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Exploration of oil fields with high concentrations of carbon dioxide brings new challenges to the oil and gas industry. The high pressures reached in production pipelines can cause the condensation of the gas phase, characterizing the appearance of an upper quadruple point in the hydrate phase diagram. To prevent the formation of hydrates, the use of thermodynamic inhibitors, such as alcohols and glycols, is common in the industry. In addition, water from oil production is naturally inhibited with salts, such as NaCl. In this work, equilibrium data not previously reported for CO2 hydrates inhibited with MEG and NaCl were determined for pressures between 8.5 and 25 MPa using an isobaric experimental procedure. By the Clausius–Clapeyron relation and concepts of water activity, the consistency of the data was evaluated with promising results. A comparison of the measured data obtained in this work with prediction tools (Multiflash, PVTsim, and CSMGem) and the model by Sirino et al.30 [Fluid Phase Equilib.20184754563] was done.

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.

Centrifugal pumps operate below their nominal capacity when handling gas–liquid flows. This problem is sensitive to many variables, such as the impeller speed and the liquid flow rate. Several works evaluate the effect of operating conditions in the pump performance, but few bring information about the associated gas–liquid flow dynamics. Studying the gas phase behavior, however, can help understanding why the pump performance is degraded depending on the operating condition. In this context, this paper presents a numerical and experimental study of the motion of bubbles in a centrifugal pump impeller. The casing and the impeller of a commercial pump were replaced by transparent components to allow evaluating the bubbles' trajectories through high-speed photography. The bubble motion was also evaluated with a numerical particle-tracking method. A good agreement between both approaches was found. The numerical model is explored to evaluate how the bubble trajectories are affected by variables such as the bubble diameter and the liquid flow rate. Results show that the displacement of bubbles in the impeller is hindered by an increase of their diameter and impeller speed but facilitated by an increase of the liquid flow rate. A force analysis to support understanding the pattern of the bubble trajectories was provided. This analysis should enlighten the readers about the dynamics leading to bubble coalescence inside an impeller channel, which is the main reason behind the performance degradation that pumps experience when operating with gas–liquid flows.