This study looked to improve reproducibility in the procedure to determine the yield stress of water-in-oil (W/O) emulsions prepared with waxy crude oil. The influence of various experimental variables was studied: measurement geometry, emulsion cooling rate, shear stress during the cooling step, gap reduction (parallel plates), final gap (parallel plates), and conditioning steps. The measured yield stress varied significantly depending upon the measuring geometry used (from 100 to 500 Pa). The geometries cross-hatched parallel plate (D = 60 mm) and grooved coaxial cylinder measured the highest yield stress, and it was observed that the shear stress during cooling was the most important measurement variable in the emulsion yield stress.
Summary One-dimensional numerical simulations of carbon dioxide (CO2)-rich crude-oil flows were performed with a commercial simulator for a typical offshore production pipeline under steady-state scenarios. Mixtures with 20–50 mol% CO2 and gas/oil ratio (GOR) of 300–600 std m3/std m3 were thermodynamically modeled with the predictive Peng-Robinson (PPR78) equation of state (EOS) (Robinson and Peng 1978; Jaubert and Mutelet 2004), and fluid properties were tabulated in pressure/volume/temperature (PVT) lookup tables. Thorough analyses on the separate CO2 and GOR effects on several flow parameters (e.g., temperature drop, pressure gradient, and flow patterns) were performed. The occurrence of the simultaneous flow of liquid and an ambiguous dense phase was quantified and discussed in depth. The properties of those phases [e.g., Joule-Thomson coefficient, viscosity, interfacial tension (IFT), and gas/liquid-density ratio] along the pipeline for several mixtures and operational conditions were addressed as well. It was seen that the dense phase can be a problem for phase-identification criteria, which can affect the flow-simulation results. This was further analyzed in simple cases of horizontal and vertical flows of CO2-rich crude-oil mixtures, under key temperature/pressure conditions. Finally, comparisons were performed between the holdup and pressure-gradient results of those cases, obtained with different liquid/liquid- and gas/liquid-modeling approaches of a hydrodynamic point model of a commercial simulator.
A distinct characteristic of reservoir fluids in different Brazilian pre-salt fields is the high Gas-Oil- Ratio (GOR) and high content of CO2 in the associated gas. In particular, the presence of CO2 in significant amounts is known to have a strong influence on the thermophysical properties and phase equilibria of the oil mixtures. Due to the strategy of re-injection of CO2-rich streams for EOR purposes, these aspects can be even more pronounced in the production fluids in future scenarios. In the present work, a parametric study is performed to investigate the influence of both CO2 molar content and GOR, in a controlled manner, on the simulations of a pre-salt field configuration for various operating conditions. PVT look-up tables were used with a commercial multiphase flow simulator. First, the thermodynamic modelling of a 20% molar CO2 pre-salt oil was performed, along with well characterized CO2-live oil mixtures taken from the literature, in order to generate PVT look-up tables. They were used to successfully reproduce field data and assess the validity of multiphase flow simulation results from a commercial software. For the CO2-rich live oil mixtures from the literature, a parametric study was performed in which the CO2 molar content ranged from 20% to 50% with 300-600 Sm3/Sm3 of GOR. Simulation results of temperature, total pressure drop, gas volume fraction and gas- liquid density ratio are presented and compared.
There are several challenges associated to the pre-salt development at the Santos basin, such as long distances from the coast, low temperature reservoirs, high pressures, high water depth, among others. Additional aspects contributing to the complex production scenario are related to fluid characteristics and flow assurance. In particular, the high CO 2 content in the dissolved gas is an important characteristic that should be also analyzed, because CO 2 is not only a heavy component, when compared to lighter components present in the gas phase, but has also a high Joule-Thomson coefficient. This affects pressure drop and specially the mixture cooling behavior during decompression. The cooling effect is expected to be strong at high production rates. Thus, the objective of the present work is to evaluate these effects under present and future production scenarios, taking into account increasing CO 2 contents due to re-injection strategies.Two different field configurations were investigated and a variety of operating conditions was used, along with real and model fluids ranging from 5% to 50% CO 2 content (molar basis). PVT data for the model fluids with high CO 2 content were generated by a simulated swelling test with CO 2 of an existing mixture with lower CO 2 content. A parametric study was carried out aiming at investigating primarily the total pressure and temperature drop in the pipeline when the total CO 2 content of the mixture is increased. Furthermore, variation of the fluid properties along the well, flowline and riser was evaluated. Results are also discussed in view of the impact of increasing CO 2 contents and the challenges experienced during simulation of such flows.
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