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FORMATION MICROIMAGER, MICROSCANNER, AND CORE CHARACTERIZATION OF NATURAL FRACTURES IN A HORIZONTAL WELL IN THE UPPER ALMOND BAR SAND, ECHO SPRINGS FIELD, WYOMING

By
L.W. EVANS
L.W. EVANS
Amoco Corporation P.O. Box 800 Denver, Colorado 80201
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D. THORN
D. THORN
Schlumberger Wireline & Testing Bogota, Colombia
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T.L. DUNN
T.L. DUNN
Institute for Energy Research P.O. Box 4068 Laramie, Wyoming 82071-4068
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Published:
December 01, 1996

ABSTRACT

One essential component of productive sweetspots in the Upper Almond marine bar sands, Green River Basin, Wyoming, is thought to be the connection to the underlying coals and sands of the coastal plain. Vertical natural extension fractures may provide this connection. In 1993 Amoco drilled and completed the first horizontal well to test the productivity of the natural fractures within the Upper Almond bar sand in Echo Springs Field. Formation Microimager and Formation MicroScanner (marks of Schlumberger), herein FMI and FMS, and oriented cores were obtained in a slanted pilot hole and from a horizontal wellbore to determine the spacing, orientation, and apertures of natural fractures within the bar sand and adjacent facies. The total fracture population strikes N50-70E, with dips near vertical. Closed fractures are cemented by barite and calcite, whereas quartz druse, kaolinite, barite, and patchy calcite line open fractures.

Fracture location and orientation determined by FMI/FMS are consistent with data derived from the core analysis. Forty individual fractures were evaluated from imaging 1490 feet of pilot hole, and 217 fractures were evaluated in over 2030 feet of horizontal wellbore. Dual induction resistivities were used to calibrate Formation Microimages in the pilot and horizontal holes for fracture aperture measurements. 5267 individual segment aperture calculations were made from 248 fracture images, and 898 measurements were made from core thin sections impregnated at in situ conditions.

The initial comparison of fracture widths between thin section scanning electron microscopy measurements and Formation Microimage calculations of mean aperture resulted in poor agreement. This lack of agreement was largely due to a difference in what was measured by the two methodologies, and in the fracture length explored by the two methods. The FMI/FMS methodology only resolves apertures in the open portion of the fractures, whereas SEM measurements can be made on open and on mineralized portions of fractures. Core measurements were made on lengths of 3 cm, whereas the imaged mean aperture is a single filtered value for fracture intersections with the wellbore that roughly averaged 80 to 100 cm. A utility that permits the documentation of fracture aperture for each individual fracture segment identified on the electrical images provides a more appropriate comparison of image-derived and thin section apertures. Good agreement between the two methods was found when FMI segment apertures were compared only to the open thin section S.E.M. aperture measurements.

The use of this coupled imaging and petrographic approach provides new avenues for mapping and understanding fracture permeability distributions in naturally fractured reservoirs.

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Contents

GCSSEPM

Stratigraphic Analysis Utilizing Advanced Geophysical, Wireline and Borehole Technology for Petroleum Exploration and Production

Jory A. Pacht
Jory A. Pacht
Seis-Strat Servies, Inc. Sugar Land, Texas
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Robert E. Sheriff
Robert E. Sheriff
University of Houston Houston, Texas
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Bob F. Perkins
Bob F. Perkins
GCSSEPM Foundation West Hartland, Connecticut
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SEPM Society for Sedimentary Geology
Volume
17
ISBN electronic:
978-0-9836097-6-6
Publication date:
December 01, 1996

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