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Bigger Is Better - Hydraulic Fracturing in the Mesaverde Formation in the Piceance Basin

Cumella, Steve 1; Weijers, Leen 2; Kama, Yusuf 2; Shemeta, Julie 3
1 Bill Barrett Corporation, Denver, CO.
2 Pinnacle, Centennial, CO.
3 MEQ Geo, Inc., Highlands Ranch, CO.

The thick lenticular sands of the Williams Fork Formation in the Piceance Basin in western Colorado require a special completion strategy for the best economic development. The Williams Fork is composed of a stacked sequence of fluvial channel and crevasse splay sands interbedded with associated overbank siltstone and floodplain shale deposits. Coals and tongues of marine sands are also present in the lower part of Williams Fork.

Results for microseismic mapping of the fracture stimulation of five wells and 40 stages in the Mamm Creek Field in the Piceance Basin in Garfield County, Colorado will be presented. The wells were drilled to true vertical depths between 4,300 and 6,500 ft.

The following issues will be discussed: 1) layout considerations for a microseismic project in the Piceance Basin. Microseismic hearing distance in Piceance Basin microseismic fracture mapping projects depends on noise level from same-pad operations, pump rates, stacking of tools, etc.; 2) importance of measuring fracture azimuth for well placement in a basin where fracture azimuth changes considerably. The fracture azimuths were very consistent between different stages, but, similar to MWX results, show a slight rotation of the fracture azimuth with depth; 3) effectiveness of limited entry stimulation strategy for fracture-height coverage. Typically injection rates of about 3 bpm/perforation were utilized in an attempt to obtain diversion through the limited-entry technique. Fracture-height growth is pronounced, and in many stages there is significant growth out of zone, resulting in large overlap between different fracture treatments. The intervals with lower ISIP gradients appear to coincide with the depths where fractures overlap more; 4) relationship between fracture volume and measured fracture half-length and height. Treatments called for an average volume of 8,000 bbl of slickwater and 190,000 lbs of 20/40 mesh Ottawa sand. Fractures are very long with an average half-length of 1200 ft and results show a relation between the fracture treatment volume and both the fracture half-length and the fracture height; 5) impact of larger fracture dimensions on production response. Well EURs have improved dramatically as a result of the larger hydraulic fracture treatments. In instances where wells on the same drilling pad were fraced with different water volumes, the wells fraced with larger water volumes were 30-200% percent better producers.


AAPG Search and Discovery Article #90090©2009 AAPG Annual Convention and Exhibition, Denver, Colorado, June 7-10, 2009