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Organic geochemical and palynological studies of the Maastrichtian source rock intervals in Bida Basin, Nigeria: implications for hydrocarbon prospectivity
(Journal of Petroleum Exploration and Production Technology (Springer), 2020-09-02) Olusola J. Ojo, Ayoola Y. Jimoh, Juliet C. Umelo, Samuel O. Akande
The Patti Formation which consists of sandstone and shale offers the best potential source beds in the Bida Basin. This inland basin is one of the basins currently being tested for hydrocarbon prospectivity in Nigeria. Fresh samples of shale from Agbaja borehole, Ahoko quarry and Geheku road cut were analysed using organic geochemical and palynological techniques to unravel their age, paleoecology, palynofacies and source bed hydrocarbon potential. Palynological data suggest Maastrichtian age for the sediments based on the abundance of microfloral assemblage; Retidiporites magdalenensis, Echitriporites trianguliformis and Buttinia andreevi. Dinocysts belonging to the Spiniferites, Deflandrea and Dinogymnium genera from some of the analysed intervals are indicative of freshwater swamp and normal sea conditions. Palynological evidence further suggests mangrove paleovegetation and humid climate. Relatively high total organic carbon TOC (0.77–8.95 wt%) was obtained for the shales which implies substantial concentration of organic matter in the source beds. Hydrocarbon source rock potential ranges from 0.19 to 0.70 mgHC/g.rock except for a certain source rock interval in the Agbaja borehole with high yield of 25.18 mgHC/g.rock. This interval also presents exceptionally high HI of 274 mgHC/g.TOC and moderate amount of amorphous organic matter. The data suggests that in spite of the favourable organic matter quantity, the thermal maturity is low as indicated by vitrinite reflectance and Tmax (0.46 to 0.48 Ro% and 413 to 475 °C, respectively). The hydrocarbon extracts show abundance of odd number alkanes C27–C33, low sterane/hopane ratio and Pr/Ph > 2. We conclude that the source rocks were terrestrially derived under oxic condition and dominated by type III kerogen. Type II organic matter with oil and gas potential is a possibility in Agbaja area of Bida Basin. Thermal maturity is low and little, or no hydrocarbon has been generated from the source rocks.
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Geochemical Fingerprints; Implication for Provenance, Tectonic and Depositional Settings of Lower Benue Trough Sequence, Southeastern Nigeria
(The International Institute for Science, Technology and Education (IISTE), 2013) Olubunmi C. Adeigbe, Yusuf A. Jimoh
The study areas, Asu River Group (ARG) and Cross River Groups (CRG) belong to Lower Benue Trough. The Trough is thought to have been deposited by marine transgression and regression. ARG covers Awi, Abakaliki and Mfamosing Formations while Ekenkpon, Eze-Aku, New Netim, Awgu and Agbani Formations fall within CRG. Sampling was done to cover both the Abakaliki Anticlinorium and Calabar Flank. The study aimed at using geochemical approach to deduce weathering, provenance, tectonic setting as well as depositional environment in a holistic manner which hitherto has not been used by any worker. A total of 56 fresh outcrop samples were obtained from the study area. The samples were subjected to detailed lithologic description by visual examination. Geochemical analysis was done using Inductively Coupled Plasma Mass Spectroscopy and Inductively Coupled Plasma Atomic Emission Spectroscopy (ICP-MS/AES) to determine major, trace and rare-earth elements using lithium metaborate/tetraborate fusion method. Weathering Indices of Chemical Index of Alteration (CIA), Plagioclase Index of Alteration (PIA), Chemical Index of Weathering (CIW) and Ruxton Ratio (RR) of ARG has a range of (0.18-86.1, 0.13-99.3, 0.18-99.5 and 1.80-25.2) with median of (76.7, 92.6, 93.5 and 5.76) respectively while CRG has a range of (2.93-97.7, 2.78- 99.7, 2.94-99.7 and 1.83-46.4) and median of (76.1, 85.5, 87.7 and 10.9) respectively, indicating moderate to high weathering at the source. The Al2O3-(K2O+CaO+MgO)-(Fe2O3+MgO), (AKF) ternary plots reveals sediments of ARG and CRG deposited in Continental, Transition and Marine zone and dominated by argillaceous, carbonaceous argillite, carbonaceous and a ferruginous argillites confirming a chemically altered sediments deposited in oxidizing and shallow marine environment. The plots of Log (Fe2O3/K2O) vs Log (SiO2/Al2O3) reveals sediments deposited in the Fe Shale, Shale, Wacke, Subarkose and Quartz arenite field. The discriminant function plots of Herron characterized the sediments as been derived from Quartzose sedimentary provenance, Intermediate igneous and Felsic provenance. Trace elements ternary plots of La-Th-Sc, Th-Sc-Zr/10 and Th-Co-Zr/10 reveal deposition within Continental Island Arc, Passive Margin and Oceanic Island Arc settings. This confirmed the tectonic discriminant plots of K2O/Na2O vs SiO2. This discriminant function diagram proposed by Roser and Korsch (1986) distinguish the sources of the sediments into four provenance zones, mafic, intermediate, felsic, igneous and quartzose sedimentary using ratio plots and raw oxides. Most of the sediments of ARG and CRG fall in, quartzose sedimentary provenance using raw oxide plots, and exceptions are the limestones that fall in intermediate igneous provenance this also corroborates with the ratio plots. Conclusively, the study shows that the Cretaceous clastic sediments of ARG and CRG have multiple provenances subjected to moderate to high weathering conditions and were deposited within an oxidizing and shallow marine setting and derived from Upper Continental Crust (UCC).
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Rock-Eval pyrolysis and organic petrographic analysis of the Maastrichtian coals and shales at Gombe, Gongola Basin, Northeastern Nigeria
(Arabian Journal of Geosciences: Springer, 2016-05-19) Ayoola Y. Jimoh & Olusola J. Ojo
The Gongola Basin forms one of the inland Cretaceous to tertiary sedimentary basins in Nigeria with relatively unknown petroleum system. In this study, the investigated source rock intervals of the Maastrichtian Gombe Formation are located at the Maiganga coal mine, near Gombe, Gongola Basin, Nigeria. The exposed part of the mine consists of about 35-m thick coarsening upward section with the basal part made up of coal and shale interbeds while the upper part consists of siltstone and sandstone and probably deposited in fluvio-deltaic environment. The coal and interbedded shale appear most prospective source rock facies in the formation and were evaluated with respect to their hydrocarbon source rock potential. The organic geochemical results showed high TOC for the coals (37.71–65.29 wt%) and moderate organic carbon concentration (1.19–4.81 wt%) for the shales. S2 values ranges from 57.96 to 103.21 mgHC/g rock and 0.51–6.22 mgHC/g rock for the coal and shales, respectively. The HI is less than 200 mgHC/gTOC in all the coal and shale samples suggesting Type III kerogen and predominant plant contributions from terrestrial sources. Consequently, gaseous hydrocarbon potential is exhibited in the source beds. The organic petrography shows vitrinite as dominant maceral followed by inertinites and liptinites with inorganic minerals like pyrite and kaolinite. The Tmax is less than 435 °C in all the samples indicating pre-oil window stage; this is corroborated by the Romax value ranging from 0.45 to 0.55 %. Plot of PI against Tmax indicates low level organic matter conversion while the vitrinite reflectance values suggest a sub-bituminous coal. The study suggests that the investigated coal and shale samples constitute good source rock and have potential for gas. The generally low HI in the coals and the associated shales indicate more allochthonous and hydrogen poor organic matters in the source beds. Maceral composition of the coals suggests wet swamp environment and predominance of arborescent vegetation type. At present level, the organic matters are immature to marginally mature deeper level equivalents might have generated gas.
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Sedimentological and geochemical evaluation of sandstones of the Ilaro formation, Dahomey Basin, Southwestern Nigeria: Insights into paleoenvironments, provenance, and tectonic settings
(Journal of the Nigerian Society of Physical Sciences: Nigerian Society of Physical Sciences:, 2023-08-20) A. Y. Jimoh, M. B. Saadu, A. A. Adetoro, J. Ajadi, T. Issa, U. Issa
Grain size analysis, geochemistry, and petrography of sandstones of the Ilaro Formation exposed at the Ajegunle area were investigated to infer provenance, transportation history, tectonic setting, paleoenvironment, and degree of palaeoweathering of the sediments. Selected sandstones were analyzed, and the major, trace, and rare earth elements were determined using Inductively Coupled Plasma Mass Spectrometry (ICP-MS). Results from the granulometric analysis showed that sandstones were deposited in fluvial conditions. The sandstones exhibit a coarse-grained texture, displaying poor sorting and being texturally immature. The petrographic analysis indicated that quartz was predominant, whereas opaque minerals, muscovite, and ferruginous ground mass were present in smaller quantities. The sandstones can be geochemically classified as arkose and subarenite. The sandstones have an average composition of SiO2 (82.87%) and Al2O3 (9.49%), while K2O, Na2O, MgO, CaO, and P2O5 have <1% each. The elevated Al2O3 content is associated with the lithic fragment composition, whereas the low concentrations of MgO (mean 0.03%), Na2O (mean 0.008%), and K2O (mean 0.04%) suggest chemical destruction in an oxidizing environment. The angularity of the grains indicated a short transportation history very close to the provenance. Bivariate and discriminant plots from major elements and trace elements suggest the sandstones were non-marine and sourced from intermediate rocks. The sandstones were deposited in an oxic-dyoxic condition under a humid climate and passive or active continental margins. The average values of the weathering indices indicate an intense degree of chemical weathering.
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Geochemical and Palynological Studies of Some Maastrichtian Source Rock Intervals (Patti and Gombe Formations) in Nigeria: Implications for Hydrocarbon Prospectivity
(American Association of Petroleum Geologist (AAPG), 2019-01-14) Olusola J. Ojo, Ayoola Y. Jimoh, and Juliet C. Umelo
The Maastrichtian Patti and Gombe Formations are located in Bida and Gongola Basins respectively. These two inland basins form part of the targets currently being tested for hydrocarbon prospectivity in Nigeria. Road cuttings and core samples of coal, coaly shale, and shale from the formations were analyzed using standard organic geochemical and palynological techniques to unravel their organic matter quantity, quality, palynofacies, expulsion efficiency, and thermal history. The age of the sediments were also constrained from the palynological data. Palynological data suggest a Maastrichtian age and influence of freshwater swamps for the sediments based on the microfloral assemblage like Retidiporites magdalenensis, Echitriporites trianguliformis, Buttinia andreevi, and Botrycoccus braunii. The organic geochemical results show relatively high TOC for the Patti shales (0.79-12.9 wt.%) and Gombe coals (38.8-61.2 wt.%) implying moderate to high concentrations of organic matter. Hydrocarbon source potential range from 0.19-0.70 mgHC/g rock except for a certain interval with high yield (30.23 mgHC/g rock) in the Patti shales. The Gombe coals have source potential ranging from 32.77-69.38 mgHC/g rock. Generally, the samples show low HI except one of the Patti shale samples with HI of 230 mgHC/g TOC (thought to be formed under reducing condition) and one of the Gombe coal samples with HI of 170 mgHC/g TOC. In spite of the favorable organic parameters, the thermal maturity is low with vitrinite reflectance and Tmax ranging between 0.41-0.52 % and 413-431 °C respectively. Biomarker analysis of the hydrocarbon extracts show abundance of odd number alkanes C27-C33, low sterane/hopane ratio (0.06-0.25). Pr/Ph in the samples are greater than 2. We conclude from the study that the Maastrichtian source rocks were sourced terrestrially under a prevailing oxic condition and dominated by Type III organic matter. Type II organic matter with oil and gas potential may be possible in the Patti Formation in the Agbaja area of Bida Basin. Thermal maturity and conversion ratio were low and not much hydrocarbon could have been generated from the source rocks.