Sand production in the life of oil and gas reservoirs is inevitable, as it is co-produced with oil and gas from the reservoirs. Its deposition in petroleum pipelines poses considerable risk to production and can lead to pipe corrosion and flow assurance challenges. Therefore, it is important that pipe flow conditions are maintained to ensure sand particles are not deposited but in continuous motion with the flow. The combination of minimum gas and liquid velocities that ensure continuous sand motion is known as the minimum transport condition (MTC). This study investigates the effect both of sand particle diameter and concentration on MTC in gas/liquid stratified flow in a horizontal pipeline. We used non-intrusive conductivity sensors for sand detection. These sensors, used for film thickness measurement in gas/liquid flows, was used here for sand detection. We found that MTC increases with increase in particle diameter for the same concentration and also increases as the concentration increases for the same particle diameter. A correlation is proposed for the prediction of sand transport at MTC in air-water flows in horizontal pipes, by including the effect of sand concentration in Thomas's lower model. The correlation accounts for low sand concentrations and gave excellent predictions when compared with the experimental results at MTC.
Experimental investigation on discharge coefficient, Cd, for high viscosity fluid through nozzles was carried out. The viscosity of the fluid used for the test ranged from 350 to 1500 mPa s. The length-to-diameter ratio of the nozzle, / and the ratio of nozzle diameter to pipe diameter ratios were used to investigate the influence of geometry on Cd. Results show a significant dependence of Cd on Re, l/d and β ratio. An empirical correlation on the discharge coefficient was developed based on the data from this study which was also compared with data from other published studies. This correlation, with an R-squared value of 0.9541, was valid for nozzle sizes 10-20 mm and for Re between 1 and 2000. Cd values obtained from experimental data, and those from the empirical correlation were compared, and a mean standard deviation of 0.0231 was obtained.
An experimental study on viscous oil-water two-phase flow conducted in a 5.5 m long and 25.4 mm internal diameter (ID) pipeline is presented. Mineral oil with viscosity ranging from 3.5 Pa.s -5.0 Pa.s and water were used as test fluid for this study. Experiments were conducted for superficial velocities of oil and water ranging from 0.06 to 0.55 m/s and 0.01 m/s to 1.0 m/s respectively. Axial pressure measurements were made from which the pressure gradients were calculated. Flow pattern determination was aided by high definition video recordings. Numerical simulation of experimental flow conditions is performed using a commercially available Computational Fluid Dynamics code. Results show that at high oil superficial velocities, Core Annular Flow (CAF) is the dominant flow pattern while Oil Plug in Water Flow (OPF) and Dispersed Oil in Water (DOW) flow patterns are dominant high water superficial velocities. Pressure Gradient results showed a general trend of reduction to a minimum as water superficial velocity increases before subsequently increasing on further increasing the superficial water velocity. The CFD results performed well in predicting the flow configurations observed in the experiments.
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