State-of-the-Art Summary

New Approaches to Liquid Removal, Innovations Boost Productivity
by Karl Lang, Hart/IRI Fuels Information Services

Technologies designed to benefit independent producers were the focus of two recent meetings: a program presented by The Energy Forum in Houston on November 6-7 titled "Next Generation E&P Technologies for Independents" and a technology transfer meeting organized by the Stripper Well Consortium (SWC) in Pittsburgh on November 12-13. Three of these technologies, highlighted below, deal with the issue of removing liquids from low pressure wells or their flowlines. In each case, a relatively novel and low cost approach is taken to deal with a well known problem, with encouraging results.

The SWC, established two years ago by the US Department of Energy (DOE) through the National Energy Technology Laboratory, pools financial and human resources to develop new technologies with financial leverage from DOE. Details on the benefits of membership and the projects completed or currently under way are available on the SWC web site at www.energy.psu.edu/swc. The Energy Forum develops energy industry functions that provide an interactive platform where knowledge transfer is facilitated (see www.theenergyforum.com).

Pumping with Coiled Tubing in Small Diameter Wells

At the Energy Forum meeting, Jason Pigott, a Senior Production Engineer with Anadarko, gave a presentation on his company's use of coiled tubing in place of conventional sucker rods in small diameter wells. By modifying a downhole rod pump to produce up the inside of a 1˝ inch coiled tubing string, Anadarko hopes to artificially lift wells where it was not previously practical (e.g., through 2 7/8 inch tubing or 3˝ inch casing) and also reduce the number of sucker rod connection failures.

The concept was put forward four years ago in Argentina by YPF S.A. (Solanet, et al., 1999) as a means for pumping slimhole marginal wells in the San Jorge Basin. Earlier last 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 currently performing well with the system. The three wells, one 1ź inch de-watering string in a gas well and two 1˝ inch oil production strings, are all installed to depths of about 6,400. At the time of this writing, Anadarko was planning a fourth oil installation.

Along with the coiled tubing (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. According to Kelly Falk, US Region CT Technical Manager for BJ Services, which has been working under agreement to develop and use this technology in the US and Canada, "All of the components are basically off-the-shelf items, with a few modifications. 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 coiled tubing rod string (CTRS) extends through the wellhead and is hung off using a polished rod clamp, with the coiled tubing 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 flowline (Figure 1). Downhole, the CTRS connector joining the CT string to the pump is the only connection in the string.

Figure 1. CTRS Wellhead at Anadarko East Texas Site

This single connection is the key to a broader market for CTRS than pumping small-diameter marginal wells. "If you can replace 200+ sucker rod couplings with one low-stress connection, the chances of rod string failure should go down significantly," says Falk. 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 ID should be minimized if not eliminated. Also, although the cross-sectional areas of a 1-inch sucker rod string and 1ž inch (0.156 inch wall thickness) CTRS are nearly identical, the buckling stiffness of the CTRS is more than 5 times that of the comparable strength rod string, further reducing the chances of failure.

In an East Texas Carthage Field case history presented by Pigott, he 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 6330 to 6460 feet. The well subsequently swabbed 40 bpd but would not flow. After installing a 1˝ inch CTRS inside 2 7/8 inch casing, the well pumped 30 bopd, declining to about 15 bopd over a two month period.

The cost of a 1˝ or 1ž-inch CTRS versus a conventional rod string inside 2 3/8 or 2 7/8-inch tubing are comparable, according to Pigott. Installation costs are expected to be similar or less than conventional sucker rod systems once the experience level increases.

The CTRS approach could also have some unexpected advantages, says Falk. "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 could also be employed in situations where casing patches have reduced the ID of a well, precluding conventional artificial lift options. There may also be ways to extend the approach to larger diameter casing strings. Pumping with CTRS in casing diameters larger than 4˝ inches may be problematic, but because the fluid is contained within the rod string, a string of used, non-spec tubing could be run as a support system for little added cost.

Anadarko is currently considering installations in other areas in addition to their East Texas applications, and BJ Services is currently working with a number of other producers interested in the system. "We're gaining experience and developing guidelines on where this approach can have the most benefit," says Falk. "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 re-drilling economics have put these reserves beyond reach."

Vortex VX Device Reduces Turbulence, Boosts Production

At both the Texas and Pittsburgh meetings, a Denver-area company, Vortex Flow LLC, described the Vortex VX tool for improving production by reducing flowline backpressure from flow turbulence. The device separates gas and liquids into a two-phase flow pattern with the liquids flowing in a spiral along the pipe wall and the gas flowing down the center. This vortex pattern prevents liquids from dropping out and hindering flow, even over long distances and substantial changes in elevation and direction.

Vortex Flow VX tools, available in a range of sizes and pressure ratings, have been installed in six states and seven oil and gas producing regions across the United States. After approximately 100 installations, wells with VX tools are exhibiting significant improvements over their projected decline rates, according to Brad Fehn, CEO of Vortex Flow, LLC. "This technology demonstrated its effectiveness in the mining industry with nearly a decade of successful experience," says Fehn. "Now, the oil and gas industry is accepting the product as VX tools are successfully enhancing production in a wide range of producing basins." Field experience is showing that the unit is eliminating flowline freeze-ups in cold weather as well as enhancing the movement of liquids in flowlines. Producers are seeing improved plunger-lift performance at the wellhead and a reduction in the need for pigging in lines that frequently become blocked. The Vortex Flow VX tool can be installed anywhere in the system. A common point is just downstream of the wellhead (Figure 2). For more information visit www.vortexflowllc.com.

Figure 2. Vortex VX Tool Installation

Automatic Pump Lowers Cost of Dewatering Gas Wells

A new pumping technology, the development and testing of which has been jointly sponsored by the SWC and the New York State Energy Research and Development Authority (NYSERDA), targets shallow stripper gas wells that produce via smaller diameter casing and require the periodic removal of liquids that slowly build up in the wellbore. Current techniques for doing this can be labor intensive, pushing wells towards unprofitability. Brandywine Energy and Development Company (BEDCO) has developed a Gas Operated Automatic Lift PetroPump (or G.O.A.L. PetroPump) for automatically lifting fluids from stripper gas wells. They presented the results of their field testing program at the SWC meeting in Pittsburgh.

The G.O.A.L. PetroPump is a unique, free floating, automatically activated in-casing tool for the removal of downhole fluids utilizing only in-well pressure. The tool is controlled by a pre-set pressure sensing control valve within the tool that remains open when the tool is dropped into the casing, allowing it to descend. Upon reaching the desired depth within the fluid column, a sensor closes the valve and, coupled with the sealing cups surrounding the tool, creates a complete seal with the well casing. Downhole pressure subsequently builds behind the tool, eventually lifting the tool and fluid. Following delivery of the fluid to the surface and subsequent production of the gas, the tool valve automatically reopens, allowing the pump to descend for another cycle. According to the developer, the tool's completely automatic operation is primarily what differentiates it from standard casing plungers in use now.

With cost-shared funding from SWC, the prototype pump was field tested during the winter of 2001-2002 in two Medina sandstone gas wells in New York state. It completed an average of 15 to 20 cycles per month. Results showed a gas production increase of between 60 and 300 % and the elimination of 5 well tender-assisted plunger runs per month. Additional tests are being planned for the winter of 2002-2003.

The standard pump is targeted to work in 4- or 5-in. inside diameter casing with downhole pressures ranging from 100 to 600 psi. A fluid lift of 0.1 to 3 bbl per cycle is typical. The wellhead must be modified to act as a tool lubricator/receiver (Figure 3) and the inside casing surface must be in good condition.

Figure 3. Wellhead Lubricator Configuration for 51" and 32" Pumps

Companies interested in learning more about the G.O.A.L. PetroPump, or in joining the SWC, should contact Gary Covatch at the National Energy Technology Laboratory's Strategic Center for Natural Gas, at 304-285-4589, or via e-mail at gcovat@netl.doe.gov.

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, presented at the SPE Annual Technical Conference in Houston, TX, October, 1999.

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