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Vol. 7, No. 3 |
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Tech Transfer Track
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New Coalbed Methane Manual AvailableLike many areas, coalbed methane is of high interest in southeast Kansas (and northeast Oklahoma). Dwayne McCune, an area consultant working under the auspices of The Tertiary Oil Recovery Project (TORP) at the University of Kansas, has recently completed a coalbed methane manual. This manual builds upon prior PTTC efforts in the coalbed methane arena and Dwayne's coalbed methane consulting experience. Although coverage is broad (sections include: (1) the properties of coal, (2) the occurrence of natural gas in coal, (3) reservoir engineering characteristics of coalbed methane production, (4) drilling, completing and equipping coalbed methane wells, and (5) developing and managing the coalbed methane prospect from defining the geology to marketing the gas), the manual contains focused, field-oriented insights relevant to Midcontinent coalbed methane operators. Copies of the manual, at nominal cost, will be available soon. Contact Dwayne McCune (phone 785-864-7398, email dmccune@cpe.engr.ukans.edu) or Lisa Love (lisa@cpe.engr.ukans.edu) at PTTC's North Midcontinent Resource Center for your copy. |
Poly-Lined Tubing: An Option for Reducing Downhole FailuresPoly-lined tubing is an option for reducing downhole failures in rod-pumped wells. In one West Texas application, average run times (considering rod parts, pump failures, tubing leaks, casing leaks, etc.) went from 112 days to 1,500+ days. For an average total liner cost of about $4,300, average annual workover costs were reduced from $9,600 to $1,100 per well. In Elk Hills in California, poly-lined tubing in green band used tubing in two deviated (12 degrees per 100 ft) wells that were experiencing less than 100 day runtimes, have been in service over 14 months. In an East Texas Woodbine well, a well pulled four times in 1996 for tubing wear by rods has had no wear-related problems since installation of poly-lined tubing in late 1996. These and other field examples were provided by Western Falcon personnel during a recent "lunch-n-learn" session in Oklahoma City. The above are not isolated examples. Western Falcon reports over 1,100 rod pump installations, and more than 1,000 injection/disposal well installations. Poly-lined tubing has also been used with progressing cavity pumps, submersible pump wells, coalbed methane production, plunger lift wells, surface flowlines, and more. Poly-lined tubing is not a cure all. Tubing inner diameter is reduced. Although working on higher temperature formulations, current Western Falcon products are limited to 160 ºF in oil wells, and 180 ºF in brine or injection wells. For more information, contact Jim Hickman (phone 832-391-9461 or email jimh@westernfalcon.com). |
Subsurface Best Practices & BenchmarkingConsidering a database of 500 projects around the world initiated since 1993, several major companies evaluated pre-project expectations versus actual project results. Some of the projects were very large, but some were small. And lessons learned, when considered in context, are applicable to any project, anywhere. The problem was found not to be with facilities, where costs can be contained within 10% of expectations, but with subsurface actions/activities-drilling, reservoir characterization, and reservoir management. On average, drilling costs were found to be 120% of AFE amounts. Another common failing was the inability to bring a project on as rapidly as predicted and, once brought on, keep production stable. Of the projects reviewed, less than 35% of projects met or exceeded expectations for first year production. Combined, these factors are critical since much of the financial value occurs during the first couple years of a project. Not unexpectedly, the more complex the reservoir, the higher the likelihood that pre-project reserves were overestimated. This look backwards at project performance highlighted the importance of truly integrated team effort, where facilities and subsurface efforts continuously and effectively interacted, versus traditional sequential or parallel efforts. The benchmarking study identified two types of activities-"best practices" or proven, every day actions and "value improving practices" or realizations that occur from a conscious look back, often with the help of an outsider, at what worked/didn't work. It is meaningful to look at focus areas for value improving practices:
Increasingly, industry is sharing their experience in benchmarking or best practice efforts. Robert Menzie, Jr., in a recent article in AAPG's Explorer magazine, outlined additional web resources for best practice information. These include:
A separate article in this issue (Artificial Lift R&D Council Forming) describes effort in the arena of artificial lift. And DOE has initiated best practice efforts through its PUMP (Preferred Upstream Management Practices) program. In total, there is a wealth of experience-based insights to guide producers as they implement new projects. One does not have to reinvent the wheel, and you can share insights/experiences without giving up competitive advantage. Acknowledgements: David Brown, Phillips Petroleum, shared the results of the subsurface benchmarking study during a luncheon presentation at SPE Midcontinent section, Tulsa, Oklahoma, on Sep. 6. Full results will be available later through an SPE paper. Websites for other best practices excerpted from article in August 2001 issue of AAPG Explorer. |
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