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AAPG Bulletin, V.
Material-balance assessment of the New Albany-Chesterian petroleum system of the Illinois basin
1U.S. Geological Survey, P.O. Box 25046, Denver Federal Center, Denver, Colorado, 80225; email: [email protected]
2U.S. Geological Survey, P.O. Box 25046, Denver Federal Center, Denver, Colorado, 80225; email: [email protected]
3U.S. Geological Survey, P.O. Box 25046, Denver Federal Center, Denver, Colorado, 80225; email: [email protected]
4U.S. Geological Survey, P.O. Box 25046, Denver Federal Center, Denver, Colorado, 80225; email: [email protected]
Michael D. Lewan is a petroleum geochemist and geologist for the U.S. Geological Survey. His research is focused on generation and expulsion processes responsible for oil and gas accumulations. He previously worked for Amoco Production Company at their Tulsa Research Center (1978-1991) and for Shell Oil Company at their New Orleans Exploration and Production Office (1972-1975). He received a Ph.D. from the University of Cincinnati (1980), an M.S. degree from Michigan Technological University (1972), and a B.S. degree from Northern Illinois University (1971).
Mitchell E. Henry is a geologist for the U.S. Geological Survey. His research interests are in the area of application of remote sensing to petroleum prospecting. Recent assignments have been focused on resource evaluation in the United States and Canada. He earned a B.S. degree in biology at Midwestern University, Wichita Falls, Texas (1969) and an M.S. degree (1974) and Ph.D. (1982) in oceanography from Texas A&M University.
Debra K. Higley is a petroleum geologist for the U.S. Geological Survey. Her research interests include reservoir characterization, thermal maturation, and petroleum resource assessment. Her background includes uranium exploration (1976-1981) and petroleum geology and geochemistry with the U.S. Geological Survey (1982-present). Her Ph.D. in geology (1994) and M.S. degree in geochemistry (1982) are from the Colorado School of Mines, and her B.S. degree in geology (1977) is from Mesa State College, Grand Junction, Colorado.
Janet Pitman is a research geologist in the Geologic Division of the U.S. Geological Survey. As a member of the Central Energy Team, she has applied sandstone diagenesis and reservoir quality analysis in domestic and world energy studies. Her present research interests include petroleum system modeling and basin history reconstruction. She is a member of AAPG and SEPM.
This study was conducted as part of the U.S. Geological Survey Energy Team, and any use of trade, product, or firm names in this article is for descriptive purposes only and does not imply endorsement by the United States Government. We appreciate the cooperation and hospitality extended by Morris Leighton and Don Oltz of the Illinois State Geological Survey (ISGS), Norman Hester and John Rupp of the Indiana Geological Survey (IGS), and Donald Haney and James Drahovzal of the Kentucky Geological Survey (KGS) during collection of samples and data on which this study was so dependent. Particular thanks is extended to David Morse (ISGS) who helped in the collection of source rock samples of the New Albany Shale and Beverly Seyler (ISGS) for providing porosity data on the main reservoir/carrier beds. We extend our appreciation to Brandon Nuttall (KGS) for providing production data and Patrick Gooding (KGS) for assistance in collecting source rock samples of the New Albany Shale. Terry Hamilton-Smith (KGS/consultant) deserves a special acknowledgement for his assistance in collecting tar samples and his compilation of metal contents on western Kentucky tars. David Williams (KGS) and John Rupp (IGS) are also acknowledged for their assistance in collecting additional tar samples. John Guthrie's (Indiana University/ExxonMobil) assistance in conducting hydrous pyrolysis on source rocks of the New Albany Shale is also acknowledged and appreciated. This article has benefited from the thorough reviews by Robert Cluff (Discovery Group), Alain-Yves Huc (Institut Francais du Petrole), and John Rupp (IGS). Internal U.S. Geological Survey reviews of this study by Joe Hatch, Gregory Ulmishek, Dick Keefer, and Katherine Varnes provided helpful suggestions and comments that enhanced the clarity and content of the final article. Hearty discussions with Martin Goldhaber and Elizabeth Rowan (U.S. Geological Survey) on fluid flow and thermal maturity in the Illinois basin were also beneficial to the study. Studies cited in this article by M. H. Barrows, R. M. Cluff, J. B. Comer, N. R. Hasenmuller, J. A. Lineback, R. F. Mast, M. C. Noger, and D. H. Swann provided the geological framework of the Illinois basin that made this study possible. Lastly, we are grateful to Henry H. Hinch for his pioneering work and helpful suggestions in defining secondary-migration catchments.
The New Albany-Chesterian petroleum system of the Illinois basin is a well-constrained system from which petroleum charges and losses were quantified through a material-balance assessment. This petroleum system has nearly 90,000 wells penetrating the Chesterian section, a single New Albany Shale source rock accounting for more than 99% of the produced oil, well-established stratigraphic and structural frameworks, and accessible source rock samples at various maturity levels. A hydrogen index (HI) map based on Rock-Eval analyses of source rock samples of New Albany Shale defines the pod of active source rock and extent of oil generation. Based on a buoyancy-drive model, the system was divided into seven secondary-migration catchments. Each catchment contains a part of the active pod of source rock from which it derives a petroleum charge, and this charge is confined to carrier beds and reservoirs within these catchments as accountable petroleum, petroleum losses, or undiscovered petroleum. A well-constrained catchment with no apparent erosional or leakage losses is used to determine an actual petroleum charge from accountable petroleum and residual migration losses. This actual petroleum charge is used to calibrate the other catchments in which erosional petroleum losses have occurred. Petroleum charges determined by laboratory pyrolysis are exaggerated relative to the actual petroleum charge. Rock-Eval charges are exaggerated by a factor of 4-14, and hydrous-pyrolysis charges are exaggerated by a factor of 1.7. The actual petroleum charge provides a more meaningful material balance and more realistic estimates of petroleum losses and remaining undiscovered petroleum. The total petroleum charge determined for the New Albany-Chesterian system is 78 billion bbl, of which 11.4 billion bbl occur as accountable in place petroleum, 9 billion bbl occur as residual migration losses, and 57.6 billion bbl occur as erosional losses. Of the erosional losses, 40 billion bbl were lost from two catchments that have highly faulted and extensively eroded sections. Anomalies in the relationship between erosional losses and degree of erosion suggest there is potential for undiscovered petroleum in one of the catchments. These results demonstrate that a material-balance assessment of migration catchments provides a useful means to evaluate and rank areas within a petroleum system. The article provides methodologies for obtaining more realistic petroleum charges and losses that can be applied to less data-rich petroleum systems.
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