Browsing by Author "Adekeye, Olabisi"
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Item The assessment of potential source rocks of Maastrichtian Araromi formation in Araromi and Gbekebo wells Dahomey Basin, southwestern Nigeria(Heliyon, 2019) Adekeye, Olabisi; Akande, Samuel O; James, Adeoye A.Drilled core samples of the Araromi Formation in the eastern Dahomey basin penetrated by Araromi and Gbekebo exploratory wells were investigated to establish the source rocks potentials in the onshore area of the basin. The sediments are of Maastrichtian age deposited in the shallow marine environment with varying thicknesses. Rock-Eval data of forty seven (40) shales give Total Organic Carbon (TOC) range of 0.50–4.78 wt%, Hydrogen Index (HI) value range of 1 - 327mgHC/gTOC, Tmax values from 398 C–437 C and Source Potential (SP) values range from 0.01 - 14.56kgHC/ton of rock. The maceral compositions of the shales are liptinite (av. 26.0%), abundance vitrinite (av. 38.1%) and inertinite (av. 35.9 %) with vitrinite reflectance (VRo) ranging from 0.51 - 0.68 %Ro. Hydrocarbons and biomarkers results reveal a bimodal n-alkane envelope between (nC16 and nC18) and (nC27 and nC29) suggesting organic matter of mixed origin of algae and higher plant generally in the two well. The Significant contribution of marine algae in the deeper part of Gbekebo well was observed by the presence of C30 24-n-propyl cholestane (%C30 sterane range from 0.45 to as high as 5.23%). Integration of the Rock-Eval, organic petrology and biomarkers data reveal that the kerogen constituents of the source rocks in Araromi well are mainly Type II/III, III and IV with a high amount of inertinite constituents suggesting they have been reworked. Type II and II/III kerogen derived from marine algae are better preserved in the deeper part of Gbekebo well located more southerly in the basin than in the Araromi well. The source rocks are generally immature to marginally mature and hydrocarbon exploration effort should be targeted towards Gbekebo well area where we have more promising potential source rocks capable of generating more hydrocarbons essentially at a deeper depth.Item Depositional environment and carbon/oxygen isotopic composition of the Paleocene carbonates exposed around Kalambaina, Sokoto basin, Nigeria(Advance Journal of Physical Sciences, 2013) Adekeye, Olabisi; Akande, Samuel; Erdtmann, B.The limestone-shale sequence exposed at the Kalambaina quarry belongs to the Paleocene marine sediments deposited in the Sokoto Basin during the second phase of sediment deposition when the Tethys Sea moved southwards through the Sahara. The exposed section measured ca.19.5m in thickness. The lower part of the section consists of limestone-shale interbeds while the upper part is phosphatised shale. The limestone is clayey, consisting of marl and shale components. The beds are generally massive to wavy laminated. Petrographic study reveal that the limestones are mud supported and consist of two main carbonate rock types including bioclastic wackestone and bioclastic packstone. Larger foraminifera, corals, bryozoans, echinoderms, algae and gastropods represent the major bioclasts while lithoslasts are the main non-bioclastic grains of the lithofacies. The associated shales consist of many detrital materials, phosphorites, gypsum and carbonaceous organic matter. Carbon/oxygen isotopic composition vary from –5.29%o to –6.55%o 18O PDB and –1.24%o to –3.40%o PDB 13C in the whole rock compare to the average values of –2.33 18O and +0.05 13C PDB for Tertiary Sea water. The lighter oxygen and carbon fractions in the samples is a reflection of the depletion of heavier isotope of oxygen and carbon consequent to late stage recrystallisation, influx of fresh water and formation of variable carbonate cements during progressive diagenesis. Estimated formational paleo temperatures for the kalambaina limestone vary from 26.80 to 32.85C. The study suggests that carbonates of the Kalambaina formation were deposited in shallow marine, shelf lagoonal setting and have undergone several stages of post depositional changes. The late stage cements have reduced the interparticles and moldic porosities of the carbonateItem Geochemistry and paleoecology of shales from the Cenomanian-Turonian Afowo formation Dahomey Basin, Nigeria: Implication for provenance and paleoenvironments(2020) Adeoye, James A.; Samuel, O Akande; Adekeye, Olabisi; Victor, AbikoyeCenomanian - Turonian (CT) Afowo shales selected from offshore X, and coastline Orimedu-1 and Ise-2 exploratory wells in the Dahomey Basin, southwestern Nigeria, were analyzed for foraminifera, major oxide and trace elements to evaluate their provenance and paleoenvironments. The hydrocarbon rich calcareous CT shale is about 100m thick in the coastline area and 300m thick in offshore area with abundant of marine planktonic and benthonic foraminifera. Benthonic species were significantly present in the coastline wells suggesting a shallow marine condition probably a neritic to inner shelf environments while abundant deep water Rotaliporid sp. and shallow water fauna heterohelix sp. in X well suggest inner shelf to bathyal (ca. >350 m) depositional environments. SiO2 and Al2O3 are the most abundant oxides of CT shale with average value of 46.4% and 12.7% in X, 57.1% and 15.65% in Orimedu-1 and 55.3% and 13.1% in Ise-2 respectively suggesting high influx of terrigenous and argillaceous sediments at the coastal area. Average Al2O3/TiO2 of 19.2 in X, 17.8 in Orimedu-1 and 19.3 in Ise-2 indicates that the sediments were sourced from intermediate igneous rock. Favorable oxic conditions for chemical weathering is more pronounce in the manganese concentration of 658–937 ppm in Orimedu-1 and 829–838 ppm in Ise-2 than 364–604 ppm in the shales from X well. Their degree of weathering estimated from chemical index of alteration (CIA) averaging 97 in the coastline wells is higher than 61 in X well, thus indicating high degree of oxidation in the depositional environments. Vanadium to nickel ratio ranging from 2.88 to 5.0 in X well suggest mixed marine and terrigenous source under dysoxic to oxic conditions for the shales while 0.48–1.2 values in Orimedu-1 further indicates a prevailing oxidizing condition at the time of deposition. Dysoxic-oxic and moderate deep-water conditions were more favorable in the offshore area and probably a significant paleo-factor for organic matter preservation of CT shales in the basin.Item Paleoenvironments and Hydrocarbon Potential of Upper Cretaceous Shales in Agbabu-1 Well, Dahomey Basin SW Nigeria(European Scientific Journal, 2021) Adekeye, Olabisi; Ogundipe, Olumide; Adeoye, James; Adeyilola, Adedoyin; Samuel, Olukayode; Akande, SamuelItem Paleoenvironments and Hydrocarbon Potential of Upper Cretaceous Shales in Agbabu-1 Well, Dahomey Basin – Insight from Geochemistry and Foraminifera Paleontology(European Scientific Journal, 2021) Adekeye, Olabisi; Ogundupe, Olumide; Adeoye, James Adejimi; Adeyilola, Adedoyin; Samuel, Olukayode; Akande, Samuel OlusegunUpper 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 195 foraminifera 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.Item Structural and geophysical constraint mapping for hydrocarbon resources within parts of the Bida Basin, Central Nigeria(Arabian Journal of Geosciences, 2022) Habu, Serah Japhet; Adekeye, Olabisi; Andongma, Wanduku TendeRemote sensing (RS) and geographic information systems (GIS) play an important role in the exploration of geological resources and are most effective when used during reconnaissance scale surveys. In Nigerian frontier basins, the use of GIS-based spatial predictive mapping and regional scale evaluation of geological structures is regarded as the best tools for downscaling exploration targets. The Fry analysis and distance correlation analysis were used to infer structural control over hydrocarbon resources, whereas the prediction area plot analysis assessed the spatial relationship between the evidential and target data. A hydrocarbon prospectivity map for the Bida Basin was generated using a multi-criteria weighted sum model, and the hydrocarbon predictive model was discretized and classified using a multi-fractal analytical approach. ROC/AUC analysis was used to evaluate and assess the reliability of the hydrocarbon predictive model. According to evidence from Fry and distance correlation analysis, hydrocarbon manifestations is primarily controlled by the WNW-ESE tectonic trend. Based on the prediction area plot analysis, there is a significant correlation between hydrocarbon occurrences and spatial data on magnetic (0.67), gravity (0.68), and distances to the WNW-ESE lineaments (0.81). The weighted sum model was used to integrate spatial data, which revealed significant potential for hydrocarbon resources in the study location’s south-central and north-eastern regions. The hydrocarbon predictive model was discretized into four classes (very low, low, high and very high) using multi-fractal analysis, with percentile extents of 25.88%, 42.43%, 21.46%, and 10.23%, respectively. The ROC/AUC revealed an accuracy level of more than 80%. The reliable identification of exploration targets, demonstrated by a high level of accuracy, suggests that this approach could be ideal for supplementing exploration expeditions in the Bida basins and other sedimentary basins throughout Nigeria.