Due to the variability of flow pattern of gas liquid two-phase flow and complexity of flow mechanism,it is very difficult to seek a single model which is able to predict pressure drop and fit for any flow condition. when the existing model of two-phase flow pressure drop is used to predict the pressure of the conditions of producing gas well,a large error occurs.Therefore, it is necessary,based on the experimental data of gas-water two phase flow,to research the flow mechanism and discover the regular existing in the process of fluid property changing .On the basis of the current two-phase flow pressure drop model, it is important to explore modified pressure loss model applicable for producing gas well with water,to improve predictability of the pressure drop of gas wells,and to provide the theory and technology guidence for development of gas reservoir with water. Underbalanced drilling (UBD) has increased in recent years because of the many advantages associated with it. These include increase in the rate of penetration and reduction of lost circulation and formation damage. Drilling of deviated and horizontal wells also increased since recovery can be improved from a horizontal or a deviated well. The drilling of deviated wells using UBD method will reduce several drilling related problems such as hole cleaning and formation damage. Prediction of flow and pressure profiles while drilling underbalanced in such wells will help in designing and planning of the well. The aim of this research is to predict the pressure drop of slug flow in the certain pressure in vertical pipes using mechanistic model and to study the behavior of the flow profile in the drillstring and the annulus under UBD conditions through the use of mechanistic two phase flow models. Mechanistic two phase flow models is been used In this research to predict the liquid hold up for phase gas- liquid slug flow which is important for the accurate calculations of the pressure drop.In particular, its evaluation is important for the vertical pipes since the liquid hold up in the slug body is the main contributor to the hydrostatic pressure drop which quite significant for the verticals flows. Further development of mechanistic models has allowed accurate prediction of wellbore pressure. Many Underbalanced Drilling operations require the use of nitrified diesel as the drilling fluid.Thus two phase flow will exist both in the drill pipe and the annulus.

Slug flow commonly occurs in gas and oil systems. Current predictive methods are based on mechanistic models, which require the use of closure relations to complement the conservation equations to predict integral flow parameters such as liquid holdup (or void fraction) and pressure gradient. These closure relations are typically developed either empirically or from semi-empirical models assuming idealized geometry of the interface, thus they carry the highest uncertainties in the mechanistic models. In this work, sensitivity analysis has determined that Taylor bubble velocity in slug flow is one such closure relation which significantly affects the calculation of these parameters. The main objective is to develop a unified higher-fidelity closure relation for Taylor bubble velocity. Here, we employ a novel approach to overcome the experimental limitations: validated 3D Computational Multiphase Fluid Dynamics (CMFD) with Interface Tracking Methods (ITMs) where the interface is tracked with a Level-Set method implemented in the commercial code TransAT®. In the literature, the Taylor bubble velocity is modeled based on two different contributions: (i) the drift velocity, i.e., the velocity of propagation of a Taylor bubble in stagnant liquid, and (ii) the liquid flow contribution. Here, we first analyze the dynamics of Taylor bubbles in stagnant liquid by generating a large numerical database that covers the most ample range of fluid properties and pipe inclination angles explored to date (Eo [epsilon] [10, 700], Mo [epsilon] [1 . 10-6, 5 . 103], and [theta] [epsilon] [0°, 90°]). A unified Taylor bubble velocity correlation, proposed for use as a slug flow closure relation in the mechanistic model, is derived from that database. The new correlation predicts the numerical database with 8.6% absolute average relative error and a coefficient of determination R2 = 0.97, and other available experimental data with 13.0% absolute average relative error and R2 = 0.84. By comparison, the second best correlation reports absolute average relative errors of 120% and 37%, and R2 = 0.40 and 0.17, respectively. Furthermore, two key assumptions made in the CMFD simulations are justified with simulations and experiments: (i) the lubricating liquid film formed above the bubble as the pipe inclines with respect to the horizontal does not breakup, i.e., the gas phase never touches the pipe wall and triple line is not formed; and (ii) the Taylor bubble length does not affect its dynamics in inclined pipes. To verify the robustness of the first assumption, the gravity-induced film drainage is analytically modeled and experimentally validated. From this model, a criterion to avoid film breakup is obtained, which holds in the simulations performed. The second assumption is validated with both experiments and simulations. Finally, simulations of Taylor bubbles in upward and downward fluid flow in vertical and inclined pipes are performed, from where it is concluded that an improvement of the current velocity prediction models is needed. In particular, Taylor bubbles in vertical downward flow where the bubble becomes non-axisymmetric at high enough liquid flows are remarkably ill-predicted by current correlations.

Publisher Description

Multiphase Transport of Hydrocarbons in Pipes An introduction to multiphase flows in the oil and gas industry The term ‘multiphase flow’ refers to the concurrent flow of oil and/or gas, alongside other substances or materials such as production water, chemical inhibitors, and solids (e.g. sand). This is a critical topic in the oil and gas industry, where the presence of multiple flow phases in pipelines affects deliverability, generates serious complications in predicting flow performance for system design and operation, and requires specific risk mitigation actions and continuous maintenance. Chemical and Mechanical Engineers interested in working in this industry will benefit from understanding the basic theories and practices required to model and operate multiphase flows through pipelines, wells, and other components of the production system. Multiphase Transport of Hydrocarbons in Pipes meets this need with a comprehensive overview of five decades of research into multiphase flow. Incorporating fundamental theories, historic and cutting-edge multiphase flow models, and concrete examples of current and future applications. This book provides a sound technical background for prospective or working engineers in need of understanding this crucial area of industry. Readers will also find: Fundamental principles supporting commercial software Detailed tools for estimating multiphase flow rates through flowlines, wells, and more Integration of conservation principles with thermodynamic and transport properties Coverage of legacy and modern simulation models This book is ideal for flow assurance engineers, facilities engineers, oil and gas production engineers, and process engineers, as well as chemical and mechanical engineering students looking to work in any of these roles.