Abstract
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.
