Many gas wells have liquid loading problems caused by oversized tubing, resulting in premature abandonment. This paper suggests that small tubing can be used in most any packerless sweet gas well, regardless of anticipated flowrate, without restricting production capacity. A method of flowrate control is recommended that insures that tubing flow stays at rates necessary to maintain mist flow, allowing all liquids to be produced up the tubing string. Excess volumes are produced up the casing/tubing annulus, where pressure drop due to friction is usually negligible. Maintaining mist flow up the tubing is accomplished by regulating the amount of gas allowed to exit through the annulus. This single loop process is controlled using cost effective, simple, reliable, oilfield equipment.
Natural gas fills a growing percentage of our nations energy requirements due to its availability, low price, and clean burn qualities. At the same time, deliverabilities of gas wells decline, and the discovery of new gas reservoirs becomes more difficult. It is therefore necessary to maximize gas recovery from every gas well, so that gas supplies are not left untapped.
One of the primary factors reducing gas well deliverability is the buildup of produced fluids in the tubing, which effectively exerts backpressure on the formation, limiting production. Numerous technical papers have been written on ways to predict and overcome gas well loading problems. The use of the Entrained Drop Model was proposed by Turner et al to predict gas velocities where liquid loading occurs. This method has gained widespread industry acceptance because of its close agreement with field data, and many other technical papers have been written as a result of this work.
Two such papers are referenced that address methods to overcome liquid loading problems. The first, titled 1A Practical Approach to Removing Gas Well Liquids" by Hutlas and Granberry, covers pumping units, liquid diverters, gas lift, and small (1") tubing strings. The advantages and disadvantages of each are discussed. The primary disadvantage that has limited wider utilization of smaller tubing strings is the associated pressure drop caused at higher flowrates. Although ideal for gas wells near the end of their producing life (many wells are being retrofitted with smaller tubing), the smaller tubing would be too restrictive to produce wells at their maximum capabilities early in their producing life. The second paper by Lea and Tighe titled "Gas Well Operation With Liquid Production" outlines other methods for minimizing liquid loading, such as wellhead compression, plunger lift, siphon strings, rotative gas lift, and foaming agents. These other methods all have disadvantages, primarily higher operating costs and maintenance requirements.
The basic problem has been that for a given gas flowrate, there are only a limited range of tubing diameters that ensure adequate velocity to remove liquids, yet are not overly restrictive to flow. As gas well deliverability declines and the flowrates decrease, smaller tubing is needed. Since it is not practical nor economical to change tubing size every few years, these other methods of liquid unloading were subsequently developed.