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.

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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.

Slug flow is one of the most critical and often encountered flow patterns in the oil and gas industry. It is characterised by intermittency which results in large fluctuations in liquid holdup and pressure gradient. A proper understanding of its parameters (such as slug holdup) is essential in the design of transport facilities (e.g. pipelines) and process equipment (slug catchers, separators etc.). In this paper, experimental investigation of slug liquid holdup (defined as the liquid volume fraction in the slug body of a slug unit) is performed. Mineral oil with viscosity, and air were used as test fluids. A 0.0254 m and 0.0762 m pipe internal diameters facilities with pipe lengths of 5.5 and 17 m respectively were used in the study. Electrical Capacitance Tomography was used for slug holdup measurements. Results obtained in the study shows that slug liquid holdup varied directly as the viscosity and inversely as the gas input fraction. Existing slug holdup correlations and models in literature did not sufficiently predict present experimental results. A new empirical predictive correlation for estimating slug liquid holdup was derived from present experimental databank and from data obtained in literature. The databank's liquid viscosity ranges from 0.189-8.0 Pa.s. Statistical analysis of the new correlation vis-à-vis existing ones showed that the present correlation gave the best performance with an average percent error, E 1 ; absolute average percent error, E 2 and standard deviation, E 3 of 0.001, 0.05 and 0.07 respectively, when tested on the high viscosity liquid-gas databank.