In the third part of this series, we introduce the mathematical model for the agglomeration of gas hydrate in oil continuous flow. The aim is to develop an expression for the agglomeration efficiency that considers the existence of a wet or a dry particle. If the particle is wet, then water is available at its outer surface, thus allowing the formation of a liquid bridge that holds the aggregate together.The criterion for a wet or dry particle was developed in part II of this series and comes from the competitions between water permeation through the porous hydrate particle, and water consumption caused by crystallization in the particle's outer surface. The new expression for the agglomeration efficiency is coupled with a population balance solved through the Method of Moments and considering simple expressions for the collision rate and the shear rate induced by the flow coming from Smoluchowski's and Kolmogorov's theory, respectively. When compared to experimental data, the model stays within the ±40% deviation range and shows capable of predicting smaller agglomerate size for higher subcooling and lower interfacial properties (use of surfactant additives).The influence of subcooling into changing the porous medium parameters (especially the porous medium interconnectivity) shows to be important into the determination of the time taken for the particle to dry out. The model is simplified for engineering purposes considering gases much more soluble in oil than in water (hydrocarbon gases) in oil-continuous flow, and a simple criterion is proposed to predict if the system behaves as dispersed (slurry) or if it agglomerates after the onset of hydrate formation.

No abstract

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.

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.

Gas hydrates are crystalline compounds, solid structures where water traps small guest molecules, typically light gases, in cages formed by hydrogen bonds. They are notorious for causing problems in oil and gas production, transportation and processing. Gas hydrates may form at pressures and temperatures commonly found in natural gas and oil production pipelines, thus causing partial or complete pipe blockages. In order to inhibit hydrate formation, chemicals such as alcohols (e.g., ethanol, methanol, mono-ethylene glycol) and salts (sodium, magnesium or potassium chloride) are injected into the produced stream. The purpose of this work is to briefly review the literature on hydrate formation in mixtures containing light gases (hydrocarbons and carbon dioxide) and water in the presence of thermodynamic inhibitors. Four calculation methods to predict hydrate formation in those systems were examined and compared. Three commercial packages (Multiflash ® , PVTSim ® and CSMGem) and a hydrate prediction routine in Fortran90 using the van der Waals and Platteeuw theory and the Peng-Robinson equation of state were tested. Predictions given by the four methods were compared to independent experimental data from the literature. In general, the four methods were found to be reasonably accurate. CSMGem and Multiflash ® showed the best results.