Hydrocarbon Potential and Biomarker Studies of EE-1 Well, Offshore Eastern Dahomey Basin, SW Nigeria

The study area is located between latitudes 6°10’N and 6°20’N and longitudes 2°0’E and 2°30’E, offshore Eastern Dahomey Basin (Figure 2).

Figure 2:

The Dahomey Basin is a coast-parallel basin, stretching from the western limit of the Niger Delta in Nigeria westwards, through Benin Republic and Togo, terminating in the Volta Delta in Ghana, with a total latitudinal stretch of about 500 km [16]. It is a marginal pull apart or marginal sag basin [17] which originated during the Early Cretaceous separation of African and South American plates [18]. The basin contains Late Cretaceous to recent sediments up to 3,000 m where they thicken markedly into the offshore and then thin beneath the deep water area. Onshore, the sediment-fill also thins both westward and eastward from the central area in Benin Republic. The maximum thickness of the sediments is around the Nigeria - Republic of Benin border. In the Nigerian sector, the sediments thin into the Basement Complex of the Okitipupa High, west of the Niger Delta. Earlier stratigraphic study of the basin by Jones and Hockey [19] recognized both Cretaceous and Tertiary sediments. Other subsequent workers recognized three chronostratigraphic units: Pre-lower Cretaceous folded sequence, Cretaceous sequence and Tertiary sequence [6, 9]. The Cretaceous stratigraphy as compiled from outcrop and borehole records comprising the Abeokuta Group is further subdivided into three informal formational units, namely, Ise, Afowo, and Araromi Formations [5]. Ise Formation is the oldest Cretaceous unit and comprises predrift succession of conglomerates, sands, and mudrocks overlying the Basement Complex. The succession continues upwards with medium to coarse, loose sands interbedded with kaolinitic clays. Omatsola and Adegoke [5] assigned a Lower Cretaceous (Neocomian) age to this formation. The deposits are products of alluvial fan setting at the basin edge, following initial rifting [16]. The Afowo Formation comprises mostly medium to coarse sandstone, with thin to thick interbeds of shales, siltstones, and claystones. It has been described as tar-bearing and petroliferous. The formation has been assigned a Turonian age [8, 15]. The Araromi Formation is the youngest Cretaceous unit that conformably overlies Afowo Formation in the Eastern Dahomey Basin. The formation consists of fine to medium sands at the base, overlain by a seaward thickening shale and siltstone with thin limestones and marls, as well as thin lignitic bands. The Araromi Formation has been assigned a Maastrichtian to Paleocene age [5]. Overlying the Cretaceous Abeokuta Group is the Ewekoro Formation. The Ewekoro Formation is predominantly limestone, but it is, however, not encountered offshore in coastal boreholes, where the shaley Imo Formation unconformably overlies the Afowo Formation [15]. Four microfaciesl, namely, bio-microsparite, shelly biomicrite, algal biosparite, and red phosphatic biomicrite, have been identified within this predominantly limestone body [4, 20]. The formation has been assigned Upper Paleocene by most authors [2, 21, 22]. The Akinbo Formation [23] overlies the Ewekoro Formation. The unit consists of fine-grained, dark micromicaceous shale, locally silty with glauconitic marl and conglomeratic at the base. The formation has been dated Upper Paleocene to Lower Eocene in age [12, 23]. The Oshosun Formation overlies the Akinbo Formation and consists of greenish grey or beige clay and shale, with interbeds of sandstones. The shale is thickly laminated and glauconitic [12]. According to Okosun [9], the basal beds consist of any of the following facies: sandstones, mudstones, claystones, clay-shale, or shale. This formation is phosphate-bearing [2, 19]. A Lower Eocene-Middle Eocene age is assigned to this formation. The Ilaro (Ijebu) Formation conformably overlies the Oshoshun Formation in the Eastern Dahomey Basin. This unit comprises massive, poorly consolidated, cross-bedded sandstones. Subrounded to rounded pure quartz grains dominate the base of the formation and it has been assigned an Eocene – Oligocene age. The Benin Formation, also called the Coastal Plain Sands [5] is the youngest sequence in the Eastern Dahomey Basin and comprises poorly sorted sands with lenses of clays. The sands are cross-bedded in part and show nearshore to continental distinctiveness. The formation age covers the Miocene to Recent periods.

There are lots of controversies concerning the stratigraphy of the Nigerian sector of the basin. This is due primarily to different stratigraphic names that have been proposed for the same formation in different localities in the basin [9, 24]. This situation can be fairly blamed on the lack of good borehole coverage and adequate outcrops for detailed stratigraphic studies [25].

Subsurface samples of EE-1 Well from offshore Eastern Dahomey Basin were obtained for this study. Of a total depth of 315 m to 2257.5 m, the interval 1200–2260 m was used in this study. The detailed lithological description of the samples is shown in Figure 3. The lithologic sequence within the interval shows that the base to depth 2100 m is a thick sequence of silty shale which is greyish to dark in colour. This is overlain by a greyish to dark shale sequence, a thick sequence of indurated, dark shale indicative of rich organic matter, which was encountered from 2020 m to 1810 m. From 1810 m to the top of the well (1210 m) is micaceous shale with clay intercalations, ranging in colour from grey to dark.

Figure 3:

The quantity of organic matter present in a rock can be expressed as a percentage of total organic carbon (TOC), which is a measure of the organic richness of a sample expressed as the percentage weight of the dry rock sample [27]. The TOC values for the samples range between 0.96 and 8.92wt% (Table 1). These values are above the 0.5 wt% minimum for clastic source rocks to generate hydrocarbons [27]. The SOM content ranged from 676 ppm to 2883 ppm (average: 1893 ppm), which indicates good to very good organic richness while the genetic potential (GP) values range from 1.18 mg HC/g to 44.53 mg HC/g (average: 5.972 mg HC/g), indicating moderate to good source rock potential [27].

The quality of organic matter content of a source rock determines the type of hydrocarbon generated [27]. Cross plots of hydrogen index versus oxygen index (OI) (Figure 4) show that the samples consist of types II and III kerogen, which indicates that the organic matter can generate both oil and gas at appropriate thermal maturity [28]. The cross plot of the remaining hydrocarbon potential (S2) against TOC (Figure 5) further supports type II/III (oil/gas prone) kerogen.

Figure 4:

Figure 5:

The generation of petroleum from organic matter during its burial history is a part of the overall processes of thermal maturation of organic matter [27]. Thermal maturity describes the extent of heat-driven reactions, which convert sedimentary organic matter into petroleum [31]. In this study, the values of T_max ranged from 422°C to 431°C (average 426.6°C), indicating immature status for the studied well [31]. Similar values have been reported by Nton et al. [12] in sediments of the Aje-1 well, Eastern Dahomey Basin where T values that ranged from 359°C to 465°C indicated the immature to marginal maturity status of the well. Cross plots of HI against T_max (Figure 6) further revealed that >95% of the samples are immature. The calculated vitrinite reflectance R_o for this study ranged from 0.44 to 0.60 and lie in the immature status defined by Peters and Cassa [32].

Figure 6:

The production index (PI) is defined as the ratio S1/ (S1 +S2) and is an indicator of the degree of thermal maturity. It is also an indication of the amount of hydrocarbon which has been produced geologically relative to the total amount of hydrocarbon that the sample can produce PI values of 0.03 – 0.24, indicated immature status for the sediments [31]. The ratio of extractable bitumen to total organic carbon (bitumen/TOC), sometimes called the transformation ratio (TR), is often used as a quantitative index to deduce the thermal maturity of sediments [31]. This ratio has been discovered to range from near zero in shallow sediments to about 250 mg/g TOC at the peak of oil generation. These values have also been observed to decrease at greater depths as a result of the conversion of bitumen to gas [31]. In the study well, the transformation ratio ranged from 22.18 to 282.73 mg/g TOC (average: 132.27) (Table 1), indicating immature to marginally mature status for the sediments. However, anomalous high figures observed in some of the samples may indicate contamination by migrated oil.

The n-alkane data and biomarker maturity parameters were used to evaluate the level of thermal maturity of the sediments. Typical representative chromatograms showing distribution of n-alkanes and isoprenoids are shown in Figure 7. Using the chromatograms, parameters indicating source input, maturity, and depositional environment were generated as shown in Table 2.

Figure 7:

The pristane/phytane (Pr/Ph) ratio, is one of the most commonly used geochemical parameters as an indicator of depositional environment, though with low specificity due to the interferences of thermal maturity and preliminary assessment of organic matter source inputs [34]. Ten Haven [35] stressed that high Pr/Ph (>3.0) indicates terrigenous input under oxic conditions, and low Pr/Ph (<0.8) indicates anoxic/hypersaline or carbonate environments. Values of Pr/Ph ranging from 1.47 to 3.20 (Table 2) indicate a mixed marine/ terrigenous environment under suboxic to oxic conditions for the sediments. Cross plots of isoprenoids/n-alkanes (Figure 8) revealed that the samples are mainly in transitional environments with strong oxic influence and biodegraded.

Figure 8:

The carbon preference index (CPI) and oddeven predominance (OEP) provide a crude estimate of source input, thermal maturity of petroleum, and dispersed organic matter [31, 36]. According to Hunt [37], CPI considerably greater than 1.0 shows contribution from terrestrial continental plants and immaturity. Over 90% of the samples have CPI >1% and strongly indicate terrestrial contribution and marine influence. The OEP values are less than 1.0 for all samples (Table 2), which further indicate low thermal maturity status of the well [38].

The composition and distribution of certain diagnostic chemical fossils (biomarkers) can indicate the maximum stress experienced by the rocks or petroleum in which the compounds are found [40]. Typical representative chromatograms showing distribution of steranes (m/z 217) and terpanes (m/z 191) from this study are shown in Figures 9 and 10. Using the chromatograms, an assessment of the thermal maturity levels was generated based on maturity parameters (Table 3).

Figure 9:

Figure 10:

The Ts/Tm ratio is used as a maturity indicator, because C₂₇ 18α-trisnorneohopane, or Ts, exhibits greater thermal stability than its regular hopane counterpart, C₂₇ 17α-trisnorhopane, or Tm, although the ratio is also source dependent [34]. The Ts/Tm values for the study well ranged from 0.22 to 0.5 (Table 3), indicating the immaturity status of the samples. The moretane/hopane ratio ranged from 0.10 to 0.48 and point to an immature to marginally mature status of the study well. The 20S/ (20S + 20R) C₂₉ steranes αββ/αββ+ααα and 22S/(22S + 22R) extended hopanes, which are used as maturity indicators, were computed for the study well. An equilibrium value of 0.55 for 22S/(22S + 22R) extended hopanes ratio corresponds to the onset of hydrocarbon generation, while > 0.5 20S/(20S + 20R) C₂₉ steranes αββ/αββ+ααα signifies thermal maturity [31]. The values of the 20S/(20S + 20R) C₂₉ steranes αββ/αββ+ααα and 22S/(22S + 22R) extended hopanes ratios ranged from 0.06 to 0.44 and 0.34 to 0.6 (Table 3), respectively, supporting the low maturity status of the study well. Calculated aromatic biomarker parameters such as MPI-1 (methyl phenanthrene index), DNR-1 (dimethyl naphthalene ratio), TMNR (trimethyl naphthalene ratio), and MDR (methyl dibenzothiophene ratio) ranged from 1.01 to 1.72, 2.96 to 4.96, 0.67 to 1.17, and 0.82 to 6.21, respectively (Table 3). These values indicate that the samples are immature to marginally mature [41].

Biomarkers provide information about the depositional environment of organic matter, the conditions during deposition as well as the lithology in which the organic matter is present [31]. Source and depositional environment parameters computed from the saturate biomarkers of the studied well are shown in Table 4.

The samples were characterized by the presence of C₂₇ to C₂₉ steranes and disateranes, which indicate derivation from mixed sources (marine and terrestrial) with capacity to generate both oil and gas. A ternary plot (Figure 11) showing sterane distributions and relationship with source indicates dominance of C₂₉ over C₂₇ and C₂₈ and suggests a mixture of marine and terrigenous biomass to the study well, with stronger terrigenous input. The presence of oleananes, a biomarker for higher plants (angiosperms), strongly supports a terrestrial precursor for the studied well [42]. The distribution of 17α, 21β (H)—homohopanes 22R + 22S C₃₅/(C₃₁–C₃₅), also known as the homohopane index, can be used as an indicator of the redox potential during and immediately after the deposition of the source sediments [31]. The studied samples have a low homohopane index (0.05 – 0.17) (Table 4), which suggests a suboxic depositional environment [43].

Figure 11:

The 17α (H)-hopanes/regular steranes ratio reflects input of prokaryotic (bacteria) versus eukaryotic (mainly algae and higher plants) organisms to the source rock. The hopane/ sterane ratio values for the well sediments ranged from 1.53 to 16.11, indicating both terrigenous and marine organic matter input. It has been suggested by Qiuhua et al. [44] that C₂₁/C₂₃ trycyclic terpane ratios < 0.5 are indicative of marine-sourced organic matter. In this study, this ratio ranged from 0.33 to 0.82, further indicating a mixed marine and terrigenous input to the sediments. The values of the gammacerane index ranged from 0.03 to 0.10 (Table 4), indicating a normal salinity environment of deposition of the initial organic matter [45]. The tetracyclic terpane ratio – C₂₄ Tet / (C₂₆ (S+R) + C₂₄ Tet) – ranged from 0.45 to 0.72 (average: 0.57), indicating a low salinity environment of deposition for the study well [31]. The abundance of 1, 2, 5-TMN (trimethyl naphthalene) observed in the samples has been reported to be indicative of significant land plant contribution to the organic matter [46, 47]. In addition, the occurrence of 1, 7-DMP (dimethyl phenanthrene) in the analyzed samples indicates a strong terrestrial organic matter input for the sediments [48].