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

2018 ◽  
Author(s):  
Hendy Rodrigues ◽  
Eduardo Pereyra ◽  
Cem Sarica
Keyword(s):  
Pressure Gradient ◽  
Flow Pattern ◽  
Gas Flow ◽  
Pressure Effects ◽  
Liquid Holdup ◽  
Liquid Loading ◽  
Inclined Pipes ◽  
Oil Gas

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.

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

The Effect of Surfactants on Vertical Air/Water Flow for Prevention of Liquid Loading

SPE Journal ◽  
2016 ◽  
Vol 21 (02) ◽  
pp. 488-500 ◽  
Author(s):  
A. T. van Nimwegen ◽  
L. M. Portela ◽  
R. A. Henkes
Keyword(s):  
Surface Tension ◽  
Pressure Gradient ◽  
Water Flow ◽  
Annular Flow ◽  
Surfactant Concentration ◽  
Gas Flow ◽  
Liquid Loading ◽  
Dynamic Surface ◽  
Flow Rates ◽  
Churn Flow

Summary From field experience in the gas industry, it is known that injecting surfactants at the bottom of a gas well can prevent liquid loading. To better understand how the selection of the surfactant influences the deliquification performance, laboratory experiments of air/water flow at atmospheric conditions were performed, in which two different surfactants (a pure surfactant, sodium dodecyl sulfate, and a commercial surfactant blend) were added to the water. In the experiments, a high-speed camera was used to visualize the flow, and pressure-gradient measurements were performed. Both surfactants increase the pressure gradient at high gas-flow rates and decrease the pressure gradient at low gas-flow rates. The minimum in the pressure gradient moves to lower gas-flow rates with increasing surfactant concentration. This is related to the transition between annular flow and churn flow, which is shifted to lower gas-flow rates because of the formation of an almost stagnant foam substrate at the wall of the pipe. At high surfactant concentration, it appears that the churn flow regime is no longer present at all and that there is a direct transition from annular flow to slug flow. The results also show that the critical micelle concentration, the equilibrium surface tension, the dynamic surface tension, and the surface elasticity are poor predictors of the effect of the surfactant on the flow.

Investigation of Back Pressure Effects on Transient Gas Flow Through Porous Media via Laboratory Experiments and Numerical Simulation

2014 ◽  
Author(s):  
Xiaolei Liu ◽  
Akkharachai Limpasurat ◽  
Gioia Falcone ◽  
Catalin Teodoriu
Keyword(s):  
Steady State ◽  
Gas Flow ◽  
Laboratory Experiments ◽  
Transient Flow ◽  
Pressure Profile ◽  
Back Pressure ◽  
Pressure Effects ◽  
Gas Wells ◽  
Liquid Loading ◽  
Final Steady State

When developing a transient numerical reservoir simulator, it is important to consider the back pressure effects that waves propagating from one end of the porous medium will have on the temporal distribution of pore fluid pressure within the medium itself. Such waves can be triggered by changing boundary conditions at the interface between reservoir and wellbore. An example is given by the transient reservoir response following pressure fluctuations at the wellbore boundary for gas wells suffering from liquid loading. Laboratory experiments were performed using a modified Hassler cell to mimic the effect of varying downhole pressure on gas flow in the near-wellbore region of a reservoir. Gauges were attached along a sandstone core to monitor the pressure profile. The results of the experiments are shown in this paper. A numerical code for modelling transient flow in the near-wellbore region was run to mimic the experiments. The comparisons of simulations and laboratory test results are presented here, for the initial and final steady-state flowing conditions, and where the inlet pressure was maintained constant while initiating a transient pressure build up at the core outlet. The concept of the U-shaped pressure profile along the near-wellbore region of a reservoir under transient flow conditions, originally proposed by Zhang et al. [1], was experimentally and numerically reproduced for single-phase gas flow. This is due to a combination of inertia and compressibility effects, leading to the reservoir response not being instantaneous. The results suggest that, in two phase gas-liquid conditions, liquid re-injection could occur during liquid loading in gas wells. From the experimental results, the U-shaped curves were more obvious and of longer duration in the case of greater outlet pressure. The transition from the initial to the final steady state condition occurred rapidly in all the cases shown here, with the U-shaped pressure profile appearing only over a relatively short time (at the small scale and low pressures tested in this study).

Flow Performance Investigation of Rich Gas Pipelines

2008 ◽  
Author(s):  
Daoming Deng ◽  
Jing Gong
Keyword(s):  
Pressure Gradient ◽  
Gas Flow ◽  
Single Phase ◽  
Temperature Drop ◽  
Gas Condensate ◽  
Gas Pipelines ◽  
Liquid Holdup ◽  
Two Phase ◽  
Operating Data ◽  
The Rich

For the rich gas transfer schemes, extraction of NGL from the natural gas is not required in the oil field or gas condensate field, so the gas treatment processes in the field is simplified and the expense from the storage and transportation of NGL is saved, and the gas processing plant could be located far from the field. Rich gas can be pipelined in single phase and/or in two-phase mode. Compared with the gas-condensate ones, the rich gas pipelines behave with lower liquid loading, and are easily controlled operationally. Therefore, the rich gas pipelining modes are increasingly preferred especially in offshore and desert petroleum developments. Prediction of the performances of rich gas flow in pipelines covers a series of calculations for fluid phase behavior, fluid properties, pressure gradient, liquid holdup and temperature drop. In the paper, a hydraulic and thermodynamic model for the analysis of rich gas flow in pipelines with single-phase or two-phase modes is outlined. On account of the low liquid holdup of rich gas two-phase flow in pipelines, the constitutive relation resulting from Ottens et al (2001) correlation is selected. The iterative method to compute the pressure gradient, liquid holdup, and temperature drop of a pipe increment is developed, which shows fast convergence and good stability through case computations. In the end, the performances of non-isothermal rich gas flow in the undulating offshore long-distance pipeline in China is investigated by analyzing the profiles of pressure, temperature, velocity and liquid holdup. The predicted results in this study agree well with the operating data. The theoretical analysis, and comparison of calculated results with operating data and OLGA indicate that the presented model for analyzing rich gas flow behavior in small diameter pipelines looks reasonable.

scholarly journals Probabilistic approach of a flow pattern map for horizontal, vertical, and inclined pipes

2019 ◽  
Vol 74 ◽  
pp. 67 ◽  
Author(s):  
Rafael Amaya-Gómez ◽  
Jorge López ◽  
Hugo Pineda ◽  
Diana Urbano-Caguasango ◽  
Jorge Pinilla ◽  
...  
Keyword(s):  
Flow Pattern ◽  
Gas Flow ◽  
Probabilistic Approach ◽  
Flow Patterns ◽  
Intermittent Flow ◽  
Two Phase ◽  
Flow Pattern Map ◽  
Segregated Flow ◽  
Probabilistic Flow ◽  
Inclined Pipes

A way to predict two-phase liquid-gas flow patterns is presented for horizontal, vertical and inclined pipes. A set of experimental data (7702 points, distributed among 22 authors) and a set of synthetic data generated using OLGA Multiphase Toolkit v.7.3.3 (59 674 points) were gathered. A filtering process based on the experimental void fraction was proposed. Moreover, a classification of the pattern flows based on a supervised classification and a probabilistic flow pattern map is proposed based on a Bayesian approach using four pattern flows: Segregated Flow, Annular Flow, Intermittent Flow, and Bubble Flow. A new visualization technique for flow pattern maps is proposed to understand the transition zones among flow patterns and provide further information than the flow pattern map boundaries reported in the literature. Following the methodology proposed in this approach, probabilistic flow pattern maps are obtained for oil–water pipes. These maps were determined using an experimental dataset of 11 071 records distributed among 53 authors and a numerical filter with the water cut reported by OLGA Multiphase Toolkit v7.3.3.

Characteristics of Pressure Gradient Fluctuation for Oil-Gas-Water Three-Phase Flow Based on Flow Pattern

2011 ◽  
Vol 66-68 ◽  
pp. 1187-1192 ◽  
Author(s):  
Hai Qin Wang ◽  
Yong Wang ◽  
Lei Zhang
Keyword(s):  
Pressure Gradient ◽  
Flow Pattern ◽  
Flow Patterns ◽  
Phase Flow ◽  
Water Mixture ◽  
Three Phase ◽  
Test Loop ◽  
Three Phase Flow ◽  
Oil Water ◽  
Oil Gas

Experiments were conducted in a horizontal multiphase flow test loop (50mm inner diameter, 40m long) to study the flow patterns for oil-gas-water three-phase flow and the pressure gradient fluctuation based on flow patterns. Using new methods of definition, 12 types of flow patterns were obtained and phase distribution characteristics of each pattern were analyzed. A new flow pattern (SW║IN) was firstly found in this work. Characteristics of the pressure gradient based on 7 flow patterns were carefully discussed. It was found that the pressure gradient increased with the increase of gas superficial velocity and oil-water mixture velocity. However, characteristics of the pressure gradient became complex with the increase of input water cut. The influence of flow structure of oil-water two-phase should be fully considered.

Slug Dynamics in Gas-Liquid Pipe Flow

2000 ◽  
Vol 122 (1) ◽  
pp. 14-21 ◽  
Author(s):  
Hong-Quan Zhang ◽  
Subash S. Jayawardena ◽  
Clifford L. Redus ◽  
James P. Brill
Keyword(s):  
Pressure Gradient ◽  
Flow Pattern ◽  
Pipe Flow ◽  
Film Flow ◽  
Control Volume ◽  
Experimental Results ◽  
Liquid Holdup ◽  
Flow Pattern Transition ◽  
Slug Flows

The continuity and momentum equations for fully developed and spatially developing slug flows are established by considering the entire film zone as the control volume. They are used for the calculations of pressure gradient, slug frequency, liquid holdup in the film, flow pattern transition, slug dissipation, and slug tracking. Comparison with available experimental results shows that these equations correctly describe the slug dynamics in gas-liquid pipe flow. [S0195-0738(00)00701-9]

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