The removal liquids from low-pressure gas wells is a serious problem for the petroleum industry. Many wells have to be shut-down prematurely because of the accumulation of water, condensate or both in the wellbore. Several techniques have been developed so far to combat this problem. Foam lifting is one such technique that has been used quite successfully in the field for removing liquids from the wellbore and the annulus. However, there is a strong need to know at which conditions foam injection is effective and under which conditions it is not. This paper discusses a systematic approach used to look at the efficiency of foam injection for a wide range of liquid and gas flow rates. A specially designed 40-long flow loop is used in which foam is injected at the bottom of the tubing. The efficiency of liquid removal is measured by comparing the liquid holdups at the end of each period of foam injection. The liquid removal efficiencies are also compared against cases in which no foam is injected (base-cases). Foam shows excellent liquid removal compared to the base-cases. Results also show that the type and concentration of the surfactants used to generate the foam has a strong influence on the liquid removal efficiency.


Gas well load up or liquid loading is defined as the loss of available reservoir energy due to the accumulation of liquids in the wellbore over time. The source of these liquids are - liquids (hydrocarbons and water) condensed from the gas due to wellbore heat loss and free liquids produced into the wellbore with gas (Coleman et al., 1991). Accumulation of liquids near the wellbore can cause severe reduction to complete loss of available transport energy due to a combination of hydrostatic pressure, relative permeability, clay swelling and other effects. In a recent study (Christiansen et al.) it has been reported that the hydrostatic pressure exerted by a 1OOO-ft (328 m) column of liquid is enough to stop gas production from many reservoirs. It only takes about 6 barrels (950 litres) of liquid to fill lOOO-fi of 2-7/8" (73 mm) tubing. To blow liquids out of a well, a minimum gas flow rate of 300 MCFD (8500 m3/day) is needed in wells operating with 2-7/8" (73 mm) tubing at a surface pressure of 100 psig (690 kPa). The study also indicated that out of about 6500 gas wells in Colorado almost 6000 produce less than 200 MCFD (5700 m3/day) and therefore probably suffer from liquid accumulation in the well and producing formation. The study of the critical flow rates, for continuous liquid removal from gas wells has been a popular subject of research for many years. Significant works in this area include those by Duggan (1961), Turner et al. (1969), Tek et a1. (1969), Ilobi and Ikoku (1981), Reinicke et a1. (1987), Upchurch (1987) and Coleman et al. (1991). Several methods of liquid removal has been discussed in the literature (Hutlas and Granberry (1972), Lea and Tighe (1983), Bernadiner (1991), Adams and Marsili (199))

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