This paper presents a study into best design and operation of dual-completed wells with Downhole Water Sink (DWS) in low productivity gas reservoirs with water production problems. DWS is an alternative technology to Downhole Gas Water Separation (DGWS) by inclusion of a second (bottom) well completion isolated by a packer from the top completion. The bottom completion diverts water from the top completion so gas production is maximized and water-free.

The study analyzed simulated performance of DWS wells for different values of well design parameters (the top and bottom completion lengths, and distance between the two completions), and operational parameter (the top/bottom completion rates, bottom hole flowing pressure at the lower completion, and the lead time when production comes only from the top completion-DWS start-up time). The simulations assumed strong aquifer support, and computed maximum gas recovery at the time when water loading occurs at the top completion.

The study demonstrates that the presence of a separating packer between the two completions is critical for the unique hydraulics of DWS, i.e. isolation of two different bottom-hole flowing pressures. Also, the results show that the maximum advantage of DWS can be achieved when the top completion is short (penetrating top 20 – 30 percent of the gas zone), bottom completion is long (penetrating the bottom part of the gas zone, or even the top of the aquifer), and the completions are as close as possible. Furthermore, water drainage should be postponed until water breakthrough occurs at the top completion. Then, water should be drained at maximum achievable rate to maximize gas production rate and delay water loading the top completion.


Water production reduces gas recovery leaving a significant amount of gas in the reservoir, particularly in low productivity gas reservoirs.

Different techniques has been used to solve water production problems in gas wells. Some techniques work inside the well bore by increasing well's lifting capacity (chemical injection, concentric pipes, thermal, gas lift, pumps, plungers, and Downhole Gas Water Separation--DGWS); other techniques work outside the wellbore by improving well inflow performance with the polymer-gel water shut-off technology.

The inside-well techniques remove water that has inflowed the well. Libson and Henry1 reported successful results injecting foaming agent into the casing annulus in very low permeability gas wells located in the Intermediate Shelf area of Southwest Texas. After 10 days of injecting a foaming agent to the wellhead, the gas rate increased from 142 Mscfd to 664 Mscfd, and water rate increased from 0.8 bwpd to 3.2 bwpd.

Hutlas and Grandberry2 reported success using a 1-in tubing string in northwestern Oklahoma and the Texas Panhandle. Running a 1-in tubing string inside the production tubing increased gas rate more than 100% in four wells.

Pigott et al.3 presented the first successful application of wellbore heating to prevent fluid condensation and eliminate liquid loading in low-pressure, low-productivity gas wells. The application was in the Carthage Field. A heater cable installed around the tubing string increased wellbore temperature.

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