Anadarko is testing an alternative to sucker rods in marginal fields.

Faced with a tight squeeze between costs and revenue in marginal fields, Anadarko has found a new path to profits - up the inside of a sucker rod string.

Deploying a string of coiled tubing (CT) in place of conventional rods and modifying the pump to produce up the inside of 11/2-in. CT has allowed the company to pump wells through 27/8-in. tubing or 31/2-in. casing. The potential for such coiled tubing rod strings (CTRS) to enable artificial lift in wells where it was not previously practical and reduce the number of failed connections could be significant.

YPF SA put forward the concept 4 years ago in Argentina as a means for pumping slimhole marginal wells in the San Jorge Basin (Solanet, et al., 1999). Although YPF encountered problems due to sand production after fracturing, operators recognized the potential of such a system. Earlier this year BJ Services described a test installation with a high-volume long-stroke pumping unit on a ChevronTexaco well in the Permian Basin (Falk, et al., 2002), and began looking at ways to refine the CTRS system. With the benefit of some design modifications, three Anadarko wells in East Texas are performing well with the system. The wells, one 11/4-in. dewatering string in a gas well and two 11/2-in. oil production strings, are installed to depths of about 6,400 ft (1,952 m). Anadarko plans a fourth oil installation.

Along with the CT, the system incorporates three unique elements: a coupling to connect the subsurface pump to the CT, a subsurface pump configured to lift fluid up the inside of the CT, and a flexible connector and standpipe arrangement at the surface.

"All of the components are basically off-the-shelf items, with a few modifications," said Kelly Falk, US region CT technical manager for BJ Services, which has been working under agreement to develop and use this technology in the United States and Canada. "BJ was involved in earlier installations for two other producers, prior to the Anadarko wells, and we've learned a lot from each installation and made adjustments along the way."

At the surface, the CTRS extends through the wellhead and is hung off using a polished rod clamp, with the CT acting as its own polished rod. Connected to the top of the CTRS is a curved steel tubular swivel joint, which in turn is connected to a flexible pressure hose that ties into the surface flow line. Downhole, the CTRS connector joining the CT string to the pump is the only connection in the string.

This single connection is the key to a broader market for CTRS than pumping small-diameter marginal wells. "If you can replace 200-plus sucker rod couplings with one low-stress connection, the chances of rod string failure should go down significantly," Falk said. In addition, the lack of connections means the distribution of contact stress is more even with CTRS than with a conventional rod string. Contact wear between the moving string and the casing or tubing inner diameter should be minimized if not eliminated. Also, although the cross-sectional areas of a 1-in. sucker rod string and 13/4-in. (0.156-in. wall thickness) CTRS are nearly identical, the buckling stiffness of the CTRS is more than five times that of the comparable strength rod string, further reducing the chances of failure.

Jason Pigott, a senior production engineer with Anadarko, discussed his company's experience with CTRS at a recent Energy Forum presentation on exploration and production technologies for independents in Houston, Texas. The East Texas Carthage field case history he presented described a dual completion where the upper zone, after having been shut in for some time, was recompleted into the Travis Peak formation across an interval from 6,330 ft to 6,460 ft (1,931 m to 1,970 m). The well subsequently swabbed 40 b/d oil but would not flow. After installing a 11/2-in. CTRS inside 27/8-in. casing, the well pumped 30 b/d of oil, declining to about 15 b/d of oil over a 2-month period.
The cost of a 11/2- or 13/4-in. CTRS vs. a conventional rod string inside 23/8- or 27/8-in. tubing is comparable, Pigott said. Installation costs are expected to be similar or less than conventional sucker rod systems once the experience level increases.

The CTRS approach also could have some unexpected advantages, Falk said. "There is some evidence that higher velocity flow inside the CT could help to maintain oil temperature longer, leading to a decrease in paraffin plugging tendency." The system also could be employed in situations where casing patches have reduced the well's inner diameter, precluding conventional artificial lift options. There also may be ways to extend the approach to larger diameter casing strings. Pumping with CTRS in casing diameters larger than 41/2 in. may be problematic, but because the fluid is contained within the rod string, a string of used, nonspec tubing could be run as a support system for little added cost.

"It could be that CTRS will lead to the recovery of substantial amounts of remaining reserves in fields where low reservoir pressures, reduced diameter tubulars and marginal redrilling economics have put these reserves beyond reach." Falk said.

References

Solanet, F., Paz, L. and Leniek, H., "Coiled Tubing Used as a Continuous Sucker-Rod System in Slim Holes: Successful Field Experience," SPE 56671, SPE Annual Technical Conference, Houston, October 1999.

Falk, K., Rowland, S., Stewart, J., Birkelbacj, L. and Leniek, H., "Artificial Lift Solutions Using Coiled Tubing," SPE 74832, SPE/ICoTA Coiled Tubing Conference, Houston, April 2002.


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