Gas/Condensate Wellbore Modeling Using a Fundamental Approach
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 102479, "Gas/Condensate Wellbore Modeling Using a Fundamental Approach," by A.A. Sadegh, SPE, J.S. Zaghloul, and M.A. Adewumi, SPE, Pennsylvania State U., prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
Multiphase flow in the wellbore poses a challenge for production engineers because characterizing the prevailing flow regime determines which pressure-drop calculation method is appropriate. The problem is complicated further when the flowing fluid under-goes phase changes. A model was developed that comprises a flow-pattern-detection routine, a hydrodynamic model, and an equation-of-state-based phase-behavior package.

Introduction
As the demand for energy rises, production companies are exploring and exploiting more-complex reservoir systems. It is necessary to optimize production and conserve the natural drive mechanisms within those reservoirs. The production system comprises the reservoir, near-wellbore region, wellbore, and the surface production facility. Optimization of this system requires accurate prediction of pressure drop in the wellbore. However, single-phase flow seldom occurs in the wellbore. More commonly, multiphase flow prevails in the wellbore as well as in gas- and oil-transmission and -distribution pipelines. The engineering calculations required to design and operate these systems are complicated by several physical phenomena. These phenomena include flow-regime transitions, turbulence, and thermodynamic phase changes with pressure and temperature. Hence, the use of empirical correlations that are based on limited laboratory or field data often leads to erroneous predictions.
Many tools used by production engineers are based on empirical correlations. The approach taken in developing these models was to generate an extensive database by varying parameters thought to affect pressure drop. These parameters include gas-flow rate, liquid-flow rate, pipe diameter, fluid viscosities, and liquid surface tension. The pressure-drop data then are correlated to dimensionless groups according to relevant variables. However, this approach cannot be extrapolated safely to predict situations for which the actual well parameters are outside the range of data initially used to develop the correlation. Additionally, it was observed that different pressure gradients arose for a varied distribution of the flowing phases in the pipe. The regime transitions also were a function of the physical parameters of the flow system under consideration. Therefore, it is necessary to predict the prevailing flow regime and then use a pressure-drop prediction method suitable for that particular flow regime.
Flow of gas/condensate, in addition to the complexities inherent in all two-phase-flow modeling, is further complicated with retrograde condensation. The in-situ liquid fraction may change with a change in pressure, temperature, or fluid composition. This problem requires incorporating compositional modeling in predicting fluid splits and gas and liquid properties. It is necessary to integrate hydrodynamic modeling with hydrocarbon-phase-behavior modeling and flow-regime-transition determination to obtain reasonable predictions. The intent of this research was to address the challenges of accurately predicting pressure drop, liquid holdup, and fluid compositions for gas/condensate wells.