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

Data publikacji: 18 Mar 2022
Tom & Zeszyt: AHEAD OF PRINT
Zakres stron: -
Otrzymano: 02 Jul 2021
Przyjęty: 18 Jan 2022
Informacje o czasopiśmie
License
Format
Czasopismo
eISSN
1854-7400
Pierwsze wydanie
30 Mar 2016
Częstotliwość wydawania
4 razy w roku
Języki
Angielski
Abstract

The hydrocarbon potential, organic source input, and paleodepositional environment of subsurface sediments from EE-1 well, offshore Eastern Dahomey Basin, were assessed using Rock-Eval pyrolysis and biomarker geochemistry. The total organic carbon (TOC) and soluble organic matter (SOM) in the sediments ranged from 0.96wt% to 8.92wt% and 676.12 ppm to 2883.85 ppm, respectively, indicating adequate to excellent organic richness. The pseudo-Van Krevelen plot classified the sediments as types II and III kerogen, which have the potential to generate both oil and gas. The Tmax and production index (PI) ranged from 422°C to 431°C (average, 426°C) and 0.03 to 0.24, respectively, suggesting low thermal maturity. The presence of C27–C29 steranes, oleanane, and hopane/sterane ratio (1.53/16.11), indicated organic matter from mixed sources with more terrigenous input. Cross plots of Pr/nC17 against Ph/nC18, C35/C31 – C35 homohopane index (0.05 – 0.17) and other related biomarker ratios such as C21/C23 trycyclic terpane ratio (0.33 – 0.82) signified that the sediments were deposited in mixed marine/terrigenous environment under oxic – suboxic conditions. This study has demonstrated that sediments had adequate organic matter with the potential to generate both oil and gas at appropriate thermal maturity.

Keywords

Introduction

The Dahomey Basin comprises a combination of inland, coastal, and offshore waters and stretches from Southeastern Ghana, through Togo and the Republic of Benin, to southwestern Nigeria [1] (Figure 1). The Eastern Dahomey Basin (Nigerian sector) has been of much geological interest as a result of the reported occurrences of bitumen, limestone, glass sands, and phosphates [2]. The initial motivation for oil exploration in the Eastern Dahomey Basin arose from the discovery of seepages and tar sand deposits as early as 1909. In the earlier days of exploration for oil in the basin, the wells drilled were classified as ‘dry’ and thus abandoned. Recent exploration and prospect re-evaluation efforts in the Nigerian segment of the basin have been encouraged following oil discovery and production in the neighbouring Benin Republic sector, west of the basin and the social unrest in the prolific Niger Delta, east of the basin [3].

Figure 1

Regional map of four countries showing the location of the Benin (Dahomey) Basin in the Gulf of Guinea [11].

Numerous studies have been carried out on the Eastern Dahomey Basin by a host of earlier workers such as those listed in references [3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14], amongst others. These studies have increased our knowledge of stratigraphic resolution, established petroleum systems, and the hydrocarbon potential of the basin. However, in comparison with the contiguous Niger Delta, much is yet to be clearly understood in the Eastern Dahomey Basin. In the Dahomey Basin, for instance, there is no consensus of opinion on the stratigraphic nomenclatures in the offshore and onshore sectors and different names are assigned to the same units at different places by different authors [5, 13, 15]. This study therefore examines the sediments of EE-1 Well, for hydrocarbon potential, palaeodepositional environment using Rock-Eval and biomarker geochemistry in line with current understanding. The resulting information will be of great interest to explorationists and researchers.

Location of study area and geologic setting

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

Dahomey embayment showing the study area (after d’Almeida et al. [14]).

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].

Materials and methods
Samples

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

Lithological log of the studied section of EE-1 Well.

Analytical methods
Total Organic Carbon Determination

Approximately 10 g of each pulverized shale sample (15) was weighed out and decarbonated by treatment with concentrated hydrochloric acid (HCl) for two hours. After decarbonation, the samples were rinsed with distilled water and flushed through a filtration apparatus, fitted with a glass microfiber filter to remove the acid. The filtrate was then removed, placed into a LECO crucible and dried in a low temperature oven (110°C) for four (4) hours. The samples were then analyzed in a LECO 600 carbon analyzer for the total organic carbon (TOC) content.

Rock-Eval pyrolysis

Based on the TOC adequacy, 100 mg of selected samples (15) were gradationally heated to 550°C at a 25°C/min heating rate using a HAWK Pyrolyzer from which the pyrograms were produced as calculated parameters. Both the TOC and Rock-Eval pyrolysis were undertaken at Geomark Research Ltd. Laboratory, Humble, Texas, USA.

Soluble organic matter extraction and fractionation

About 30–50 g of each pulverized shale sample was extracted using a mixture of methylene chloride/methanol in a Soxhlet extractor Tecator Soxtec System HT 2 1045 Extraction Unit. After the extraction, the solvent was distilled and the soluble organic matter (SOM) was evaporated in a rotary evaporator, and the extracts were weighed. The extracts were later fractionated on silica gel column chromatography into saturate, aromatic, polar (NSO) fractions by successive additions of n-hexane, n-hexane/dichloromethane (4:1, v/v), and dichloromethane/methanol (1:1, v/v), respectively.

Gas chromatography—mass spectrometry

The saturate and aromatic fractions recovered from the liquid chromatography were analysed for their biomarkers by gas chromatography/mass spectrometry (GC/MS) using the selected ion monitoring mode (SIM). The fingerprints (fragmentograms) acquired from this analysis were identified by relative retention times from the GC/MS traces using 5b-Cholane and o-terphenyl standards for saturate and aromatic fractions, respectively, and quantifying of biomarkers was done by measuring peak heights. The chromatographic data were acquired using MS Chemstation software, version G1701BA, for Microsoft NT. The bitumen extraction, fractionation and GC/MS analyses were carried out at Exxon Mobil Geochemical Laboratory, Qua Iboe Terminal (QIT), Eket. The detailed analytical procedures can be obtained from Emordi [26].

Results and discussion
Organic matter quantity

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].

Results of TOC and Rock-Eval Pyrolysis of the studied samples.

Sample ID Depth (m) SOM (ppm) TOC S1 S2 S3 Tmax Calc. %Ro GP (S1 + S2) HI OI SOM/TOC S1/TOC PI
S1 1240 676.12 1.14 0.13 1.11 2.23 423 0.45 1.24 97 196 59.31 11 0.10
S2 1340 2004.31 1.01 0.16 1.02 2.36 422 0.44 1.18 101 234 198.45 16 0.14
S3 1410 ND 1.19 0.16 1.31 2.78 425 0.49 1.47 110 234 ND 13 0.11
S4 1480 1417.71 1.41 0.19 1.93 2.55 428 0.54 2.12 137 181 100.55 13 0.09
S5 1560 ND 0.96 0.15 1.15 2.51 429 0.56 1.3 120 262 ND 16 0.12
S6 1620 2456.23 0.97 0.15 1.26 1.96 429 0.56 1.41 131 203 43.03 16 0.11
S7 1700 2883.85 1.02 0.21 1.66 2.79 427 0.53 1.87 163 274 13.04 21 0.11
S8 1760 1835.19 1.47 0.25 2.60 2.39 430 0.58 2.85 177 163 15.28 17 0.09
S9 1830 1599.37 1.94 0.34 5.84 2.51 426 0.51 6.18 301 129 11.96 18 0.06
S10 1906 1205.55 2.63 0.93 8.24 2.53 427 0.53 9.17 313 96 6.13 35 0.10
S11 1965 2698.84 1.91 1.00 4.11 2.51 431 0.60 5.11 215 131 23.64 52 0.20
S12 2040 1826.01 2.03 0.95 2.99 3.29 425 0.49 3.94 147 162 6.28 47 0.24
S13 2118 ND 1.18 0.39 2.94 2.30 429 0.56 3.33 249 195 ND 33 0.12
S14 2180 2143.91 1.15 0.63 3.25 2.79 422 0.44 3.88 283 243 186.43 55 0.16
S15 2257.5 1978.45 8.92 1.35 43.18 3.15 426 0.51 44.53 484 35 22.18 15 0.03

TOC = weight percent organic carbon in rock, GP = petroleum genetic potential

Tmax = °C, HI = hydrogen index

S1 +S2 = mg HC/g of rock, OI = oxygen index

S3 = mg CO /g of rock, PI = production index = S1 / (S1+S2)

S1/TOC = normalized oil content, Calc. % Ro = Calculated vitrinite reflectance

SOM = Soluble Organic Matter, ND = Not done

Organic matter type

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

A cross plot of hydrogen index (HI) versus oxygen index (OI) showing that the organic matter of the studied well is of types II and type III kerogen (Modified after Van Krevelen [29]).

Figure 5

A cross plot of remaining hydrocarbon potential (S2) against total organic content (TOC) showing the organic matter type and origin (after Jackson et al. [30]).

Maturity of organic matter

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 Tmax ranged from 422°C to 431°C (average 426.6°), 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 Tmax values that ranged from 359° to 465°C indicated the immature to marginal maturity status of the well. Cross plots of HI against Tmax (Figure 6) further revealed that >95% of the samples are immature. The calculated vitrinite reflectance Ro for this study ranged from 0.44 to 0.60 and lie in the immature status defined by Peters and Cassa [32].

Figure 6

Plot of hydrogen index (HI) against Tmax showing that the kerogen is in the immature window [33].

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.

Normal alkanes and acyclic isoprenoids

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

Total ion chromatograms showing the distribution of the saturated hydrocarbon fraction of representative Samples 4B and 6B from the study well.

Data showing values of isoprenoids, isoprenoids/n-alkane ratios and other parameters for EE-1 well.

Sample ID Pr/Ph Pr/n-C17 Ph/n-C18 CPI OEP-1 OEP-2
1B 1.47 0.98 0.62 1.93 0.51 0.83
2B 1.74 1.20 0.90 1.66 0.45 0.76
4B 2.38 2.41 1.08 1.70 0.51 0.8
6B 2.05 2.99 1.83 1.51 0.46 0.62
7B 3.20 2.42 1.40 1.67 0.53 0.7
8B 2.33 1.58 0.76 1.23 0.39 0.51
9B 1.49 2.31 1.55 1.27 0.47 0.49
10B 1.78 1.24 0.63 1.01 0.35 0.41
11B 2.20 0.99 0.51 1.12 0.39 0.44
12B 1.65 0.92 0.54 1.04 0.37 0.4
14B 1.94 0.60 0.46 0.37 0.4 0.08
15B 1.80 0.80 0.42 1.12 0.41 0.42

Abbreviations: Pr/Ph, pristane/phytane; Pr/nC17, pristane/normal-C17 alkane; Ph/nC18, phytane/normal-C18 alkane; CPI, carbon preference index, 2 (C23 + C25 + C27 + C29) / (C22 + 2 C24 + C26 + C28) + C30); OEP-1, (C21 + C23 + C25) / (4C22 + 4C24); OEP-2, (C25 + C27 + C29) / (4C26 + 4C28); OEP, odd-to-even predominance.

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

Cross plot of Pr/n-C17 versus Ph/n-C18 showing the sources of organic matter and the depositional environment (Modified after Cortes et al. [39]).

The carbon preference index (CPI) and odd-even 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].

Biomarker geochemistry

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

m/z 217 mass chromatograms showing the distribution of steranes and diasteranes in the selected samples 4B and 12B.

Figure 10

m/z 191 mass chromatograms showing the distribution of terpanes and hopanes in the EE-1 Well samples 4B and 12B.12B.

Biomarker maturity parameters computed for the studied well samples.

Sample ID Ts /Tm Mor / Hop αββ/αββ+ααα C29 Sterane 22S/22S+22R MPI-1 DMN TMN-1 MDBT
1B 0.22 0.26 0.28 0.37 1.72 3.56 0.89 2.98
2B 0.25 0.26 0.25 0.34 1.46 2.96 0.73 3.35
4B 0.35 0.48 0.06 0.40 1.75 4.19 0.91 2.83
6B 0.32 0.29 0.21 0.38 1.37 4.04 1.13 3.11
7B 0.27 0.22 0.24 0.42 1.41 3.53 0.97 6.21
8B 0.34 0.18 0.23 0.46 1.35 2.25 1.06 1.81
9B 0.32 0.16 0.18 0.48 1.48 3.74 1.05 1.98
10B 0.35 0.14 0.30 0.57 1.12 3.01 1.17 0.82
11B 0.48 0.13 0.34 0.60 1.16 3.33 0.79 1.07
12B 0.50 0.11 0.44 0.58 1.01 3.25 0.67 1.51
14B 0.44 0.14 0.35 0.58 1.28 4.96 1.11 2.19
15B 0.45 0.10 0.42 0.59 1.32 4.36 0.79 1.47

Abbreviations: Ts/(Ts+Tm), trisnorneohopanes/trisnorhopanes ratio; Mor/Hop, 17β, 21α (H)Mortane/17 α, 21β (H) hopane ratio; 22S/22S+22R, 22S/22S+22R extended hopanes ratio; MPI-1 - methyl – phenanthrene index, 1,5 (2MP + 3MP) / (P + 1MP + 9MP); DMN – dimethyl naphthalene ratio, 2, 6 DMN + 2,7 DMN)/1,5 DMN; TMN-1 – trimethyl naphthalene ratio, (1,3,7 TMN)/(1,3,7 TMN + 1,2,5 TMN); MDBT – methyl-dibenzothiopene ratio, 4MDBT/1MDBT.

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].

Depositional environment

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.

Source and depositional environment parameters computed from the saturate biomarkers of the EE-1 well.

Sample ID %C27 Sterane %C28 Sterane %C29 Sterane C21T/C23T C23T/C24T Hop/Ster dia/reg Ole/Hop Gam/Hop C24 Tet / (C26 (S+R) + C24 Tet) C25/C26 (S+R) C35/C31–C35 Hom
1B 33.50% 19.68% 46.82% 0.58 1.49 4.13 0.18 0.1 0.08 0.52 0.69 0.06
2B 34.79% 22.11% 43.10% 0.8 1.59 2.99 0.15 0.11 0.1 0.49 0.54 0.14
4B 27.36% 19.31% 53.33% 0.49 1.33 1.98 0.28 0.62 0.04 0.6 0.48 0.05
6B 33.10% 20.73% 46.18% 0.82 1.66 1.62 0.21 0.42 0.05 0.62 0.89 0.05
7B 33.35% 20.97% 45.68% 0.78 1.39 3.65 0.27 0.29 0.04 0.67 0.48 0.05
8B 36.81% 21.02% 42.17% 0.62 1.73 4.1 0.23 0.33 0.04 0.64 0.41 0.05
9B 36.85% 25.19% 37.96% 0.55 1.98 1.53 0.13 0.21 0.04 0.6 0.44 0.07
10B 40.18% 25.85% 33.97% 0.33 3.45 6.04 0.33 0.07 0.04 0.52 0.69 0.09
11B 38.09% 24.36% 37.55% 0.39 3.1 11.45 0.42 0.04 0.03 0.72 0.67 0.06
12B 38.86% 27.19% 33.95% 0.36 2.57 16.11 0.48 0.06 0.04 0.45 0.67 0.09
14B 36.49% 23.80% 39.71% 0.46 1.91 6.27 0.35 0.14 0.06 0.5 0.56 0.11
15B 37.53% 41.63% 45.42% 0.37 1.92 6.91 0.38 0.08 0.09 0.45 0.63 0.17

Abbreviations: Ole/Hop, oleanane index; Hop/Ster, hopane/sterane ratio; dia/reg, diasterane index; Gam/Hop, gammacerane index; C35/C31–C35 Hom, homohopane index; C25/C26(S+R), C25/C26(S+R) trycyclic terpane ratio; C24 Tet / (C26 (S+R) + C24 Tet), tetracyclic terpane ratio.

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

Ternary plot showing distribution of C27, C28, and C29 steranes for EE-1 Well. (After Huang and Meinschein [49]).

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].

Conclusions

Subsurface samples from EE-1 Well, offshore Eastern Dahomey Basin, have been analysed for their lithofacies distribution, hydrocarbon potentials, and paleodepositional environment based on Rock-Eval studies and biomarker evaluation. The sediments have adequate to excellent source rock potential. Organic matter type indicated the presence of mainly types II and III kerogen, implying a prospect to generate both oil and gas at appropriate thermal maturity. Evaluations of saturate and aromatic biomarker parameters indicate the thermal immaturity status, organic matter of mixed terrigenous and marine origin with higher terrigenous input, as well as deposition under oxic – suboxic conditions. It can be deduced that the sediments have adequate organic richness, deposited under mixed marine/terrigenous environment under oxic – suboxic conditions with significant terrestrial organic matter input and potential to generate both oil and gas at appropriate thermal maturity.

Figure 1

Regional map of four countries showing the location of the Benin (Dahomey) Basin in the Gulf of Guinea [11].
Regional map of four countries showing the location of the Benin (Dahomey) Basin in the Gulf of Guinea [11].

Figure 2

Dahomey embayment showing the study area (after d’Almeida et al. [14]).
Dahomey embayment showing the study area (after d’Almeida et al. [14]).

Figure 3

Lithological log of the studied section of EE-1 Well.
Lithological log of the studied section of EE-1 Well.

Figure 4

A cross plot of hydrogen index (HI) versus oxygen index (OI) showing that the organic matter of the studied well is of types II and type III kerogen (Modified after Van Krevelen [29]).
A cross plot of hydrogen index (HI) versus oxygen index (OI) showing that the organic matter of the studied well is of types II and type III kerogen (Modified after Van Krevelen [29]).

Figure 5

A cross plot of remaining hydrocarbon potential (S2) against total organic content (TOC) showing the organic matter type and origin (after Jackson et al. [30]).
A cross plot of remaining hydrocarbon potential (S2) against total organic content (TOC) showing the organic matter type and origin (after Jackson et al. [30]).

Figure 6

Plot of hydrogen index (HI) against Tmax showing that the kerogen is in the immature window [33].
Plot of hydrogen index (HI) against Tmax showing that the kerogen is in the immature window [33].

Figure 7

Total ion chromatograms showing the distribution of the saturated hydrocarbon fraction of representative Samples 4B and 6B from the study well.
Total ion chromatograms showing the distribution of the saturated hydrocarbon fraction of representative Samples 4B and 6B from the study well.

Figure 8

Cross plot of Pr/n-C17 versus Ph/n-C18 showing the sources of organic matter and the depositional environment (Modified after Cortes et al. [39]).
Cross plot of Pr/n-C17 versus Ph/n-C18 showing the sources of organic matter and the depositional environment (Modified after Cortes et al. [39]).

Figure 9

m/z 217 mass chromatograms showing the distribution of steranes and diasteranes in the selected samples 4B and 12B.
m/z 217 mass chromatograms showing the distribution of steranes and diasteranes in the selected samples 4B and 12B.

Figure 10

m/z 191 mass chromatograms showing the distribution of terpanes and hopanes in the EE-1 Well samples 4B and 12B.12B.
m/z 191 mass chromatograms showing the distribution of terpanes and hopanes in the EE-1 Well samples 4B and 12B.12B.

Figure 11

Ternary plot showing distribution of C27, C28, and C29 steranes for EE-1 Well. (After Huang and Meinschein [49]).
Ternary plot showing distribution of C27, C28, and C29 steranes for EE-1 Well. (After Huang and Meinschein [49]).

Data showing values of isoprenoids, isoprenoids/n-alkane ratios and other parameters for EE-1 well.

Sample ID Pr/Ph Pr/n-C17 Ph/n-C18 CPI OEP-1 OEP-2
1B 1.47 0.98 0.62 1.93 0.51 0.83
2B 1.74 1.20 0.90 1.66 0.45 0.76
4B 2.38 2.41 1.08 1.70 0.51 0.8
6B 2.05 2.99 1.83 1.51 0.46 0.62
7B 3.20 2.42 1.40 1.67 0.53 0.7
8B 2.33 1.58 0.76 1.23 0.39 0.51
9B 1.49 2.31 1.55 1.27 0.47 0.49
10B 1.78 1.24 0.63 1.01 0.35 0.41
11B 2.20 0.99 0.51 1.12 0.39 0.44
12B 1.65 0.92 0.54 1.04 0.37 0.4
14B 1.94 0.60 0.46 0.37 0.4 0.08
15B 1.80 0.80 0.42 1.12 0.41 0.42

Results of TOC and Rock-Eval Pyrolysis of the studied samples.

Sample ID Depth (m) SOM (ppm) TOC S1 S2 S3 Tmax Calc. %Ro GP (S1 + S2) HI OI SOM/TOC S1/TOC PI
S1 1240 676.12 1.14 0.13 1.11 2.23 423 0.45 1.24 97 196 59.31 11 0.10
S2 1340 2004.31 1.01 0.16 1.02 2.36 422 0.44 1.18 101 234 198.45 16 0.14
S3 1410 ND 1.19 0.16 1.31 2.78 425 0.49 1.47 110 234 ND 13 0.11
S4 1480 1417.71 1.41 0.19 1.93 2.55 428 0.54 2.12 137 181 100.55 13 0.09
S5 1560 ND 0.96 0.15 1.15 2.51 429 0.56 1.3 120 262 ND 16 0.12
S6 1620 2456.23 0.97 0.15 1.26 1.96 429 0.56 1.41 131 203 43.03 16 0.11
S7 1700 2883.85 1.02 0.21 1.66 2.79 427 0.53 1.87 163 274 13.04 21 0.11
S8 1760 1835.19 1.47 0.25 2.60 2.39 430 0.58 2.85 177 163 15.28 17 0.09
S9 1830 1599.37 1.94 0.34 5.84 2.51 426 0.51 6.18 301 129 11.96 18 0.06
S10 1906 1205.55 2.63 0.93 8.24 2.53 427 0.53 9.17 313 96 6.13 35 0.10
S11 1965 2698.84 1.91 1.00 4.11 2.51 431 0.60 5.11 215 131 23.64 52 0.20
S12 2040 1826.01 2.03 0.95 2.99 3.29 425 0.49 3.94 147 162 6.28 47 0.24
S13 2118 ND 1.18 0.39 2.94 2.30 429 0.56 3.33 249 195 ND 33 0.12
S14 2180 2143.91 1.15 0.63 3.25 2.79 422 0.44 3.88 283 243 186.43 55 0.16
S15 2257.5 1978.45 8.92 1.35 43.18 3.15 426 0.51 44.53 484 35 22.18 15 0.03

Source and depositional environment parameters computed from the saturate biomarkers of the EE-1 well.

Sample ID %C27 Sterane %C28 Sterane %C29 Sterane C21T/C23T C23T/C24T Hop/Ster dia/reg Ole/Hop Gam/Hop C24 Tet / (C26 (S+R) + C24 Tet) C25/C26 (S+R) C35/C31–C35 Hom
1B 33.50% 19.68% 46.82% 0.58 1.49 4.13 0.18 0.1 0.08 0.52 0.69 0.06
2B 34.79% 22.11% 43.10% 0.8 1.59 2.99 0.15 0.11 0.1 0.49 0.54 0.14
4B 27.36% 19.31% 53.33% 0.49 1.33 1.98 0.28 0.62 0.04 0.6 0.48 0.05
6B 33.10% 20.73% 46.18% 0.82 1.66 1.62 0.21 0.42 0.05 0.62 0.89 0.05
7B 33.35% 20.97% 45.68% 0.78 1.39 3.65 0.27 0.29 0.04 0.67 0.48 0.05
8B 36.81% 21.02% 42.17% 0.62 1.73 4.1 0.23 0.33 0.04 0.64 0.41 0.05
9B 36.85% 25.19% 37.96% 0.55 1.98 1.53 0.13 0.21 0.04 0.6 0.44 0.07
10B 40.18% 25.85% 33.97% 0.33 3.45 6.04 0.33 0.07 0.04 0.52 0.69 0.09
11B 38.09% 24.36% 37.55% 0.39 3.1 11.45 0.42 0.04 0.03 0.72 0.67 0.06
12B 38.86% 27.19% 33.95% 0.36 2.57 16.11 0.48 0.06 0.04 0.45 0.67 0.09
14B 36.49% 23.80% 39.71% 0.46 1.91 6.27 0.35 0.14 0.06 0.5 0.56 0.11
15B 37.53% 41.63% 45.42% 0.37 1.92 6.91 0.38 0.08 0.09 0.45 0.63 0.17

Biomarker maturity parameters computed for the studied well samples.

Sample ID Ts /Tm Mor / Hop αββ/αββ+ααα C29 Sterane 22S/22S+22R MPI-1 DMN TMN-1 MDBT
1B 0.22 0.26 0.28 0.37 1.72 3.56 0.89 2.98
2B 0.25 0.26 0.25 0.34 1.46 2.96 0.73 3.35
4B 0.35 0.48 0.06 0.40 1.75 4.19 0.91 2.83
6B 0.32 0.29 0.21 0.38 1.37 4.04 1.13 3.11
7B 0.27 0.22 0.24 0.42 1.41 3.53 0.97 6.21
8B 0.34 0.18 0.23 0.46 1.35 2.25 1.06 1.81
9B 0.32 0.16 0.18 0.48 1.48 3.74 1.05 1.98
10B 0.35 0.14 0.30 0.57 1.12 3.01 1.17 0.82
11B 0.48 0.13 0.34 0.60 1.16 3.33 0.79 1.07
12B 0.50 0.11 0.44 0.58 1.01 3.25 0.67 1.51
14B 0.44 0.14 0.35 0.58 1.28 4.96 1.11 2.19
15B 0.45 0.10 0.42 0.59 1.32 4.36 0.79 1.47

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