Predicting Solid Particle Erosion in Multiphase Flow: Challenges and Success Stories (Keynote Paper)

CFD Simulations of Abnormal Flow in Horizontal Pipes for Offshore Hydrocarbon Transport

Multiphase flow is an important the phenomenon existing widely in nature, daily life, as well as petroleum and chemical engineering industry. It is especially important to understand the flow behavior of multiphase flow in a subsea hilly terrain and offshore pipelines. Accurate flow regime identification in multiphase flow is critical since multiphase flow affects the measurement accuracy of phase fraction, flow rate and other phase parameters. The main objective of this research work is to obtain a better understanding of the multiphase flow characteristics in a long pipeline. In this study, the results of an experimental research on multiphase flow that investigates fluid characteristics in a pipe has been presented. The experimental unit consists of pipes that are made up of clear PVC, which is capable of producing several different flow regimes (Stratified, bubble, slug, and annular-mist flow) of gas-liquid flows. The entire length of the flow loop is 20.574 m. The experimental unit includes sensors such as pressure transducers, thermocouples and flowmeters that enable to measure the pressure ranges from 20–300KPa, temperature ranges from 0 to 20 °C and volume flow ranges from 12–45 liter/min at numerous locations respectively. In this experimental work, bubble, and slug flow regimes have been selected in the multiphase flow pattern to be examined on the multiphase flow assurance. The results of this research will provide valuable new experimental data on multiphase flow characteristics for designated flow regimes that can improve flow assurance in subsea conditions by including the temperature and Pressure effects.

Multiphase flow phenomena are widespread in nature and production process. The study of the flow mechanism and characteristics are a very important in the multiphase pipe flow. The establishment of multiphase flow experimental devices and systems is necessary in the study. In order to multi-phase pipe flow simulation, the small-scale physical experimental system based on the PLC control, and the experimental simulation system of based on Configuration software design are achieved. The physical experimental system can be achieved signals acquisition and control. Bubble flow, stratified flow, wavy flow, slug flow and other flow patterns can be formed in the experimental pipeline by changing the oil-gas-water flow rate. The virtual experimental system consists of the control interface and virtual physical interface. The simulation experiments of the multiphase flow generation can be achieved through the data exchange by two computers. This system meets the requirements for multiphase flow experiment.

Previous multiphase pipe flow tests have mainly been conducted in horizontal and vertical pipes, with few tests conducted on multiphase pipe flow under different inclined angles. In this study, in light of mid–high yield and highly deviated wells in the Middle East and on the basis of existent multiphase flow pressure research on well bores, multiphase pipe flow tests were conducted under different inclined angles, liquid rates, and gas rates. A pressure prediction model based on Mukherjee model, but with new coefficients and higher accuracy for well bores in the study block, was obtained. It was verified that the newly built pressure drawdown prediction model tallies better with experimental data, with an error of only 11.3%. The effect of inclination, output, and gas rate on the flow pattern, liquid holdup, and friction in the course of multiphase flow were analyzed comprehensively, and six kinds of classical flow regime maps were verified with this model. The results showed that for annular and slug flow, the Mukherjee flow pattern map had a higher accuracy of 100% and 80–100%, respectively. For transition flow, Duns and Ros flow pattern map had a higher accuracy of 46–66%.

The aim of this research is to investigate the characteristics of the sub regime of slug flow in horizontal pipe. Here, a 16 mm inner diameter horizontal pipe is utilized in order to observe the specific behavior of each flow pattern. The air and water superficial velocity are 0.7 – 8 m/s and 0.2 m/s – 1.13 m/s, respectively. To obtain thorough insight through visualization, a high speed video camera is installed on the area 190 D where the flow is fully developed. A pair of CECM sensor is also placed to gather the quantitative data from the liquid slug hold up. Furthermore, the pressure characteristics of each sub regime flow pattern are recorded by using pressure transducer. As a result, the present study has been able to provide a comprehensive data of the slug flow sub regime. Broadly, there are four observed sub regime on the slug flow. Slug and plug flow is characterized by the presence of plug flow intermittently. The less aerated slug and highly aerated slug can be distinguished by the degree of aeration which can be verified by liquid hold up measurement. While the slug and wavy flow contains wavy interface on the stratified layer. The analysis of each flow pattern is followed by the propose of a slug flow sub regime flow pattern map which can be a reference for conducting further study or fulfilling industrial need.

The developments of oil and gas fields in deep waters (5000 ft and more) will become more common in the future. It is inevitable that production systems will operate under multiphase flow conditions (simultaneous flow of gas, oil and water possibly along with sand, hydrates, and waxes). Multiphase flow prediction tools are essential for every phase of hydrocarbon recovery from design to operation. Recovery from deep-waters poses special challenges and requires accurate multiphase flow predictive tools for several applications, including the design and diagnostics of the production systems, separation of phases in horizontal wells, and multiphase separation (topside, seabed or bottom-hole). It is crucial for any multiphase separation technique, either at topside, seabed or bottom-hole, to know inlet conditions such as flow rates, flow patterns, and volume fractions of gas, oil and water coming into the separation devices. Therefore, the development of a new generation of multiphase flow predictive tools is needed. The overall objective of the proposed study is to develop a unified model for gas-oil-water three-phase flow in wells, flow lines, and pipelines to predict flow characteristics such as flow patterns, phase distributions, and pressure gradient encountered during petroleum production at different flow conditions (pipe diameter and inclination, more » fluid properties and flow rates). In the current multiphase modeling approach, flow pattern and flow behavior (pressure gradient and phase fractions) prediction modeling are separated. Thus, different models based on different physics are employed, causing inaccuracies and discontinuities. Moreover, oil and water are treated as a pseudo single phase, ignoring the distinct characteristics of both oil and water, and often resulting in inaccurate design that leads to operational problems. In this study, a new model is being developed through a theoretical and experimental study employing a revolutionary approach. The basic continuity and momentum equations is established for each phase, and used for both flow pattern and flow behavior predictions. The required closure relationships are being developed, and will be verified with experimental results. Gas-oil-water experimental studies are currently underway for the horizontal pipes. Industry-driven consortia provide a cost-efficient vehicle for developing, transferring, and deploying new technologies into the private sector. The Tulsa University Fluid Flow Projects (TUFFP) is one of the earliest cooperative industry-university research consortia. TUFFP's mission is to conduct basic and applied multiphase flow research addressing the current and future needs of hydrocarbon production and transportation. TUFFP participants and The University of Tulsa are supporting this study through 55% cost sharing. « less

Design strategy of a microchannel device for liquid–liquid extraction based on the relationship between mass transfer rate and two-phase flow pattern

Flow regime behavior in upwards oil-water flow has been studied in a large diameter, inclinable, multiphase flow loop. With the pipe vertical, bubble flow occurred for all conditions tested. When the pipe was inclined by 5 or 15° from vertical, a new flow regime, countercurrent bubble flow, was observed over a wide range of flow conditions. Theoretical flow regime maps developed for gas-liquid flow did not properly predict oil-water flow regime behavior.

Two-phase flows are observed in various industrial plants and piping systems. Understanding two-phase flow behaviors such as flow patterns and unsteady void fraction in horizontal and vertical pipes are crucial in improving plant safety. Notably, the flow patterns observed in a large diameter pipe (approx. 4–6 in or larger) are significantly different from those observed in a medium diameter pipe. In a vertical large diameter pipe, no slug flow is observed due to the instantaneous slug bubble breakup caused by the surface instability. Besides, in a horizontal pipe, flow regime transition from stratification of liquid and gas to slug (plug) flow that induces unsteady flow should be taken into account. From this viewpoint, it is necessary to predict the flow regime in horizontal and vertical large diameter pipes with some elbows and to evaluate the unsteady flow regime. In this study, the simulation method based on the two-fluid model is developed. The two-fluid model is considered the most accurate model because the governing equations for mass, momentum, and energy transfer are formulated for each phase. When using the two-fluid model, some constitutive equations should be given in computing the momentum transfer between gas and liquid phases. In this study, several state-of-art constitutive equations of the bubble diameter, the interfacial drag force and non-drag forces such as the lift force and the bubble-bubble collision force, are implemented in the platform of ANSYS FLUENT. The developed simulation method is validated with visualization results and force from an air-water flow at the elbow of the piping system.

Introduction. Prediction of multiphase flow patterns in pipelines of gas and oil industry is a complicated hydrodynamic process. Hydraulics of gas-liquid flows and erosion processes in pipelines with many bends in which gas, water, oil and air move are insufficiently studied. There are known studies of movement in single-phase flow conditions with one elbow, which is insufficient for design of modern pipeline systems. Therefore, there is a need for in-depth analysis of interaction of media in multiphase flow and transported sand particles. In this paper the effects of elbows on multiphase flow hydraulics and erosion of pipe sections are investigated using computational fluid dynamics (CFD) modelling tools for 100 seconds’ of process. Materials and methods. A liquid volume model (VOF) was used to simulate three-phase flow: air-water with solids in a pipe with two elbows. Turbulence effects have been accounted for with the RNG k–ε model. The model verification methods from previous studies have been used. For the numerical solution, the Ansys Fluent version 20.1 software package has been used. The results of CFD modelling of the volumetric gas content have shown a good agreement with the available experimental data. Results. The results showed that the change in the flow regime remains unchanged before the first elbow and after the se-cond elbow in the cork flow. However, for the initial churn flow regime, the flow regime varies at different segments of the flow area before and after each elbow. Conclusions. The preliminary churn flow in the upper vertical section was transformed to wavy stratified flow in the horizontal section between the two elbows and wavy annular flow in the vertical pipe after the second elbow. The flow pattern in slug flow maintained same after the first elbow, but the Taylor bubbles are lengthier in the horizontal section between the first and second elbows.

Slug liquid holdup is one of the most important parameters of slug flow. It is closely related to the average liquid holdup and pressure gradient of slug flow in wells and pipelines. Barnea and Brauner (1985) and Zhang et al. (2003a) mechanistic models are based on the turbulent nature of liquid slugs, which is typical for low viscosity oils. However, for high viscosity oil slug flow, the liquid slug is laminar due to low slug Reynolds number. In this study, a slug liquid holdup mechanistic model is developed for low and high viscosity oil slug flows. The model is based on two shear mixings including shear between the slug front and pipe wall, and shear between the slug body and liquid film. The equations are solved based on slug flow characteristics which can be calculated by solving the continuity and momentum equations of slug flow. A data bank consisting of 418 slug liquid holdup measurements is used to validate the model. In the data bank, liquid viscosity ranges from 0.0016 to 0.589 Pa·s (1.6 to 589 cP). Pipe inclination angle is from −30? to upward vertical. Pipe inner diameter (ID) varies from 5.08 to 10 cm. Statistical evaluations are also conducted against predictions of other models. Significant improvement is observed in the performance of the new model. Introduction Heavy oil constitutes a major portion of the world's total oil reserve. It is discovered and produced around the world and has become one of the most important future hydrocarbon resources with ever increasing world energy demand and depletion of conventional oils. However, heavy oil possesses very high viscosity which poses many challenges for its production and transportation. Accurate pressure gradient and liquid holdup predictions of high-viscosity oil multiphase pipe flows are imperative for heavy oil production and transportation. Most of the current multiphase flow experimental studies, correlation and model developments were conducted using low-viscosity conventional oils or other liquids. However, high-viscosity oil multiphase flow behaves very differently than low-viscosity oil multiphase flow. Significant discrepancies were observed in model comparisons. Slug flow is a dominant flow pattern in high-viscosity oil/gas pipe flow. In two-phase slug flow, liquid slugs and gas pockets propagate alternatively in the pipe. Liquid slugs without gas entrainment are rare under normal pipeline operating conditions. Instead, gas bubbles are often entrained in the liquid slugs. The liquid volume fraction in the slug body is known as the slug liquid holdup. The slugs can carry different amount of entrained gas, which primarily depends on flow rates, fluid properties, and pipe diameter. A slug unit consists of the slug body and a liquid film zone. The fast moving aerated slug body over rides the slow moving liquid film ahead of it. The slug scoops the liquid film and accelerates it to the velocity of the slug (mixture velocity). Liquid is shed from the tail of the slug to a trailing film. Slug liquid holdup is an important parameter for slug flow modeling. Most of the pressure drop in slug flow occurs in the slug body. The frictional pressure drop is greater in the slug body than in the film region. The liquid film acceleration also causes significant pressure drop in the mixing zone at the slug front. Thus the overall pressure gradient depends greatly on the slug liquid holdup and slug length.

Vertical two-phase flow is normally classified into the four basic flow regimes bubble, slug, churn and annular flow. The transition between the different flow regimes does not occur suddenly and many extensions of this classification can be found in literature. For the prediction of flow patterns empirical and theoretical flow pattern maps have been developed. A new criterion is presented for the transition between bubble and slug flow which is based on local instantaneous conductivity measurements with a wire mesh sensor (1 kHz that means 1024 frames per second, 242 measuring points in a tube cross section area). The high resolution allows the calculation of particle size distributions. The transition from homogeneous bubble flow to heterogeneous bubble flow is indicated by the appearance of a bimodal bubble size distribution. If the equivalent bubble diameter exceeds the tube diameter the transition from bubble to slug flow occurs. A comparison of the new criterion with different empirical and theoretical flow maps shows a good agreement.

ABSTRACTThe present study investigates the phenomenon of steam condensation in a rectangle horizontal channel with a mass flux range of 20–70 kg/m2/s and a vapor quality of 0.2–0.8. Mass flux and vapor quality were presented to primarily affect the heat transfer coefficient in shear-dominated flow regime, such as the mass flux is greater than 40 kg/m2/s. At the low mass flux, only slug flow, plug flow, and wave flow were observed. At the high mass flux, the wave flow and annular flow were observed even at the low-vapor quality, and the slug and plug flow were not found during the entire condensation process. Observed flow patterns agreed with Tandon’s flow pattern map. Four kinds of correlations are employed to predict the condensing heat transfer coefficient, and the result reveals that Cavallini’s correlation agrees with the experimental results relatively well. The measured pressure drop has a good agreement with the Lockhart–Martinelli correlation.

Analysis of flow pattern transition from segregated to slug flow in upward inclined pipes

Sand erosion in multiphase flow is receiving widespread attention from the oil and gas industry. Several tools to predict erosion have been developed. One tool, called SPPS (Sand Production Pipe Saver), predicts penetration rates (pipe thickness loss rate) in fittings such as elbows. This tool accounts for many different operating conditions and can also be used to predict threshold flow rates that will result in only a tolerable amount of erosion. The SPPS model can be used to help avoid major pipeline failures, plan inspections and maintenance, develop cost to benefit projections, or estimate life expectancy of a pipeline for known flow conditions and sand production rates. Many flow regimes can occur in multiphase flow. This study focuses on the flow properties that effect sand erosion rates for slug flow. Experiments were conducted and a mechanistic flow model was developed. Erosion data were obtained for slug flow through an elbow and in a straight section of pipe. Erosion data show the effects of varying the superficial liquid and gas velocities, the liquid viscosity, the sand size, and sand rate. Data acquisition was accomplished through electrical resistance (ER) probes. Two flat-head ER probes were positioned in an elbow at 45° and 90° flush with the pipe wall. One intrusive probe was deployed in a straight section and protruded into the flow. Increasing the superficial gas velocity in these flow regimes extensively increases the erosion rate while increasing the superficial liquid velocity does not significantly increase erosion. Increased viscosity decreases the impacting velocity of impinging particles, and thereby reducing the magnitude of erosion on the pipe wall. The affect of particle size has been investigated and found to vary with viscosity. These trends were also found to vary with location of the probe. A mechanistic erosion model was also been developed. Model results are compared with sand erosion data. Predicted erosion rates from the model developed during this investigation agree well with the data collected in the present work and in previous studies.