Paleoenvironments and Hydrocarbon Potential of Upper Cretaceous Shales in Agbabu-1 Well, Dahomey Basin SW Nigeria

Upper Cretaceous shales partially exposed in the northern fringes of the Dahomey Basin are well developed in the subsurface in Southwestern part of the basin where Agbau-1 well is sited. These shales were evaluated in respect to their paleoenvironments and potentials for hydrocarbon using foraminiferal assemblages, biomarkers and Rock Eval pyrolysis studies. The dominance of benthonic foraminifera species suggests a shallow marine environment and high percentage of calcareous to arenaceous benthic www.eujournal.org 195foraminifera indicate high water salinity and hypersline environment. Dysoxic oxygen condition is also prevalent probably because most of the benthic foraminifera recovered are epifauna that live in a reduced oxygen condition. 1.90 wt%, 244 mgHC/gTOC and 429℃ average values of total organic carbon, hydrogen index and Tmax reveal that the Upper Cretaceous shales have relatively fair to good organic matter, predominantly Type II-III kerogen and currently immature. Though three is a trend of an increase in maturity down the hole. All the steranes have uniform distributions (C27>C28>C29), suggesting a relatively higher input from the marine red algae and a low level of land plant contribution to the source organic matter. Pristane/phytane ratios and C29/C27 steranes confirmed the organic matter type to be a Type II/III and anoxic source rock depositional condition as well as a reducing diagenetic system in the sediment water column. The Upper Cretaceous shales in Dahomey Basin can be targeted for exploration as an unconventional petroleum resource.

Sedimentation, depositional environments, and hydrocarbon potential of the Maastrichtian-Paleocene Araromi Formation, eastern Dahomey (Benin) Basin, southwestern Nigeria

The Cretaceous sediments in southwestern Nigeria are host to one of the largest bitumen deposits in the world. In the current paper, an integrated study on sedimentology, palynology, and applied petroleum geochemistry of the Maastrichtian-Paleocene Araromi Formation was used to determine the depositional environments and hydrocarbon potentials of the formation on the eastern Dahomey Basin. Four sedimentary lithofacies were identified from core samples, namely, lower limestone (F1); medium to coarse-grained sandstone (F2); lower loosely consolidated sandstone (F3); and shale and siltstone (F4). Sedimentation in the eastern Dahomey Basin occurred mainly in fluvial and shallow-marine (shelf) environments. The palynological assemblages of the Araromi Formation reflect deposition in coastal through brackish water to shallow shelf environment with periods of localized wind-induced storms. The shale and siltstone samples of the Araromi Formation are characterized by total organic carbon (TOC) values of up to 2.50 wt % and S2 (hydrocarbon-generating potential) values ranging from 0.26 to 0.70 mgHC/g rock, indicating poor source rocks. Shales show poor quality and thermally immature organic matter at shallow depth and could neither have generated liquid hydrocarbon nor contributed to the heavy oil occurrence on the bitumen and tar-sand belt of eastern Dahomey (Benin) Basin.