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AAPG Bulletin, V.
Use of fault-seal analysis in understanding petroleum migration in a complexly faulted anticlinal trap, Columbus Basin, offshore Trinidad
1BP Canada Energy Co., 240 4th Ave. SW., Calgary, Alberta T2P 2H8, Canada
2BP Upstream Technology Group, Chertsey Road, Sunbury on Thames, Middlesex TW16 7LN, United Kingdom
Richard Gibson received his Ph.D. and his M.S. in geology from Virginia Tech and his B.S. degree from Allegheny College. At Amoco Research from 1989 to 1995, he focused on fluid flow and kinematic studies of faults. During the next five years working on Trinidad exploration at Amoco/BP, his interests evolved toward a holistic view of the petroleum system. He is currently working in production geology in the Rocky Mountain foothills.
Peter A. Bentham received a B.A. degree in geology from Oxford University (1988) and a Ph.D. in geology from the University of Southern California (1992). He joined Amoco as a structural geologist in 1992 and has worked as a structural consultant in a wide variety of exploration projects in North and South America and North Africa. He is currently structural geology network leader for BP and works in the Upstream Technology Organization in Sunbury, United Kingdom.
The work presented here would not have been possible without the previous mapping and geologic studies of many individuals in the BP (Amoco) Trinidad Exploration team including, but not limited to, Ken Ortmann, Maria Henry, Granville Smith, Linda Kinslow, Erika Frantz, and Lesli Wood. However, the analysis presented here is solely the responsibility of the authors. We thank BP Energy of Trinidad and Tobago for permission to publish this paper.
In the Columbus Basin, offshore Trinidad, evaluating the controls on fault seal is a prerequisite for understanding how the petroleum fields were charged. In this paper, we present a case study from Mahogany field, where interbedded Pliocene–Pleistocene shales and reservoir sands occur in a broad four-way-closed anticline cut by numerous normal faults. Fault seals in this stratigraphic sequence can be successfully evaluated using shale gouge ratio (SGR), with a transition between sealing and nonsealing faults occurring in the SGR = 0.15–0.25 range. Because of the high net-to-gross ratio of individual sands, low SGR values typically correspond to areas of reservoir self-juxtaposition, whereas good seals (SGR 0.2) exist where different sands are juxtaposed against one another.
The larger structural geometry, which changes significantly from the shallow reservoirs to the deeper ones, closely controls the distribution of stacked, fault-sealed petroleum accumulations in this field. Petroleum column heights in individual fault blocks within the structure are limited either by (1) a cross-fault spill point at a low-SGR window on the west side of a fault block or (2) a synclinal spill point within a fault block from which petroleum leaves the overall four-way closure. The pattern of hydrocarbon-water contacts in the field suggests that petroleum filled and spilled its way from northeast to southwest across the structure with individual sands acting as a separate flow systems. Despite juxtaposition against each other, communication between stratigraphically different sands is minimal. Vertical migration of petroleum along faults is not required to explain the distribution of charged sands, and this is consistent with both petrophysical data and the known sealing character of the faults. This petroleum migration model serves as a tool for evaluating charge risk and column heights in untested fault blocks in the area.
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