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The AAPG/Datapages Combined Publications Database
AAPG Bulletin
Abstract
(Begin page 491)
AAPG Bulletin, V.
Petrophysical characteristics and facies of carbonate reservoirs: The Red
River Formation (Ordovician), Williston basin
Lillian Hess Tanguay,1 Gerald M.
Friedman2
1Department of Earth and Environmental Science, C. W.
Post Campus, Long Island University, 720 Northern Boulevard, Brookville, New York,
11548-1300; email: [email protected]
2Department of Geology, Brooklyn College of the City University of New York,
Brooklyn, New York, 11210; Department of Earth and Environmental Sciences, The Graduate
School and University Center of the City University of New York, 33 West 42nd Street, New
York, New York, 10036; Northeastern Science Foundation affiliated with Brooklyn College of
the City University of New York, Rensselaer Center of Applied Geology, 15 Third Street,
P. O. Box 746, Troy, New York, 12181-0746; email: [email protected]
AUTHORS
Lillian Hess Tanguay is an assistant professor of geology and director of the Graduate Program in Environmental Studies at the C. W. Post Campus of Long Island University (LIU). Her previous position at LIU was the assistant dean of the College of Liberal Arts and Sciences. She received her Ph.D. in earth and environmental sciences from the Graduate School of the City University of New York in 1993. Prior to her doctoral studies she was an exploration geologist at Husky Oil Company in Denver, Colorado.
Gerald M. Friedman is Distinguished Professor of Geology at the City University of New York, serving at Brooklyn College and the Graduate School and University Center. His previous position was at Rensselaer Polytechnic Institute, where he is now emeritus professor. At the research center of Amoco in Tulsa, Oklahoma, he was supervisor of Sedimentary Geology. Within the last 30 years, 10,500 petroleum geologists in industry have taken his short courses in carbonate geology and sedimentology. He is an honorary member of AAPG, SEPM, and the International Association of Sedimentologists. AAPG has honored him with the Distinguished Educator Award and the Sidney Powers Memorial Medal.
ACKNOWLEDGMENTS
This research was supported by a grant from the United States Department of Energy under Grant No. DE-FG02-84-ER-13322. Cores, well log data, and core log data were made available through the courtesy of Shell Oil Company. We thank Schlumberger Research Laboratory, Connecticut, and the Department of Geology, Queens College of the City University of New York, New York, for use of their image analyzers. Special thanks go to Matt Draud who provided the statistical analysis. Critical reviews by M. Draud, N. Hurley, M. W. Longman, F. J. Lucia, and N. C. Wardlaw have improved the article considerably.
ABSTRACT
Similarly shaped capillary-pressure curves, classified according to pore-throat size sorting, the maximum threshold-entry radius (MTER), and percent recovery efficiency (RE), delineate petrophysical facies. Capillary-pressure curves of carbonates that have a well-sorted (WS) pore-throat size distribution are characterized by MTER occurring at less than 20% mercury imbibition and horizontal to subhorizontal plateaued injection curves resulting from a unimodal pore-throat size distribution. Capillary-pressure curves of carbonates that have a moderately sorted (MS) pore-throat size distribution are generally sinusoidal in shape and have MTER between 10 and 40% cumulative pore volume imbibition. Capillary-pressure curves of carbonates that have a poorly sorted (PS) pore-throat size distribution are generally oblique or diagonal and have no plateau and poorly defined MTER.
The concept of petrophysical facies is applied to the Red River Formation (Ordovician) of the Williston basin. Capillary-pressure curves are used to determine the spatial distribution of petrophysical characteristics within the Red River carbonates. Curve types are spatially clustered and subdivide the formation into petrophysical facies, which are laterally and vertically continuous. Capillary-pressure curves of dolostones that have high porosity and good reservoir potential are characterized by WS pore-throat size distributions, MTER within the range from 0.448 to 8.55 µm, and greater than or equal to 30% RE.
Optimum reservoir potential occurs in dolostones that have greater than 70% dolomite, WS pore-throat size distribution, greater than or equal to 13.5% apparent porosity (AP), more than 49% total pore system saturation by 500 psia and more than 87% total pore system saturation by 1000 psia during mercury porosimetry, 0.1 to 0.65 µm average pore-throat radius (APR), 0.18 to (Begin page 492) 1 µm median pore-throat radius (MPR), 0.6 to 3.6 µm MTER, and 46 to 63% RE. A positive correlation occurs between AP and RE where, as porosity increases to 21%, the RE increases to 64%.
Pore diameters that have optimum reservoir potential are not necessarily the largest found in dolostones. Moderate size pore diameters occurring in intercrystalline pore systems produce the highest porosity and RE. The AP is also a function of the pore-throat radius. Highest porosity occurs in dolostones that have relatively small pore-throat radii. As the APR increases from 1 to 3.2 µm, the AP slightly decreases. Dolostones that have APR larger than 3.2 µm have no AP.
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