Abstract

The south Texas Eagle Ford shale formation in is an important emerging shale play in the United States. More than 1510 wells have either been drilled or permitted in the play. What has emerged is a well-defined downdip gas play that transitions rapidly updip into less well-defined wet gas and oil fairways. With initial gas well rates exceeding 17 million cubic feet per day and initial oil well rates in excess of 1000 barrels of oil per day common in the expanding play, exploration companies are pursuing methods to optimize drilling plans. Limited well and core data describing the Eagle Ford require the use of 3D seismic to help characterize reservoir quality variations, avoid drilling hazards, and help predict sweet spots. Modern, long-offset, full-azimuth 3D is an essential tool for building a geophysical description of the shale between wells. Anisotropic time imaging, feeding both acoustic and elastic inversions, is helping operators gain better insight into the reser-voir's variability. The following discussion highlights components of an ongoing effort to extract value from seismic data in shale prospecting. Unfortunately, limited well data for calibration, as in many immature shale plays, remains the primary constraint on confident linkage between the actual reservoir quality and seismic measurements.

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