In this thesis, a 7-field Lagrangian slug capturing and slug tracking model with higher order methods and an adaptive grid is investigated for predicting the behaviour of two-phase gasliquid flow in multiphase flow pipelines. The model is capable of simulating both compressible and incompressible slugs, and pigs. The model has the possibility to simulate gas-liquid flow, including a liquid droplet field in the gas and entrained gas in the liquid.Walls consisting of multiple layers of different materials can be added to the pipes, and the energy equations for both the pipe walls and the fluids are solved. The mass, momentum and energy equations are solved in an iterative manner. Several additional tools and features have also been developed, like a steady state solver for the velocity, holdup, pressure and temperature, a unit-cell model which can be used as a standalone tool or as a sub-grid model in the dynamic model, fully period boundary conditions, curved pipe geometry, usage of tabulated PVT-files, and modelling of interfacial mass transfer. Higher order schemes are available for both spatial and temporal discretization. Different details in the two-fluid model have also been investigated, amongst other how to handle changes in the pipe cross-sectional area correctly for the border movement and level gradient. It is also shown how the upwind velocity must be modified by scaling factors to obtain the correct Bernoulli effect in the case of incompressible flow.The work resulted in four papers. In Paper 1 the model was tested against large scale experimental data, and was shown to give good predictions of the slugging periods after including a liquid droplet field and including the separator in the simulations. In Paper 3 the slug capturing capabilities of the model are tested against experimental data from a medium Furthermore I want to thank Jon Harald Kaspersen, my superior at SINTEF Petroleum, who allowed me to take a partial absence of leave in order to do this work. ..................................................................................................................... 92 2.9.7 Generic equation class ................................................................................................................ IntroductionIn the petroleum industry, multiphase flow occurs when transporting oil and gas (and possibly water) in the same pipe through long multiphase pipeline systems. The behaviour of the flow can take many forms (flow patterns), depending on several parameters like fluid velocities, pipe diameter, pipe inclination, and the fluid properties. The fluid properties are again dependent on the pressure and temperature in the system, especially the gas density and the fluid viscosity. Certain flow patterns can cause significantly reduced production, or even such operational challenges that the pipeline must be abandoned. It is therefore of crucial importance to be able to predict the behaviour of the flow when investigating how to design the pipeline. The simplest of the...
This article presents void fraction and pressure gradient data for sulfur hexafluoride (SF6) with gas densities of 28 and 45 kg/m3 and oil (with viscosity 35 times that for water) in a 127 mm diameter pipe. The superficial velocities of gas ranged from 0.1 to 3 m/s and those for liquid from 0.1 to 1 m/s, respectively. Measurements of void fraction data were recorded using a capacitance wire mesh sensor (WMS) system, which permits the 3D visualization of the flow patterns. All the data were obtained with a data acquisition frequency of 1,000 Hz. A differential pressure transducer was used to measure the pressure drops along the length of the pipe. The WMS provide time and cross‐sectionally resolved data on void fraction and from an analysis of its output, flow patterns were identified using the characteristic signatures of probability density function (PDF) plot of time series of void fraction. The PDF plots showed the single peak shapes associated with bubbly and churn flows but not the twin‐peaked shape usually seen in slug flows. This confirms previous work in larger diameter pipes but with less viscous liquids. For the bubble and churn flows investigated, the pressure gradient was observed to decrease with an increase in gas superficial velocity. Nevertheless, there was an insignificant observed effect of pressure on void fraction below certain transitional flow rates, the effect however became significant beyond these values. In the present work, wisps appear to be smaller, which might be due to the different fluid properties of the working fluids employed. In addition, wisps are easily revealed as long as there is a transition between churn and annular flows regardless of the pressure. Experimental data on void fraction and pressure gradient are compared against existing data. Reasonably good agreements were observed from the results of the comparison.
Long slugs arriving in separators/slug catchers is a major flow assurance concern in the offshore oil production industry, potentially causing flooding and/or severe separation problems. The sizing of the receiving facilities is determined by the longest slugs, so the economic implications of slug length predictions can be substantial. Slugs may also over time cause serious fatigue issues in free-span pipe sections, as large load variations can drastically reduce the lifetime of the flange connections. In most laboratory experiments reported in the literature, slugs rarely become longer than around 30-40 pipe diameters, while in many oil production fields, slugs can be considerably longer. Consequently, there is a clear need to better understand how and why such long slugs appear in production systems, and in this paper we present results that shed some light on this matter. We present a unique set of two- and three-phase slug flow experiments conducted in a 766 meter long 8" pipe at 45 bara pressure. The first half of the pipe was horizontal, while the second half was inclined by 0.5 degrees. A total of ten narrow-beam gamma densitometers were mounted on the pipe to study flow evolution, and in particular slug length development. In addition, the average phase fractions were measured using two traversing gamma densitometers, and one 160 meter long section with shut-in valves. The pressure drop was also measured along the loop using a total of twelve pressure transmitters. The results show that the mean slug length initially increases with the distance from the inlet, but this increase slows down and the mean slug length typically reaches a value between 20 and 50 diameters at the outlet. At low flow rates, the slug length distributions tend to be extremely wide, sometimes with standard deviations approaching 100%. The longest slugs that we observed were over 250 pipe diameters (50 meters). At higher flow rates, the slug length distributions are generally narrower. The effect of the water cut on the slug length distribution is significant, but complex, and it is difficult to establish any general trends regarding this relationship. Finally, it was observed that slug flow often requires a very long distance to develop. Specifically, in most of the slug flow experiments, the flow regime 50 meters downstream of the inlet was not slug flow. The reported experiments are the first three-phase slug flow experiments ever conducted in a large-scale setup. By using a long, heavily instrumented pipe, we were able to study the evolution of slug length distributions over a long distance. We believe that these experiments can be of considerable value for developing tools for predicting slug lengths in multiphase transport systems, which is a critical matter for oil field operators.
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