Effects of high oil viscosity on oil‐gas downward flow in deviated pipes. Part 2: Holdup and pressure gradient

2020 ◽  
Author(s):  
Gabriel Soto‐Cortes ◽  
Eduardo Pereyra ◽  
Cem Sarica ◽  
Fabian Rivera‐Trejo ◽  
Carlos Torres
Keyword(s):  
Pressure Gradient ◽  
Oil Viscosity ◽  
Downward Flow ◽  
Oil Gas

Effect of oil viscosity on the flow structure and pressure gradient in horizontal oil–water flow

2012 ◽  
Vol 90 (8) ◽  
pp. 1019-1030 ◽  
Author(s):  
N. Yusuf ◽  
Y. Al-Wahaibi ◽  
T. Al-Wahaibi ◽  
A. Al-Ajmi ◽  
A.S. Olawale ◽  
...  
Keyword(s):  
Pressure Gradient ◽  
Water Flow ◽  
Flow Structure ◽  
Oil Viscosity ◽  
Oil Water

CFD Simulation of Two-Phase Vertical Annular Flow in Both Upward and Downward Direction in a Small Pipe

2019 ◽  
Author(s):  
Ekhwaiter Abobaker ◽  
Abadelhalim Elsanoose ◽  
John Shirokoff ◽  
Mohammad Azizur Rahman
Keyword(s):  
Film Thickness ◽  
Multiphase Flow ◽  
Pressure Gradient ◽  
Annular Flow ◽  
Cfd Simulation ◽  
Flow Direction ◽  
Flow Behavior ◽  
Two Phase ◽  
Downward Flow ◽  
Disturbance Wave

Abstract Computational fluid dynamics (CFD) simulation is presented to investigate the annular flow behavior in the vertical pipe by using ANSYS Fluent platform 17.2. The study was analyzed complex behavior of annular flow in two cases (upward and downward flow) for different air superficial velocities and range of Reynolds number for water, in order to obtain the effect of orientation flow and increasing superficial gas and liquid velocities on the base film, mean disturbance wave thickness, the average longitudinal size of disturbance wave as well as pressure gradient. For multiphase flow model, the volume of fluid method (VOF) for two-phase flow modelling was used and coupled with RNG k-ε turbulence model to predict fully annular flow structures in the upward and downward flow direction. From CFD simulation results, it is clear to see how increases in air velocity result in reductions in film thickness and increase in pressure gradient. Additionally, the results showed monotonic enhancement of film thickness occurring in tandem with increases in the liquid flow rate. However, due to the effect of gravitational force and interfacial friction, the film thickness and pressure gradient are slightly larger for the upward flow than for the downward flow. The results agree with the recent experimental data that studied the annular flow behavior and pressure drop in the upward and downward flow direction. This study will be very helpful in understanding multiphase flow behavior in natural gas wells.

A Case Study in Oil-Gas Transportation through Subsea Pipeline in Liaohe Tanhai Oilfield

2011 ◽  
Vol 317-319 ◽  
pp. 2239-2243
Author(s):  
Yang Liu ◽  
Zhi Hua Wang ◽  
Li Xin Wei ◽  
Ren Shan Pang
Keyword(s):  
Freezing Point ◽  
Self Control ◽  
Outlet Temperature ◽  
Oil Viscosity ◽  
Long Distance ◽  
Pump System ◽  
Public Projects ◽  
Well Production ◽  
Water Cut ◽  
Oil Gas

The crude oil in Kuidong region of Liaohe Tanhai Oilfield is characterized by high oil viscosity, high density, high content of colloid asphalt, low content of wax and low freezing point. In the shallow region, the large current, high content of silt, long-distance subsea buried pipeline and drift ice in winter have brought great challenge to offshore construction and oil-gas transportation. In this paper, the investigations of offshore construction project and platform process are shown. Based on the well production rate, gas-oil ratio, water cut, wellhead back pressure and outlet temperature, the range of daily transportation volume was acquired, as well as the maximum inlet pressure and pressure difference of the pump. The paper also selected technically and economically feasible pumps, then designed the public projects, corresponding electric power and self-control facilities. The selected skidded twin screw multiphase pump system can smoothly transport produced liquid to the terminal systems onshore without any effect on the daily output.

Numerical Modelling of Stratified Gas-Liquid Flow in Inclined Circular Pipes

2009 ◽  
Author(s):  
Jose´ L. H. Faccini ◽  
Paulo A. B. De Sampaio ◽  
Jian Su
Keyword(s):  
Pressure Gradient ◽  
Liquid Flow ◽  
Numerical Solutions ◽  
Stokes Equations ◽  
Numerical Data ◽  
Downward Flow ◽  
Liquid Height ◽  
Circular Pipes ◽  
Linear Differential ◽  
Gas Liquid Flow

In this paper, a fully developed stratified gas-liquid flow in inclined circular pipes is numerically modeled. The model is applied on a stratified gas-liquid downward flow with smooth and horizontal interface, in pipes with inclination angles varying from 0 to −10 degrees. A system of non-linear differential equations, consisting of the Reynolds averaged Navier-Stokes equations with the κ – ω turbulence model, are solved by using an inner iteration loop based on the Newton-Raphson scheme and the finite element method. Numerical solutions are obtained for the liquid height and pressure gradient which were compared with experimental and numerical data. An excellent agreement with the experimental data was obtained, leading to conclusion that the present model is adequate to simulate the stratified gas-liquid downward flow, and it can be used to estimate the flow parameters such as the liquid height and pressure gradient.

A Crucial Role of the Applied Capillary Pressure in Drainage Displacement

SPE Journal ◽  
2021 ◽  
pp. 1-19
Author(s):  
Danial Arab ◽  
Apostolos Kantzas ◽  
Ole Torsæter ◽  
Salem Akarri ◽  
Steven L. Bryant
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Crucial Role ◽  
Driving Force ◽  
Oil Reservoirs ◽  
Injection Velocity ◽  
Oil Viscosity ◽  
The Core

Summary Waterflooding has been applied either along with primary production to maintain reservoir pressure or later to displace the oil in conventional and heavy-oil reservoirs. Although it is generally accepted that waterflooding of light oil reservoirs in oil-wet systems delivers the least oil compared to either water-wet or intermediate-wet systems, there is a lack of systematic research to study waterflooding of heavy oils in oil-wet reservoirs. This research gives some new insights on the effect of injection velocity and oil viscosity on waterflooding of oil-wetreservoirs. Seven different oils with a broad range of viscosity ranging from 1 to 15 000 mPa·s at 25°C were used in 18 coreflooding experiments in which injection velocity was varied from 0.7 to 24.3 ft/D (2.5×10−6 to 86.0×10−6 m/s). Oil-wet sand (with contact angle of 159.3 ± 3.1°) was used in all the flooding experiments. Breakthrough time was precisely determined using an in-line densitometer installed downstream of the core. Oil-wet microfluidics (164.4 ± 9.7°) were used to study drainage displacement at the pore scale. Our observations suggest the crucial role of the wetting phase (oil) viscosity and the injection velocity in providing the driving force (capillary pressure) required to drain oil-wet pores. Capillarity-driven drainage can significantly increase oil recovery compared to injecting water at smaller pressure gradients. Increasing viscosity of the oil being displaced (keeping velocity the same) increases pressure gradient across the core. This increase in pressure gradient can be translated to the increase in the applied capillary pressure, especially where the oil phase is nearly stationary, such as regions of bypassed oil. When the applied capillary pressure exceeds a threshold, drainage displacement of oil by the nonwetting phase is facilitated. The driving force to push nonwetting phase (water) into the oil-wet pores can also be provided through increasing injection velocity (keeping oil viscosity the same). In this paper, it is demonstrated that in an oil-wet system, increasing velocity until applied capillary pressure exceeds a threshold improves forced drainage to the extent that it increases oil recovery even when viscous fingering strongly influences the displacement. This is consistent with the classical literature on carbonates (deZabala and Kamath 1995). However, the current work extends the classical learnings to a much wider operational envelope on oil-wet sandstones. Across this wider range, the threshold at which applied capillary pressure makes a significant contribution to oil recovery exhibits a systematic variation with oil viscosity. However, the applied capillary pressure; that is, the pressure drop observed during an experiment, does not vary systematically with conventional static parameters or groups and thus cannot be accurately estimated a priori. For this reason, the scaling group presented here incorporates a dynamic capillary pressure and correlates residual oil saturation more effectively than previously proposed static scaling groups.

Effects of High Oil Viscosity on Oil/Gas Flow Behavior in Horizontal Pipes

2008 ◽  
Vol 3 (02) ◽  
pp. 1-11 ◽  
Author(s):  
Bahadir Gokcal ◽  
Qian Wang ◽  
Hong-Quan Zhang ◽  
Cem Sarica
Keyword(s):  
Gas Flow ◽  
Flow Behavior ◽  
Oil Viscosity ◽  
Horizontal 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.

Effects of high oil viscosity on oil-gas upward flow behavior in deviated pipes

2019 ◽  
Vol 109 ◽  
pp. 109896
Author(s):  
Gabriel Soto-Cortes ◽  
Eduardo Pereyra ◽  
Cem Sarica ◽  
Fabian Rivera-Trejo ◽  
Carlos Torres
Keyword(s):  
Flow Behavior ◽  
Upward Flow ◽  
Oil Viscosity ◽  
Oil Gas

Oil-Gas-Water Three-Phase Slug Flow Liquid Holdup Model in Horizontal Pipeline

2006 ◽  
Author(s):  
Jing Mei Zhao ◽  
Jing Gong ◽  
Da Yu
Keyword(s):  
Slug Flow ◽  
Water Film ◽  
Mineral Oil ◽  
Superficial Velocity ◽  
Oil Viscosity ◽  
Liquid Holdup ◽  
Three Phase ◽  
Water Based ◽  
Water Cut ◽  
Oil Gas

According to experiments and relational documents, slug regime, appeared in this experiment, can be divided into the following flow regimes: oil-based separated slug, oil-based dispersed slug, water-based separated and water-based dispersed slug. Experiments for oil-gas-water three-phase flow in a stainless steel pipe loop (25.7mm inner diameter, 52m long) are conducted. Compressed air, mineral oil and water are used as experiment medium. Mineral oil Viscosity is 64.5mPa.s at 20°C. Gas superficial velocity, liquid superficial velocity and water cut ranges are 0.5∼15 m/s, 0.05∼0.5 m/s and 0∼100% respectively. There are some strange observed in this experiment. At the very low gas superficial velocity less than 1m/s, the average liquid holdup of low liquid superficial velocity was larger than that of higher liquid superficial velocity especially in higher inlet water cut experiments. This is because at very low gas superficial velocity, the regime is separated slug flow which has water film below their liquid film zone, velocity difference between oil film and water film will affect the average liquid holdup greatly. With the increase of gas and liquid superficial velocity, the regime becomes dispersed slug flow which oil and water are homogeneous. It will be more obvious with the increasing of water cut for the thicker water film. A new liquid holdup model of oil-based and water-based separated slug has been developed. Based on statistical analysis, it is observed that the new model gives excellent results against the experimental data.

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