Solving Gas-Well Liquid-Loading Problems
Authors: Lea James F. , Nickens Henry V. 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Summary
Eventually, gas wells will cease producing as the reservoir pressure depletes. The usual presence of some liquids can reduce production even faster. This paper describes the problem of liquid accumulation in a gas well. Recognition of gas-well liquid-loading problems and solution methods are discussed.1

Introduction
Gas wells producing dry gas have a low flowing bottomhole pressure (FBHP), especially for low-rate wells. When liquids are introduced, the FBHP increases. Liquids in the gas may be produced directly into the wellbore or condensed from vapor in the upper portion of the tubing.
The total flowing-pressure drop can be expressed as the sum of the pressure drops from elevation (weight of the fluids), friction, and acceleration. For low-rate wells, the acceleration term is very small, and, with correctly sized tubing, the friction term is also small. The elevation, or gravity term, becomes larger when liquid loading occurs.
Fig. 1 shows the approximate flow regimes as gas velocity decreases in a gas/liquid well. If the well is flowing as a mist of liquid in gas, then the well still may have a relatively low gravity-pressure drop. However, as the gas velocity begins to drop, the well flow can become slug and then bubble flow. In this case, a much larger fraction of the tubing volume is filled with liquid. As liquids accumulate, the increased FBHP will reduce or prevent production.
Several actions can be taken to reduce liquid loading.Flow the well at a high velocity to stay in mist flow by use of smaller tubing or by creating a lower wellhead pressure.Pump or gas lift the liquids out of the well (many variations).Foam the liquids, enabling the gas to lift liquids from the well.Inject water into an underlying disposal zone.Prevent liquid formation or production into the well (e.g., seal off a water zone or use insulation or heat to prevent condensation).
If liquid accumulations in the flow path can be reduced, then the FBHP will be reduced and production increased. The liquid-loading problem will have been solved.

Recognizing Liquid Loading
Liquid loading is not always obvious. If a well is liquid loaded, it still may produce for a long time. If liquid loading is recognized and reduced, higher producing rates are achieved. Symptoms indicating liquid loading include the following.Sharp drops in a decline curve (Fig. 2).Onset of liquid slugs at the surface of well.Increasing difference between the tubing and casing flowing pressures (i.e., Pcf-Ptf) with time, measurable without packers present.Sharp changes in gradient on a flowing-pressure survey.

Critical Velocity.
Turner et al.2 developed two mechanistic models to estimate critical velocity.A film of liquid on the wall of the tubing.A droplet suspended in the flowing gas.
The model that best fit their well data was the droplet model. Gas rates exceeding critical velocity are predicted to lift the droplets upward. Lower rates allow droplets to fall and accumulate. Coleman et al.3 later correlated to well data with lower surface flowing pressures than did Turner. Turner&#x0027;s analysis gives the following for critical velocity:
Equation 1
where k&#x003D;1.92 (Turner et al.2) or 1.59 (Coleman et al.3).
Assuming2 s&#x003D;20 and 60 dynes/cm and ?l &#x003D;45 and 67 lbm/ft3 for condensate and water, respectively, a gas gravity of 0.6, z&#x003D;0.9, and a temperature of 120&#x00B0;F, then
Equation
where C is 5.34 for water or 4.02 for condensate2 or 4.43 for water or 3.37 for condensate.3
The corresponding critical gas rate, Qgc, in MMscf/D is
Equation
If any water is produced, conservatively use water properties to calculate critical velocity. Typically evaluated at the wellhead, the above equations are valid at any well depth if the in-situ pressure and temperature are known. The distance between the tubing end and the perforations should be minimized because casing flow is usually liquid loaded.

Stability and Nodal Analysis.
As liquids accumulate at lower gas rates, tubing performance can become unstable. Fig. 3 shows a tubing performance curve (TPC), or &#x0022;J&#x0022; curve, evaluated at the tubing bottom near perforations. This flowing pressure is needed for varying production rates at a constant gas/liquid ratio (GLR). It is plotted across a gas-deliverability curve, or inflow-performance curve.