September 1999
Special Report

CT-deployed dewatering system installs quickly in gas wells

A new coiled-tubing-deployed electric submersible pump system addresses liquid loading in shallow gas wells and is up to 50% faster to install than conventional pumping systems.
September 1999 Supplement 
Feature Article 

CT-deployed dewatering system installs quickly in gas wells

Gerald V. Chalifoux ( and Tony A. Young, Petrospec Engineering Ltd., Edmonton, Alta., Canada

Bottom line. A new coiled-tubing-deployed electric submersible pump system addresses liquid loading in shallow gas wells and is up to 50% faster to install than conventional pumping systems.

Water encroachment problems. Gas fields in northeast Alberta generally are shallow (less than 3,300 ft) and typically have an active gas / water contact. As wells mature and reservoir pressures decline, the gas / water contact rises and water production increases, Fig. 1.

Fig. 1

Fig. 1. Gas and water production trend for typical wells shows that water-to-gas ratio (WGR) substantially increases and displays a typical crossover between gas and water production as wells load up or water out, ceasing production.

In many cases, a large percentage of initial gas in place is unrecoverable because of water encroachment. Typical shallow gas wells may be shut in, with unrecovered reserves caused by several factors, including:

  • Severe liquid loading in the wellbore
  • Liquid loading in pipelines
  • High cost of water hauling or surface-water disposal
  • Significant sand production
  • Formation damage
  • Capital costs of dewatering equipment.

Solution. The CT-deployed electrical submersible pump (ESP) system developed by Petrospec Engineering is an economic alternative for unloading water in shallow gas wells. It disposes of produced water downhole, allowing water-free gas production to surface. System improves gas flowrates while extending reserve life and reducing operating expenses.

Since produced water is disposed downhole, environmental liabilities associated with handling produced water at surface are eliminated. In high water-to-gas-ratio (WGR) wells, in which gas flowrates are still high enough to lift the water to surface, a downhole separator is added to eliminate surface liquids and associated water disposal costs. This separator also reduces liquid hold up in the wellbore, resulting in increased gas flowrates.

Field tests. The CT-conveyed dewatering system was deployed in three wells operated by Amoco Canada: Well 15-8-77-8 W4 (Well 15-8), Well 06-9-77-8 W4 (Well 6-9) and Well 9-14-77-9 W4 (Well 9-14).

Fig. 3

Fig. 3. The CT-deployed ESP system installs up to 50% quicker than conventional systems. In this example, the pump assembly was landed 4 ft above the disposal perforations. Casing volume between production perforations and packer was 1.8 bbl, accounting for pump and tubing displacement.

Well 15-8. This well was placed on production in 1986 and continued to flow with a stable decline until January 1998. WGR began to steadily increase in 1992. From January to March 1998, the well was kept on line by allowing it to blow to atmospheric conditions through 2-7/8-in. tubing. Gas production was sporadic, averaging less than 500 Mcfd. Water production at this time was near 160 bpd. The well’s production subsequently went to zero, and the well was shut in because of severe liquid loading, Fig. 2.

Amoco Canada recompleted the well for downhole disposal in July 1998. The lower Clearwater formation was perforated, and an injectivity test was completed. Test results indicated that injection rates of 700 bpd could be achieved with an injection pressure less than 600 psi. Permeability in the producing interval, up to two Darcys, is typical for the area. The CT-deployed ESP system was installed (Fig. 3) and the pump and packer assembly was landed 4 ft above the disposal perforations. Casing volume between production perforations and packer was 1.8 bbl, accounting for pump and tubing displacement.

Start-up was trouble-free with gas production restored to about 1994 rates. The combination of dewatering the wellbore and increasing the flow path for gas in the casing resulted in significantly higher than anticipated gas production rates. System control was tuned, and well equipment operated trouble-free for 125 days. Payout occurred in about one month.

The system was shut down in mid-October 1998 when problems were experienced with Amoco’s generator. Using calculations of sump volume and pump cycles, it was determined that the completion interval was producing an estimated 320 bpd of water after installation of the ESP. The produced water was injected into the deeper zone and no water production to surface was observed.

Wells 6-9 and 9-14. As a result of the first well’s success, Amoco Canada installed two additional systems in August 1998, Table 1. The wells were prepared by removing 2-3/8-in. production tubing and perforating the disposal zone. Both wells were installed and commissioned in two days.

While the CT-deployed systems worked well in disposing of produced water, very little incremental gas was realized. Low gas rates were attributed to geology (wells were located structurally low within the reservoir), formation damage and higher than anticipated gas depletion. After 70 to 80 days of operation, Amoco elected to shut down these two systems because of uneconomic gas flowrates.

  Table 1. Before and after performance with CT-deployed ESPs  
Well  Peak production 
before watering

 before pump 

after pump

 gas production 

15-8-77-8 W4   300 (1997)  95 0 0 1,100 315 1,100
6-9-77-8 W4  100 (1996)  13 0 0 128 89   128
9-14-77-9 W4  320 (1996)  57 0 0 250 252   250

Operational advantages. The CT-deployed dewatering system offers several advantages over standard gas completion systems, including:

  • Precise pump off control. Since electric motors are sensitive to load conditions, there is a distinct drop in current when wells pump off. In the CT-deployed system, the load reduction is picked up by a simple controller that shuts off the ESP. When water rises in the sump (the distance between producing formation and disposal formation) to a point where it covers the producing perforations, flowrate drops. By adjusting the controller to start up just before this occurs, a straight-lined production chart can be produced.
  • Large range of production rates. Variations in water production rates and injection pressures can be handled by system variations. If the wellbore completion has a relatively deep sump, a simple on / off pumping cycle is sufficient. If the sump is shallow, pumping rates can be matched more closely to water production rates by using a variable speed drive (VSD) control system. Operating in a 30- to 80-hertz range, a VSD can effectively adjust the pump performance curve. Speeding up the pump will essentially pump higher volumes at higher pressures, and slowing down the pump will lower pumping volumes and pressures.
  • Wellbore optimization. Gas is produced to surface up the casing with only minor energy losses, since the only restriction in the wellbore is the 1-1/2-in. CT. As a result of the large flow area within the wellbore, gravity separation is enhanced.
  • Electric cable protection. The control cable is shielded in the CT, offering excellent mechanical protection. This allows the operator to run less expensive, commercial-grade wire while still maintaining maximum protection.
  • Deployment speed. Run-in speeds are three to four times faster for CT-deployed systems than for systems deployed on conventional jointed tubing. The entire downhole assembly, including packer, can be deployed in one trip.
  • Reduced risk of formation damage. The ability to install and retrieve the completion system in a live well eliminates the need to kill the well with fluids. This reduces risks of formation damage or disturbance of formation-face stability.

Lessons learned. The installation in Well 15-8 was an economic success, paying out within a month. Systems installed in Wells 6-9 and 9-14 functioned properly, but were not economic because of reservoir issues. Overall, the systems proved to be 50% faster to install than conventional pumping systems. Key lessons learned from these field applications are:

  • Take an engineered approach on a well-by-well basis.
  • Conduct gas / liquid ratio tests and disposal zone injection tests to design a system.
  • Take all possible precautions to minimize or avoid formation damage. If the well is killed with excess amounts of fluids, there is a risk of water blockage or excess sand production when the well is brought back on production. Sand production is especially a problem; equipment may become sanded off or show premature wear. Sand blockages in the disposal zone can result in very high injection pressures. Sand production alone can prohibit the use of downhole disposal equipment.
  • Develop an operational scheme and commissioning strategy for each well that ensures that the system is brought on line in a step rate fashion, minimizing disturbances to the formation. The control system should be tuned after start-up before leaving the well unattended.


Herb Ziegler, Amoco Canada Petroleum Ltd., Edmonton, Alta., and Scott Kiser, Caliber Coil Tubing, Calgary, Alta.


The authors

Gerald V. Chalifoux is president and senior engineer of Petrospec Engineering Ltd., where he is responsible for design of oil and gas production and process systems, well completions and artificial lift systems. He held previous engineering and management positions at A. Comeau & Associates Ltd., as well as Amoco Canada Petroleum Co. Ltd. Chalifoux earned a BS in petroleum engineering from the University of Alberta.

Tony A. Young is technical specialist and operations manager of Petrospec Engineering Ltd., where he is responsible for product design and development, field technical projects and oil and gas optimization products. His previous positions include technical specialist at Secure Oil Tools and senior operator and project facilitator at Imperial Oil Canada Ltd. Young has an educational background as a mining technologist and in geology.

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