The oil and gas production in deeper water scenarios (e.g. pre-salt) has been increasing due to the growth in industrial production. The exploration fields under more severe conditions is accompanied by concerns about solid precipitation/deposition and hydrate formation. Transient operations, involving shut-in and restart is the most challenging scenario with risk for hydrate problem. The residence time of the production fluids associated to the rate of heat loss to the ambient seabed during the period of shut-in may increase the potential risk of hydrate blockage. This work is focused on understanding the hydrate formation, breakup, agglomeration and deposition, reproducing the shut-in and restart conditions in a lab-scale. Experiments were performed using a high pressure cell coupled to a rheometer using a custom-designed impeller and a rocking cell experiments with visual capabilities. A two-phase (water and gas) and three-phase (water, oil and gas) systems were used in the experiments. Also, the impact of the shear applied at restart on the hydrate morphology was evaluated. The viscoelastic behavior was observed in most shut-in and restart tests. Understanding the mechanism of hydrate formation and agglomeration during transient conditions may help to develop strategies to avoid hydrate plugging and allow the formation of a hydrate slurry yielding flowable conditions.
Transient
operations in oil and gas production can result in conditions
with a high potential for the formation of hydrate plugs. In restart
operations, the shear flow and the increased pressure can induce rapid
hydrate formation possibly leading to a plug or severe flow reduction.
In order to study favorable and unfavorable restart conditions, experiments
were performed in a high pressure cell coupled to a rheometer. Hydrate
slurry behavior was investigated under transient conditions. Experiments
were carried out in three-phase systems containing mineral oil or
crude oil, water, and a model natural gas mixture of 92/8 mol % methane/propane.
Two commercial antiagglomerants were added in the tests. Experiments
were conducted at varying water volumetric fractions (10, 30, 50 vol
%), subcooling (6 °C, 10 °C, 15 °C, 16 and 18 °C),
pressure (42, 56, and 70 bar), and mixing rates (100, 200, and 300
rpm). The viscoelastic behavior was observed in most shut-in and restart
tests. The experiments showed subcooling as an important parameter
that affects hydrate morphology. Also, experiments varying the rotation
speed showed that the apparent viscosity was unaffected by decreasing
the rotation speed, suggesting that hydrate particle/aggregate size
was unchanged. However, increasing the rotational speed resulted in
a decrease of the apparent viscosity, in the case without an additive,
or an increase in the apparent viscosity in the case with an antiagglomerant.
Results using crude oil, antiagglomerant, and high water cut did not
show viscoelastic behavior at shut-in and restart conditions. Both
antiagglomerants formed hydrate dispersions, indicating that a flowable
hydrate slurry had formed due to the antiagglomerant effect.
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