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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Summary We present a unique set of two- and three-phase slug-flow experiments conducted in a 766-m-long, 8-in. pipe at 45-bara pressure, using Exxsol™ D60 fluid (ExxonMobil Chemical, Houston, Texas, USA) as the oil phase and nitrogen as the gas phase. The first one-half of the pipe was horizontal, while the second one-half was inclined by 0.5°. A total of 10 narrow-beam gamma densitometers were mounted on the pipe to study flow evolution, and in particular slug-length development. 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 mixture velocities (<3 m/s), the slug-length distributions tend to be extremely wide, sometimes with standard deviations approaching 100%. The longest slugs that we observed were more than 250 pipe diameters (50 m). At higher mixture velocities (>3 m/s), the slug-length distributions are in general narrower. The effect of the water cut (WC) 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 57 m downstream of the start of the horizontal section was not slug flow.

This paper describes a flow assurance method known as "cold flow". The method is suitable for deepwater liquid dominated fields and reduces costs and carbon emissions compared to conventional flow assurance methods by letting hydrate and wax deposits travel as inert solids with the production stream to the host fascility (e.g. an FPSO). A compact subsea unit that utilizes the cold flow method is presented and an experimental test setup at SINTEF's Multiphase Flow Laboratory is described. The unit consists of a recycle stream that seeds dry particles to a place where the bulk flow temperature is close to the hydrate formation temperature (HFT) and the wax appearance temperature (WAT). Water droplets coat the dry particles and become a part of the particles absorbing free water in the flow. In addition to the seeding mechanism, a robot operated induction coil removes inner pipe wall deposits by heating the pipe locally. Results from the tests show no build-up of solids inside the cold flow unit itself or downstream the unit. The flow system is also robust in terms of shutdowns and the production flow is regained easily. Measurements also show that the unit is robust with respect to increasing water cut (WC).