Source rock characteristics, burial history reconstruction and thermal maturity modelling of Late Cretaceous sequences in the Chad (Bornu) Basin, NE Nigeria.

Adebanji Kayode Adegoke1*, Wan Hasiah Abdullah1

1. Department of Geology, University of Malaya, 50603, Kuala Lumpur, Malaysia

Introduction

Chad (Bornu) Basin, one of Nigeria’s frontier inland sedimentary basins has recently been subject of interest where exploration activitiesare currently being undertaken. These inland basins constitute parts of a series of rift basins in central and west Africa whose origin is linked to the separation of the African crustal blocks in the Cretaceous as part of the West and Central African Rift System (Genik, 1993). Apart from the Chad (Bornu) Basin in Nigeria, commercial hydrocarbon deposits have been discovered in the other parts of the rift trend in neighbouring countries of Chad, Niger and Sudan, which are genetically related and have the same structural settings (Obaje et al., 2004).The poor knowledge of the evolution of the subsurface rocks in the Chad (Bornu) Basin, especially with respect to their characteristics and their thermal/burial histories may have been responsible for the unsuccessful exploration attempts within the basin.Although, few studies have been undertaken on the basin’s source rock potential and organic matter (OM) maturity (Obaje et al., 2004), detailed organic geochemical investigations on the origin of organic matter, and their thermal/burial histories, and the timing of hydrocarbon generation and expulsion are lacking.

Basin modelling is a very useful discipline to reveal thetiming, and to understand and quantify the complex processes of petroleum formation (Waples, 1994). The incorporation of source rock characteristics into basin modelling can give more detailed information needed to answer exploration questions on hydrocarbon generation and expulsion of the source rocks. This current study focuses on the detailed geochemistry of the Upper Cretaceous sediments in Chad (Bornu) Basin, to provide an overview of the organic richness, hydrocarbon generation potential and level of maturity of the organic matter in the sediments. In addition, the results of source rock characteristics were incorporated into basin modelling in order to know and determine the timing of hydrocarbon generation and expulsion of the source rocks. This is aimed at providing further insight into the source rocks of the basin, for the current and future petroleum exploration programme and resource assessment in the basin.

Samples and methods

Organic geochemical analyses were carried out on a total of 115 cutting samples from five exploration wells (Kanadi-1, Kemar-1, Kinasar-1, Kuchalli-1 and Tuma-1 Wells) drilled by the Nigerian National Petroleum Corporation in the Chad (Bornu) Basin. The samples were collected from Gongila and Fika formations, which have been generally regarded as potential source rocks in the basin.

Geochemical analyses

The Geochemical methods used to evaluate the source rock potential of the sediments included the determination of total organic carbon (TOC) content, pyrolysis and open pyrolysis-gas chromatography (Py-GC). Whole rock samples were crushed and analysed using Weatherford Source Rock Analyzer-TPH/TOC (SRA) instrument. Parameters measured include total organic carbon (TOC), free hydrocarbons (S1) in the rock, remaining hydrocarbon generative potential, mg HC/g rock (S2), CO2 expelled from pyrolysis of kerogen(S3) and temperature of maximum pyrolysis yield (Tmax). Hydrogen (HI), oxygen (OI), production yield (PY), and production (PI) indexes were calculated. Following pyrolysis, some samples were selected for further geochemical analyses and microscopic examinations. Open system pyrolysis-gas chromatography (Py-GC) was applied to provide compositional and structural characteristics of kerogen. This analysis was performed on isolated kerogen samples using a Double-Shot Pyrolyzer PY-2020iD from Frontier Laboratories Ltd. An HP-Ultra1, 50 m x 32 mm i.d., dimethylpoly-siloxane-coated column (0.52 lm film thickness) was fitted into an Agilent GC chromatograph equipped with a pyrolysis unit and flame ionization detector. Pyrolysis products were released over the range 300–600 °C (25 °C/min) and collected in a nitrogen-cooled trap. Identification of peaks based on reference chromatograms was done manually with Agilent ChemStation software. Samples for petrographic examinations were made using standard organic petrographic preparation techniques. Polished sections of cutting samples were analysed. Petrographic examinations were carried out under oil immersion in a plane polarized reflected light, using a LEICA DM 6000M microscope and LEICA CTR6000 photometry system equipped with fluorescence illuminators. Mean vitrinite reflectance (Ro %) was measured and conducted on particles of vitrinite maceral that are not associated with strong bitumen staining using a microscope with white light source, photometer, and oil immersion objectives.

1-D basin models

In this study, quantitative one-dimensional (1-D) basin modeling was performed to evaluate the burial/thermal histories and timing of hydrocarbon generation and expulsion of the Late Cretaceous sequences in the Chad (Bornu) Basin. The reconstruction of the burial, thermal and maturity histories was modelled using PetroMod 1-D (version 10.0 SP1) software developed by IES, Aachen, Germany. Major 1-D model input parameters comprise events or formations within the chronostratigraphy, deposition age, present and eroded thicknesses of formations and events, volumetric lithological mixes, kerogen types and kinetics and further geochemical parameters such as initial %TOC. The modelling results were also calibrated with measured vitrinite reflectance and borehole temperatures (BHT) of the five wells in the study area.

Results and discussion

Over 90% of the analysed samples have TOC > 0.5 wt.%, which is the required threshold for hydrocarbon generation (Peters and Cassa, 1994). The analysed shale samples also have S2 pyrolysis yield and HIvalues in the range of 0.06–1.96 mg HC/g rock and 18–185 mg HC/g TOC, respectively. These values reveal that most of the analysed samples meet the accepted standards of a source with fair to good hydrocarbon generative potential.Characterisation of organic matter type conducted based on whole rock samples using pyrolysis data such as HI, OI, and Tmax values indicates that the organic matter in the shale samples is predominantly Type III kerogen with mixture of Type II-III kerogen. All of the shale samples have hydrogen indices that can be expected for mainly gas- and oil- prone source rocks.

The Py-GC pyrograms of the isolated kerogen from shales samples are generally dominated by a homologous series of n-alkene/alkane doublets, reaching a maximum chain length of > 30 carbon atoms. The Py-GC pyrograms also display prominent n-alkane/n-alkene doublets in the low molecular weight end (<n-C10) and high molecular weight end (>n-C15) with some abundant light aromatic compounds such as benzene, toluene, ethylbenzene, xylenes, alicyclic compounds such as naphthalenes, and sulphur compounds, mainly thiophenes (Fig. 1). These are indicative of relatively aliphatic- rich with significant aromatic compounds and suggest a mixture of oil and gas generation.Eglinton et al. (1990) introduced a ternary diagram based on pyrolysate 2,3-dimethylthiophene, o-xylene and C9:1 (alkane component), which represents the organic sulfur, aromatic and aliphatic structures within the macromolecular organic matter. Furthermore, the selected compounds can be directly related to different kerogen types (I, II, III and II-S). Following this classification, most of the organic matter in the analysed samples comprises of Type II to Type III paraffinic kerogen (Fig. 2).Horsfield (1989) has also shown that the distribution of n-alkyl chains within kerogen pyrolysates can be directly related to the petroleum type formed from the respective kerogen in nature. The majority of the analysed shale samples fall within the field of low wax paraffinic-naphthenic-aromatic (PNA) oils with a gradual transition into the high wax PNA and paraffinic oil field.

Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature (BHT) data reveals that the present-day heat flow in the Chad (Bornu) Basin varies from 55.0 mW/m2 to 60.0 mW/m2 and paleo-heat flow value at approximately 68 mW/m2. The maturity modelling of the wells indicates that the Gongila and Fika source rocks are presently at a stage of oil, condensates and gas generation with thermal maturity ranging from 0.70% to 1.39% Ro. The modelled burial history also suggests that maximum burial occurred in the late Miocene and that erosion might have been the cause of the thinning of the Tertiary sediments in the present time.

Left- Fig. 1: Representative Py-GC chromatogram of one of the analysed samples (KEM 755), a wax rich Type II kerogen (oil and gas-prone). Right-Fig. 2:Kerogen type classification of Pyrolysis-GC data according to Eglinton et al. (1990).

Conclusions

Organic geochemical and petrographic investigations indicate that the Upper Cretaceous sediments possess generally fair to occasionally good source generative potential. The sediments have attained sufficient burial depth and thermal maturity for significant hydrocarbon generation potential. The incorporation of source rock characteristics into basin modelling has given more detailed information needed to answer exploration questions on hydrocarbon generation and expulsion of the source rocks. This has provided further insight into the source rocks of the basin, for the current and future petroleum exploration programme and resource assessment in the basin.

Acknowledgements

This work was supported by the University of Malaya IPPP Research Grant No: PV016-2012A. The authors are also grateful to the Nigerian Geological Survey Agency (NGSA) and the Nigerian National Petroleum Corporation (NNPC), for supplying the samples and data for this research.

References

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