Guidelines for the Proper Application of Critical Velocity Calculations

Abstract

Summary Critical velocity calculations in the form of charts or simple equations are frequently used by field personnel to evaluate a gas well's flowing conditions to determine if the well is experiencing liquid-loading problems. Literature detailing the critical velocity necessary to keep a gas well unloaded suggests using the conditions at the top of the well as an evaluation point. This is convenient for personnel conducting the evaluation because wellhead pressure and temperature data are readily available. A number of situations exist where the use of the wellhead as the evaluation point can lead to erroneous conclusions. The most obvious situation occurs with a change in geometry downhole when a tapered tubing string is run in a well or when the tubing is set above the perforations. In these instances a more robust evaluation results from using conditions at the bottom of the well and the downhole tubing geometry. Other conditions exist where the use of downhole conditions provides a better evaluation point. The assumptions used in the development of the standard, simplified form of the critical velocity equations and charts may not be appropriate for downhole application. In these cases, the fundamental equations must be used. The calculation of critical velocity requires knowledge of pressure, temperature, produced fluids, and pressure/volume/temperature (PVT) properties. The determination of critical rate requires the same properties with the addition of pipe diameter. The required PVT properties, including surface tension and density for both the gas and liquid phases, are reviewed. Correlations to calculate water-gas surface tension were found to have excessive error, so a new, more accurate method is presented. This paper provides recommendations for the use of a surface or a downhole evaluation point is more appropriate for the determination of the minimum critical gas velocity in a well.

Liquid loading in gas wells: From core-scale transient measurements to coupled field-scale simulations

“…As presented in Table 1, several investigators have suggested different modified expressions derived from Turner model. Turner et al, 1969 Created the widely accepted Turner equation Coleman et al, 1991 Suggested not to use the 20% correction factor for low pressure gas wells Nosseir et al, 2000 Considered influences from different flow regimes Li et al, 2002 Involved the droplets' shape Veeken et al, 2003 Defined the concept of Turner ratio Guo et al, 2006 Took the minimum required kinetic energy of gas flow into account Belfroid et al, 2008 Concerned with the effects due to wellbore inclination Sutton et al, 2010 Used more realistic PVT properties Zhou and Yuan, 2010 Included the liquid droplet concentration in gas wells Veeken et al, 2010 Designed a specific expression for offshore gas wells Luan and He, 2012 Comprised droplets rollover in the gas rising process…”

A New Comprehensive Model for Predicting Liquid Loading in Gas Wells

“…The droplet-reversal model suggests that the falling of liquid droplets in the gas core triggers the onset of liquid loading. The widely used droplet model is a correlation developed by Turner et al (1969). The equation suggests that the inception of liquid loading is related to the minimum gas velocity to lift the largest liquid droplet in the gas core.…”

“…Later, Coleman et al (1991aColeman et al ( , 1991b) examined the Turner et al (1969) method with low wellhead pressure data. They concluded that the original Turner et al derivation (without the 20% upward adjustment) matches better with their own data.…”

“…For vertical wells, the new model can better predict the inception of liquid loading than the widely used Turner et al (1969) equation. For deviated wells, it is observed in the field and in laboratories that liquid loading starts much earlier than in vertical wells, and most liquid-loading equations are not appropriate for deviated wells.…”

A New Concept of Wellbore Boundary Condition for Modeling Liquid Loading in Gas Wells

“…The industry has collected a great amount of experience on how to apply this criterion in gas wells where the liquid can be water or condensate or both; for up-to-date summaries see e.g. Sutton et al (2010), Wang et al, (2010) and Zhou and Yuan (2012). Recent experimental work shed more light on the role of the liquid film in the flow reversal (Van't Westende et al, 2008;Veeken and Belfroid, 2010;Waltrich, et al 2012;Alamu, 2012;Skopich et al 2013), but it is expected that the above two expressions will be still in the core of future prediction methods.…”