Virtual Measurement in Pipes: Part 2-Liquid Holdup and Flow Pattern Correlations

1995 ◽  
Author(s):  
J. Ternyik ◽  
H.I. Bilgesu ◽  
S. Mohaghegh
Keyword(s):  
Flow Pattern ◽  
Liquid Holdup

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 Engineering Simulation Tests on Multiphase Flow in Middle- and High-Yield Slanted Well Bores

Energies ◽  
2018 ◽  
Vol 11 (10) ◽  
pp. 2591 ◽  
Author(s):  
Dan Qi ◽  
Honglan Zou ◽  
Yunhong Ding ◽  
Wei Luo ◽  
Junzheng Yang
Keyword(s):  
Multiphase Flow ◽  
Prediction Model ◽  
Flow Pattern ◽  
Pipe Flow ◽  
Slug Flow ◽  
High Yield ◽  
Transition Flow ◽  
Liquid Holdup ◽  
Flow Pattern Map ◽  
Flow Pressure

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%.

Study on the Pigging Process of Rich Gas Pipeline

2014 ◽  
Vol 884-885 ◽  
pp. 242-246
Author(s):  
Wei Qiang Wang ◽  
Kai Feng Fan ◽  
Yu Fei Wan ◽  
Ming Wu ◽  
Le Yang
Keyword(s):  
Natural Gas ◽  
Flow Pattern ◽  
Fluid Model ◽  
Simulation Software ◽  
Gas Pipeline ◽  
Liquid Holdup ◽  
Two Phase ◽  
Natural Gas Pipeline ◽  
Fluid Transient ◽  
Safety Operation

Intensive study on flowing properties of two-phase fluid of gas and liquid during pipeline pigging helps to improve the safety operation of rich gas pipeline. Therefore, based on the multiphase fluid transient simulation software, a two-fluid model is employed to study the flowing regulation of gas and liquid in practical operation of natural gas pipeline pigging,especially the change rule of velocity,flow pattern, pressure, liquid holdup ratio, and liquid slug in the passing ball process. The results reveal that three flow patterns appeared in pipeline pigging. They are stratified flow, slug flow and bubble flow. The place where the particular flow pattern appears is related to the terrain. The biggest pressure is found at the entrance, then pressure comes down along the pipeline, and fluctuate according to the fluid amount and terrain; the transient velocity of pig is coherent with the terrain and liquid holdup ratio; small slug flows are easy to gather and form into a longer one. The research can somehow guide to the safety operation of natural gas pipeline pigging.

Effect of Surfactant (Foamer) Delivery Location on Horizontal Wells Deliquification

2017 ◽  
Author(s):  
Carolina V. Barreto ◽  
Hamidreza Karami ◽  
Eduardo Pereyra ◽  
Cem Sarica
Keyword(s):  
Pressure Drop ◽  
Flow Pattern ◽  
Flow Rate ◽  
Gas Flow ◽  
Vertical Section ◽  
Horizontal Wells ◽  
Static Mixer ◽  
Liquid Holdup ◽  
Liquid Loading ◽  
Delivery Location

One of the methods to unload liquid from gas wells is foam-assisted lift. The applied surfactant reduces the liquid surface tension facilitating foam stability, and consequently, reducing mixture density and gas slippage. In this experimental study, a 2-in ID facility consisting of a 64-ft lateral section followed by a 41-ft vertical section is used to determine the optimum surfactant delivery location in horizontal wells. Water and compressed air are the liquid and gas phases, and an anionic surfactant is applied continuously with fixed concentration. Lateral section inclination is varied between ±1°, and four injection points are tested, including one with a static mixer, used as an external source of agitation. Recorded parameters are flow pattern, pressure gradient, liquid holdup, and foam quality. In the lateral section, the highest efficiency is obtained by using a static mixer causing significant drop in liquid holdup and increase in pressure drop due to frictional losses. All other injection points show similar behavior to the air-water case, due to negligible generated foam amid the existing flow pattern agitation. In the vertical section, all injection points show similar and significant drops in liquid holdup and delays in liquid loading onset compared to air-water case, and foam quality decreases as gas flow rate is reduced. Increasing the liquid flow rate causes increases in liquid holdup and pressure drop and shifts liquid loading onset to higher gas flow rates. The experimentally observed liquid loading onset is compared to the predictions of Turner et al. (1969), and a modification is proposed in this correlation to consider the effects of surfactant injection. The number of experimental studies investigating foam effects on liquid loading is limited especially for off-vertical configurations. The results of this study provide an experimental source to optimize foam lift in deviated wells.

Investigation of two-phase flow pattern, liquid holdup and pressure drop in viscous oil–gas flow

2014 ◽  
Vol 67 ◽  
pp. 37-51 ◽  
Author(s):  
Hatef A. Khaledi ◽  
Ivar Eskerud Smith ◽  
Tor Erling Unander ◽  
Jan Nossen
Keyword(s):  
Pressure Drop ◽  
Flow Pattern ◽  
Gas Flow ◽  
Two Phase Flow ◽  
Phase Flow ◽  
Liquid Holdup ◽  
Two Phase ◽  
Viscous Oil ◽  
Oil Gas

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.

Analysis of Two-Phase Tests in Large-Diameter Flow Lines in Prudhoe Bay Field

1981 ◽  
Vol 21 (03) ◽  
pp. 363-378 ◽  
Author(s):  
James P. Brill ◽  
Zelimir Schmidt ◽  
William A. Coberly ◽  
John D. Herring ◽  
David W. Moore
Keyword(s):  
Flow Pattern ◽  
Slug Flow ◽  
Pressure Loss ◽  
Large Diameter ◽  
Small Diameter ◽  
Liquid Holdup ◽  
Flow Lines ◽  
Two Phase ◽  
Diameter Pipe ◽  
Prudhoe Bay

Abstract A total of 29 two-phase flow tests was conducted in two 3-mile-long flow lines in the Prudhoe Bay field of Alaska. Of these, 11 were for a l2-in.-diameter line and 18 were for a 16-in. line. Nine of the tests were in slug flow, and 20 were in froth flow. Flow rates, inlet and outlet pressures, and temperatures were measured for each test. Gamma densitometers were used to monitor flow pattern and to determine mixture densities and slug characteristics. It was found that a modified Beggs-Brill1 pressure-loss correlation predicted culled data to within -1.5% on the average compared with +11.4% for a modified Dukler-Eaton2,3 correlation. Very little scatter was observed with either method. Analysis of flow-pattern observations showed that none of the slug-flow tests were in the Schmidt4 severe slug region characterized by extremely long slugs. It also was found that the slug/froth (dispersed) flow-pattern boundary existed at a much lower liquid flow rate than predicted by either Mandhane et al.5 or Taitel and Dukler.6 Four of the slug-flow tests in 16-in. lines lasted for a sufficient time to permit statistical analysis of slug-length distributions. Sixteen additional tests on 4- and 7-in.-diameter pipe reported by Brainerd and Hedquist* were analyzed statistically. It was found that slug lengths could be represented by a log-normal distribution. A regression analysis approach was successful for estimating the mean slug length for stabilized flow as a function of superficial mixture velocity and pipe diameter. The extreme percentiles of the slug-length distribution then can be computed using standard probability tables, making possible probability statements about expected maximum slug length. A mechanistic analysis of the slug-flow tests resulted in equations for predicting slug velocities, liquid holdup in both the liquid slug and the gas bubble, and the volumes of liquid that are produced and overrun. These parameters are important for predicting liquid-slug effects on separator performance. Introduction The simultaneous flow of gas and liquid in pipes is encountered frequently in the petroleum industry. production of oil with associated gas has led to numerous attempts to predict pressure loss in tubing and flow lines. An abundance of empirical correlations has been developed for predicting two-phase steady-state pressure losses and liquid holdup. All of these correlations were based on data in small-diameter pipe. The recent increase in exploration and production activity in hostile environments such as the North Slope of Alaska and several offshore areas has resulted in decisions to transport gas and liquid simultaneously in large-diameter flow lines over relatively long distances. Design of large-diameter flow lines has required use of empirical correlations based on small-diameter pipe. In general, pressure-loss predictions from this approach have been acceptable, but prediction of liquid volumes in the pipe has been poor.

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