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.

A Two-Phase Flow Model for Reserves Estimation in Tight-Oil and Gas-Condensate Reservoirs Using Scaling Principles

2021 ◽  
pp. 1-18
Author(s):  
L. M. Ruiz Maraggi ◽  
L. W. Lake ◽  
M. P. Walsh
Keyword(s):  
Gas Flow ◽  
Single Phase ◽  
Oil And Gas ◽  
Two Phase Flow ◽  
Gas Condensate ◽  
Tight Oil ◽  
Phase Flow ◽  
Reservoir Pressure ◽  
Single Phase Flow ◽  
Two Phase

Summary A common approach to forecast production from unconventional reservoirs is to extrapolate single-phase flow solutions. This approach ignores the effects of multiphase flow, which exist once the reservoir pressure falls below the bubble/dewpoint. This work introduces a new two-phase (oil and gas) flow solution suitable to extrapolating oil and gas production using scaling principles. In addition, this study compares the application of the two-phase and the single-phase solutions to estimates of production from tight-oil wells in the Wolfcamp Formation of west Texas. First, we combine the oil and the gas flow equations into a single two-phase flow equation. Second, we introduce a two-phase pseudopressure to help linearize the pressure diffusivity equation. Third, we cast the two-phase diffusion equation into a dimensionless form using inspectional analysis. The output of the model is a predicted dimensionless flow rate that can be easily scaled using two parameters: a hydrocarbon pore volume and a characteristic time. This study validates the solution against results of a commercial simulator. We also compare the results of both the two-phase and the single-phase solutions to forecast wells. The results of this research are the following: First, we show that single-phase flow solutions will consistently underestimate the oil ultimate recovery factors (URFs) for solution gas drives. The degree of underestimation will depend on the reservoir and flowing conditions as well as the fluid properties. Second, this work presents a sensitivity analysis of the pressure/volume/temperature (PVT) properties, which shows that lighter oils (more volatile) will yield larger recovery factors for the same drawdown conditions. Third, we compare the estimated ultimate recovery (EUR) predictions for two-phase and single-phase solutions under boundary-dominated flow (BDF) conditions. The results show that single-phase flow solutions will underestimate the ultimate cumulative oil production of wells because they do not account for liberation of dissolved gas and its subsequent expansion (pressure support) as the reservoir pressure falls below the bubblepoint. Finally, the application of the two-phase model provides a better fit when compared with the single-phasesolution. The present model requires very little computation time to forecast production because it only uses two fitting parameters. It provides more realistic estimates of URFs and EURs, when compared with single-phase flow solutions, because it considers the expansion of the oil and gas phases for saturated flow. Finally, the solution is flexible and can be applied to forecast both tight-oil and gas condensate wells.

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.

scholarly journals Productivity Influence Factors of Tight Sandstone Gas Reservoir with Water Produced

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Yongchao Xue ◽  
Qingshuang Jin ◽  
Hua Tian
Keyword(s):  
Pressure Gradient ◽  
Relative Permeability ◽  
Gas Flow ◽  
Influence Factors ◽  
Stress Sensitivity ◽  
Consumption Pattern ◽  
Tight Sandstone ◽  
Gas Reservoir ◽  
Two Phase ◽  
Start Up

Finding ways to accelerate the effective development of tight sandstone gas reservoirs holds great strategic importance in regard to the improvement of consumption pattern of world energy. The pores and throats of the tight sandstone gas reservoir are small with abundant interstitial materials. Moreover, the mechanism of gas flow is highly complex. This paper is based on the research of a typical tight sandstone gas reservoir in Changqing Oilfield. A strong stress sensitivity in tight sandstone gas reservoir is indicated by the results, and it would be strengthened with the water production; at the same time, a rise to start-up pressure gradient would be given by the water producing process. With the increase in driving pressure gradient, the relative permeability of water also increases gradually, while that of gas decreases instead. Following these results, a model of gas-water two-phase flow has been built, keeping stress sensitivity, start-up pressure gradient, and the change of relative permeability in consideration. It is illustrated by the results of calculations that there is a reduction in the duration of plateau production period and the gas recovery factor during this period if the stress sensitivity and start-up pressure gradient are considered. In contrast to the start-up pressure gradient, stress sensitivity holds a greater influence on gas well productivity.

scholarly journals Optimization and Extended Applicability of Simplified Slug Flow Model for Liquid-Gas Flow in Horizontal and Near Horizontal Pipes

Energies ◽  
2020 ◽  
Vol 13 (4) ◽  
pp. 842
Author(s):  
Tea-Woo Kim ◽  
Nam-Sub Woo ◽  
Sang-Mok Han ◽  
Young-Ju Kim
Keyword(s):  
Slug Flow ◽  
Pressure Loss ◽  
Gas Flow ◽  
Flow Model ◽  
Flow Coefficient ◽  
Coefficient Of Determination ◽  
Liquid Holdup ◽  
Two Phase ◽  
Horizontal Pipes ◽  
Image Velocimetry

The accurate prediction of pressure loss for two-phase slug flow in pipes with a simple and powerful methodology has been desired. The calculation of pressure loss has generally been performed by complicated mechanistic models, most of which require the iteration of many variables. The objective of this study is to optimize the previously proposed simplified slug flow model for horizontal pipes, extending the applicability to turbulent flow conditions, i.e., high mixture Reynolds number and near horizontal pipes. The velocity field previously measured by particle image velocimetry further supports the suggested slug flow model which neglects the pressure loss in the liquid film region. A suitable prediction of slug characteristics such as slug liquid holdup and translational velocity (or flow coefficient) is required to advance the accuracy of calculated pressure loss. Therefore, the proper correlations of slug liquid holdup, flow coefficient, and friction factor are identified and utilized to calculate the pressure gradient for horizontal and near horizontal pipes. The optimized model presents a fair agreement with 2191 existing experimental data (0.001 ≤ μL ≤ 0.995 Pa∙s, 7 ≤ ReM ≤ 227,007 and −9 ≤ θ ≤ 9), showing −3% and 0.991 as values of the average relative error and the coefficient of determination, respectively.

A Robust Asymptotically Based Modeling Approach for Two-Phase Flow in Porous Media

2009 ◽  
Vol 131 (10) ◽  
Author(s):  
M. M. Awad ◽  
S. D. Butt
Keyword(s):  
Porous Media ◽  
Pressure Gradient ◽  
Single Phase ◽  
Present Model ◽  
Flow In Porous Media ◽  
Pressure Gradients ◽  
Two Phase ◽  
New Model ◽  
Proposed Model ◽  
Phase Liquid

A simple semitheoretical method for calculating the two-phase frictional pressure gradient in porous media using asymptotic analysis is presented. The two-phase frictional pressure gradient is expressed in terms of the asymptotic single-phase frictional pressure gradients for liquid and gas flowing alone. In the present model, the two-phase frictional pressure gradient for x≅0 is nearly identical to the single-phase liquid frictional pressure gradient. Also, the two-phase frictional pressure gradient for x≅1 is nearly identical to the single-phase gas frictional pressure gradient. The proposed model can be transformed into either a two-phase frictional multiplier for liquid flowing alone (ϕl2) or a two-phase frictional multiplier for gas flowing alone (ϕg2) as a function of the Lockhart–Martinelli parameter X. The advantage of the new model is that it has only one fitting parameter (p), while the other existing correlations, such as the correlation of Larkins et al., Sato et al., and Goto and Gaspillo, have three constants. Therefore, calibration of the new model to the experimental data is greatly simplified. The new model is able to model the existing multiparameter correlations by fitting the single parameter p. Specifically, p=1/3.25 for the correlation of Midoux et al., p=1/3.25 for the correlation of Rao et al., p=1/3.5 for the Tosun correlation, p=1/3.25 for the correlation of Larkins et al., p=1/3.75 for the correlation of Sato et al., and p=1/3.5 for the Goto and Gaspillo correlation.

scholarly journals IMPROVING THE EFFICIENCY OF THE FUNCTIONING OF GAS PIPELINES, TAKING INTO ACCOUNT THE STRUCTURAL FEATURES OF GAS FLOWS

2021 ◽  
Vol 447 (3) ◽  
pp. 34-39
Author(s):  
Elman Kh. Iskandarov
Keyword(s):  
High Speed ◽  
Gas Flow ◽  
Structural Changes ◽  
Oil And Gas ◽  
Structural Features ◽  
Transportation Systems ◽  
Gas Condensate ◽  
Gas Flows ◽  
Gas Pipelines ◽  
Processing Depth

The multi-phase and different composition of gas flows during the development of offshore oil and gas-condensate fields leads to high costs of energy in the system of in-field storage and transportation of well products. The analysis of the existing storage and transportation systems of gas-condensate mixtures shows that the geophysical nature and complexity of the internal structure of the transported fluids must be taken into account when choosing the mode parameters and calculation schemes of the pipelines. High-speed gas lines can be operated in a so-called "dry" mode, in which the liquid is carried along with the gas, the pipeline profile is relatively straight, without ups and downs. In this case, the formation of so-called "stagnant zones" in the pipeline is excluded. However, if the processing depth of the gas does not allow it to be transported in a single-phase state, then the condensing gas factor manifests itself. The hydraulic characteristics of vertical ups and downs on offshore pipelines are complicated, and pipelines are often filled with water and condensate. As a result, the pressure in the pipeline increases and the location of the collection point for condensing gases away from the production site can cause major problems. If we characterize oil and gas-condensate flows as a dynamic system in which alternating structural changes take place, the question of whether these systems are fractal is of great scientific interest. Based on the change in the fractal value, it is possible to diagnose structural changes during the transportation of various systems, including condensing gases in the pipelines. In this article the modes of change of basic parameters of a gas flow (pressure, flow rate and temperature) on various lines of a gas pipeline for the purpose of the producing of diagnostic criterion for revealing of liquid inclusions as a part of transported gas are investigated in this article. It is established, that in the presence of liquid inclusions at movement of gas flows there are the structural changes peculiar to fluid systems, systems which can be identified by variations of fractal dimensions of flowcharacteristics. Studies have shown that the study of the dynamics of structural changes in gas flows can play a role in diagnosing the formation of liquid phase embryos in gas pipelines. For this purpose, diagnostics for the movement of gas streams accompanied by liquid deposits in the pipelines has been proposed.

A Robust Asymptotically Based Modeling Approach for Two-Phase Flow in Porous Media

2008 ◽  
Author(s):  
M. M. Awad ◽  
S. D. Butt
Keyword(s):  
Porous Media ◽  
Pressure Gradient ◽  
Single Phase ◽  
Theoretical Method ◽  
Flow In Porous Media ◽  
Pressure Gradients ◽  
Two Phase ◽  
New Model ◽  
Proposed Model ◽  
Phase Liquid

A simple semi-theoretical method for calculating two-phase frictional pressure gradient in porous media using asymptotic analysis is presented. Two-phase frictional pressure gradient is expressed in terms of the asymptotic single-phase frictional pressure gradients for liquid and gas flowing alone. In the present model, the two-phase frictional pressure gradient for x ≅ 0 is nearly identical to single-phase liquid frictional pressure gradient. Also, the two-phase frictional pressure gradient for x ≅ 1 is nearly identical to single-phase gas frictional pressure gradient. The proposed model can be transformed into either a two-phase frictional multiplier for liquid flowing alone (φl2) or two-phase frictional multiplier for gas flowing alone (φg2) as a function of the Lockhart-Martinelli parameter, X. The advantage of the new model is that it has only one fitting parameter (p) while the other existing correlations such as Larkins et al. correlation, Sato et al. correlation, and Goto and Gaspillo correlation have three constants. Therefore, calibration of the new model to experimental data is greatly simplified. The new model is able to model the existing multi parameters correlations by fitting the single parameter p. Specifically, p = 1/3.25 for Midoux et al. correlation, p = 1/3.25 for Rao et al. correlation, p = 1/3.5 for Tosun correlation, p = 1/3.25 for Larkins et al. correlation, p = 1/3.75 for Sato et al. correlation, and p = 1/3.5 for Goto and Gaspillo correlation.

A Review of Wet Gas Flow Rate Measurements by Means of Single-Phase Meters

2018 ◽  
Author(s):  
Enrico Munari ◽  
Michele Pinelli
Keyword(s):  
Flow Rate ◽  
Gas Flow ◽  
Single Phase ◽  
Rate Measurement ◽  
Gas Flow Rate ◽  
Flow Rate Measurement ◽  
Two Phase ◽  
Beneficial Effects ◽  
Wet Gas ◽  
Depth Analysis

Nowadays, wet gas flow rate measurement is still a challenge for experimental investigators and it is becoming an even more important issue to overcome in the turbomachinery sector as well, due to the increasing trend of wet compression applications in industry. The requirement to determine gas turbine performance when processing a wet gas leads to the need to understand certain phenomena, such as type of liquid flow re-distribution, and errors introduced when the mass flow rate measurement of a two-phase gas is attempted. Unfortunately, this measurement is often affected by the presence of liquid. Literature does not offer a unique definition of the term wet gas, although it is recognized that a wet gas can generally be defined as a two-phase gas in which the liquid percentage is lower than the gas one. This paper aims to collect and describe the main works present in literature in order to clarify i) the most used parameters that describe the types of wet gas, and ii) the types of errors and flow patterns which occur in different types of applications, in terms of pressure, percentage of liquid, Reynolds number, etc. Therefore, this literature review offers a comprehensive description of the possible effects of liquid presence in a wet gas and, and an in-depth analysis of the limitations and beneficial effects of current single-phase flow rate sensors in order to identify the best solutions, and empirical corrections available in literature to overcome this challenge.

Film-Thickness, Pressure-Gradient, and Turbulent Velocity Profiles in Annular Dispersed Flows

1993 ◽  
Vol 115 (2) ◽  
pp. 264-269 ◽  
Author(s):  
A. N. Skouloudis ◽  
J. Wu¨rtz
Keyword(s):  
Film Thickness ◽  
Pressure Gradient ◽  
Single Phase ◽  
Phase Flow ◽  
Single Phase Flow ◽  
Two Phase ◽  
Flow Parameters ◽  
Dispersed Flows ◽  
Turbulence Parameters ◽  
Transverse Variation

A regional model has been described for dispersed turbulent two-phase flow which accounts for the transverse variation of velocity. The two-phase turbulence parameters are introduced in direct analogy to well-known single-phase flow parameters which are then correlated to experimental data. The advantages of this approach are its simplicity and the absence of arbitrary parameters which need calibration at different experimental ranges. Its generality has been tested by comparisons at high and low operating pressures with air-water and steam-water mixtures. Comparisons between calculated and measured values have been carried out for the film thickness and the pressure gradient at different experimental setups.

Parameters for Computing Pressure Gradients and the Equilibrium Saturation of Gas-Condensate Fluids Flowing in Sandstones

1974 ◽  
Vol 14 (03) ◽  
pp. 203-215 ◽  
Author(s):  
Jerry D. Ham ◽  
James P. Brill ◽  
C. Kenneth Eilerts
Keyword(s):  
Turbulent Flow ◽  
Pressure Gradient ◽  
Gas Phase ◽  
Gas Condensate ◽  
Darcy Flow ◽  
Pressure Gradients ◽  
Two Phase ◽  
Darcy Equation ◽  
Liquid Saturation ◽  
Gas Ratio

Abstract Data obtained by flowing two-phase fluids through sandstone cores were used to develop empirical equations for computing the pressure gradients and liquid saturations that will occur during the recovery of gas-condensate fluids like those in the Gulf Coast area. Equilibrium saturation may be computed for a given pressure, velocity, and liquid/gas ratio of flow. For this purpose, the minimum liquid flow saturation at high pressures, S, was developed for characterizing a core and a fluid. The effects of saturation on the mobility for Darcy flow and on the coefficient for non-Darcy flow are considered in an equation with parameters in addition to the Klinkenberg and Forchheimer coefficients. All parameters for these equations may be determined parameters for these equations may be determined either by routine measurements or by correlations. Introduction Fluid properties required for computing the transient flow of gas-condensate fluids and data obtained to meet this need were discussed at the 1966 SPE-AIME Fall Meeting. In the following year Dranchuk and Kolada described a means of analyzing laboratory data for nonlinear parameters pertaining to flow of gases. Gewers and Nichol pertaining to flow of gases. Gewers and Nichol investigated the effect of liquid saturation on the non-Darcy-flow term of the pressure-gradient equation. Modine and Fields used this kind of information to simulate turbulent flow in gas wells. An equation is needed for computing a more realistic value of the pressure gradient for flowing two-phase fluids than is possible with the Darcy equation. An equation is needed to compute as a boundary condition the liquid saturation possible in the porous medium near flowing wells. This paper describes two such equations that give effect paper describes two such equations that give effect to pressure, fluid velocity, liquid/gas ratio, and saturation. Seven parameters each required for the pressure-gradient and saturation equations may be pressure-gradient and saturation equations may be calculated by means of correlation equations that utilize routinely measured core properties. Concepts and Equations The Darcy equation was modified to include the Klindenberg effect "slip flow" and the Forchheimer coefficient to represent "inertial" or "turbulent" flow of gases in dry porous media,(1) By controlling the velocity (u) and pressure (p), measuring the gradient (dp/dx) and the viscosity [mu(p)], and calculating the density [p(p)], the properties k, b, and beta were determined for properties k, b, and beta were determined for representative cores by least-squares methods. As a step in the modification of Eq. 1 to obtain an equation applicable to the flow of two-phase fluids, mobility, A, for a two-phase fluid must replace the ratio of a known permeability to a viscosity, for the gas phase(2) The quantities k and mu(p) are to have the same* significance as in Eq. 1, except that mu(p) is the viscosity of a single-phase saturated gas. Relationships of liquid- and gas-phase mobilities, lambda and lambda, to fluid mobility, lambda, have been described in Appendix C of a previous publication. Briefly, lambda = lambda + lambda = f(S, p, F, u) k/mu(p). Now mu(p) is the viscosity of the flowing fluid mu under steady-state conditions only when F = 0.

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