FOR FALLING LIQUID FILM REGIMES IN VERTICAL PIPES." In MULTIPHASE FLOW 2019. Southampton UK: WIT Press, 2019. http://dx.doi.org/10.2495/mpf190091.

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Almabrok, A., L. Lao, and H. Yeung. "Effect of 180° bends on gas/liquid flows in vertical upward and downward pipes." In MULTIPHASE FLOW 2013. Southampton, UK: WIT Press, 2013. http://dx.doi.org/10.2495/mpf130361.

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Min, J. K., and I. S. Park. "Comparison of numerical schemes for computational simulation of liquid wavy film flow on vertical wall." In MULTIPHASE FLOW 2011. Southampton, UK: WIT Press, 2011. http://dx.doi.org/10.2495/mpf110031.

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