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Gas hydrates cold flow can be defined as flow of non-adhesive and non-cohesive hydrate particles dispersed in the production fluids flowlines. Implementation of cold flow related hydrate management strategies might significantly reduce the costs of oil and gas field development and production by removing or reducing the need for injection of chemicals, insulation, and heating. Several research groups have performed experiments focusing on different methods of producing hydrate dispersion. Hydrate particles can be seeded into the production fluids at hydrate stable conditions to initiate controlled growth of hydrates as the dispersion is cooled to temperature conditions in production systems. Alternatively, the water droplet size in water in oil dispersions can be reduced by utilizing static mixers, high velocity, or small concentrations of chemicals, which might facilitate readily conversion of the small water droplets into hydrate particles. One researcher has proposed separating liquid phases from gas and supercooling of liquid phases before mixing the phases for hydrate formation. Use of antiagglomerants combined with reducing viscosity by increasing water content has been proposed by other researchers. Cold flow as a component of a natural gas dehydration process is described in a patent application but has not been experimentally tested. Laboratory-scale flow loop experiments indicate that cold flow works well for low to medium gas/oil ratios and up to 20% water cut for both oil and condensate dominated systems. Experiments with crude oils containing wax show that cold flow could significantly reduce or eliminate wax deposition on pipeline walls. A field trial of the cold flow method in a once-through flowline focused on reducing droplet size, resulting in hydrate deposition. This review discusses utilized methods and published results on cold flow from various research groups in light of known mechanisms for hydrate formation. Some suggestions are also given with focus for future research in order to develop, validate, and implement cold flow as a reliable technology for hydrate management method in the production of hydrocarbon fluids.

Sloughing of gas hydrates from deposits formed on the pipe wall is a phenomenon that can cause hydrate accumulation and blockage of the flow in oil/gas pipelines. While hydrate sloughing has been recognized as an important mechanism leading to hydrate blockage, its observation and measurements have not been reported. Experiments performed in a visual rocking cell to emulate multiphase flow conditions with a methane−ethane gas mixture, fresh water, and non-emulsifying oil or condensate as hydrocarbon liquid demonstrated that hydrate sloughing occurs at a wide range of subcooling and temperature gradient conditions. However, sloughing was not detected in a narrow operational window defined by both subcooling lower than 4 °C and temperature gradient in the cell lower than 1 °C. The potential existence of an operational window for conditions without sloughing might be valuable for the development of hydrate management strategies for blockagefree production.

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