Gas hydrate formation is a stochastic phenomenon of considerable significance for any risk-based approach to flow assurance in the oil and gas industry. In principle, well-established results from nucleation theory offer the prospect of predictive models for hydrate formation probability in industrial production systems. In practice, however, heuristics are relied on when estimating formation risk for a given flowline subcooling or when quantifying kinetic hydrate inhibitor (KHI) performance. Here, we present statistically significant measurements of formation probability distributions for natural gas hydrate systems under shear, which are quantitatively compared with theoretical predictions. Distributions with over 100 points were generated using low-mass, Peltier-cooled pressure cells, cycled in temperature between 40 and -5 °C at up to 2 K·min and analyzed with robust algorithms that automatically identify hydrate formation and initial growth rates from dynamic pressure data. The application of shear had a significant influence on the measured distributions: at 700 rpm mass-transfer limitations were minimal, as demonstrated by the kinetic growth rates observed. The formation probability distributions measured at this shear rate had mean subcoolings consistent with theoretical predictions and steel-hydrate-water contact angles of 14-26°. However, the experimental distributions were substantially wider than predicted, suggesting that phenomena acting on macroscopic length scales are responsible for much of the observed stochastic formation. Performance tests of a KHI provided new insights into how such chemicals can reduce the risk of hydrate blockage in flowlines. Our data demonstrate that the KHI not only reduces the probability of formation (by both shifting and sharpening the distribution) but also reduces hydrate growth rates by a factor of 2.
Asphaltenes
are the heaviest and most polar class of compounds
in crude oil, which may precipitate out of solution due to changes
in the pressure, composition, or temperature. During production, aggregation
between asphaltene solids may lead to viscosification of the oil phase
and/or deposition of the solids on the flowline wall. This study presents
the first measurement of asphaltene interparticle cohesive forces
using a micromechanical force (MMF) apparatus, which is similar to
that used previously to investigate gas hydrate interparticle cohesion.
Asphaltene solids were precipitated from two crude oils, and cohesive
force measurements were performed for particle pairs with diameters
ranging from 100 to 200 μm. In air, the measured cohesive forces
between the asphaltene particles were approximately one-half of those
measured between hydrate particles in cyclopentane-saturated nitrogen
vapor. Asphaltene cohesive force was measured in liquid cyclopentane,
to provide a comparison against cyclopentane hydrate; in the liquid
phase, the asphaltene cohesive forces were 1 order of magnitude smaller
than the cohesive forces between cyclopentane hydrates. In addition,
the hydrate–asphaltene adhesive force in liquid cyclopentane
was measured to be of the same order of magnitude as that of hydrate
particle cohesion; this result suggests the potential for asphaltene-hydrate
solid aggregation as a potential flow assurance risk in oil and gas
production flowlines.
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