Experimental investigation of high viscous multiphase flow in horizontal pipelines

Diminishing reserves of “conventional” light crude oil, increased production costs amidst increased world energy demand over the last decade has spurred industrial interest in the production of the significantly and more abundant “unconventional” heavy crude oil. Recent findings have shown that unconventional oil being a veritable energy source accounts for over two-thirds of the world total oil reserve. The exploration of this vast resource for easy production and transportation requires a good understanding of multiphase system for which the knowledge of the effect of fluid viscosity is of great importance. Heavy oils are known for their high liquid viscosities which make them even more difficult and expensive to produce and transport in pipelines at ambient temperatures. In the light of this, it has become imperative to investigate the rheology of high viscosity oils and ways of enhancing its production and transportation since a critical understanding of multiphase flow characteristics are vital to aid engineering design. It is clear from experimental investigation reported so far in literatures and in Cranfield University that the behaviour of high viscosity oil-gas flows differs significantly from that of low viscosity oils. This means that most of the existing prediction models in the literature which were developed from observations of low viscosity liquid-gas flow will not perform accurately when compared to oil-gas flow data for high viscosity oil. Therefore, this research work seek to extend databank and provide a clearer understanding of the physics of high viscous multiphase flows. Experimental investigation have been conducted using 3-inch and 1-inch ID horizontal test facilities for oil-gas and oil-water respectively using different oil viscosities. The effects of liquid viscosities on oil-gas two phase flow parameters (i.e. pressure gradient, mean liquid holdup, slug frequency, slug translational velocity and slug body length) have been discussed. Assessment of existing prediction models and correlations in the literature are also carried out and their performance highlighted. New/improved prediction correlations for high viscosity oil-gas flow slug frequency, slug translational velocity and slug body have been proposed with their performance evaluated against the results obtained for this study and in literature. As for high viscosity oil-water flows, a new flow pattern maps have been established for high viscous oil-water two-phase flow in horizontal pipe with ID = 0.0254 m for which four flow patterns were observed namely; rivulet, core annular, plug and dispersed flows were observed. Generally, it was observed that increase in oil viscosity favoured the Core Annular Flow pattern, similar behaviour was also observed for increased oil holdup. Comparatively analysis of results obtained here with low viscous kerosene and water flow study obtained under similar flow geometry and conditions shows significant difference in flow patterns under similar flow conditions

Interfacial friction in upward annular gas–liquid two-phase flow in pipes

Accurate prediction of interfacial friction between the gas and liquid in annular two-phase flow in pipes is essential for the proper modelling of pressure drop and heat transfer coefficient in pipeline systems. Many empirical relationships have been obtained over the last half century. However, they are restricted to limited superficial liquid and gas velocity ranges, essentially apply to atmospheric pressures, and the relationships are only relevant for pipes with inner diameters between 10 and 50 mm. In this study, we carried out experiments in a large diameter flow loop of 101.6 mm internal diameter with the superficial gas and liquid ranges of 11–29 m/s and 0.1–1.0 m/s respectively. An examination of published interfacial friction factor correlations was carried out using a diverse database which was collected from the open literature for vertical annular flow. The database includes measurements in pipes of 16–127 mm inner diameter for the liquid film thickness, interfacial shear stress, and pressure gradient for air-water, air-water/glycerol, and argon-water flows. Eleven studies are represented with experimental pressures of up to 6 bar. Significant discrepancies were found between many of the published correlations and the large pipe data, primarily in the thick film region at low interfacial shear stress. A correlation for the interfacial friction factor was hence derived using the extensive database. The correlation includes dimensionless numbers for the effect of the diameter across pipe scales to be better represented and better fit the wide range of experimental conditions, fluid properties, and operating pressures

Void fraction development in gas-liquid flow after a U-bend in a vertically upwards serpentine-configuration large-diameter pipe

We investigate the effect of a return U-bend on flow behaviour in the vertical upward section of a large-diameter pipe. A wire mesh sensor was employed to study the void fraction distributions at axial distances of 5, 28 and 47 pipe diameters after the upstream bottom bend. The study found that, the bottom bend has considerable impacts on up-flow behaviour. In all conditions, centrifugal action causes appreciable misdistribution in the adjacent straight section. Plots from WMS measurements show that flow asymmetry significantly reduces along the axis at L/D = 47. Regime maps generated from three axial locations showed that, in addition to bubbly, intermittent and annular flows, oscillatory flow occurred particularly when gas and liquid flow rates were relatively low. At this position, mean void fractions were in agreement with those from other large-pipe studies, and comparisons were made with existing void fraction correlations. Among the correlations surveyed, drift flux-type correlations were found to give the best predictive results

Upward gas–liquid two-phase flow after a U-bend in a large-diameter serpentine pipe

We present an experimental study on the flow behaviour of gas and liquid in the upward section of a vertical pipe system with an internal diameter of 101.6 mm and a serpentine geometry. The experimental matrix consists of superficial gas and liquid velocities in ranges of 0.15–30 m/s and from 0.07 to 1.5 m/s, respectively, which cover bubbly to annular flow. The effects on the flow behaviours downstream of the 180° return bend are significantly reduced when the flow reaches an axial distance of 47 pipe diameters from the U-bend. Therefore, reasonably developed flow is attained at this development length downstream of the bend. Other published measurements for large-diameter film thickness show similar trends with respect to the superficial gas velocity. However, the trends differ from those of small-diameter pipes, with which the film thickness decreases much faster with increasing gas flow. As a result, only a few of the published correlations for small pipe data agreed with the experimental data for large pipe film thickness. We therefore modified one of the best-performing correlations, which produced a better fit. Qualitative and statistical analyses show that the new correlation provides improved predictions for two-phase flow film thickness in large-diameter pipes

Sand minimum transport conditions in gas–solid–liquid three-phase stratified flow in a horizontal pipe at low particle concentrations

Sand production in the life of oil and gas reservoirs is inevitable, as it is co-produced from reservoirs. Its deposition in petroleum pipelines poses considerable risk to production and can lead to pipe corrosion and flow assurance challenges. Therefore, it is important that pipe flow conditions are maintained to ensure sand particles are not deposited but in con- tinuous motion with the flow. The combination of minimum gas and liquid velocities that ensure continuous sand motion is known as the minimum transport condition (MTC). This study investigates the effect both of sand particle diameter and concentration on MTC in gas/liquid stratified flow in a horizontal pipeline. We used non-intrusive conductivity sen- sors for sand detection. These sensors, used for film thickness measurement in gas/liquid flows, were used for the first time here for sand detection. We found that MTC increases with increase in particle diameter for the same concentration and also increases as the concen- tration increases for the same particle diameter. A correlation is proposed for the prediction of sand transport at MTC in air–water flows in horizontal pipes, by including the effect of sand concentration in Thomas’s lower model. The correlation accounts for low sand con- centrations and gave excellent predictions when compared with the experimental results at MT

Slug length for high viscosity oil-gas flow in horizontal pipes: experiments and prediction

An experimental investigation was carried out on the effects of high liquid viscosities on slug length in a 0.0762-m ID horizontal pipe using air-water and air-oil systems with nominal viscosities ranging from 1.0 to 5.5 Pa s. The measurements of slug length were carried out using two fast sampling gamma densitometers with a sampling frequency of 250 Hz. The results obtained show that liquid viscosity has a significant effect on slug length. An assessment of existing prediction models and correlations in the literature was carried out and statistical analysis against the present data revealed some discrepancies, which can be attributed to fluid properties in particular, low viscous oil data used in their derivation Hence, a new high viscous oil data presented here from which we derive a new slug length correlation was derived using dimensional analysis. The proposed correlation will improve prediction of slug length as well as provide a closure relationship for use in flow simulations involving heavy oil. This is important since most current fields produce highly viscous oil with some reaching 10 Pa s

Assessment of Coriolis meters as instrumentation for gas void fraction measurement in air–liquid multiphase flow in a pipeline riser system

Measurement of void fraction in gas-liquid flow systems is important in determining pumping requirements, designing downstream facilities and in detecting off-design problems such as cavitation and flashing during operation. Hence, it is key that this parameter is known in real time during oil & gas production and other process operation. As a result, the use of clamp-on flow meters which operate on the Coriolis principle are useful for such purposes as they instantaneously measure the flow’s density which can change depending on the gas fraction in the flowing mixture. In this study, we demonstrate the use of Coriolis mass flow meters in instantaneously measuring the void fraction in a multiphase mixture flowing in a 2-inch pipeline riser system at Cranfield University, UK. A Coriolis meter was installed on the vertical section of the facility. A set of experiments were conducted at fixed liquid superficial velocities of 0.25 and 1 m/s and air flow rates of 6-100 Sm3/h (corresponding to 0.39–3 m/s). The instantaneous densities of the mixtures were recorded at 100 Hz acquisition frequency. These were then used to estimate the gas void fraction at the vertical section using the homogenous model for the mixture density. Also, a well-calibrated 16 by 16 wire mesh sensor (WMS) fitted at the same vertical location to validate the gas void fraction measurements of the Coriolis flow meter. It was found that the Coriolis flow meter presented excellent agreement with the WMS for void fraction measurement at high gas flow rates. We observed that the agreement coincided with conditions that exhibit core-peaking void fraction distributions, i.e., at conditions that are not bubbly flow. Hence, it may be concluded that the Coriolis flow meter can be used with some confidence in industrial application at these condition

High viscous oil–water two–phase flow: experiments & numerical simulations

An experimental study on highly viscous oil-water two-phase flow conducted in a 5.5 m long and 25.4 mm internal diameter (ID) pipeline is presented. Mineral oil with viscosity ranging from 3.5 Pa.s – 5.0 Pa.s and water were used as test fluid for this study. Experiments were conducted for superficial velocities of oil and water ranging from 0.06 to 0.55 m/s and 0.01 m/s to 1.0 m/s respectively. Axial pressure measurements were made from which the pressure gradients were calculated. Flow pattern determination was aided by high definition video recordings. Numerical simulation of experimental flow conditions is performed using a commercially available Computational Fluid Dynamics code. Results show that at high oil superficial velocities, Core Annular Flow (CAF) is the dominant flow pattern while Oil Plug in Water Flow (OPF) and Dispersed Oil in Water (DOW) flow patterns are dominant high water superficial velocities. Pressure Gradient results showed a general trend of reduction to a minimum as water superficial velocity increases before subsequently increasing on further increasing the superficial water velocity. The CFD results performed well in predicting the flow configurations observed in the experiments

Study of High Viscous Multiphase Flow Using OLGA Flow Simulator

The continuous depletion of conventional reserves of the world oil and gas has spurred investigation towards the exploration and production from unconventional sources of hydrocarbons such as heavy oil. However, heavy oils are known for their high liquid viscosities making them even more difficult and expensive to produce and transport in pipelines at ambient temperatures. As a consequence of this, a critical understanding of multiphase flow characteristics is vital to aid engineering design it has become imperative to investigate the rheology of high viscosity oils and ways of enhancing its production and transportation. In this study, the characteristics of high viscous oil flows were studied using OLGA flow simulator. A comparison between simulation results from the flow simulator and those of data acquired for high oil-gas viscosity experiments (i.e. for oil viscosity ranging from 0.7-5.0 Pa.s) for two phase flow parameters such liquid holdup and pressure gradient exhibited huge discrepancies and under prediction

Study of High Viscous Multiphase Flow Using OLGA Flow Simulator

The continuous depletion of conventional reserves of the world oil and gas has spurred investigation towards the exploration and production from unconventional sources of hydrocarbons such as heavy oil. However, heavy oils are known for their high liquid viscosities making them even more difficult and expensive to produce and transport in pipelines at ambient temperatures. As a consequence of this, a critical understanding of multiphase flow characteristics is vital to aid engineering design it has become imperative to investigate the rheology of high viscosity oils and ways of enhancing its production and transportation. In this study, the characteristics of high viscous oil flows were studied using OLGA flow simulator. A comparison between simulation results from the flow simulator and those of data acquired for high oil-gas viscosity experiments (i.e. for oil viscosity ranging from 0.7-5.0 Pa.s) for two phase flow parameters such liquid holdup and pressure gradient exhibited huge discrepancies and under prediction.    Keywords— High viscosity oil, Liquid holdup, OLGA, Pressure gradien