Summary Oil/water flow-pattern transitions in horizontal pipes have been studied both experimentally and theoretically. A new state-of-the-art oil/water test facility was designed, constructed, and operated. A transparent test section (5.013-cm inside diameter x 15.54 m long) can be inclined at any angle, to study both upward and downward flow simultaneously. Mineral oil and water were the working fluids (µo/µw=29.6, po/pw=0.85, and o=36 dynes/cm at 25.6°C). A new classification for oil/water flow patterns based on published and acquired data is proposed. Six flow patterns were identified and classified into two categories: segregated flow and dispersed flow. Stratified flow and stratified flow with some mixing at the interface (ST&MI) are segregated flow patterns. The dispersed flow can be either water dominated or oil dominated. A dispersion of oil in water over a water layer and an emulsion of oil in water are water-dominated flow patterns. An emulsion of water in oil and a dual dispersion are oil-dominant flow patterns. The oil/water flow-pattern transitions for light oils are predicted using the two-fluid model and a balance between gravity and turbulent fluctuations normal to the axial flow direction. Stability analyses reveal that the stratified/nonstratified transition must be addressed with the complete two-fluid model. Stratified flow is predicted by the viscous Kelvin-Helmholtz (KH) analysis while inviscid KH theory predicted the ST &MI flow pattern. For the dispersed flow pattern, the predicted drop sizes from the Hinze and Levich models are modified to account for the effect of the dispersed phase concentration. The controlling parameter for the coalescence phenomena is the water fraction. The model performance is excellent and compares well with published data. Introduction The need for reliable design methods for multiphase flow has been the driving force behind an extensive research effort in this area, especially for gas/liquid flow, over the past 30 years. Recently, the industry has turned its attention towards the understanding of the simultaneous flow of gas/oil/water mixtures. However, the limiting case where no gas phase is present has received inadequate attention. Dynamic flow characteristics of oil/water mixtures are important in applications such as designing water-lubricated pipelines, production strings in oil wells, and artificial-lift methods. Understanding of oil/water flow behavior in pipes can be crucial in determining the amount of free water in contact with the pipe wall that could cause corrosion/erosion problems. Oil/water flow behavior is also important in arriving at the correct interpretation of the response of production-logging instruments. The performances of separation facilities and multiphase pumps are a strong function of the upstream flow pattern. A knowledge of the distinctive features of oil/ water mixtures, together with those for gas/liquid systems, can be used in the future as a basis to understand the more complex case of gas/oil/water mixtures.

We collected all of the published data we could find on the rise velocity of long gas bubbles in stagnant fluids contained in circular tubes. Data from 255 experiments from the literature and seven new experiments at PDVSA Intevep for fluids with viscosities ranging from 1 mPa s up to 3900 mPa s were assembled on spread sheets and processed in log–log plots of the normalized rise velocity, $\hbox{\it Fr} \,{=}\,U/(gD)^{1/2}$ Froude velocity vs. buoyancy Reynolds number, $R\,{=}\,(D^{3}g (\rho_{l}-\rho_{g}) \rho_{l})^{1/2}/\mu $ for fixed ranges of the Eötvös number, $\hbox{\it Eo}\,{=}\,g\rho_{l}D^{2}/\sigma $ where $D$ is the pipe diameter, $\rho_{l}$, $\rho_{g}$ and $\sigma$ are densities and surface tension. The plots give rise to power laws in $Eo$; the composition of these separate power laws emerge as bi-power laws for two separate flow regions for large and small buoyancy Reynolds. For large $R$ ($>200$) we find \[\hbox{\it Fr} = {0.34}/(1+3805/\hbox{\it Eo}^{3.06})^{0.58}.\] For small $R$ ($<10$) we find \[ \hbox{\it Fr} = \frac{9.494\times 10^{-3}}{({1+{6197}/\hbox{\it Eo}^{2.561}})^{0.5793}}R^{1.026}.\] The flat region for high buoyancy Reynolds number and sloped region for low buoyancy Reynolds number is separated by a transition region ($10\,{<}\,R\,{<}\, 200$) which we describe by fitting the data to a logistic dose curve. Repeated application of logistic dose curves leads to a composition of rational fractions of rational fractions of power laws. This leads to the following universal correlation: \[ \hbox{\it Fr} = L[{R;A,B,C,G}] \equiv \frac{A}{({1+({{R}/{B}})^C})^G} \] where \[ A = L[\hbox{\it Eo};a,b,c,d],\quad B = L[\hbox{\it Eo};e,f,g,h],\quad C = L[\hbox{\it Eo};i,j,k,l],\quad G = m/C \] and the parameters ($a, b,\ldots,l$) are \begin{eqnarray*} &&\hspace*{-5pt}a \hspace*{-0.8pt}\,{=}\,\hspace*{-0.8pt} 0.34;\quad b\hspace*{-0.8pt} \,{=}\,\hspace*{-0.8pt} 14.793;\quad c\hspace*{-0.8pt} \,{=}\,\hspace*{-0.6pt}{-}3.06;\quad d\hspace*{-0.6pt} \,{=}\, \hspace*{-0.6pt}0.58;\quad e\hspace*{-0.6pt} \,{=}\,\hspace*{-0.6pt} 31.08;\quad f\hspace*{-0.6pt} \,{=}\, \hspace*{-0.6pt}29.868;\quad g\hspace*{-0.6pt}\,{ =}\,\hspace*{-0.6pt}{ -}1.96;\\ &&\hspace*{-5pt}h = -0.49;\quad i = -1.45;\quad j = 24.867;\quad k = -9.93;\quad l = -0.094;\quad m = -1.0295.\end{eqnarray*} The literature on this subject is reviewed together with a summary of previous methods of prediction. New data and photographs collected at PDVSA-Intevep on the rise of Taylor bubbles is presented.

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A modified mechanistic model is formulated to predict the pressure drop in horizontal slug flow for two-phase flow (viscous liquid and air). The model is evaluated by using accurate PDVSA INTEVEP experimental data for liquid with viscosity of 480 cP. A comparison between the modified model and experimental data shows that the absolute average relative error in pressure drop prediction is less than 6%. Introduction Venezuela has the world largest heavy oil reserves. PDVSA has launched several projects to develop the technology for optimum exploitation and production schemes. Special attention have been focused on multiphase flow along the production system, which includes horizontal & multilateral wells, vertical wells (tubing & annular flow), pipelines and production networks. Multiphase flow is characterized for the existence of flow patterns. There are different types of them, where the most common one is called slug flow, see Fig 1. Therefore, proper production system design requires of reliable pressure drop models for slug flow. Current pressure drop models for slug flow, have been developed and validated for low viscosity oils. Fluid properties affect the slug flow characteristics as well as the behavior of the pressure losses. Available pressure drop models estimate the pressure gradient with average errors about 30% as can be seen in Fig 2. This uncertainty might affect CAPEX and OPEX up to 10%. The interest of this work is to develop a rigorous pressure drop model that can be applied for both light and heavy oils. The model should be validated initially with lab data and then with field data. Due to the lack of high quality laboratory data for pressure drop in heavy oils, PDVSA INTEVEP built a multiphase production laboratory. The experimental facility and the slug flow model will be described next. Experimental Setup Test facility description Experiments were carried out in a 2-in test loop facility at PDVSA INTEVEP. Lube oil (480 cP) and air were testing fluids.