Liquid loading in low production gas wells is a nuisance for production engineers in the natural gas industry. It is essential to maintain gas wells free of liquid; otherwise, the production will be severely reduced by backpressure of the accumulated liquids, and by reduced gas relative permeability in the surrounding formation.

The most fundamental solution for the liquid loading problem is to select tubing diameter for the well such that the natural energy in the reservoir will give a gas velocity sufficient to lift liquids from the sand face of the reservoir to the surface. Unfortunately, the optimum diameter varies for different periods in the life of a well.

Here, a new approach to the liquid loading problem is reported. By introducing restrictions, such as orifices, inside the tubing to alter flow mechanisms, liquid may be lifted by gas flow rates below the conventionally accepted critical rate. Extensive laboratory experiments with a 40-foot-tall flow loop with 1.5-inch-inside-diameter tubing were conducted to test the effect of five different designs of restrictions. In these experiments, the effects of gas flow rate, of restriction design, of flow loop inclination, and of design of the outlet at the top of the loop were considered. The experiments proved that the restrictions alter two-phase flow behavior and improve liquid lifting rate in the flow loop.

Introduction

Natural gas that had been flared or re-injected for pressure maintenance and artificial lift in the U. S. and elsewhere has become commercially attractive since the 1950s due to the strong domestic and international demand. Because natural gas does not cost as much as oil per unit of energy content, and because its combustion produces less harmful emissions than oil and coal, it is increasingly desired as an alternative fuel for automobiles and electric power plants, as well as for residential heating.

When natural gas is produced from a reservoir, species such as water and intermediate to heavy hydrocarbons can condense as liquids in the well bore, depending on the composition of gas produced at the bottom of the well. Condensation is not the only source of liquid in the well bore; free brine or free hydrocarbon liquid can be produced directly from the reservoir. As long as gas flow rate is sufficiently high to maintain annular mist flow, these liquids are lifted from the well.

As flow rate declines in a maturing gas field, the flow regime switches from annular mist flow to churning flow, and the liquid lifting capacity of the flowing gas decreases dramatically. The flow rate for this switch in flow regimes is called the critical flow rate. When the liquid cannot be lifted to the surface, it accumulates in the well to create undesired backpressure on the producing formation, restricting gas production rate. If a liquid-lifting method, such as soap sticks, plungers, rod pump, or swabbing is not implemented, the production rate will continue to decline toward zero.

Duggan 1 and Turner, Hubbard, and Duckler 2 investigated the critical flow rate in the 1960s. Duggan reported on field experience with wells producing condensate; Turner et al. reported on theoretical models and field tests. Turner et al. developed an expression for estimating the critical gas flow rate for lifting liquids from a well:

(Equation)

(Some of the equations for critical velocity and critical flow rate in Turner et al. contain incorrect multiplicative constants. The corresponding equations in Coleman et al.3 are error free. Equation 1 above is copied from Eq. 1 of Coleman et al.) Equation 1 includes the 20% upward adjustment to match field data suggested by Turner et al. The THD expression is widely referenced for estimating critical flow rate for continuous liquid removal. 4,5,6,7,8,9,10

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