Guidelines for Proper Application of Critical-Velocity Calculations

Abstract

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 120625, "Guidelines for the Proper Application of Critical- Velocity Calculations," by Robert P. Sutton, SPE, and Stuart A. Cox, SPE, Marathon Oil Company; James F. Lea, SPE, PLTech; and O. Lynn Rowlan, SPE, Echometer Company, prepared for the 2009 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 4–8 April. The paper has not been peer reviewed. Critical-velocity calculations in the form of charts or simple equations are used frequently by field personnel to determine a gas well's flowing conditions to determine if it is experiencing liquid-loading problems. Situations exist in which the use of the wellhead as the analysis point can lead to erroneous conclusions and for which the use of downhole conditions provides a better analysis. The assumptions used to develop the standard, simplified form of the critical-velocity equations and charts may not be appropriate for downhole application. Recommendations are made for determining whether the use of a surface or downhole analysis point is more appropriate to calculate the minimum critical gas velocity for a well. Introduction The critical velocity for producing fluid up the wellbore of natural-gas wells must be exceeded to prevent liquids from accumulating in the well. Use of the Turner method to determine this critical velocity has gained wide acceptance and use within the industry. To lift water to the surface efficiently, gas wells should produce in the mist-flow region in which liquid exists as a film on the wall of the pipe or as droplets within the flow stream. The basis of the Turner method is determination of the gas rate necessary to overcome the terminal fall velocity of a liquid droplet. Application of Turner's Method The accepted point for calculating the critical velocity is the wellhead. This location is convenient because wellhead pressure and temperature are readily available. This recommendation assumes a constant wellbore geometry and must be modified when the wellbore geometry is not constant. In many cases, the critical velocity can be relatively constant with depth. The flow velocity may exceed the critical velocity in the tubing; however, if the end of the tubing is set above the producing interval, the resulting flow velocity in the casing will be much lower and can be less than the critical velocity. In this instance, the critical velocity should be determined for the larger-diameter flow conduit and the conditions at this point in the well should be used to determine the corresponding gas-flow rate. For instances in which the flow geometry is constant, determining a minimum-gas-production rate should enable exceeding the critical velocity along the entire flow path. This philosophy ensures that liquid cannot accumulate in the well. If the flow velocity drops below the critical velocity near the bottom of the well, the flow regime will change from mist to slug flow, and liquid can begin to accumulate. As the process continues, a static liquid column often is noted in the bottom of the well. This is a gaseous-liquid column resulting from gas producing through the liquid, which exhibits a reduced mixture density.