Awgu Formation Research Articles

Elemental geochemistry and organic facies of selected cretaceous coals from the Benue Trough basin in Nigeria: Implication for paleodepositional environments

Benue Trough basin is geologically subdivided into three segments. It consists of marine and continental sediments that are affected by folding movements. In the upper section, the continental coal-bearing Campano-Maastrichtian-age is found within Gombe Sandstone and the Cenozoic Kerri-Kerri Formation of the Tertiary. In the middle segment, the late Turonian/early Santonian coal-bearing Awgu Formation lies conformably on the Ezeaku Formation. In the lower part, shales at Nkporo mark marine incursion and deposition of the Maastrichtian Mamu Formation coal measures. Cretaceous coal samples taken from the three segments of Benue Trough basin were examined using ultimate and proximate, organic petrographic, x-ray fluorescence (XRF) and laser ablation-induced coupled plasma spectroscopy (LA-ICPMS) analytical techniques. Results of trace element ratios, Ce/Ce* values (“where Ce* is the theoretical Ce value derived from a chondrite-normalized rare earth element (REE) pattern”), authigenic uranium values, and low hydrogen content indicate deposition under oxic to suboxic conditions. However, the V/Ni and V/Sc ratios indicate under oxic, suboxic to reducing conditions. The Y/Ho values for selected coals are lower than the range for seawater, indicating terrigenous influence. The Sr/Ba values indicate low influence of saline water during deposition and a strong continental rather than marine influence. High value of vitrinite and low proportion of liptinite/intertinite suggest that peat in the study areas were situated on the irregular basin floor where sediment thicknesses vary from place to place thus the depositional environments shifted causing mineral matter filling in coal. Based on the tissue preservation index (TPI) and gelification index (GI), LFB, CHK, OKB, LMZ, IMG; and ENG (high GI and high TPI) were deposited in telmatic facies; wet-forest swamps with rapid organic matter accumulation. This trend indicates mild humification and strong gelification of plant tissues which ascribed to high rate of subsidence with wood- and bark-derived telovitrinite. The MGA peats were deposited in terrestrial facies in a dry-forest swamp with wood-derived telo-inertinite. The coal samples code-named IMG and ENG were deposited in planar margin mires. However, coal samples code-named LFB, CHK and LMZ were deposited in planar central mires. Lastly, OKB and MGA were deposited in transitional-wet and transitional-dry mire. The low V and Ni concentrations, low H/C, high O/C, high C/N, and very low N/C ratios <0.05 implies Type III land-plant organic matter that is not oil-prone. The depositional environments interpretations of investigated coal seams indicate that the coals were deposited within a telmatic, limnic, limno-telmatic and open march zone. Generally, a combination of results from inorganic geochemistry and organic petrology is required for precise and all-inclusive determination of coal depositional environments.

Characterization of Organic Matter from Bituminous Coals of Lafia-Obi, Middle Benue Trough, Nigeria

The present work deals with a study based on the geochemical techniques such as biomarkers, Rock-Eval pyrolysis, and detailed petrographic study to evaluate hydrocarbon generation potential of coal by collecting nine coal and carbonaceous shale samples from boreholes in Awgu Formation of Middle Benue Trough, Nigeria. The values vitrinite reflectance (0.94–1.15%VR) and Tmax (446–469°C) confirmed that samples are matured enough to generate liquid and gaseous hydrocarbon in coal. The coal samples also contain sufficient quantity of vitrinite and liptinite macerals varying from 70.28% to 74.10 wt%, which confirm the production of liquid hydrocarbon. The cross-plot between H/C and O/C atomic ratio indicates that samples were predominant in the bituminous rank and having kerogen Type III makes it suitable for hydrocarbon generation. Similar results were found in Rock-Eval pyrolysis analysis (Types II-III and Type III kerogen). The homohopane index (C35/C31 - C35) and homohopane ratio (C35αβS/C34αβS) range from 0.02 to 0.12 and 0.15 to 0.92 indicates oxic condition during organic matter deposition from Lafia-Obi samples. The Moretane/Hopane, Hopane/Hopane + Moretane, Ts/Ts + Tm, 22S/22S + 22RC32homohopane ratios range from 0.06 to 0.14; 0.88 to 0.94; 0.34 to 0.66; and 0.53 to 0.62 and 20S/20S+20R and αββ/αββ+ααα C29 ratios range from 0.43 to 0.58 and 0.42 to 0.55 indicate samples ar e within the late oil window/gas phase. Plots of 22S/22S+22R C32hopanes against C29αββ/αββ+ααα steranes show that Lafia-Obisamples are thermally mature.

Foraminifera Biostratigraphy, Palynofacies and Paleoenvironment of deposition of the Albian to Santonian sediments in the Southern Benue Trough, Nigeria

The Albian-Santonian sedimentary sequence in the Ndeaboh-Nenwe area of Enugu, Southern Benue Trough, were analysed for foraminifera and integrated with ostracod and palynofacies analyses to comprehensively appraise the age and depositional environment of the sediments. This is paramount since the studied formations have intermittent series of non-marine sedimentary influences throughout the basin. The results of foraminifera evaluation indicate that the Abakaliki Formation is barren of foraminifera species, whereas the Eze-Aku and Awgu formations have preponderance of planktonic foraminifera assemblages over benthic forms. The Eze-Aku Formation records an abundance of species of Hedbergella and a peak for Heterohelix. The co-occurrence of Whiteinella archeocretacea, Hedbergella planispira, Heterohelix delrieonsis and the ostracod species Ovocytherida symmetrica, suggests a Late Cenomanian to Early Turonian age. Rare species of short-ranging and keeled planktonic taxa are present in Awgu Formation, which has a preponderance of Heterohelix reussi, Heteroheix globulosa, Heterhelix pulchra, Whiteinella baltica, and the ostracods Brachycythere ekpo and Cythereis sp. The Awgu Formation is Middle Turonian to Santonian. The percentage of amorphous organic matter and lithologic characteristics suggest a marine environment for the Abakaliki Formation, although the water depth cannot be ascertained. In the Eze-Aku Formation, the prevalence of Hedbergella and its co-occurrence with Whiteinella and associated palynofacies data (amorphous organic matter, black debris, few structured terrestrial phytoclasts) and dinoflagellate cysts suggest a fairly deep (200–300 m) marine environment with occasional terrestrial input. The low diversity of agglutinated benthic foraminifera assemblage in the Awgu Formation indicates deposition at a minimum paleo-water depth. The paucity of benthic foraminifera, rare occurrence of keeled planktonic species, and the dominance of Hedbergella and Heterohelix; low oxygen tolerant species, in the studied interval are attributed to anaerobic bottom conditions possibly caused by poor bottom water circulation and high organic productivity in the oceans and seas during the Cenomanian-Santonian.

Organic geochemical evaluation and hydrocarbon prospects of the Coniacian Awgu Formation, southern Benue Trough, Nigeria

Samples of shale from the Coniacian Awgu Formation (southern Benue Trough, Nigeria) were subjected to petro-geochemical analyses in order to determine the hydrocarbon potentials of the formation. The results of the analyses, which included total organic carbon (TOC) content determination and Rock-Eval pyrolysis, show that TOC ranges from 0.53 to 2.91 wt% (with average value of 1.76 wt%), while the generative potential and the hydrogen index range from 0.56 to 3.42 mg HC/g (av. 1.93 mg HC/g) and 67 to 109 mg HC/g TOC (av. 94 mg HC/g TOC), respectively. The results also show vitrinite reflectance value that vary between 0.52 and 0.63% Ro (av. 0.60% Ro) and pyrolysis temperature 428 to 433 °C (av. 431 °C), and organic matter predominantly the type III. On the basis of the TOC, the average TOC (1.76 wt%) exceeds the minimum value of 0.50 wt% required for good hydrocarbon source rocks, and the other assessed parameters which indicate terrestrial-sourced organic matter, this study reveals that the Awgu Formation is a potential source rock, but with more capabilities to generate gas than oil. The overall thermal maturity stage of the kerogens in the formation is within the immature to early (threshold) mature.

Density and reservoir properties of Cretaceous rocks in southern Benue Trough, Nigeria: implications for hydrocarbon exploration

Densities and reservoir properties of rocks were determined using 167 representative fresh rock samples of Cretaceous sedimentary rocks outcropping in the southern portion of the Benue Trough, Southeastern Nigeria, through the application of the Archimedes principle and grain size analysis. Result of the analysis indicates that the mean bulk densities for the rocks in the study area are as follows: Asu River Group (1.65 g/cm3), volcanic rocks (1.60 g/cm3), Eze-Aku Group (2.44 g/cm3), Awgu Formation (1.83 g/cm3), Nkporo Group (1.77 g/cm3), Mamu Formation (1.79 g/cm3), Ajali Sandstones (2.20 g/cm3), Nsukka Formation (1.74 g/cm3). Porosity and permeability values of the sandstones are as follows: Asu River (6.81%; 98.36 mD), Amasiri Sandstone (11.12%; 120.30 mD), Afikpo Sandstone (8.90%; 133.11 mD), Owelli Sandstone (11.15%; 659.37 mD), Mamu Sandstone (14.53%; 1596.45 mD), Ajali Sandstone (18.52%; 759.61 mD), Nsukka Sandstone (14.64%; 3838.61 mD). Porosity of the pre-Santonian shales is controlled by age and burial history, whereas those of the post-Santonian shales are more controlled by their physical properties than age and depth of burial. Porosity of the pre-Santonian sandstones is controlled by texture, depth of burial, and rock matrix, whereas that of the post-Santonian sandstones are controlled by depth of burial and rock matrix. While compaction and diagenetic alterations have influenced the permeability of the pre-Santonian sandstones, degree of sorting cum depth of burial has been a major factor influencing the permeability of the post-Santonian sandstones. The reservoir properties of the Asu River Group sandstones indicate that they cannot make good reservoirs. The reservoir properties of the Amasiri, Afikpo, Owelli, Mamu, Ajali, and Nsukka sandstones indicate that they can make good reservoirs. However, aside from the Amasiri, Afikpo, and Owelli sandstones, the sandstones of Mamu, Ajali, and Nsukka formations are not stratigraphically positioned to serve as hydrocarbon reservoirs in the study area.

Petroleum Potential of Awgu Shale Benue Trough, Nigeria

Shale samples were collected from a borehole that penetrated Awgu formation of the middle Benue trough, Nigeria. Source-rock potential was studied using Rock-Eval analysis and gas chromatography-mass spectrometry. The Rock-Eval pyrolysis data indicate that the samples contain a minimum amount of organic matter required to serve as a moderate source rock for hydrocarbons and classified the organic matter as type III kerogen. The distribution of n-alkane in the samples indicates mixed origin of organic matter. The pr/ph ratio (0.40–3.07) indicates organic matter deposition under anoxic to oxic environment. All maturity parameters computed indicate that the samples are within the oil generation window.

Biomarkers, carbon isotopic composition and source rock potentials of Awgu coals, middle Benue trough, Nigeria

Coal and carbonaceous shale samples were collected from two boreholes (BH 94 and BH 120) in Awgu formation of Middle Benue Trough, Nigeria. Source rock potentials of the samples were studied using biomarkers and carbon isotopic composition. Biomarkers in the aliphatic fractions in the samples were studied using Gas Chromatography–Mass Spectrometry (GC–MS). The Carbon isotope analysis of individual n-alkanes in the aliphatic fraction was performed using Gas Chromatography–Combustion–Isotope Ratio Mass Spectrometer (GC–IRMS). The abundance of hopanes, homohopanes (C31–C35), and C29 steranes in the samples indicate terrestrial plant, phytoplankton and cyanobacteria contributions to the organic matter that formed the coal. High (Pr/Ph) ratio (3.04–11.07) and isotopic distribution of individual alkanes showed that the samples consisted of mixed terrestrial/marine organic matter deposited under oxic condition in lacustrine–fluvial/deltaic depositional environment. The maturity parameters derived from biomarker distributions showed that the samples are in the main phase of oil window.

Hydrocarbon potential of Cretaceous sediments in the Lower and Middle Benue Trough, Nigeria: Insights from new source rock facies evaluation

The Nigerian Benue Trough is an intracratonic rift structure which evolution is related to the Early Cretaceous opening of the South Atlantic Ocean and the Gulf of Guinea. Previous hydrocarbon potential assessments of the successions in the trough revealed a number of organic rich intervals capable of yielding significant quantities of hydrocarbons in the Cretaceous sections. Stratigraphic continuity of these intervals suggests their potentials for hydrocarbons if thermally mature and both oil and gas can be generated.The present study have expanded on some previously reported source rock data of the Cretaceous formations in the Benue Trough by detailed mapping of the stratigraphic intervals with source rock potentials on the basis of their structural setting, lithologic characteristics, and depositional environments. Further characterization of the organic matter within the Cenomanian to Coniacian on one hand and the Campanian to Maastrichtian intervals were carried out to determine the geochemical character of the organic rich zones, their maturity and effectiveness to generate and expel hydrocarbons.In the Lower Benue Trough, mature facies of the Cenomanian to Turonian Eze–Aku Formation with a predominance of Types II and III kerogen, the Turonian to Coniacian Type III dominated Awgu Formation and the Type III dominated Lower Maastrichtian sub-bituminous coals of the Mamu Formation have proven potentials as oil and gas source rocks. In the Middle Benue Basin, the preserved mature intervals of the Awgu Formation shales and coals are good gas source rocks with some oil prone units in view of the predominating Type III kerogen. Targets for hydrocarbons generated by these source rock intervals should focus on the non-emergent Cretaceous reservoirs within the pre-Santonian successions whereas, the mature equivalents of the sub-bituminous coal facies would generate and charge both Upper Cretaceous reservoirs and possibly the sub-Niger Delta successions in the sub-surface.

BIOSTRATIGRAPHY AND DEPOSITIONAL ENVIRONMENT OF THE OIL SHALE DEPOSIT IN THE ABAKALIKI FOLD BELT, SOUTHEASTERN NIGERIA

The oil shale deposit in the Abakaliki anticlinorium has not been demarcated. The present study focused on the age, correlation and depositional environment of the oil shale using abundance, planktonic/benthonic ratio and species diversity of foraminiferal and ostracod assemblages. The result shows that three prominent peaks or biozones namely 1, 2 and 3 were recognized. The 1 biozone showed that Praeglobotrucana and Guembelitria are the dominant species and ranged from Albian to Mid-Cenomanian (96–108 my). The 2 biozone indicated that Hedbergella and Heterohelix are the dominant species, and ranged from Upper Cenomanian to Early Turonian (92–95 my). The 3 biozone showed that Heterohelicids are the dominant species and ranged from Middle Turonian to Coniacian (82–91 my). The 1, 2, and 3 biozones correspond to the deposition of Asu River Group (Abakaliki Shale), Eze-Aku Formation and Awgu Formation respectively. The 2 peak is bimodal and has the highest frequency and this supports the maximum transgression occurring at the Cenomanian-Turonian boundary event (ocean anoxic event). The oil shale is deposited in outer shelf to bathyal environment and ranged from Upper Cenomanian to Early Turonian age and belongs to the Eze-Aku Formation.

Hydrocarbon prospectivity of Nigeria's inland basins: From the viewpoint of organic geochemistry and organic petrology

Hydrocarbon prospectivity of Nigeria's inland basins: From the viewpoint of organic geochemistry and organic petrology

Maceral associations, organic maturation and coal-derived hydrocarbon potential in the Cretaceous Awgu Formation, Middle Benue Trough, Nigeria

About 6,000m of alternating marine, paralic, and continental sediments of Cretaceous — Tertiary ages have been deposited in the Benue Trough. Conspicuous amongst these are the coal beds and coal-bearing strata, of which those of the Awgu Formation in the Middle Benue Trough have attained a rank of high to medium volatile bituminous coal stage. Maceral analysis on samples from the coal seams and some organic matter-rich interseam sediments obtained from four boreholes and two outcrop sections allows distinction of three petrographic facies which are related to the maceral associations, namely the vitrinite-fusinite coal facies, the trimaceritic coal facies and the shaly coal facies Vitrinite reflectance values measured on these samples generally increase with depth from 0.76 – 1.25%. At these values, usually large amounts of volatile matter are yielded in the form of methane, carbon dioxide and water as the primary products of progressive maturation and devolatifisation of humic organic matter.

POTENTIAL FOR COAL‐DERIVED GASEOUS HYDROCARBONS IN THE MIDDLE BENUE TROUGH OF NIGERIA

About 6,000m of alternating marine, paralic, and continental sediments of Cretaceous to Tertiary ages are present in the Benue Trough. Conspicuous amongst these are coal‐bearing strata, of which those in the Middle Benue Trough have attained a high‐ to medium‐volatile bituminous rank.Coal beds are now known to be major sources of associated and non‐associated gases, and increasingly are becoming exploration targets in many parts of the World. In the Middle Benue Trough, the Turonian Awgu Formation, about 400‐m thick, is the main coal‐bearing unit.Maceral analysis of samples from coal seams and from organic matter‐rich interseam sediments obtained from four boreholes and two outcrop sections allowed three petrographic facies to be identified, namely:Vitrinite reflectance values measured on these samples generally increase with depth from 0.74 ‐ 1.25Rm%. At these values, large amounts of volatile matter are yielded in the form of methane, carbon dioxide and water during progressive devolatization of humic organic matter.Organic matter in the underlying dark‐black, carbonaceous marine shales of the Cenomanian Ezeaku and Albian Arufu/Uomba/Gboko Formations may also be at the rank of medium‐volatile bituminous coal, and probably reaches the low‐volatile bituminous stage. These would correspond with the interval of maximum gas generation and the generation of methane, accompanied by strong aromatisation and ring condensation. A vitrinite‐fusinite coal facies, which is vitrinite‐dominated with minor amounts of liptinite and variable amounts of inertinite; the content of mineral matter is low. A trimaceritic coal facies, which is vitrinite‐dominated with moderate amounts of liptinite and inertinite; the content of mineral matter is low. A shaley coal facies, which is dominated by mineral matter, with variable amounts of vitrinite, liptinite and inertinite.

Petrographic composition and depositional environments of Cretaceous coals and coal measures in the Middle Benue Trough of Nigeria

Cretaceous coals and coal measure sequences in the area around the Obi/Lafia part of the Middle Benue Trough of Nigeria were studied petrographically. The Turonian-Santonian Awgu Formation and the Maastrichtian Lafia Formation constitute the sedimentary successions in both outcrop and borehole profiles of this area. Maceral analyses of 32 coal samples from this area allow subdivision of the coal beds into three different coal facies: the vitrinite-fusinite coal facies, the trimaceritic coal facies and the shaly coal facies. In the vitrinite-fusinite coal facies, vitrinite constitutes, on average 67.3%, liptinite 4.2%, inertinite 17.1% and mineral matter 11.4%. The trimaceritic coal facies has 42.3% vitrinite, 22.4% liptinite, 23.8% inertinite and 11.5% mineral matter. In the shaly coal facies, vitrinite constitutes 29.9%. Liptinite, inertinite and mineral matter are 13.8%, 22.0% and 34.3%, respectively. Correlation of the distribution of microfossils in the interseam sediments with the tissue preservation, gelification, groundwater and vegetation indices of the coal facies indicates that the vitrinite-fusinite coal facies was deposited in wet forest swamp subenvironments along and within lagoons. The trimaceritic facies was deposited in limno-telmatic clastic marsh subenvironments in lower delta plains. The shaly coal facies shows characteristics of various subenvironments but generally tends to be more marine than the other two facies.

Gravity and vertical magnetic gradient investigations of a localised area of the Benue Trough, Nigeria

Gravity and vertical magnetic gradient studies were carried out in Lokpanta-Lekwesi area in the Lower Benue Trough to investigate the local structures which might be associated with the Lead-Zinc mineralisation as evident in the adjacent area (Ishiagu Pb-Zn mineralisation). For this reason 134 gravity and vertical magnetic gradient readings were taken at intervals of 250 m along major roads and track routes that connect widely separated parts of the 25 km 2 area. The instruments used are the Canadian Scintrex CG-2 gravimeter (No. 318), the American Paulin altimeter and the Proton Precession Magnetometer. The geology of the areacomprises the Ezeaku Formation, and the Awgu Formation, their ages ranging from Middle to Upper Cretaceous. The study was used to delineate two igneous intrusions in the Ezeaku Formation. The intrusive bodies show high positive Bouguer anomalies which ranged from 0.5 mgal to 3.3 mgal in contrast to the negative Bouguer anomaly of the country rock that ranged from 0 to − 3.0 mgal. The vertical magnetic gradient method identified the two intrusive bodies as negative anomalies having vertical magnetic gradient values ranging from −5.0 to −25.0 gammas per meter in contrast to 5.0 to 10.0 gammas per meter values of the country rock. The Profiles were interpreted using computer assisted evaluation procedure of non-linear optimization and interactive techniques. Based on two dimensional model, the minimum depth computations to the upper surfaces of the anomalies A and B by gravity method are 60mm and 160 m respectively while the vertical magnetic gradient method gave a minimum depth estimates of the anomaly A as 75 m and that of B as 180 m.