The hydrocarbon potential of the Nigerian Chad Basin from wireline logs (original) (raw)
AAPG Bulletin, 2004
On a basinal evaluation level, incorporating source rock data from the other formations in the respective sectors, plots on the modified Van Krevelen diagram alongside biomarker and maceral data indicate good to fair source rock qualities (oil and gas) in the Anambra basin and middle Benue trough and fair to poor source rock qualities (gaseous to dry) in the upper Benue trough and the Chad basin, with sporadic good to fair source rock qualities in the Lamja Formation (coals) and shales of the Cenomanian-Coniacian Yolde, Dukul, and Pindiga Formations in that part of the Benue trough. Although TOC values and liptinite contents are relatively high in the Mid-Niger (Bida) basin, T max values and biomarker data show that hydrocarbons are probably just being generated in the basin and may not yet have been expelled nor migrated in large quantities. INTRODUCTION Nigeria's current national petroleum reserves asset (proven), put at 32 billion bbl of oil and about 170 trillion standard ft 3 of gas (Nexant, 2003), derives solely from the Niger Delta onshore and offshore. Some exploration campaigns have been undertaken in the inland basins with the aim of expanding the national exploration and production base and thereby add to the proven reserves asset. The inland basins of Nigeria comprise the Anambra basin, the lower, middle, and upper Benue trough, the southeastern sector of the Chad basin, the Mid-Niger (Bida) basin, and the Sokoto basin (Figure 1a). However, these inland basins have continued to frustrate the efforts of many explorers, principally because of the poor knowledge of their geology and the far distance from existing infrastructure (discovery must be large enough to warrant production investments), and for these reasons, many international companies have turned their focus away from frontier onshore to frontier deepwater and ultradeep-water offshore. The inland basins of Nigeria constitute one set of a series of Cretaceous and later rift basins in central and west Africa whose origin is related to the opening of the South Atlantic (Figure 1b). Commercial hydrocarbon accumulations have recently been discovered in Chad and Sudan in this rift trend. In southwest Chad, exploitation of the Doba discovery (with an estimated reserve of about 1 billion bbl of oil) has caused the construction of a 1070-km (665-mi)-long pipeline through Cameroon to the Atlantic Coast. In the Sudan, some giant fields (Unity 1 and 2, Kaikang, Heglig, etc.) have been discovered in the Muglad basin (Mohamed et al., 1999). The major source rocks and reservoirs are in the Aptian-Albian-Cenomanian continental deposits of the Abu Gabra and Bentiu formations, respectively, which are similar and correlatable to the well-developed Bima Sandstone in the Nigerian upper Benue trough. In the Republic of Niger, oil and gas shows have also been encountered in Mesozoic-Cenozoic sequences in the east Niger graben, which is structurally related to the Benue, Chad, Sudan, and Libyan rift complexes (Zanguina et al., 1998).
Geochemical evaluation of the hydrocarbon prospects of sedimentary basins in Northern Nigeria
Sedimentary basins of Northern Nigeria comprise the Middle and Upper Benue Trough, the southeastern sector of the Chad Basin, the Mid-Niger (Bida) Basin, and the Sokoto Basin. Organic geochemical and organic petrologic studies indicate the existence of potential source rocks in the Benue Trough and the Chad Basin, with coal beds constituting major potential source rocks in the whole of the Benue Trough. The generation and production of liquid and gaseous hydrocarbons from coal beds presently is world-wide indisputable.
2022
Hydrocarbon prospect, analysis and characterization are entailed in the processes used in identifying and delineating features/structures in the subsurface that are likely to be potential hydrocarbon reservoirs. The research was done by analyzing and interpreting well logs in combination with seismic data as obtained from Kolo Creek. Well logs were used in identifying lithologies present. Sand and shale layers were identified using the gamma ray log, potential hydrocarbon zones were interpreted using the resistivity log. These identified zones where taken into consideration for Petrophysical evaluation in which parameters such as porosity, permeability, water and hydrocarbon saturation were obtained as details in the four wells. The lithologies were correlated across the four wells to define the continuity of the identified pay zones. Seismic-to-well tie was done using checkshot data obtainable in only Well-2. There were three payzones identified, with gas, oil, and water as the fluid types. Porosity values ranges from 20% to 34%, water saturation obtained were within the range of 24% and 40%, and hydrocarbon saturation (defined as whole minus water saturation) ranged from 60% to 76%. These values showed that the hydrocarbon were present in commercial quantity hence production can take place. Three horizons were picked, six faults labelled A-F, four synthetic and two antithetic were identified across the seismic sections. The horizons were studied in detail, for time, depth and attribute studies. Time structural map was generated and it showed anticlinal structure present at its center. Depth map generated also depicted information as revealed by the time map thus validating the presence of hydrocarbon. An extracted attribute map indicated areas of high amplitudes and bright spots area being indicative of hydrocarbon accumulation present. The volumetric results showed that Reservoir A had OOIP of 467 x 106 STB and STOOIP of 389 x 106 STB.
MODELING HYDROCARBON GENERATION IN ANAMBRA BASIN, SOUTHEASTERN NIGERIA: IMPLICATIONS ON HYDROCARBON
Volume 3 of 2, July , 2022
The Anambra Basin contains oil and gas producing reservoirs in the southeastern part of Nigeria. Two-dimensional (2-D) modeling, using data from three (3) exploration wells has been carried out to assess the maturity, timing, and distribution of hydrocarbon generation in the Anambra Basin. This current study focuses on two sources in Anambra Basin namely; Coniacian Agwu and Nkporo source rocks. The results of models generated indicate that the onset of hydrocarbon generation from Awgu source rock started in the area of deepest subsidence during the late Campanian (77.30Ma). Awgu source rock in the model has a present-day transformation ratio of about 60-65%. This range indicates that the Awgu source rock has sufficient generation for hydrocarbon expulsion to occur. Nkporo source rock was equally observed to have capacity for hydrocarbon generation, but the generation was insufficient for expulsion because it has lower transformation ratio (<10%). Migrated hydrocarbon from the Coniacian Awgu source rock must have accumulated as oil and gas pools within the Coniacian Agbani and upper Campanian Owelli Sandstone. The discovery of gas in the Coniacian Agbani sandstone of Amansiodo-1, Akukwa-2, and Nzam-1 wells indicates the existence of petroleum traps in Cretaceous beds of the Anambra Basin. Keywords: Two dimensional modelling, Hydrocarbon generation and expulsion, Anambra basin, Transformation ratio, Awgu and Nkporo shales
IOSR Journals , 2019
Rocks inthe southern part of the offshore Tano Basin Ghanaare made up of the Apollonian series, with reservoirs structurally controlled in some places. Past studies in the basin gave an indication of oil and gas of considerable economic importance. The main objective of this study was to evaluate the petroleum potential of the South Tano field by finding new reservoir zones which have not yet been established due to inappropriate data analysis. This was done by processing old data from this area using the Petrel 2013 software. A combination of results using petrophysical, volumetric, seismic interpretation, and modelling, showed that the central part of the study area reveals a four-way dip closure anticline in the Intra Upper Albian Formation (IUAF), and is bounded by three distinct normal faults. Oil-water and gas-oil contactswere identified in sands of the IUAF at depths of 19234m and 1828m respectively. Volumes calculated in the reservoir sands gave a STOOIIP of 1247x10 6 million barrels(bbl) and GIIP of 41x10 6 standard cubic meter (sm 3) respectively.Previous work done in the South Tano field gave indication of oil and gas shows ofconsiderable economic relevance.
An evaluation of the hydrocarbon potentials of the gboko formation, middle benue trough, nigeria
Global Journal of Geological Sciences
A total of seventeen (17) rock samples from the Albian Gboko Formation were collected from the quarry of Benue Cement Company for organic geochemical analysis, in order to evaluate its hydrocarbon potential . Total Organic Carbon (TOC) values for the samples ranges from 0.11-0.5wt%. The rock-eval data recorded S2, hydrogen index (HI), Oxygen index (OI), Tmax, and production index (PI) of 0.04-0.11, 25-54, 50-400, 310-4610C, and 0.4-0.6, respectively. These implies that the samples has a fair to poor source rock quality with a type IV kerogen. Optical methods (R0, TAI & VKF) conducted on three selected samples of shales reveal vitrinite reflectance (R0) of 0.77%, 1.11% and 1.54%, while thermal alteration index (TAI) recorded 2.7, 3.3 and 3.7. Kerogen fluorescence indicated weak to non fluorescence. These results infer that the sediments had evolved from oil to gas window due to severe thermal effects . This indicates their potential to generate hydrocarbon gas
HYDROCARBON RESERVOIR CHARACTERIZATION USING WELL LOG IN NIGER DELTA BASIN OF NIGERIA
A study for the characterization of hydrocarbon reservoirs using well logs have been carried out in the Niger Delta in order to evaluate the field’s hydrocarbon prospectivity, delineate hydrocarbon and water bearing zones and petrophysical properties of the hydrocarbon reservoirs of interest. Data from four composite well logs comprising of gamma ray, resistivity, neutron, density logs were used for the study. Gamma ray log was used for lithology differentiation, Resistivity log was used to identify form the response of resistivities of various zones. High resistivity signifies hydrocarbon bearing zone while low resistivity value indicates shaley zones. The combined density and neutron logs was used for the identification and differentiation of the various fluids in the sections. The results from the study showed that nine out of the twenty-two zones of interest (sand bodies) was delineated and correlated across for possible identification of hydrocarbon, and were identified as potential hydrocarbon reservoirs. Also the result indicates that there is an increase in porosity with an increase in permeability. The evaluated petrophysical parameter indicated that porosity ranges between (18-31%), water saturation (14-44%), hydrocarbon saturation (56-86%), permeability (138-10662)
Potential Petroleum Source Rocks in the Termit Basin, Niger
Journal of Petroleum Geology, 2012
Potential source rocks from wells in the Termit Basin, eastern Republic of Niger, have been analysed using standard organic geochemical techniques. Samples included organic-rich shales of Oligocene, Eocene, Paleocene, Maastrichtian, Campanian and Santonian ages. TOC contents of up to 20.26%, Rock Eval S 2 values of up to 55.35 mg HC/g rock and HI values of up to 562 mg HC/g TOC suggest that most of the samples analysed have significant oil-generating potential. Kerogen is predominantly Types II, III and II-III. Biomarker distributions were determined for selected samples. Gas chromatograms are characterized by a predominance of C 17-C 21 and C 27-C 29 n-alkanes. Hopane distributions are characterized by 22S/(22S+22R) ratios for C 32 homohopanes ranging from 0.31 to 0.59. Gammacerane was present in Maastrichtian-Campanian and Santonian samples. Sterane distributions are dominated by C 29 steranes which are higher than C 27 and C 28 homologues. Biomarker characteristics were combined with other geochemical parameters to interpret the oil-generating potential of the samples, their probable depositional environments and their thermal maturity. Results indicate that the samples were in general deposited in marine to lacustrine environments and contain varying amounts of higher plant or bacterial organic matter. Thermal maturity varies from immature to the main oil generation phase. The results of this study will contribute to an improved understanding of the origin of the hydrocarbons which have been discovered in Niger, Chad and other rift basins in the Central African Rift System.
Hydrocarbon resource potential of the Bornu basin northeastern Nigerian
Global Journal of Geological Sciences, 2012
The separation of Africa from South America was accompanied by rifting and sinistral strike-slip movements that formed the Bornu Basin. The Bornu Basin form part of the West African Rift System. Geochemical analyse of samples from the Fika Shale shows that eighty percent of the samples have TOC values >0.5 wt%. Plots on the modified Van Krevelen diagram indicate organic matter that is predominantly Type III kerogen. A corresponding plot on the HIT max diagram indicates an entirely gas generative potential for the source rocks. In the Bornu Basin which belongs to the West African Rift Subsystem (WARS) two potential petroleum systems are suggested. "Lower Cretaceous Petroleum System"-is the phase 1 synrift sediments made up of sandstones with an extensive system of lacustrine deposits developed during Barremian to Albian time. "Upper Cretaceous Petroleum System"-is the phase II rift sediments in the Bornu Basin which comprise mainly shallow marine to paralic shales, deltaic to tidal flat sandstones and minor carbonates. TOC values range generally from 0.23 wt. % to 1.13 wt. % with an average of 0.74 wt. % for the Fika Shale.
Hydrocarbon Potential of Two Coastal Basins (Cameroon)
International Journal of Geosciences
The problem related to the occurrence of oil accumulations in a sedimentary basin requires knowledge of the different geological structures present in this basin. The aim of this article is to show that the geological structure of sedimentary basins has an impact on the generation of oil accumulations. The case of Cameroon's coastal basins has been studied: the Douala/Kribi-Campo basin (DKC) and the Rio Del Rey basin (RDR), which are producing basins in Cameroon. The work carried out has enabled to classify the DKC and RDR basins as passive margin basins. The lithology and geological structures present in the Douala/Kribi-Campo basin suggest the existence of source rocks (RM-1, RM-2, RM-3, RM-4 and RM-5), seal rocks (Mundeck clay, Logbabaclay...), stratigraphic, structural and mixed traps; the best oil potential is identified in its eastern part. On the other hand, the sandy levels are abundant, clean, and thick with a great porosity, which makes them excellent hydrocarbon reservoirs. In the Rio Del Rey basin, the lithology and geological structures present suggest the occurrence of source rocks (Akata clay and Agbada base clay), seal rocks (Akata clay) and multilayered reservoir rocks sandy or silty Agbada Formation and the freshwater sands of the Benin Formation. Unlike the Douala/Kribi-Campo basin, the best oil potential in the Rio Del Rey Basin lies in the center, in the so-called "deltaic alternation" formations dated from the late Miocene to the Pliocene.
Petroleum Geochemistry Of Kuchalli -1 In The Nigerian Sector Of The Chad Basin
2007
Kuchalli -1 well, one of the twenty-three exploratory oil wells drilled in the Nigerian sector of the Chad Basin penetrated a Cretaceous succession comprising the Bima, Gongila, Fika and Chad formations. Organic geochemical analyses were carried out to assess the source-rock potential of forty (40) selected ditch cuttings. Total Organic Carbon (TOC) content was found to vary between 0.5 – 2.0wt % (moderate to good) at a depth of 1700m and 2300m. Hydrogen Index (HI) values correlated against TOC and T<sub>max </sub>values indicate gas generative potential. Results of the investigation show that the Chad Basin has hydrocarbon source rock potential at the indicated interval. TOC of > 0.5wt% was recorded in both the Gongila and Fika shales. The Bima Sandstone and the Gombe Sandstone could serve as potential reservoir rocks. An integrated exploration programme is recommended for use in the Chad Basin to enable a better understanding of the petroleum systems of the basin.
Hydrocarbon Formation Evaluation Using Well Log Data Of Well Tmg-02, Opolo Field, Niger Delta
Global Journal of Pure and Applied Sciences
Well TMG-02 with the depth interval of 5058.77 to 9389.43ft of Opolo field located in the Niger delta was assessed for hydrocarbon using suite of geophysical well logs. Suite includes gamma ray (GR), formation density (RHOB), neutron porosity (NPHI), and resistivity logs. The analysis was carried out to estimate the field’s hydrocarbon prospect by identifying hydrocarbon bearing reservoirs and their properties. The quantitative and qualitative results, identified thicker units of sand than shale lithology, three reservoirs A, B, C within the depth ranges from 5058.77ft to 9389.43ft, capable of accumulating hydrocarbon based on the petrophysical parameters calculated were delineated. The effective porosity for each of the reservoir are: 27%, 24% and 19% respectively. It was observed that reservoir A, B had excellent permeability while reservoir C was low as a result of thicker shale sequence within the reservoir. The result obtained shows presence of hydrocarbon bearing gas water con...
2020
The LECO and Rock–Eval pyrolysis for 7 shale and 3 coal samples, as well as, multivariate statistical analysis have been used to probe source rock characteristics, correlation between the assessed parameters (S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Sokoto Basin and Anambra Basin of northwestern and southeastern Nigeria respectively. The geochemical results show that 93% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approach...
Journal of Petroleum Exploration and Production Technology, 2015
The source kitchen of a petroleum system is that part of the pod of active source rock which is mature and generates the petroleum that charges the reservoir rock. The location of the source kitchen of a petroleum system is vital to the explorationist, its knowledge fosters the prediction of migratory pathways and the migratory losses prior to present times, also estimates potential volume of accumulation. Hither to, mapping of the petroleum basins was based on total organic carbon (TOC), hydrogen index (HI) signatures and maturity history of the source rock and has been used as the basis to suggest locations of petroleum kitchens. In contemporary times, 4D seismic or 3D time lapse geochemistry had been used to suggest location of source kitchen. However, settled is the concept of lateral maturity gradients, implying that within reservoir scales of a kilometer to tens of kilometers, regional petroleum emplacement direction could be deduced from subtle changes in maturity of successive charges of petroleum into the reservoir. In this study, the sterane isomerization ratio (20S/20S ? 20R aaaC 29 ) was used to determine the maturities of the hydrocarbons from various wells in the Kolo Creek and the Nembe Creek reservoirs. Subtle increases in maturities were observed to be in a NE-SW direction for the Kolo Creek reservoir and in a NW-SE direction for the Nembe Creek reservoir. The direction of increasing maturities relative to the location of the reservoirs could be extrapolated for both reservoirs towards offshore Gulf of Guinea; this is invariably the direction of location of the source kitchen for the Niger Delta oils.
International Journal Geology and Mining, 2018
An integrated study involving detailed lithofacies analysis and source rock evaluation were carried out to reconstruct the paleoenvironment and assess the petroleum potentials of the Ikom-Mamfe embayment, southeastern Nigeria. Sedimentological field mapping involving detailed description of lithologic characteristics and facies characterisation was carried out. Geochemical studies were carried out to determine the quantity of organic matter total organic carbon (TOC), soluble organic matter (SOM), the organic matter quality (organic matter type) and level of maturity. Results show that the dominant vertical succession of the various lithofacies indicate a general finning upward succession with basal massive pebbly sandstone, medium to coarse grained sandstones with intercalation of shale and mudstones. Seven lithofacies A to G, were identified. These include: conglomerates, massive pebbly sandstone, trough cross-bedded sandstone, planar cross-bedded sandstone, shale/mudstone facies. These facies were compared with established standard facies association for determining paleoenvironment of deposition. The facies analysis carried out pointed to fluvial (alluvial-braided) depositional system as the environment of deposition. TOC values range from 0.05-4.13 wt% indicating poor to excellent and SOM range from 200-6000 ppm indicating also poor to excellent. The amount of pyrolizable carbon derived as S1 and S2 peaks suggested that the source rocks possess organic matter capable of generating hydrocarbons. Hydrogen and oxygen indices (HI and OI) ranged from 0.24 to 656 and 0.53 to 61.90 mg/gTOC respectively. Analyses of the evaluated source rock shows that the hydrocarbon potential of the study area is lean and typically of a reworked terrestrial deposit of fluvial depositional system.
The Principal Source Rocks For Petroleum Generation In The Dahomey Basin, Southwestern Nigeria
2010
The Upper Cretaceous (Maastrichtian) Araromi Shale formation in the Nigeria sector of the Dahomey basin has been investigated for its petroleum generation potential. From three exploratory wells, Araromi, Bode Ashe and Gbekebo in the eastern end (west of Niger Delta), source rock potential has been evaluated for over one hundred (100) drill core and ditch cutting samples. The investigated shallow marine shale facies have Total Organic Carbon (TOC) value range of 0.50-4.78wt% and Hydrogen Index (HI) value range of 1-327mgHC/gTOC with the maceral composition of liptinite (av. 26.0%) and abundance of vitrinite (av. 38.1%) plus inertinite (av. 35.9%) in all the samples investigated. Vitrinite reflectance values vary from 0.51-0.68%R<sub>o</sub>. The T<sub>max</sub> values vary from 398<sup>o</sup>C-437<sup>o</sup>C and the kerogen Types include type II, II/III, III, and IV in all the samples. The Source Potential (SP) values range from 0.0...
Aspects of Hydrocarbon Potential of the Tertiary Imo Shale Formation in Anambra Basin, Southeastern Nigeria. , 2017
The Tertiary Imo Shale Formation, a lithofacies equivalent of marine Akata Formation (prolific source rock) in subsurface Niger Delta, requires proper evaluation of its hydrocarbon generative potentials to complement organic geochemical data in Anambra Basin. This study attempts to evaluate aspects of the source rock potential for hydrocarbon generation of the Imo Shale Formation penetrated by the Akukwa-II and Nzam-I wells in Anambra basin. The sediments encountered at depth range of 120 to 240 m and 550 to 650 m in Akukwa-II and Nzam-1 wells respectively, are made up of shales, sandy shale and mudstones. The shales are fine grained, fissile and light to dark grey in colour, the sandy shale is medium grained and grey in colour while the mudstones are fine grained and brownish grey in colour. The Total Organic Carbon (TOC) values of the samples range from 0.39 to 0.94 wt. % (av. 0.60 wt. %) in Akukwa-II well and 0.39 to 2.07 wt. % (av. 0.70 wt. %) in Nzam-I well indicating that the sediments contain appreciable quantity of organic matter that can generate hydrocarbon. Hydrogen Index, Oxygen Index and Tmax of the samples range from 11.0 to 28.0 mg HC/g TOC, 53.0 mg/g to128 mg/g and 409 to 430 o C respectively in Akukwa-II well and 14.0 to 48.0 mg HC/g TOC, 45.0 to 294.0 mg HC/g TOC and 421 to 497 o C respectively in Nzam-I well. Genetic Potential (GP), Production Index (PI) and Calculated vitrinite reflectance (% Ro) in Akukwa-II and Nzam-I wells are 0.10 to 0.34 mg/g, 0.22 to 0.50, 0.202 to 0.580 and 0.08 to 0.73 mg/g, 0.04 to 0.32, 0.418 to 1.786 respectively. Rock-eval data suggest that the sediments are poor to fair source rock for gaseous hydrocarbon and the organic matter is predominantly type IV kerogen sourced from terrestrial materials which does not yield significant amounts of hydrocarbon. Thermal maturity derived from Rock-eval data revealed that the Imo Formation samples are immature with respect to hydrocarbon generation. The sediments may generate very little dry gas at appropriate maturity due to inert nature of type IV kerogen.
A Short Note on the Petroleum Potential of the Sokoto Basin in North-western Nigeria
Petroleum Science and Engineering, 2020
The stratigraphy of the Sokoto Basin has the Illo/Gundumi Formation at the bottom, followed successively upward by the Taloka, Dukamaje, Wurno, Dange, Kalambaina, Gamba and GwanduFormations. Re-mapping of the basin carried out in this studyshows that the geological framework remainslargely as previously outlined except that some hitherto unreported tectonically controlled structures have been documented. The basin is generally shallower at the margin and deepens towards the centre such that the areas around the border with Niger Republic are deepest and hence most prospective on the Nigerian side. Geophysical aeromagnetic interpretation has assistedto analyze the depth to basement configurations. Organic geochemical studies show that the dark shales and limestones of the Dukamaje Formation constitute the source rocks in the potential petroleum system. With averages for source rock thickness of 50m, area of basin of 60,000km 2 , TOC of 7.5wt%, and HI of 212mgHC/gTOC, charge modeling indicates 808.10 million barrels of oil equivalent extractable hydrocarbons in the Sokoto Basin, at current knowledge of the geology and if the appropriate maturity has been attained at deeper sections. The sandstones of the Illo/Gundumi Formation as well as in the Taloka and Wurno Formations and carbonates of the Kalambaina Formation provide potential reservoir packages. The paper shale of the Gamba Formation and the clays of the Gwandu Formation provide regional seals. If the presently mapped tectonic structures are ubiquitous in the whole basin, structural and stratigraphic traps may upgrade the petroleum system. Other petroleum systems may exist in the basin with either or both the Illo/Gundumi and Taloka Formation (s) providing the source and reservoir rocks.