Pressure Gradient and Liquid Holdup in Irrigated Packed Towers

1969 ◽  
Vol 8 (3) ◽  
pp. 502-511 ◽  
Author(s):  
J. E. Buchanan
Keyword(s):  
Pressure Gradient ◽  
Liquid Holdup

Experimental Study of DRA for Vertical Two-Phase Annular Flow

2009 ◽  
Vol 131 (2) ◽  
Author(s):  
R. L. J. Fernandes ◽  
B. A. Fleck ◽  
T. R. Heidrick ◽  
L. Torres ◽  
M. G. Rodriguez
Keyword(s):  
Pressure Gradient ◽  
Drag Reduction ◽  
Production Rate ◽  
Annular Flow ◽  
Liquid Holdup ◽  
Two Phase ◽  
High Production Rate ◽  
High Production ◽  
Feasibility Test ◽  
Main Effects

Experimental investigation of drag reduction in vertical two-phase annular flow is presented. The work is a feasibility test for applying drag reducing additives (DRAs) in high production-rate gas-condensate wells where friction in the production tubing limits the production rate. The DRAs are intended to reduce the overall pressure gradient and thereby increase the production rate. Since such wells typically operate in the annular-entrained flow regime, the gas and liquid velocities were chosen such that the experiments were in a vertical two-phase annular flow. The drag reducers had two main effects on the flow. As expected, they reduced the frictional component of the pressure gradient by up to 74%. However, they also resulted in a significant increase in the liquid holdup by up to 27%. This phenomenon is identified as “DRA-induced flooding.” Since the flow was vertical, the increase in the liquid holdup increased the hydrostatic component of the pressure gradient by up to 25%, offsetting some of reduction in the frictional component of the pressure gradient. The DRA-induced flooding was most pronounced at the lowest gas velocities. However, the results show that in the annular flow the net effect will generally be a reduction in the overall pressure gradient by up to 82%. The findings here help to establish an envelope of operations for the application of multiphase drag reduction in vertical flows and indicate the conditions where a significant net reduction of the pressure gradient may be expected.

Experimental and Modeling Studies on Pressure Gradient Prediction for Horizontal Gas Wells Based on Dimensionless Number Analysis

2021 ◽  
Author(s):  
Chengcheng Luo ◽  
Ning Wu ◽  
Sha Dong ◽  
Yonghui Liu ◽  
Changqing Ye ◽  
...  
Keyword(s):  
Experimental Investigation ◽  
Pressure Gradient ◽  
Flow Behavior ◽  
Scaling Up ◽  
Low Pressure ◽  
Dimensionless Number ◽  
Gas Wells ◽  
Liquid Holdup ◽  
Dimensionless Numbers ◽  
New Model

Abstract Accurate prediction of pressure gradient in gas wells is the theoretical basis of gas well performance analysis, production optimization and deliquification technologies design. Experiment is the best access to characterize the flow behavior of gas wells. For low-pressure experimental investigation and gas wells, the most difference is the pressure (gas density), which could lead to totally different flow behavior. Dimensionless numbers are often used in the flow pattern maps to account for the flow similarities at different conditions, which means liquid holdup in the high pressure can be also predicted at low pressure conditions if we choose proper dimensionless numbers for pressure scaling up. However, no studies have focused on this point before. Besides, gas wells have high GLR, most empirical models were intended to developed for oil wells, which have greater weight in low GLR, decreasing the accuracy in gas wells. In order to predict the pressure gradient in horizontal gas wells, an experimental investigation of gas-water flow has been conducted. The experimental test matrix was designed to cover all the flow patterns. The experiment was conducted in a 5-m long pipe. The liquid holdup and pressure gradient were measured. Subsequently, the effect of gas velocity, liquid velocity, pipe diameter, and inclined angle on liquid holdup was analyzed. Then the dimensionless numbers proposed in the literature have been investigated and analyzed for pressure scaling up. Finally, a comprehensive model was established, which is developed for prediction pressure drop in gas wells. Some field and experimental data were provided to evaluate the new model. The results show that the Duns-Ros dimensionless number was not proper for pressure scaling up while the Hewitt-Robert Number performs best. Compared to widely used pressure gradient models with field data, the new model with Hewitt-Robert Number performed best, which shows that it is capable of dealing with prediction of pressure gradient in gas wells.

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.

Performance of Two-Phase Flow Models on the Prediction of Oscillatory Flow Conditions

2016 ◽  
Author(s):  
Catalina Posada ◽  
Paulo Waltrich
Keyword(s):  
Experimental Data ◽  
Steady State ◽  
Pressure Gradient ◽  
Two Phase Flow ◽  
Percentage Error ◽  
Phase Flow ◽  
Liquid Holdup ◽  
Two Phase ◽  
Flow Models ◽  
Absolute Percentage Error

The present investigation presents a comparative study between two-phase flow models and experimental data. Experimental data was obtained using a 42 m long, 0.05 m ID tube system. The experimental data include conditions for pressures ranging from 1.2 to 2.8 bara, superficial liquid velocities 0.02–0.3 m/s, and superficial gas velocity ranges 0.17–26 m/s. The experimental data was used to evaluate the performance of steady-state empirical and mechanistic models while estimating liquid holdup and pressure gradient under steady-state and oscillatory conditions. The purpose of this analysis is first to evaluate the accuracy of the models predicting the liquid holdup and pressure gradient under steady-state conditions. Then, after evaluating the models under state-steady conditions, the same models are used to predict the same parameters for oscillatory and periodic conditions for similar gas and liquid velocities. The transient multiphase flow simulator OLGA, which has been widely used in the oil and gas industry, was implemented to model one oscillatory case to evaluate the prediction improvement while using a transient instead of a steady-state model to predict oscillatory flows. For the model with best performance for steady-state pressure gradient prediction, the absolute percentage error is 12% for Uls = 0.02 m/s and 5% for Uls = 0.3. For oscillatory conditions, the absolute percentage error is 30% for Uls = 0.02 m/s and 4% for Uls = 0.3. OLGA results underpredict the experimental pressure gradient under oscillatory conditions with errors up to 30%. Therefore, it was possible to conclude that the models can predict the average of the oscillatory data almost as well as for steady-state conditions.

A Model To Predict Liquid Holdup and Pressure Gradient of Near-Horizontal Wet-Gas Pipelines

2007 ◽  
Vol 2 (02) ◽  
pp. 1-8 ◽  
Author(s):  
Yongqian Fan ◽  
Qian Wang ◽  
Hong-Quan Zhang ◽  
Thomas John Danielson ◽  
Cem Sarica
Keyword(s):  
Pressure Gradient ◽  
Gas Pipelines ◽  
Liquid Holdup ◽  
Wet Gas

A Model To Predict Liquid Holdup and Pressure Gradient of Near-Horizontal Wet-Gas Pipelines

2005 ◽  
Author(s):  
Yongqian Fan ◽  
Qian Wang ◽  
Hong-Quan Zhang ◽  
Cem Sarica ◽  
Thomas John Danielson
Keyword(s):  
Pressure Gradient ◽  
Gas Pipelines ◽  
Liquid Holdup ◽  
Wet Gas

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.

Experimental Investigation of Vertical Downward Two-Phase Flow in Annulus

2020 ◽  
Vol 142 (7) ◽  
Author(s):  
Renato P. Coutinho ◽  
Ligia Tornisiello ◽  
Paulo J. Waltrich
Keyword(s):  
Experimental Data ◽  
Pressure Gradient ◽  
Flow Regime ◽  
Two Phase Flow ◽  
Flow Regimes ◽  
Intermittent Flow ◽  
Phase Flow ◽  
Liquid Holdup ◽  
Two Phase ◽  
Downward Flow

Abstract A limited amount of work exists on gas–liquid flow in vertical pipe annulus, and, to the knowledge of the authors, there is no work on the literature to characterize vertical downward two-phase flow in pipe annulus. In the petroleum industry, downward two-phase in annulus is encountered on liquid-assisted gas-lift (LAGL) unloading and production operations. This study presents experimental data for pressure gradient, liquid holdup, and flow regimes for vertical downward two-phase (air and water) flow in pipe annulus. Also, the applicability of two-phase flow models are evaluated. The experimental results show that the liquid holdup is consistently higher for downward flow in annulus than in pipes for the annular flow regime, and these differences are as high as 45%. When the flow regime map for downward flow in annulus is compared with the ones in the literature for flow in pipes, it is observed that the intermittent flow in pipes occurs at lower liquid velocities than flow in annulus. The comparison between experimental data and model results also shows some discrepancy for liquid holdup and pressure gradient. These differences are high for annular and intermittent flow regimes, with errors of 100% for the liquid holdup and 200% for pressure gradient. However, the errors for bubble flow regime are much smaller, generally lower than 20%.

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