Fault-Zone Seals in Siliciclastic Strata of the Columbus Basin, Offshore Trinidad

Abstract

This study combines observations from outcrop and drill core with an analysis of the hydrocarbon distribution in two mature oil and gas fields to document the factors controlling the existence of fault seals in the Tertiary sandstone-shale sequence of the Columbus Basin. Juxtaposition of reservoir sandstones against shale intervals across normal faults cannot explain the oil and gas distribution in this area, indicating that fault zones serve as the lateral seals for these hydrocarbon accumulations. The fault-zone seals for the largest hydrocarbon columns (50-200 m) consist of shale smears formed by ductile deformation of shale beds during fault slip. Empirical evidence suggests that these zones are spatially continuous only where the shale content of the section displace along a fault exceeds 25% (shale smear factor <=4). Pore-throat radn of these shale-smear fault zones, calculated from observed column heights, are in the 0.05-1 mm range, decreasing exponentially with depth. Fault segments that do not meet the criteria for development of a shale smear appear to be transmissible or can seal only small columns (<20 m). Such poorly sealing fault segments are comprised primarily of cataclastically deformed sandstone, which, based on laboratory test data, does not have small enough pore throats to serve as high-capacity capillary seals in this area. Two different modes of fault-sealed trap leakage during hydrocarbon migration can be defined. Where shale smears are discontinuous, such as where a sandstone body is partially juxtaposed against itself, column heights are cross-fault spillpoint limited and can be analyzed using fault-plane sections combined with mapping of shale-smear continuity. These traps are likely to preferentially spill high-density hydrocarbons once trap capacity is reached. In contrast, traps bounded by spatially continuous shale smears probably leak through the pore network of the fault-zone material at the top of the trap, thus favoring preferential movement of low-density hydrocarbons in a two-phase system. Maximum column height estimates for such traps can be calculated using capillary pressure relationshi s. Hydrocarbon migration through stratigraphic sections containing fault-sealed traps of these two types may result in geochemical fractionation and phase segregation, both of which are observed in the Columbus Basin fields.