Abstract
Organic geochemical studies and fossil molecules distribution results have been employed in characterizing subsurface sediments from some sections of Anambra Basin, southeastern Nigeria. The total organic carbon (TOC) and soluble organic matter (SOM) are in the range of 1.61 to 69.51 wt% and 250.1 to 4095.2 ppm, respectively, implying that the source rocks are moderately to fairly rich in organic matter. Based on data of the paper, the organic matter is interpreted as Type III (gas prone) with little oil. The geochemical fossils and chemical compositions suggest immature to marginally mature status for the sediments, with methyl phenanthrene index (MPI-1) and methyl dibenzothiopene ratio (MDR) showing ranges of 0.14–0.76 and 0.99–4.21, respectively. The abundance of 1,2,5-TMN (Trimethyl naphthalene) in the sediments suggests a significant land plant contribution to the organic matter. The pristane/phytane ratio values of 7.2–8.9 also point to terrestrial organic input under oxic conditions. However, the presence of C27 to C29 steranes and diasteranes indicates mixed sources—marine and terrigenous—with prospects to generate both oil and gas.
1. Introduction
The Anambra Basin is a late Cretaceous–Paleocene delta complex located in the southern Benue Trough (Figure 1). It is characterized by enormous lithologic heterogeneity in both lateral and vertical extension, derived from a range of paleoenvironmental settings ranging from Campanian to Recent [1].
The search for commercial crude oil in the Anambra Basin has remained a real source of concern especially to oil companies and research groups. Initial efforts were unrewarding and this led to the neglect of this basin in favour of the Niger Delta, where hydrocarbon reserves have been reportedly put at 40 billion barrels of oil and about 170 trillion standard cubic feet of gas [2–4].
The Nigerian sedimentary basin was formed after the breakup of the South American and African continents in the Early Cretaceous [5, 6]. Various lines of geomorphologic, structural, stratigraphic, and paleontological evidences have been presented to support a rift model [7–10]. The stratigraphic history of the region is characterised by three sedimentary phases [11], during which the axis of the sedimentary basin shifted. More than 3000 m of rocks comprising those belonging to Asu River Group and the Eze-Aku and Awgu Formations were deposited during the first phase in the Abakaliki-Benue Basin and the Calabar Flank. The resulting succession from the second sedimentary phase comprises the Nkporo Group, Mamu Formation Ajali Sandstone, Nsukka Formation, Imo Formation, and Ameki Group. The third phase, credited for the formation of the petroliferous Niger Delta, commenced in the Late Eocene as a result of a major earth movement that structurally inverted the Abakaliki region, displacing the depositional axis further to the south of the Anambra basin [12].
Reports of various authors are valuable in the exploration activities in the Anambra Basin. Avbovbo and Ayoola [13] reviewed exploratory drilling result for the Anambra Basin and proposed that most parts of the basin probably contain gas-condensates due to abnormal geothermal gradient. Agagu and Ekweozor [14] concluded that the senonian shales in the Anambra syncline have good organic matter richness with maturity increasing significantly with depth. Unomah [15] evaluated the quality of organic matter in the Upper Cretaceous shales of the Lower Benue Trough as the basis for the reconstruction of the factors influencing organic sedimentation. He deduced that the organic matter and shales were deposited under a low rate of deposition. Specific references to the organic richness, quality, and thermal maturity in the Mamu Formation and Nkporo shales have been reported by Unomah and Ekweozor [16], Akaegbobi [1], and Ekweozor [17]. They reported that the sediments are organic rich but of immature status. Iheanacho [18] investigated aspects of hydrocarbon source potential of the organic rich shales belonging to some parts of the Anambra basin. He indicated the source rocks as shales and coals, which present good prospects in terms of economic viability as typified by the quantity and quality of organic matter they contain.
This study thereby aims at producing an extensive molecular fossil record of some parts of Enugu Shale and coal measures of the Mamu Formation.
2. Location of Study Area and Geology
The study area is located between latitude 6°15′N–6°45′N and longitude 7°15′E–7°30′E and falls within the Anambra Basin (Figure 1). The stratigraphic succession of the Anambra Basin, at the second sedimentary phase, comprises the Campanian-Maastrichtian Enugu/Nkporo/Owelli Formations (which are lateral equivalents). This is succeeded by the Maastrichtian Mamu Formation and Ajali Sandstone. The sequence is capped by the Tertiary Nsukka Formation and Imo Shale. These are discussed below.
2.1. Nkporo-Enugu Shale Group
These units consist of dark grey fissile, soft shales, and mudstone with occasional thin beds of sandy shale, sandstone, and shelly limestone. A shallow marine shelf environment has been predicted due to the presence of foraminifera Milliamina, plant remains, poorly preserved molluscs, and algal spores [2, 19, 20]. Nyong [21] inferred the Nkporo Shale to have been deposited in a variety of environments including shallow open marine to paralic and continental settings.
North of Awgu, the Nkporo Shale shows a well-developed medium to coarse-grained sandstone facies referred to as Owelli Sandstone. The Owelli Sandstone member is about 600 metres thick [19].
2.2. Mamu Formation
This formation is also known as “Lower Coal Measures.” It contains a distinctive assemblage of sandstone, sandy shale, shale, mudstone, and coal seams [19]. Surface sections reveal that the Mamu Formation comprises mainly white, fine-grained and well-sorted sands. There are frequent interbeds of carbonaceous shales with sparse arenaceous microfauna and coal beds [20]. The exposed thickness of this Formation ranges from 5 to 15 m. According to Reyment [19], the coals occurring in Enugu area are in five seams ranging from 30 cm to nearly 2 m. The middle seam—the thickest—outcrops along the Enugu Escarpment for 11 km. The coals of Enugu area form only a part of the total coal resources of Nigeria [19].
2.3. Ajali Sandstone
This is a Maastrichtian sandy unit overlying the Mamu Formation. It consists of white, thick, friable, poorly sorted cross-bedded sands with thin beds of white mudstone near the base [22]. Studies have suggested that the Ajali Sandstone is a continental/fluviodeltaic sequence characterised by a regressive phase of a short-lived Maastrichtian transgression with sediments derived from Westerly areas of Abakaliki anticlinorium and the granitic basement units of Adamawa-Oban Massifs [23]. The Formation, where exposed, is often overlain by red earth, formed by weathering and ferruginization of the Formation [24]. According to Nwajide and Reijers [25], the coal-bearing Mamu Formation, and Ajali Sandstone accumulated during the regressive phase of the Nkporo Group with associated progradation. The authors characterised the Ajali Sandstones as tidal sands.
2.4. Nsukka Formation
The Nsukka Formation is a Late Maastrichtian unit, lying conformably on the Ajali Sandstone. The unit consists of alternating succession of sandstone, dark shales, and sandy shales with thin coal seams at various horizons, hence termed the “Upper Coal Measures” [22]. The Formation begins with coarse to medium-grained sandstones passing upward into well-bedded blue clays, fine-grained sandstones, and carbonaceous shales with thin bands of limestone [12, 19]. Agagu et al. [20] reported that the Formation has a thickness range of 200–300 m and consists of alternating succession of fine-grained sandstone/siltstones and grey-dark shale with coal seams at various horizons. A strand plain/marsh environment with occasional fluvial incursions similar to that of the Mamu Formation was inferred for this Formation.
2.5. Imo Shale
The Imo Shale overlies the Nsukka Formation in the Anambra Basin and consists of blue-grey clays and black shales with bands of calcareous sandstone, marl, and limestone [19]. Ostracod and foraminifera recovered from the basal limestone unit indicate a Paleocene age for the Formation [26]. Lithology and trace fossils of the basal sandstone unit reflect foreshore and shoreface or delta front sedimentation [27]. The Imo Formation is the lateral equivalent of the Akata Formation in the subsurface Niger Delta [11]. The Formation becomes sandier towards the top where it consists of alternations of sandstone and shale [26]. Nwajide and Reijers [25] interpreted the Imo Shale to reflect product of shallow-marine shelf in which foreshore and shoreface are occasionally preserved.
3. Weathering and Contamination of Rock Samples
Borehole samples are preferred because they provide a continuity of vertical sections over tens or hundreds of metres. Even some of the best natural outcrops or exposures do not provide this coverage, because beds are weathered away [28]. The weathering of outcrop samples and contamination could give rise to false and pessimistic indications of hydrocarbon potential. Although well samples can be contaminated by drilling fluid additives (diesel contamination, e.g., can be recognised from gas chromatography by the high concentrations of -alkanes up to C20), steranes and triterpenes should be unaffected. Borehole samples were therefore used for this study.
4. Analytical Methods
Borehole samples from Enugu 1325 and 1331 wells were obtained from Nigerian Geological Survey Agency (NGSA), Kaduna and used in this study. The borehole samples, Enugu 1325, range in depths from 165 to 177 m while Well 1331 range in depths from 219 to 233 m. Enugu well 1325 has a sequence beginning from shale, overlain by siltstone, coal, shale, and siltstone successively (Figure 2). The shales are dark grey and fissile; the siltstone is brown to light grey while the coal is blackish. Enugu well 1331 has a bottom to top sequence which begins from coal, shale, and siltstone successively. In the middle section is a siltstone-shale sequence which is overlain by another coal, shale, and siltstone succession (Figure 3). Thirteen (13) representative core samples made up of four (4) coal samples and nine (9) shale samples were subjected to organic geochemical analysis.
4.1. Total Organic Carbon (TOC) Determination
Approximately 0.10 g of each pulverized sample was accurately weighed and then treated with concentrated hydrochloric acid (HCl) to remove carbonates. The samples were left in hydrochloric acid for a minimum of two (2) hours. The acid was separated from the sample with a filtration apparatus fitted with a glass microfiber filter. The filter was placed in a LECO crucible and dried at 110°C for a minimum of one hour. After drying, the sample was analysed with a LECO 600 Carbon Analyzer. The analysis was carried out at the Weatherford Geochemical Laboratory, Texas, USA.
4.2. Rock Eval Pyrolysis
The thirteen samples were further characterised by rock eval pyrolysis to identify the type and maturity of organic matter and petroleum potential in the studied area. Rock-Eval II Pyroanalyzer was used for this analysis. Pulverised samples were heated in an inert environment to measure the yield of three groups of compounds (S1, S2, and S3), measured as three peaks on a program. Sample heating at 300°C for 3 minutes produced the S1 peak by vapourising the free hydrocarbons. High S1 values indicate either large amounts of kerogen derived bitumen or the presence of migrated hydrocarbons. The oven temperature was increased by 25°C per minute to 600°C. The S2 and S3 peaks were measured from the pyrolytic degradation of the kerogen in the sample. The S2 peak is proportional to the amount of hydrogen-rich kerogen in the rock, and the S3 peak measures the carbon dioxide released providing an assessment of the oxygen content of the rock. The temperature at which S2 peak reaches maximum——is a measure of the source rock maturity.
4.3. Determination of Soluble Organic Matter (SOM)
The soluble organic matter content of both shale and coal samples was carried out to estimate the free hydrogen content of the samples. This was done using the Soxhlet System HT2 Extraction Unit and Methylene Chloride/Methanol mixture (9 : 1) as the solvent. Each pulverised sample, after been weighed, was placed into labelled cellulose thimbles and plugged with glass wool and adapter. For shale sample, 20 g was taken while 2–4 g was taken for coal. The thimble, extraction cups and 100 mls of methylene chloride : methyl solution were placed inside a tecator system. The solvent was allowed to boil, and then the thimbles were lowered into the solvent and left for an hour. The stop cork was closed for faster evaporation. After evaporation, soluble matter were turned into preweighed, labeled 20 mL glass vials, and dried with nitrogen at 40°C. The dried extract was weighed at room temperature.
The soluble organic matter was then calculated; thus, The extraction was carried out at Exxon Mobil Geochemical Laboratory, Que Iboe Terminal (QIT), Eket.
4.4. Gas Chromatography of Whole Oil
The analyses were carried out in a Hewlett Packard 6890A gas chromatograph, equipped with dual flame ionization detectors. The chromatograph was fitted with HP-1 capillary column (30 m × 0.32 mm I.D × 0.52 microns) using helium as the carrier gas. The column temperature was programmed at 35°C to 300°C/min with a flow rate of 1.1 mls/min. The bitumen extract (SOM) was diluted with drops of carbon disulphide while agitating until sample is dissolved. A little volume was placed in a labeled auto-sampler vial which was transferred to the autosampler tray for the analysis to run. 1.0 μL of the diluted extract was rapidly injected to the gas chromatograph in split mode, using a graduated Hp 10 μL injection syringe. This analysis was carried out at the Exxon Mobil Geochemical Laboratory (QIT), Eket, Nigeria.
4.5. Gas Chromatography Mass Spectrometry
For GC/MS to be carried out on an extract (soluble organic matter), it must be separated into its fractions, that is, saturate, aromatic, asphaltene, and resin. The gravimetric column chromatography method was applied in the separation of extract into saturate, aromatic, resin, and asphaltene fractions (SARA). It is modified from the “SARA” procedure (Exxon Mobil operation manual).
The saturate and aromatic fractions recovered from the liquid chromatography were analysed for their biomarker by gas chromatography/mass spectrometry (GC/MS) using the selected ion monitoring mode (SIM). Hexane was added to each sample vial containing the saturates and aromatic fractions to obtain concentrations of 25 μg/μL and 12.5 μg/μL, respectively. The samples were mixed with a vortex mixer to agitate and then transferred to an auto-sampler vial and capped. Vials were then placed on the auto-sampler to be run in an HP 6890 gas chromatograph silica capillary column (30 m × 0.25 mm ID, 0.25 μm film thickness) coupled with HP 5973 Mass Selective Detector (MSD). The extract was rapidly injected into the gas chromatograph using a 10 μL syringe. Helium was used as the carrier gas with oven temperature programmed from 80°C to 290°C. The mass spectrometer was operated at electron energy of 70 Ev, an ion source temperature of 250°C, and separation temperature of 250°C. The chromatographic data were acquired using Ms Chemstation software, version G1701BA for Microsoft NT. This analysis was carried out at Exxon Mobil Geochemical Laboratory, Eket.
4.6. Aromatic Biomarker Parameters
According to Radke et al., [29], MPI-1 (methyl phenanthrene index), DNR-1 (dimethyl naphthalene ratio), and MDR (methyl dibenzothiopene ratio) can be used as source and maturity parameters. The necessary calculations were made using the results obtained from peak identification and height of aromatic biomarkers of the studied wells (see Table 2).
5. Organic Richness
According to Conford [30], adequate amount of organic matter measured as percentage total organic carbon is a prerequisite for sediment to generate oil or gas. Shown in Table 1 are the results of total organic matter content (TOC). The coal samples from both wells show a higher organic richness than shale. Nevertheless, both wells have values above the threshold of 0.5 wt% considered as minimum for clastic source rocks to generate petroleum [31]. The soluble organic matter (SOM) of the samples generally exceeds 500 ppm except for samples P3 (EN 1325) and V5 (EN 1331) with SOM values of 250.1 and 467.8 ppm, respectively. These show that the samples can be classified as fair to excellent source rocks. Based on the quality definition of Baker [32], the organic matter is adequate and indicates good hydrocarbon potential for the studied wells.
6. Organic Matter Type
The organic matter type in a sedimentary rock, among other conditions, influences to a large extent the type and quality of hydrocarbon generated due to different organic matter type convertibilities [31]. The Hydrogen Index (HI) for the shale and coal samples ranges from 83 to 245 mgHC/gTOC with an average value of 178 mgHC/gTOC. This can be interpreted as type III (gas prone). The plot of hydrocarbon potential versus TOC (Figure 4) indicates type II/III organic matter which means a potential to generate oil and gas. The majority fall within the type III organic matter indicating that gas will dominantly be generated, with little oil. Peters [33] suggested that at thermal maturity equivalent to vitrinite reflectance of 0.6% ( 435°C), rocks with HI > 300 mgHC/gTOC produce oil, those with HI between 150 mgHC/gTOC and 300 mgHC/gTOC produce oil and gas, those with HI between 50 mgHC/gTOC and 150 mgHC/gTOC produce gas, and those with HI < 50 mgHC/gTOC are inert. From this study, the range of HI is from 83 to 245 for the shales and coal. This indicates oil and gas prone.
Petroleum generating potential (GP) is the sum of S1 and S2 values obtained from rock eval pyrolysis (Table 1). The values obtained range from 2.34 to 177.36. According to Dyman et al. [34], values greater than 2 kgHC/ton of rock indicate good source rock. This suggests oil and gas potential.
7. Thermal Maturity
The degree of thermal evolution of the sedimentary organic matter was derived from Rock Eval and biomarker parameter. According to Peters et al., [35], biomarkers (geochemical fossils) can provide information on the organic source materials, environmental conditions during its deposition, the thermal maturity experienced by a rock or oil, and the degree of biodegradation.
The values (Table 1) range from 425 to 435°C. These indicate that the shales and coal range from immature to early peak mature (oil window) but on the average are immature. The interpretation is in line with those given by Peters [33], Dow [36], and Miles [37]. This is further highlighted by the plot of HI versus (Figure 5).
(C27: 17α(H)-22,29,30-Trisnorhopane) represents biologically produced structures and (C27: 18α(H)-22,29,30-Trisnorneohopane) generated in sediments and rocks by diagenetic or thermal process or both. is a ratio used as both source and maturity parameters. The 191 (hopanes) (Figure 6) and 217 steranes (Figure 7) chromatograms of all the samples are similar. H30 (hopanes) are the most abundant in the 191 chromatogram. The maturity and source parameters derived from the hopane distributions in the shales and coals are shown in Tables 2 and 4. Also shown are calculated parameters of aromatic biomarkers. Parameters such as MPI-1 (methyl phenanthrene index), DNR-1 (dimethyl naphthalene ratio), TMNR (trimethyl naphthalene ratio), and MDR (methyl dibenzothiopene ratio) with respective range of values 0.14–0.76, 0.75–2.51, 0.17–0.50, and 0.99–4.21 all indicate that the samples are immature to marginally mature [29]. According to Sonibare et al. [38], the abundance of 1,2,5 TMN (trimethyl naphthalene) suggests a significant land plant contribution to the organic matter (Figure 8).
Some -alkane ratios can be used to estimate the thermal maturity of sediments [39]. Pristane/C17 and phytane/C18 can be used to calculate thermal maturity. For the studied wells, the Pr/C17 values ranged between 0.8 and 3.91 (Table 3); this falls in the immature zone. Ph/C18 values ranged from 0.2 to 0.57, which is below the threshold value, indicating immature organic matter.
Carbon preference index (CPI) is the relative abundance of odd versus even carbon-numbered -alkanes and can also be used to estimate thermal maturity of organic matter [40]. In this study, the CPI values obtained range from 1.53 to 1.83 (Table 3). Hunt [41] has pointed out that CPI considerably greater than 1.0 shows contribution from terrestrial continental plants and immaturity. Maxwell et al., [42] have shown that strong odd/even bias of heavy -alkanes is indicative of sediment immaturity. For this study, the odd numbered -alkanes are more abundant than the even numbered -alkanes, indicating that the sediments are immature. The odd-even predominance (OEP) values are less than 1.0, this is indicative of low maturity [43].
8. Palaeodepositional Environment
Moldowan et al. [44] have indicated that the presence of bisnorhopane and diasterane is indicative of suboxic conditions. A plot of versus dia/(dia + reg)C27 steranes, as shown in Figure 9, is indicative of a suboxic condition. Pristane/phytane (Pr/Ph) ratio of sediments can be used to infer depositional environment [35]. Pr/Ph ratios < 1 indicate anoxic depositional environment, while Pr/Ph > 1 indicate oxic conditions. Pr/Ph 1 < 2 indicate a marine-sourced organic matter and Pr/Ph > 3 indicates terrigenous organic matter input with oxic conditions. The values obtained from the studied wells ranged from 5.08 to 8.97, thus indicating that the samples have terrigenous-sourced organic matter deposited in an oxidizing environment. Crossplots Pr/C17 versus Ph/C18 (Figure 10) reveal that the sediments were deposited in an oxidizing environment and are from terrestrial and peat environments. This is consistent with the samples as some of them are of coal environment.
Dahl et al. [45] reported that a low ratio of homophane index is characteristic of a suboxic environment (Table 4). On the other hand, Pr/Ph ratio tend to be high (>3) in more oxidizing environment such as in swamps. High Pr/Ph values from the work indicate a terrigenous input under oxic conditions. A large proportion of the results point to the fact that a suboxic condition prevailed in the deposited sediments. These indicate that a significant portion of the facies were probably deposited in an offshore, shallow to intermediate marine environment under suboxic water conditions which probably had no connection with the widespread Cretaceous anoxic events but are related to the Campanian-Maastrichtian transgression.
9. Summary and Conclusion
Detailed geochemical analysis of the coal and shale intervals gotten from the Anambra Basin, Nigeria, has been used to investigate the aspects of their molecular fossil. The lithostratigraphic sequence penetrated by both wells (Enugu 1325 and 1331) consists of shales, coal, and siltstones. The shales are dark grey and fissile. The siltstones are brown to light grey in colour while the coal is blackish.
Organic richness of the samples was deduced from SOM and TOC as fair to excellent. The organic matter type is predominantly terrestrial. This is based on the HI values, HI- plot, the presence of oleanane, the abundance and predominance of C29, C35 homophane index, and the abundance of 1,2,5 Trimethyl Naphthalene.
Biomarker parameters were used to determine the degree of thermal evolution of the sediment organic matter. The presence of bisnorhopane, diasterane, plot of against dia/(dia + reg)C27 sterane and the homophane index all indicate suboxic and high Eh conditions.
Discrepancies were observed in the results used in the interpretation of physicochemical conditions prevailing in the deposited sediments. These varied between oxic and suboxic conditions. It is thereby concluded that the lithologies from the core samples are those of the Mamu Formation and Enugu-Shale Group which were deposited in a partial or normal marine (suboxic to oxic water conditions) environment. There is no strong evidence to show that the shales and coals have expelled petroleum although they possess what it takes to be economic, largely in terms of gas, thus presenting a good prospect.
Conflict of Interests
The author declares that there is no conflict of interests regarding the publication of this paper.
Acknowledgments
The author is grateful to the Nigerian Geological Survey Agency (NGSA), Kaduna, for provision of borehole samples. The author remains grateful to the members of staff of Weatherford Geochemical Laboratory, Texas, USA, and ExxonMobil Geochemical Laboratory, Eket, Nigeria, for the technical services rendered. The author’s sincere gratitude goes to Dr. M. E. Nton of the Department of Geology, University of Ibadan, for his suggestions. The author also thanks the anonymous reviewers for their constructive comments which led to improving this paper.