Experimental Investigation of Gas-Hydrate Formation and Particle Transportability in Fully and Partially Dispersed Multiphase-Flow Systems Using a High-Pressure Flow Loop

Abstract

Summary As the oil-and-gas industries strive for better gas-hydrate-management methods, there is the need for improved understanding of hydrate formation and plugging tendencies in multiphase flow. In this work, an industrial-scale high-pressure flow loop was used to investigate gas-hydrate formation and hydrate-slurry properties at different flow conditions: fully dispersed and partially dispersed systems. It has been shown that hydrate formation in a partially dispersed system can be more problematic compared with that in a fully dispersed system. For hydrate formation in a partially dispersed system, it was observed that there was a significant increase in pressure drop with increasing hydrate-volume fraction. This is in contrast to a fully dispersed system in which there is gradual increase in the pressure drop of the system. Further, for a partially dispersed system, studies have suggested that there may be hydrate-film growth at the pipe wall. This film growth reduces the pipeline diameter, creating a hydrate bed that then leads to flowline plugging. Because there are different hydrate-formation and -plugging mechanisms for fully and partially dispersed systems, it is necessary to investigate and compare systematically the mechanism for both systems. In this work, all experiments were specifically designed to mimic the flow systems that can be found in actual oil-and-gas flowlines (full and partial dispersion) and to understand the transportability of hydrate particles in both systems. Two variables were investigated in this work: amount of water [water cut (WC)] and pump speed (fluid-mixture velocity). Three different WCs were investigated: 30, 50, and 90 vol%. Similarly, three different pump speeds were investigated: 0.9, 1.9, and 3.0 m/s. The results from these measurements were analyzed in terms of relative pressure drop (ΔPrel) and hydrate-volume fraction (ϕhyd). It was observed that, for all WCs investigated in this work, the ΔPrel decreases with increasing pump speed, at a similar hydrate-volume fraction. Analysis conducted with the partially-visual-microscope (PVM) data collected showed that, at constant WC, the hydrate-particle size at the end of the tests decreases as the mixture velocity increases. This indicates that the hydrate-agglomeration phenomenon is more severe at low mixture velocity. Calculations of the average hydrate-growth rate for all tests conducted show that the growth rate is much lower at a mixture velocity of 3.0 m/s. This is attributed to the heat generated by the pump. At a high mixing speed of 3.0 m/s, the pump generated a significant amount of heat that then increased the temperature of the fluid. Consequently, the hydrate-growth rate decreases. It should be stated that this warming effect should not occur in the field. Flow-loop plugging occurred for tests with 50-vol% WC and pump speeds lower than 1.9 m/s, and for tests with 90-vol% WC at a pump speed of 0.9 m/s. In addition, in all 90-vol%-WC tests, emulsion breaking, where the two phases (oil and water) separated, was observed after hydrate formation. From the results and observations obtained from this investigation, proposed mechanisms are given for hydrate plugging at the different flow conditions. These new findings are important to provide qualitative and quantitative understanding of the key phenomena leading to hydrate plugging in oil/gas flowlines.