Geochemical and Organic Petrological Evaluation of Organic Matter from Tertiary Sediments of Baga Field in Chad Basin, Northeast Nigeria

: The Upper Cretaceous sediments in Bornu are considered an important regional source rock in the Chad Basin. This study therefore evaluated the geochemical and organic petrological evaluation of organic matter in tertiary sediments of Chad Basin, Northeast Nigeria by collecting 25 cutting samples from these organic-rich shale sediments from four wells drilled in Baga field in the Nigeria sector (Bornu) of the Chad Basin, in order to geochemically assess the type of organic matter, thermal maturity, and palaeoenvironmental conditions. Results reveal that Bornu sediments contain high organic matter more than 2.0 wt% TOC and have an excellent oil-generation potential. This is supported by high bitumen extractions and hydrocarbon yields with values 5827 and 3547 ppm, respectively. The investigated biomarkers indicated that the shale sediments contain a high abundance of C 27 regular sterane concentrations, high C 27 /C 29 regular sterane ratios and relatively low value of the biomarker sterane/hopane ratio as well as the presence of tricyclic terpanes. A mainly suboxic to relatively anoxic preservation conditions is inferred from Pr/Ph ratios (1.03–2.53). This is support by normal alkane distributions, which are characterized by dominance of types I/II kerogen and low medium molecular weight n-alkane compounds, respectively. This is further supported by lower amounts of acyclic isoprenoids compared to n-alkanes (e.g., pristane/n-C 17 and phytane/n-C 18 ratios). This is also supported by a mixture of algal and amorphous organic matter that was deposited in a lacustrine environment identified from kerogen microscopy. Based on the analyzed biomarkers, triterpanes and terpanes thermal maturity indicates that the Bornu sediments organic matters have entered into early mature stage for oil generation. This is also supported by vitrinite reflectance values of 0.57–0.71 % Ro indicate that these organic matters have reached oil window maturity.

Petroleum source rocks are the primary component of the petroleum system concept introduced by Magoon and Dow (1994).They constitute the precursors of petroleum which, under favourable conditions, may subsequently migrate to reservoirs and be sealed to form accumulation.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 (Obaje et al., 2004).Some exploration campaigns have been undertaken in sedimentary basins of Northern Nigeria with the aim to expanding the national exploration and production base and to thereby add to the proven reserves asset (Obaje et al., Geochemical and Organic Petrological Evaluation of Organic Matter….. 496 UZOEGBU, M. U; OGHONYON, R 2006).Sedimentary basins of Northern Nigeria comprise the Middle and Upper Benue Trough, the southeastern sector (Bornu) of the Chad Basin, the Mid-Niger (Bida) Basin, and the Sokoto Basin.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 deep-water and ultradeep-water offshore (Obaje et al., 2006).This study therefore evaluated the geochemical and organic petrological evaluation of organic matter in tertiary sediments of Baga field in Chad Basin, Northeast Nigeria

MATERIALS AND METHODS
The sedimentary basins of Northern Nigeria are one part 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 (Figs. 1&2).Commercial hydrocarbon accumulations have recently been discovered in Chad and Sudan within this rift trend.In SW Chad, exploitation of the Doba discovery (with an estimated reserve of about 1 billion barrels of oil) has caused the construction of a 1070 km-long pipeline through Cameroon to the Atlantic coast.In the Sudan, some "giant fields" (Unit 1 & 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 Niger Republic, 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-Libyan rift complexes (Zanguina et al., 1998).Within the sedimentary basins of Northern Nigeria, the Nigerian National Petroleum Corporation (NNPC) through its frontier exploration services arm (NAPIMS) has drilled some wells in the Nigerian sector of the Chad Basin and only gas shows were encountered.The first well in the Benue Trough region, Kolmani-River-1, drilled by Shell Nigeria Exploration and Production Company (SNEPCO) to a depth of about 3000 m in 1999 encountered some 33 billion standard cubic feet of gas and little oil (that has been the only well drilled by that company in that area to date).Two other wells, Kuzari-1 and Nasara-1, drilled by Elf Petroleum Nigeria Limited (Total Fina Elf) in 1999 to a depth of 1666 m and Chevron Nigeria Limited (ChevronTexaco) in 2000 to a depth of about 1600 m, respectively, were reportedly dry (Obaje et al., 2006).With this development, it has become necessary to adequately evaluate and characterize the petroleum source rocks in this basin by using well established geochemical techniques.At the core of any petroleum system is a good-quality source rock (total organic carbon (TOC) > 0.5%, hydrogen index (HI) > 150 mgHCg -1 TOC, liptinite content > 15%, Tmax ≥ 430 o C, and Ro 0.5-1.2%,biomarker validation).However, other petroleum system elements must also include, apart from established source rocks, reservoir and seal lithologies, establishable trapping mechanisms, and favourable regional migration pathways (Obaje et al., 2004).The aims of this study were to evaluate a shale sample from the basin using modern techniques of petroleum geochemistry in order to: (i) assess in detail the quality of its organic matter; (ii) evaluate its thermal evolution, and (iii) highlight its potential as a source.The results of this study may stimulate further interest in petroleum exploration and exploitation in the Chad basin.A total of 25 cutting samples from four wells in the Bornu (Baga) field, Nigeria sector (sub-basin) of the Chad Basin were analyzed (Table 1).The samples were collected from organic-rich shale and claystone intervals within the Bornu sediments (Fig. 2).Geochemical and some organic petrological analyses include determination of total organic matter (TOC) and sulfur (TS) contents, bitumen extraction, gas chromatographymass spectrometry (GC-MS), and vitrinite reflectance measurements.Elemental content was subsequently performed on approximately 100 mg pulverized whole sample using elemental analyzer instrument (Multi EA2000 model) to determine the TS and TOC contents 497 UZOEGBU, M. U; OGHONYON, R Bitumen extractions were performed on the powdered samples using a Soxhlet apparatus for 72 h using an azeotropic mixture of dichloromethane and methanol (CH3OH) (93:7v/v).The extracts were separated into saturated hydrocarbon, aromatic hydrocarbon, and NSO compounds by liquid column chromatography.
A chromatographic column (30×0.72 cm) was packed silica gel of 60-120 mesh that was activated for 2 h at 120 °C and capped with a few centimeters of alumina.
Only the saturated fractions were analyzed in this study.The saturated fractions were dissolved in petroleum ether and analyzed using GC-MS.The GC-MS analysis was performed on an Agilent 5975B inert MSD mass spectrometer with a gas chromatograph attached directly to the ion source (70 eV ionization voltage, 100 mA filament emissions current, 230 °C interface temperature).Samples for petrographic examinations were made using standard petrographic preparation techniques.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.The filter system consists of BP 340-380 excitation filters, a RKP 400 dichromatic mirror, and a LP425 suppression filter.Measurement of vitrinite reflectance was carried out using a microscope under reflected white light, with ×50 oil immersion objectives using immersion oil with a refractive index (ne) of 1.518 at 23 °C.A sapphire glass standard with 0.589 % reflectance value was used for calibration.Reflectance measurements were determined in the random mode (Rrand) on vitrinite maceral at a wavelength of 546 nm, and the values reported were arithmetic means of at least 25 measurements per sample.Kerogen typing analysis was carried out using the single scan method, where identification of kerogen was done using both normal reflected "white" light and ultraviolet (UV) light.
Regional Geologic Setting: The Benue Trough of Nigeria is a rift basin in central West Africa that extends NNE-SSW for about 800 km in length and 150 km in width.The trough contains up to 6000 m of Cretaceous-Tertiary sediments of which those predating the mid-Santonian have been compressionally deformed, faulted, and uplifted in several places.Its southern limit is the northern boundary of the Niger Delta, while to the north it is bordered by the Chad Basin.The Trough can be divided into Lower, Middle and Upper portions (Fig. 1).It contains up to 6000 m of Cretaceous -Tertiary sedimentary rocks, of which those pre-dating the mid-Santonian have been folded, faulted and uplifted.The Upper Benue Trough can be subdivided into the east-west trending Yola Basin (or "Arm") and the north-south trending Gongola Basin (Fig. 1).Guiraud (1990) and Dike (2002) identified a third basin, the NE -SW trending Lau Basin or Main Arm.Reviews on the geology of the Benue Trough, and particularly the Upper Benue Trough, have been presented by Petters, 1982;Petters and Ekweozor, 1982;Benkhelil, 1982;Dike, 1993Dike, , 2002;;Obaje, 1994;Zaborski et al., 1997;andZaborski, 2000, 2003.Delta (Obaje et al., 2006).
Geochemical and Organic Petrological Evaluation of Organic Matter….. Details on the evolution and stratigraphic framework of the Chad Basin have been given in Avbovbo et al. (1986) and Olugbemiro et al. (1997).Details on the stratigraphic successions in the Benue Trough and the Chad Basin and as they relate to the Anambra Basin and the Niger Delta are depicted on Fig. 3.

RESULTS AND DISCUSSION
Maceral Properties: Under incident light, microscopy indicates that the organic matter of the Bornu sediments in the Chad Basin is dominated by liptinitic material of which fluorescing amorphous organic matter (AOM), intimately associated with mineral matter, constitutes the major component (Fig. 3a-c).
The AOM appears well aggregated, light brown in color and irregular in shape under normal white light (Fig. 3a-c) and commonly shows yellow fluorescent under ultraviolet light excitation (Fig. 3b, c).Alginite with morphology similar to the extant Botryococcus alga is observed in all the samples (Fig. 3d-f).The kerogen composition implies a high proportion of type II kerogen (alginite) followed by smaller amounts of type I kerogen (AOM + liptinite).The common association of alginite with the fluorescing AOM indicates a potential for oil prone and was derived to a large extent from the degradation of algal material or other phytoplanktonic origin (Hakimi et al. 2012a(Hakimi et al. , 2013;;Makeen et al., 2013).In addition, the mean vitrinite reflectance (%Ro) for the studied Chad Basin samples that ranges between 0.57 and 0.71 % (Table 1) indicate that these sediments are thermally early mature to mature and have reached oil generation window.This thermal maturity rank is also supported by relatively low fluorescence of alginite and amorphous organic matter under UV light excitation (Fig. 3b-f).
Geochemical Evaluation: The ability of source rocks to generate hydrocarbons is determined by the kerogen's quantity of organic matter, expressed as total organic carbon (TOC) content.The TOC determination was carried out on 25 samples consisting of claystones and shales (Table 1).The analyzed Bornu sediments have high TOC values ranging from 1.20 to 7.20 wt%, ranking these samples as good to very good source rocks (Tissot and Welte, 1984). .In addition to the determine the organic richness and source rock potential from TOC content, the quantity of the extractable organic matter obtained from source rocks were examined to understand the gross composition.The concentrations of extractable organic matter (EOM) together with the relative proportions of saturated, aromatic fractions, and NSO compounds were calculated (Fig. 4).The saturated and aromatic fractions formed the crude-like (hydrocarbon) fraction; which the sum of these two fractions is known to be HCs.The EOM yields a range from 1638 to 5827 ppm (Table 1), and it is shown that the EOM contains a complex mixture of hydrocarbons and non-hydrocarbon components (NSO) as seen in Fig. 5.The saturated fractions and NSO components UZOEGBU, M. U; OGHONYON, R contain the major fractions in the analyzed samples (Table 1).The saturated fractions and NSO compounds are ranging from 22.64 to 64.57% and 20.69 to 73.70%, respectively, whereas aromatic fractions range from 13.77 to 38.88% (Table 1).Since the hydrocarbon portion of the bitumen extracted from sediment is the crude-like portion, it is used as an important parameter in the source-rock evaluation (Philippi, 1957;Baker, 1972).In this respect, most of the Bornu samples are likely the most prolific petroleum sources where abundant naphthenic oils might be expected to be generated (Fig. 6).This is suggested by high hydrocarbon fractions (42.70-81.59%) in Fig. 5 and relatively high saturated hydrocarbon proportions (22.64 -64.57%).The hydrocarbon generative potential of a source rock can also be estimated from plot of TOC content versus EOM (Fig. 7) and plot of hydrocarbon yields vs. TOC (Fig. 8).These plots shows that the analyzed Bornu samples have very good source rock potential for oilgeneration based on classification by Peters and Cassa (1994) as supported by high TOC content (>1.0 wt%).The n-alkane distributions display a full suite of saturated hydrocarbons between C12-C34 n -alkanes and isoprenoids pristane (Pr) and phytane (Ph) (Fig. 9) and shows a predominance of low to medium molecular weight compounds (n-C14-n-C23) with the presence of significant waxy alkanes (+n-C23) thus gave moderate CPI values (Table 2).These distributions are typical of lacustrine sediments receiving mixed algal with a minor amount of terrigenous organic matter input (e.g., Gülbay et al., 2012).Acyclic isoprenoids occur in a significant amount in all studied Bornu samples (Fig. 9), and diagnostic biomarker ratios are listed in Table 2. Pristane (Pr) and phytane (Ph) are usually the most important acyclic isoprenoids hydrocarbons in terms of concentration (Powell and McKirdy, 1973) and frequently occur in sediments and oils (Chandra et al., 1994).The pristane to phytane ratios of ancient sediments and oils reflect the palaeoenvironmental conditions of source rocks and are considered as potential indicators of the redox conditions during sedimentation and diagenesis (Didyk et al., 1978).Isoprenoids, in particular, pristane, occur in high relative concentrations, possessing pristane/phytane (Pr/Ph) ratios in the range of 1.03-2.53suggest that the Bornu sediments were deposited under suboxic to relatively anoxic conditions (Peters and Moldowan, 1993;Hakimi et al., 2011Hakimi et al., , 2012b)).Furthermore, lower amounts of acyclic isoprenoids compared to n-alkanes (Fig. 9), thus giving distinctively low pristane/n-C17 and phytane/n-C18 ratios in the range of 0.31-0.89and 0.21-0.70,respectively, corresponding to mixed organic matter deposited under suboxic to relatively anoxic conditions (Fig. 10).
Geochemical and Organic Petrological Evaluation of Organic Matter…..  Maturity Indicators: Several parameters have been suggested and used to evaluate the level of organic maturity such as mean vitrinite reflectance data (%Ro), pyrolysis Tmax, thermal alteration of sporepollen (TAI), and biomarker thermal indicators.In this study, the thermal maturity was evaluated based primarily on biomarker distributions and supported with the mean vitrinite reflectance (%Ro) as VR is considered more satisfactory and widely accepted by many authors and exploration geologists as a technique for measuring the thermal maturity of source rocks (e.g., Douglas and Williams, 1981;Peters and Moldowan, 1993).In this study, a variety of biomarker maturity indicators have been used to evaluate the level of thermal maturity of the Bornu organic-rich sediments; these include pentacyclic triterpanes and regular sterane isomer ratios.The ratios of C32 homohopane 22S/(22S+22R), moretane/hopane, and C29 sterane 20S/(20S+20R) and ββ/(ββ+αα) can be used to evaluate the thermal maturity of the analyzed samples (Peters and Moldowan, 1993;Peters et al., 2005).A widely used biomarker maturity parameter is the [22S/(22S+22R)] homohopane ratio (Ensminger, 1977).The ratios of C32 22S/ (22R+22S) are increase from 0 to about 0.6 at equilibrium (Seifert and Moldowan, 1986) during  2).These biomarker maturation ratios are indicating that the analyzed Bornu samples have entered early mature for oil generation window (Fig. 13).This is supported by moretane/hopane ratios consistent with low relative abundance of C30 moretane.Moretane converts to C30 hopane with increasing thermal maturity (Seifert and Moldowan, 1986), and thus, moretane decreases as thermal maturity increases.The ratio of moretane to their corresponding hopanes decreases with increasing thermal maturity, from about 0.8 in immature sediments to about 0.15-0.05 in mature source rocks and oils (Mackenzie et al., 1980;Seifert and Moldowan, 1986).The Bornu samples have moretane/hopane ratio in the range of 0.14-0.26,suggesting that samples are early mature.Overall, the biomarker thermal maturity parameters are indicating that all analyzed Bornu samples are at least early mature, and are likely to be approaching oil window maturity (Fig. 13) and therefore support the mean vitrinite reflectance (%Ro) of 62%Ro that from 0.57 to 0.71 %Ro (Table 1).In addition, the maturity of an organic matter can be expressed by its bitumen/TOC ratios, which is defined as the ratio of the amount of free hydrocarbons generated to the total amount of the organic matter due to maturity.The bitumen/TOC ratios are between 0.07 and 0.22, which correspond to early-peak oil window maturity as previously reported by Peters and Cassa (1994).1) and relatively high amounts of organic carbon with alginite and amorphous organic matter (Fig. 3).TS contents are generally within the range observed in a freshwater lacustrine (Fig. 14; after Berner and Raiswell, 1983), and the presence of alginite with morphology similar to the recent alga Botryococcus in several of the samples further implies a lacustrine origin.This interpretation is also consistent with biomarker distributions (Table 2).The n-alkane distributions are consistent with a typical of lacustrine setting receiving mixed algal and amorphous organic matter as indicated by kerogen microscopy (Fig. 3) and lower amounts of acyclic isoprenoids compared to n-alkanes (Fig. 11).
This is suggested by a strong predominance of C27 regular steranes, consisting predominantly of plankton/algal with bacterial organic matter (Fig. 15; after Huang and Meinschein, 1979).These conclusions are also supported by high values of C27/C29 regular sterane ratios (Fig. 16) and the presence of relatively high concentrations of tricyclic terpane in the m/z 191 mass fragmentograms (Fig. 11).

Fig. 2 :
Fig. 2: Regional tectonic map of western and central African rifted basins showing the relationship of the Muglad, Doba and East Niger Basins to the Benue Trough/Gongola Basin.Locations of regional shear zones (marked with half-arrow) and major zones extension (complete arrow) are shown (Adapted from Schull, 1988).

Fig. 3 :
Fig. 3: Stratigraphic successions in the Benue Trough, the Nigerian sector of the Chad Basin and the relationship to the Niger Delta (Obaje et al., 2006).
498UZOEGBU, M. U; OGHONYON, RThe stratigraphic succession in the Upper Benue Trough is illustrated in Fig.3.The oldest sediments consist of continental deposits of the Late Jurassic to Albian Bima Formation which rest unconformably on Precambrian basement rocks.The Bima Formation is conformably overlain by the Cenomanian continental to marine Yolde Formation, which consists of sandstones and shales at the base, and sandstones, shales and calcareous sandstones above.The formation is overlain by contemporaneous marine successions of the Pindiga and the Gongila/Fika Formations in the Gongola Basin, and their lateral equivalents (Dukul, Jessu, Sekuliye, Numanha and Lamja Formations) in the Yola Basin.Zaborski et al.  (1997)  proposed that the Pindiga Formation consists of five members in the Gongola Basin.The youngest Cretaceous sedimentary rocks in the Upper Benue Trough are restricted to the Gongola Basin, and are represented by the lacustrine to deltaic Gombe Formation which unconformably overlies the premid-Santonian sequences in some places.The continental claystones (sandstones and siltstones) and shales of the Paleogene Kerri -Kerri Formation mark the end of sedimentation in the Upper Benue Trough.

Fig. 3 :
Fig. 3: Photomicrographs of macerals from Chad Basin organicrich sediments in the Nigerian sector sub-basin; amorphous organic matter (a-c) and alginite (d-f) under reflected light white (a) and under UV light (b-f), field width=0.2mm

Fig. 7 :
Fig. 7: Plot of TOC content vs. bitumen extractions, showing source potential rating and hydrocarbon source-rock richness for the studied Bornu samples

Fig. 8 :
Fig. 8: Plot of hydrocarbon yields vs. TOC, showing source potential rating and hydrocarbon source-rock richness for the studied Bornu samples

Fig. 9 :
Fig. 9: Gas chromatograms-mass spectrometry (TIC) of saturated hydrocarbons of the analyzed Bornu extracts Geochemical and Organic Petrological Evaluation of Organic Matter….. 503 UZOEGBU, M. U; OGHONYON, R maturation.Values in the range of 0.50-0.54have barely entered oil generation, whereas ratios from 0.57 up to 0.62 indicate that the oil window has been reached.Most of Bornu extracted samples have C32 22S/22S+22R values in the range of 0.50-0.62,suggesting that they have reached equilibrium and that the oil window has been reached.The 20S/(20S+20R) and ββ/(ββ+αα) C29 sterane ratios of the Bornu extracts are ranging from 0.27 to 0.55 (Table

Fig. 17 :
Fig. 17: Hopane and isoprenoid ratios of extracts which allow discrimination of the depositional environments of Bornu sediments in the Chad basin (modified after Peters et al., 2005).

Table 1 :
Bulk geochemical results of extractable organic matter (EOM) yields (ppm), relative proportions of saturated hydrocarbon fractions, aromatic hydrocarbon fractions, and NSO compounds of the EOM (in wt%) and measured Total organic carbon (TOC), sulfur content (TS), and vitrinite reflectance values (%Ro) of the analyzed Bornu samples

Table 2 :
n-alkane and isoprenoids biomarker ratios calculated from GC (TIC), m/z 191 and m/z 217, mass fragmentograms of analyzed Bornu extracts.UZOEGBU, M. U; OGHONYON, R n-Alkanes and isoprenoids:Whole extract gas chromatograms of the Bornu organic-rich sediments show that n-alkanes are the dominant components.

Table 3 :
Peaks for alkane hydrocarbons in the gas chromatograms of saturated fractions in the m/z 191 and 217 mass fragmentograms compound abbreviation.