Solutions From the Field

"Independent's Day" at SPE/DOE 2002 Improved Oil Recovery Symposium

April 16, 2002 (Tulsa, OK) by the Symposium and PTTC's North and South Midcontinent Regions, Presentations during special PTTC Session.

BOTTOM LINE

Current activity in Oklahoma coalbed methane in the Northeast Shelf and Arkoma Basin reveals a viable source of new gas reserves. As in most coalbed methane basins, completion and stimulation practices have a major influence on well productivity and ultimate economics. For conventional oil and gas wells, solid propellant stimulation treatments are proving a low-cost option for increasing productivity. In certain Midcontinent reservoirs producing high water, such as the Arbuckle in Kansas, larger volume gel polymer treatments using MARCITSM technology are proving effective. When wells must be plugged, as all will ultimately be, industry is evaluating lower-cost options to control this exit cost.

PROBLEM ADDRESSED

Independents must apply new technologies across a broad spectrum of operations—from development of new reserves, such as coalbed methane, to well stimulation to water shut-off to well abandonment—to increase their profitability.

Gas Storage: Case Studies and New Potential

May 29, 2002 (Morgantow, WV) by PTTC's Appalachian Region

BOTTOM LINE

Several DOE-funded projects directly address the deliverability issue in gas storage operations. Different approaches include CO2 remediation of organic damage, sonication and other innovative approaches for inorganic damage, a systems approach whose effectiveness is supported by case studies, and, at least for one operator, a horizontal lateral. Improved electronic data management and geological/operations modeling are enabling storage operators to improve their operations.

PROBLEM ADDRESSED

Deliverability enhancement is and always will be a key issue in conventional storage reservoirs. In recent years, DOE and others have funded work to better understand damage mechanisms and develop new approaches for enhancing deliverability. To help storage operators understand recent developments, this workshop presents results from recent R&D projects, many of which are supported with field test data.

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June 2002 Case Studies

Large-volume, gel-polymer treatments successful in Kansas's Arbuckle

Charlie Adams, Citation Oil and Gas Corp., Houston; and J. T. Portwood, TIORCO, Inc., Ft. Worth, Texas

Bottom line: Since 1997, TIORCO, Inc. has treated 21 Arbuckle wells in three Kansas fields - Bemis-Schutts (17 wells), North Hampton (3 wells) and Blue Hills (1 well) using its large-volume, proprietary MARCIT gel-polymer treatments. The economic success rate has been 100%, with payouts of total costs (polymer, plus well preparation and workover) less than six months.

Incremental reserves are estimated at more than 540,000 bbl for three leases in Bemis-Schutts, or an average incremental of 39,000 bbl oil per well. Finding costs in three leases in the field range from $0.59 to $2.34 per incremental barrel of oil. Reduced water-handling costs alone exceed $1.4 million. Operator ultimate return on investment ranges from 8.5:1 to more than 17:1.

Rod-pump controllers profitable in East Texas operations

H. Pete Berg, Stetson Petroleum Corp., Denison, Texas; and Karl Sakocius, eProduction Solutions, Houston.

Bottom line: Stetson Petroleum Corp. purchased and installed rod-pump controllers, replacing time clocks, in 15 wells in its East Linden (Cotton Valley) field in East Texas. Wells there are about 10,000-ft deep, producing 42 to 46°-API gravity oil, with a 5 to 50% watercut. With contract pumpers, timers and a trial-and-error process for setting timers, Stetson saw upside potential from using rod-pump controllers (RPCs). Based on two years' experience, it found that the controllers reduced rod and tubing failures by 31% and electric costs by 40%, equating to about $50,000 per year savings. RPC equipment costs paid out in less than a year, on average.

Holistic producing-well improvement reduces failures/servicing costs

Kent Gantz, Schlumberger IPM, Midland, Texas

Bottom line: Schlumberger IPM used the Producing Well Improvement Process (PWIP) in a Permian basin project with 900 active producers near Pennwell, Texas. Excessive well failures result in lost production, elevate lifting costs and can lead to premature abandonment. Through using PWIP since 1991, well-failure frequency has been reduced by a factor of about10, from 2.5 to 0.27 failures per well per year. Well-servicing costs have been reduced from $700M to $270M, a threefold improvement.

Log on to the World Oil website for full versions of these case studies: www.worldoil.com/Magazine/MAGAZINE_DETAIL.asp?ART_ID=1783&MONTH_YEAR=Jun-2002

Table of Contents	Vol. 8, No.2 2nd Quarter 2002