Discharge coefficient of high viscosity liquids through nozzles

Experimental investigation on discharge coefficient, Cd, for high viscosity fluid through nozzles was carried out. The viscosity of the fluid used for the test ranged from 350 to 1500 mPa s. The length-to-diameter ratio of the nozzle, l/d and the ratio of nozzle diameter to pipe diameter ratios β were used to investigate the influence of geometry on Cd. Results show a significant dependence of Cd on Re, l/d and β ratio. An empirical correlation on the discharge coefficient was developed based on the data from this study which was also compared with data from other published studies. This correlation, with an R-squared value of 0.9541, was valid for nozzle sizes 10–20 mm and for Re between 1 and 200. Cd values obtained from experimental data, and those from the empirical correlation were compared, and a mean standard deviation of 0.0231 was obtained

Particle-Transport Mechanism in Liquid/Liquid/Solid Multiphase Pipeline Flow of High-Viscosity Oil/Water/Sand

In this study, an investigation of sand transport in heavy-oil/water multiphase flow is performed. The study is conducted in three multiphase-flow pipeline-test facilities with internal diameters (IDs) of 1, 1, and 3 in. The pipeline orientations relative to the horizontal in the facilities are 0, +30, and 0°, respectively. Oil viscosity of 3.5 and 10.0 Pa·s with sand volume fractions from 0.010 to 0.100 vol% were used in the study. The effects of oil viscosity, upward inclination, sand volume fraction, pipe ID, and water cut on the sand-transport mechanism in pipelines are investigated. In the horizontal test section, flow patterns—namely, dispersed flow (DF), plug flow (PF), plug flow with moving sand bed (PFM), and plug flow with stationary sand bed (PFS)—were identified through flow visualization. In addition to the aforementioned, two flow patterns—stratified wavy flow with moving sand bed (SWM) and stratified wavy flow with dunes (SWD)—were observed in the inclined pipeline orientation. The pressure gradient measured decreased with a decrease in water cut until a minimum value was reached. Beyond the minimum pressure gradient, further reduction in water cut led to an increase in pressure gradient. The sand minimum transport condition (MTC) in the oil/water/sand test was largely the same for the 1-in. 30° upward inclined and the 1-in. horizontal test section. In contrast, that of the 3-in. horizontal test section was considerably higher. An improved MTC predictive correlation is proposed for multiphase heavy-oil/water/sand flow. The proposed correlation outperforms the existing models when tested on the heavy-oil/water/sand data set

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 translational velocity for highly viscous oil and gas flows in horizontal pipes

Slug translational velocity, described as the velocity of slug units, is the summation of the maximum mixture velocity in the slug body and the drift velocity. Existing prediction models in literature were developed based on observation from low viscosity liquids, neglecting the effects of fluid properties (i.e., viscosity). However, slug translational velocity is expected to be affected by the fluid viscosity. Here, we investigate the influence of high liquid viscosity on slug translational velocity in a horizontal pipeline of 76.2-mm internal diameter. Air and mineral oil with viscosities within the range of 1.0–5.5 Pa·s were used in this investigation. Measurement was by means of a pair of gamma densitometer with fast sampling frequencies (up to 250 Hz). The results obtained show that slug translational velocity increases with increase in liquid viscosity. Existing slug translational velocity prediction models in literature were assessed based on the present high viscosity data for which statistical analysis revealed discrepancies. In view of this, a new empirical correlation for the calculation of slug translational velocity in highly viscous two-phase flow is proposed. A comparison study and validation of the new correlation showed an improved prediction performance

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

Characteristics of horizontal gas-liquid two-phase flow measurement in a medium-sized pipe using gamma densitometry

Two-phase flows are common occurrences in many industrial applications. The understanding of their characteristics in industrial piping systems is vital for the efficient design, optimization, and operation of industrial processes. Most of the previous experimental studies involving the use of gamma densitometers for holdup measurements in air-water mixtures are limited to smaller diameter pipes (generally regarded as those with < 50 mm in nominal diameter). Further, very few literature report experimental data obtained using gamma desitometers. This paper presents an application of a gamma densitometer in the measurement of two-phase flow characteristics in an intermediate diameter pipe (nominal diameter between 50 mm and 100 mm). Scaled air-water experiments were performed in a 17-m long, 0.0764-m internal diameter horizontal pipe. Liquid superficial velocity ranged between 0.1–0.4 m/s while gas superficial velocity ranged from 0.3 to 10.0 m/s. The measured parameters include liquid holdup, pressure gradient, flow pattern, and slug flow features. The flow patterns observed were stratified, stratified-wavy, plug, slug, and annular flows. Plug and slug flow patterns showed good agreement with established flow pattern maps. Furthermore, the slug translational velocity was observed to increase with increasing mixture velocity, as reported by previous authors, hence establishing the reliability of the instrumentation employed. The slug body length was also measured using the gamma densitometer and was found to be within the range 24–36D with a mean length of 30.6D

Estimating slug liquid holdup in high viscosity oil-gas two-phase flow

Slug flow is one of the most critical and often encountered flow patterns in the oil and gas industry. It is characterised by intermittency which results in large fluctuations in liquid holdup and pressure gradient. A proper understanding of its parameters (such as slug holdup) is essential in the design of transport facilities (e.g. pipelines) and process equipment (slug catchers, separators etc.). In this paper, experimental investigation of slug liquid holdup (defined as the liquid volume fraction in the slug body of a slug unit) is performed. Mineral oil with viscosity, and air were used as test fluids. A 0.0254 m and 0.0762 m pipe internal diameters facilities with pipe lengths of 5.5 and 17 m respectively were used in the study. Electrical Capacitance Tomography was used for slug holdup measurements. Results obtained in the study shows that slug liquid holdup varied directly as the viscosity and inversely as the gas input fraction. Existing slug holdup correlations and models in literature did not sufficiently predict present experimental results. A new empirical predictive correlation for estimating slug liquid holdup was derived from the present experimental databank and from data obtained in literature. The databank's liquid viscosity ranges from 0.189 to 8.0 Pa s. Statistical analysis of the new correlation vis-à-vis existing ones showed that the present correlation gave the best performance with an average percent error, E1; absolute average percent error, E2 and standard deviation, E3 of 0.001, 0.05 and 0.07 respectively, when tested on the high viscosity liquid–gas databank

A two-fluid model for high-viscosity upward annular flow in vertical pipes

Proper selection and application of interfacial friction factor correlations has a significant impact on prediction of key flow characteristics in gas–liquid two-phase flows. In this study, experimental investigation of gas–liquid flow in a vertical pipeline with internal diameter of 0.060 m is presented. Air and oil (with viscosities ranging from 100–200 mPa s) were used as gas and liquid phases, respectively. Superficial velocities of air ranging from 22.37 to 59.06 m/s and oil ranging from 0.05 to 0.16 m/s were used as a test matrix during the experimental campaign. The influence of estimates obtained from nine interfacial friction factor models on the accuracy of predicting pressure gradient, film thickness and gas void fraction was investigated by utilising a two-fluid model. Results obtained indicate that at liquid viscosity of 100 mPa s, the interfacial friction factor correlation proposed by Belt et al. (2009) performed best for pressure gradient prediction while the Moeck (1970) correlation provided the best prediction of pressure gradient at the liquid viscosity of 200 mPa s. In general, these results indicate that the two-fluid model can accurately predict the flow characteristics for liquid viscosities used in this study when appropriate interfacial friction factor correlations are implemented

Experimental Study on Sand Transport Characteristics in Horizontal and Inclined Two-Phase Solid-Liquid Pipe Flow

An experimental investigation on the hydraulic transport of sand particles in pipelines is presented in both horizontal and 30° upward inclined orientations. The pipe, with an internal diameter of 0.0254 m, had sand transported in various water superficial velocities at low and high sand concentrations [0.1%–10% volume-to-volume ratio (v/v)]. Sand particles were polydisperse (144–250 μm) with