Petroleum geochemistry of Cretaceous outcrops from the Calabar Flank, southeastern Nigeria

Marine and Petroleum Geology 48 (2013) 171e185

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Petroleum geochemistry of Cretaceous outcrops from the Calabar Flank, southeastern Nigeria B.O. Ekpo a, *, N. Essien b, E.P. Fubara c, U.J. Ibok a, E.J. Ukpabio d, H. Wehner e a Environmental and Petroleum Geochemistry Research Group (EPGRG), Department of Pure & Applied Chemistry, University of Calabar, P. O. Box 3766, Calabar 540004, Nigeria b Department of Geology, University of Calabar, P.M.B. 1115, Calabar, Nigeria c Department of Chemistry, Rivers State University of Education, Port Harcourt, Nigeria d TDI Brooks, Nigeria e Federal Institute for Geosciences and Natural Resources, Hannover, Germany

a r t i c l e i n f o

a b s t r a c t

Article history: Received 30 July 2012 Received in revised form 26 July 2013 Accepted 12 August 2013 Available online 21 August 2013

A combined geochemical and molecular characterisation of a wide section of Cretaceous outcrop sedimentary rocks (with no significant effects of weathering) from the Calabar Flank, southeastern Nigeria has been undertaken for petroleum potential evaluation. Rock-Eval pyrolysis and lipid biomarkers show organic matter (OM) to contain varying proportions of marine and continental materials. OM content in the samples is variable. Low values of total organic carbon (TOC) ranging from 0.01to 9.49% with varying extractability (44e4215 ppm), low hydrogen indices (HI ¼ 10e190 mg hydrocarbons (HC)/g TOC, Tmax in the range 414  Ce460  C, and vitrinite reflectance values from 0.41% to 0.47% Ro were obtained indicating immature to marginally mature terrestrially derived OM of type III kerogen. Awi Formation of Aptianmiddle Albian age with an average genetic potential of 4.3 kg HC/ton rock, has the highest potential for oil/gas. 13C/12C ratios of the kerogen, biomarker distribution pattern, and some specific compound ratios (Ts/Tm, oleanane/C30-hopane, C31-22S/22R þ 22S homohopane, and moretane/C30-hopane are useful in determining the source and thermal maturity of the OM. The ConiacianeCampanianeMaastrichian black shales of New Netim and Nkporo Formations differ significantly from other formations because of the presence of oleanane which may serve to delineate the late Upper Cretaceous boundary. Ó 2013 Elsevier Ltd. All rights reserved.

Keywords: Geochemistry Petroleum potential Calabar Flank Outcrop sediments Oleanane Nigeria

1. Introduction The term Calabar Flank was first proposed by Murat (1972) for that part of the southern sedimentary basin in the Niger Delta of Nigeria characterised by crustal block faulting (Fig. 1). It was formed by incipient rifting during the breakaway of South America from Africa and the opening of the South Atlantic in Albian times (Whiteman, 1982) with the basement structures that align parallel to those underlying the coastal basins of Gabon, Congo and Angola. The structures in these basins formed during the opening of the South Atlantic Ocean are similar, except for the absence of evaporites in the Calabar Flank which were prevented from deposition by the Guinea Ridge (De Ruiter, 1978). There is considerable lithologic similarity including carbonate development between the West African South Atlantic Coastal basins and the Calabar Flank. They are therefore classified as components of a typical divergent, rafted

* Corresponding author. Tel.: þ234 08037183898 (mobile). E-mail address: [email protected] (B.O. Ekpo). 0264-8172/$ e see front matter Ó 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.marpetgeo.2013.08.011

continental margin, and in general can be linked to a single evolutionary geologic history. The Cretaceous sedimentary rocks of the Calabar Flank are unique in that the whole Upper Cretaceous sequence is exposed in outcrops within a narrow strip of about 8 km. The Cretaceous rocks are important targets in deep sea drilling projects, for instance, in the marginal basins of Brazil and West Africa: Gabon, Cabinda and Angola, the Cretaceous rocks are important source rocks (Mello et al., 1988a,b; 1989, 1991). Similar potential source rocks exist in the Calabar Flank with no hydrocarbon discoveries made so far. Therefore, the recent discovery of oil seeps in the Calabar Flank has generated renewed interest in appraising the petroleum potential of the area. For a better understanding of the hydrocarbon generation potential of the Calabar Flank, we conducted detailed geochemical and organic petrographic studies with the aim of reconstructing paleoenvironmental control on the deposition of organic-rich shales in the Calabar Flank. Previous studies on the Cretaceous sedimentary rocks that outcrops in the Calabar Flank are mostly limited to geological descriptions (Adeleye and Fayose, 1978; Petters, 1982;

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Figure 1. The map of Niger Delta showing structural elements and the Calabar Flank in relation to other sedimentary basins in Nigeria. Adapted from Nyong and Ramanathan (1985).

Reyment, 1965; Petters et al., 1995). Preliminary geochemical studies include organic geochemical appraisal (Essien et al., 2005), geochemical studies of subsurface limestone (Ekwere, 1993) and geochemistry and organic petrography (Ekpo et al., 2012). This paper aims at demonstrating the use of Rock-Eval pyrolysis and biomarker data in elucidating the source (marine or terrigenous), quality, maturation status and depositional environment of the Calabar Flank Cretaceous sedimentary rocks with a view to comparing on a regional basis our data with that of the marginal basins of Brazil and West Africa: Gabon, Cabinda and Angola. Detailed studies of this kind have not been conducted for this region and the results will provide a better understanding of the petroleum potential of this sedimentary basin and may serve as one of exploration inland frontier basins that would lead to a major petroleum exploration direction in Nigeria. 2. Geology of the study area The Calabar Flank is that part of the southern Nigerian sedimentary basin characterised by crustal block faulting and is bounded by the Oban Massif to the north and the Calabar hinge line delineating the Niger Delta basin in the south (Fig. 2). It is also separated from the Ikpe platform to the west by a NEeSW trending fault. In the east, it extends up to the Cameroon volcanic ridge. The Cretaceous shales exposed in the Calabar Flank are unique in that the whole Upper Cretaceous sequence is exposed in outcrops within a narrow strip of about 8 km. The total sediment thickness is over 3500 m, with a featheredge of outcrops north of Calabar along the margin of the Oban basement (Fig. 2). The ages of the sedimentary rocks in the Calabar Flank range from Aptian to Campanian-Maastrichtian. Sedimentation started with deposition of the Awi Formation (Adeleye and Fayose, 1978) consisting of fluvio-deltaic shales, mudstone, and arkosic sandstone, dated to be of Aptian age. This stratigraphic unit unconformably overlies the basement complex (Fig. 2). The Awi Formation is directly overlain by platform carbonates of the Mfamosing Limestone Formation (Petters, 1982), deposited in various

environmental settings during the first significant marine transgression in the Gulf of Guinea in Mid-Albian times. A hard ground separates the carbonate build up from a thick sequence of black, highly fissile shales with minor intercalations of marls, calcareous mudstones and shell beds belonging to the Ekenkpong and New Netim Formations and this thick sequence spans late AlbianCenomanian-Turonian age. Santonian and early Campanian sedimentary rocks have not been reported in the Calabar Flank, probably representing a period of non-deposition and/or erosion. Cretaceous rocks in the Flank are capped by dark grey carbonaceous, friable shales with intercalation of mudstone and gypsiferous beds of the Nkporo Shale (Reyment, 1965). The Nkporo Shale Formation is late Campanian-Maastrichtian in age and was deposited in various environmental settings including shallow open marine, paralic and continental regimes. The lithostratigraphy of the Calabar Flank outcrops is shown in Figure 3. In the Calabar Flank, evidence from ammonites and planktonic foraminifera (Nyong and Ramanathan, 1985) support the presence of three major transgressive episodes with oxygen-deficient conditions that resulted in the deposition of dark-coloured organicrich shales during the BarremianeAptianeAlbian, Cenomaniane Turonian and, to a lesser extent, ConiacianeSantonian stages. The basement structures of the Calabar Flank are aligned parallel to those of the coastal basins of Gabon, Congo and Angola. These structures were produced during the opening of the South Atlantic Ocean. Except for the absence of evaporites which were closed off from the Calabar Flank by the Guinea Ridge (De Ruiter, 1978), there are considerable lithologic similarities including carbonate development between the southerly West African coastal basins and the Calabar Flank. They are classified as components of a typical divergent, rafted continental margin and in general can be linked to a single evolutionary geologic history. 3. Experimental methods Forty-two outcrop samples were taken to represent different sedimentary facies (Table 1, Fig. 4). As weathering is always a factor

B.O. Ekpo et al. / Marine and Petroleum Geology 48 (2013) 171e185

173

Figure 2. Idealised geological cross-section of the Calabar Flank showing the main structural features and sequences. Adapted from Nyong and Ramanathan (1985).

of concern for geochemical studies of outcrop samples, the weathered rock surface was exploded off with dynamite before samples were taken. The inner core of the rocks was used and the outer rim discarded. Care was also taken to sample fresh road cuts. Prior to analysis, the samples were scrubbed and exhaustively cleaned with distilled water to remove traces of surficial dirt and plant growth. The rocks were dried at 35  C for 12 h, grounded in a disc mill and subsequently sieved through 200 mm mesh size. Separate portions were analysed as detailed below. The TOC content was measured using a LECO CS-444 analyser. Powdered shale samples (0.18 g) were treated with 2N HCl for the removal of inorganic carbon. Subsequently, the samples were oven

dried at 60  C for 24 h. The combustion took place in an oxygen atmosphere at a temperature of 1800  C. Two replicate analyses were performed for each sample (precision  2%). Rock-Eval pyrolysis was performed on the whole powdered ditch cutting samples using a Rock-Eval 5 Delsi instrument (Espitalie et al., 1977). To reduce the level of contamination during the analysis of the lipids, all glasses were cleaned with soap and water, rinsed with distilled water, heated in an oven at 550  C for 8 h and preextracted with hexane and acetone mixture to get rid of any traces of surficial organic matter. The thimbles and the glass wool were pre-extracted before use for sample extraction. The powdered samples (50 g) were extracted with n-hexane-acetone (1:1) mixture in a SOXTEC system for 18 h. The extracts obtained are a measure of the amount of soluble organic matter (SOM). The asphaltenes were removed from the extracts by precipitation with petroleum-ether (bp 40e60  C, Wehner and Teschner, 1981). The separation of the deasphalted extracts into saturated, aromatic and heterocompounds (resins or NSO-compounds) was carried out by liquid chromatography using silica-gel (70/230 mesh, activated 6 h at 400  C) and aluminium oxide (neutral, activated 2 h at 700  C). nHexane (50 ml) was used to elute the saturated (aliphatic hydrocarbons) and dichloromethane (50 ml) to elute the aromatic fractions (monoaromatic and polycyclic aromatic hydrocarbons). Finally, the mixture, (1:2) methanol-dichloromethane (50 ml) was used to remove the heterocompounds The saturated hydrocarbons were analysed by gas chromatography (GC) using a HewlettePackard 5890 gas chromatograph equipped with a fused-silica capillary column (30 m  0.25 mm) coated with a 0.25 mm film of DB-5MS, programmed from 60 to 295  C at 3  C/min. The carrier gas was helium at 30 cm/s flow rate. The gas chromatography-mass spectrometry (GCeMS) analysis of the saturated fractions was carried out using a HewlettePackard 5972 Mass Selective Detector (m/z 50e500 at 1 scan per sec), to monitor selected fragment ions characteristic of tricyclic and pentacyclic terpane (m/z 191) and sterane biomarkers (m/z 217) respectively. 4. Results 4.1. Bulk geochemical data

Figure 3. Lithostratigraphy of the Calabar Flank.

The TOC content, SOM content, hydrogen index (HI), generation potential (GP), vitrinite reflectance (Ro) and Tmax data for the

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Table 1 Content of organic carbon, solubles and bulk composition of extract from Cretaceous outcrop sedimentary rocks from the Calabar Flank, South Eastern Nigeria. Co-Nr.

40893 40894 40895 40896 40897 40898 40899 40900 40901 40902 40903 40904 40905 40906 40907 40908 40909 40886 40887 40888 40889 40890 40891 40892 40881 40882 40883 40884 40885 40875 40876 40877 40878 40879 40880 40870 40871 40872 40873 40874 40868 40869

Old name

Solvent extraction

NK-1 NK-2a NK-2b NK-2c NK-2d NK-2e NK-2f NK-2g NK-2h NK-3a NK-3b NK-3c NK-3d NK-3e NK-3f NK-4 NK-5 NN-1 NN-2 NN-3a NN-3b NN-3c NN-3d NN-3e EK-1 EK-2 EK-3 EK-4 EK-5 MF-1 MF-2 MF-3 MF-4 MF-5 MF-6 AW-1a AW-1b AW-1c AW-1d AW-1e AW-2a AW-2b

TOC

SOM

(%)

(ppm)

2.06 3.83 1.69 2.00 1.79 1.67 1.82 1.38 1.68 1.78 1.68 1.74 1.38 1.34 1.78 1.59 0.56 0.11 0.16 0.46 0.65 0.44 0.65 0.43 0.70 0.62 1.54 1.01 2.10 0.10 0.20 0.13 0.13 0.10 0.08 8.01 3.13 1.93 9.87 9.49 0.12 0.13

775 2145 846 1361 1037 1378 1503 847 1122 730 893 844 845 821 1220 750 348 83 104 327 452 299 616 429 416 234 540 260 641 124 58 57 63 57 44 3336 1175 1933 3402 4215 108 97

SOM/TOC

376 560 501 680 579 825 826 614 668 410 531 485 613 613 685 472 622 756 649 710 695 678 948 997 595 377 351 257 305 1240 292 438 482 573 544 416 375 1001 345 444 903 749

Sat

Arom

Het

Asph.

Loss

Sat

Arom

Het

Asph.

(ppm)

(ppm)

(ppm)

(ppm)

(ppm)

%

%

%

%

%

44 175 94 70 56 62 64 94 165 64 58 74 61 84 126 27 310 6 9 31 47 29 48 35 8 5 4 6 4 11 15 14 7 9 15 96 46 36 9 216 15 16

105 486 194 259 68 96 81 194 239 153 160 141 118 115 198 64 31 11 10 49 75 36 94 46 72 42 82 48 92 18 12 14 7 9 15 370 220 1173 542 492 16 11

415 1113 398 571 549 570 638 407 580 204 424 422 414 357 612 462 215 55 66 180 251 186 358 262 136 75 154 66 174 50 22 20 14 32 7 1285 481 367 1611 1295 27 41

23 3 90 429 342 1241 838 46 8 8 30 7 6 56 64 216 76 21 9 19 67 80 48 117 86 211 370 160 460 364 650 720 152 138 192 252 206 253 306 284 238 112

0 0 0 0 0 0 0 0 0 118 0 0 0 0 0 0 0 3 0 0 0 0 0 0 80 11 7 20 71 0 1 2 4 0 1 1496 0 15 0 376 27 27

5.7 8.2 11.1 5.1 5.4 4.5 4.3 11.1 14.7 8.8 6.5 8.8 7.2 10.2 10.3 3.6

13.5 22.7 22.9 19.0 6.6 7.0 5.4 22.9 21.3 21.0 17.9 16.7 14.0 14.0 16.2 8.5 8.9 13.3 9.6 15.0 16.6 12.0 15.3 10.7 17.3 17.9 15.2 18.5 14.4 14.5 20.7 24.6 11.1 15.8 34.1 11.1 18.7 60.7 15.9 11.7 14.8 11.3

53.5 51.9 47.0 42.0 52.9 41.4 42.4 48.1 51.7 27.9 47.5 50.0 49.0 43.5 50.2 61.6 61.8 66.3 63.5 55.0 55.5 62.2 58.1 61.1 32.7 32.1 28.5 25.4 27.1 40.3 37.9 35.1 22.2 56.1 15.9 38.5 40.9 19.0 47.4 30.7 25.0 42.3

3.0 0.1 10.6 31.5 33.0 90.1 55.8 5.4 0.7 1.1 3.4 0.8 0.7 6.8 5.2 28.8 21.8 25.3 8.7 5.8 14.8 26.8 7.8 27.3 20.7 90.2 68.5 61.5 71.8 293.5 1120.7 1263.2 241.3 242.1 436.4 7.6 17.5 13.1 9.0 6.7 220.4 115.5

24.3 17.2 8.3 2.4 2.1 0.0 0.0 12.5 11.6 41.2 24.7 23.7 29.1 25.5 18.0 0.0 7.5 0.0 9.6 14.7 2.7 0.0 11.0 0.0 27.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 40.0 18.9 5.4 27.5 45.7 0.0 0.0

Cretaceous outcrop sedimentary rocks of the Calabar Flank versus age are shown in Figure 5 as a geochemical log. Based on TOC values, the five formations can tentatively be distinguished from the top to bottom. The amount and composition of the OM of the Aptian-middle Albian Awi Formation is highly variable, but still this formation has the highest amount of organic matter. TOC and SOM reach maximum values of 9.89 wt.% and 4215 ppm (sample AW1e) respectively. Variations in TOC contents are similar to those of SOM and HI (Fig. 5). HI and Tmax values (Fig. 5) vary between 15 and 166 mg HC/g TOC and 376  C (sample AW2a, not indicative of the true maturity, but probably influenced from S1 peak) to 460  C (sample MF-6) respectively. The overlying middle-Albian Mfamosing Formation displays uniformity in TOC, SOM and HI values which are lower than 0.2wt.%, 124 ppm and 40 mg HC/g TOC respectively (Fig. 5). The Cenomanian-Turonian Ekenkpon Formation shows fluctuations in TOC (0.62e2.10 wt. %) which correlate with SOM (234e 641 ppm) and HI (13e162 mg HC/g TOC)(Fig. 4). Tmax values range between 427  C and 438  C (Table 2). The Coniacian New Netim marl Formation (Fig. 5) reveals rather uniform and low TOC (0.11e0.65wt.%) and SOM contents (83e

7.2 8.7 9.5 10.4 9.7 7.8 8.2 1.9 2.1 0.7 2.3 0.6 8.9 25.9 24.6 11.1 15.8 34.1 2.9 3.9 1.9 0.3 5.1 13.9 16.5

Loss

Total HC

S/A

149 662 287 329 124 158 145 288 404 216 218 215 179 198 324 91 62 16 19 80 122 65 141 81 144 84 163 97 183 28 28 27 15 18 30 466 265 1209 551 708 31 27

0.42 0.36 0.48 0.27 0.83 0.65 0.78 0.48 0.69 0.42 0.36 0.53 0.52 0.73 0.64 0.43 0.99 0.54 0.95 0.62 0.62 0.80 0.51 0.77 1.00 1.00 1.00 1.00 1.00 0.60 1.21 1.00 1.00 1.00 1.00 0.26 0.21 0.03 0.02 0.44 0.94 1.42

616 ppm). The striking feature is the values of HI (Fig. 5) which range from 131 to 190 mg HC/g TOC), the highest recorded in the Calabar Flank, but less than 200 mg HC/g TOC which classify the unit as gas-prone, Type III organic matter. Tmax values are uniform and range from (434  Ce443  C). The Campanian-Maastrichtian Nkporo Formation is characterised by TOC contents between 0.50 and 3.83wt.% (Fig. 5) which are parallel to those of the SOMvalues (348e2145 ppm) and low HI values (<44 mg HC/g TOC). The relative composition of the extracts is shown in the ternary diagram (Fig. 6). A strong predominance of the NSO compounds over the saturated and aromatic hydrocarbons is revealed. The saturated-to-aromatic (Sat/Arom) hydrocarbon ratio in the entire sample suites is less than 1.5 (Table 1) which suggests immaturity of the samples. The petroleum potential and free hydrocarbon content of the entire sample suite is indicated by the S2 and S1 Rock-Eval parameters respectively (Table 2). The SOM content is dependent on the TOC content. The low petroleum potentials for most of the samples (Fig. 7) with S2 in the range of 0.02e2.00 kg HC/ton rock corroborate the mineralogical composition of the samples containing illite and carbonate (w50%) (Ekpo et al., 2012).

B.O. Ekpo et al. / Marine and Petroleum Geology 48 (2013) 171e185

Figure 4. Geological map of the Calabar Flank showing sample locations. Adapted from Nyong and Ramanathan (1985).

Figure 5. Geochemical log of Cretaceous outcrop sedimentary rocks from the Calabar Flank.

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Table 2 Rock-Eval pyrolysis and vitrinite reflectance data for Cretaceous outcrop sedimentary rocks from the Calabar Flank, South Eastern Nigeria. Sample TOC% S1 S2 PI code (ppm) (ppm)

HI(mg GP(kg HC/ Tmax(oC) %Ro HC/g TOC) t rock)

NK-1 NK-2a NK-2b NK-2c NK-2d NK-2e NK-2f NK-2g NK-2h NK-3a NK-3b NK-3c NK-3d NK-3e NK-3f NK-4 NK-5 NN-1 NN-2 NN-3a NN-3b NN-3c NN-3d NN-3e EK-1 EK-2 EK-3 EK-4 EK-5 MF-1 MF-2 MF-3 MF-4 MF-5 MF-6 AW-1a AW-1b AW-1c AW-1d AW-1e AW-2a AW-2b

51 55 22 54 32 44 45 24 22 19 23 31 23 29 29 13 21 36 37 152 150 131 166 190 162 54 84 13 28 40 e 30 30 20 25 106 30 10 88 104 16 15

2.06 3.83 1.69 2.00 1.79 1.67 1.82 1.38 1.68 1.78 1.68 1.74 1.38 1.34 1.78 1.59 0.56 0.11 0.16 0.46 0.65 0.44 0.65 0.43 0.70 0.62 1.54 1.01 2.10 0.10 0.20 0.13 0.13 0.10 0.08 8.01 3.13 1.93 9.87 9.49 0.12 0.13

0.30 0.07 0.09 0.16 0.09 0.38 0.34 0.15 0.27 0.17 0.22 0.23 0.19 0.16 0.08 0.22 0.11 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.03 0.11 0.21 0.18 0.00 e 0.00 0.00 0.00 0.00 0.35 0.07 0.03 0.33 0.63 0.02 0.00

1.06 2.14 0.38 1.08 0.58 0.74 0.82 0.34 0.38 0.34 0.40 0.54 0.32 0.4 0.52 0.22 0.12 0.04 0.06 0.70 0.98 0.58 1.08 0.82 1.14 0.34 1.30 0.14 0.60 0.04 e 0.04 0.04 0.02 0.02 8.52 0.96 0.20 8.70 9.92 0.02 0.02

0.22 0.03 0.20 0.13 0.14 0.34 0.29 0.31 0.42 0.34 0.35 0.30 0.38 0.29 0.13 0.50 0.50 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.08 0.08 0.62 0.23 0.00 e 0.00 0.00 0.00 0.00 0.04 0.07 0.14 0.04 0.06 0.50 0.00

1.36 2.21 0.47 1.24 0.67 1.12 1.16 0.49 0.65 0.51 0.62 0.77 0.51 0.56 0.60 0.44 0.23 0.04 0.06 0.70 0.98 0.58 1.09 0.82 1.14 0.37 1.41 0.35 0.78 0.04 0.00 0.04 0.04 0.02 0.02 8.87 1.03 0.23 9.03 10.55 0.04 0.02

433 419 419 425 414 421 419 421 417 428 419 421 423 425 423 423 427 434 443 436 435 438 434 434 435 428 442 438 427 447 e 445 440 445 460 443 437 440 442 445 376 451

0.44 0.42 0.44 0.40 0.46 0.42 0.44 0.39 0.35 0.45 0.44 0.45 0.41 0.42 0.41 0.43 0.43 0.44 e 0.40 0.38 0.40 e 0.47 0.44 0.42 0.47 0.41 0.44 0.42 0.41 0.43 0.45 0.35 e 0.55 0.62 0.60 0.57 0.57 0.41 0.40

Figure 7. Variation of the Rock-Eval S2 pyrolysis parameter with TOC.

The relationship between SOM and TOC contents (Fig. 8) is useful in the assessment of the petroleum potential of the sample suites showing majority of the samples plotting within the source rock zone. For example, most of Mfamosing and a few samples from Awi and New Netim Formations are classified as barren source rocks while majority of the samples from the Ekenkpon and New Netim are considered to be poor source rocks (Fig. 8a). The plot of TPH and TOC (Fig. 8b) further discriminates the samples suites as having potential to generate gas. Similarities in organic facies within the different formations may account for the clustering of the samples. Awi Formation samples show the highest potential to generate gas (Fig. 8b) with an average generation potential of 4.0 kg HC/ton rock. Generally, there is an increasing potential for petroleum generation with increasing age. 4.2. Hydrocarbons

HET Geologic Formations

100

0

Awi Sandstones Mfamosing Limestones

90

10

Ekenkpon Shales New Netim Marls 80

20

Nkporo Shales

70

30

60

40

50

50

40

60

30

70

20

80

10

90

0

100

SAT

AROM 0

10

20

30

40

50

60

70

80

90

100

Figure 6. Ternary diagram comparing contents of saturated hydrocarbons, aromatic hydrocarbons and nonhydrocarbons (NSO) in extracts Cretaceous outcrop sedimentary rocks from the Calabar Flank.

The gas chromatograms and two fragmentograms (m/z 191 and 217) of saturated hydrocarbon fractions of some samples are presented in Figure 9AeE. The biomarker peaks are identified on Table 3. The n-alkanes, which are prominent components of the aliphatic hydrocarbon fraction in all the samples, show considerable variation in amount and distribution. In all the samples, the low and high molecular weight n-alkanes are completely absent. The medium molecular weight n-alkanes (with a maximum at n-C19 to n-C23) are relatively lower than or in similar abundance to the triterpanes and steranes which are also evident in most of the samples. The Nkporo Formation samples show n-alkane distribution pattern with medium molecular weight compounds (maximising at n-C21 e n-C23) with odd/even carbon predominance (Fig. 9A). Phytane is greater in abundance than pristane, and in some samples phytane is the most abundant alkane. The ratios of nC17/Ph, n- C18/Pr and Pr/Ph vary between 0.24 and 1.0, 0.31 and 1.43 and 0.24 and 0.83 respectively. The C19 e C20 regular acyclic isoprenoids are significant components of the saturated hydrocarbon fractions. Samples from the Ekenkpon Formation show n-alkane distribution pattern (Fig. 9B) with medium molecular weight compounds (maximising at n-C22 and n-C23) with a slight odd/even carbon predominance. The phytane is greater in abundance than pristane. The n-C17/Pr, n-C18/

B.O. Ekpo et al. / Marine and Petroleum Geology 48 (2013) 171e185

177

EXCELLENT

100000

GOOD

(b)

100

VERY POOR

(a)

Lean to Barren Source Rocks

FAIR

1000

POOR

TPH(ppm)

VERY GOOD

10000

10 0.1

1

TOC (%)

10

100

Figure 8. (a): Soluble organic matter vs total organic carbon, showing source-rock potentials. (b) Hydrocarbon vs Total organic carbon, showing source-rock richness.

Ph and Pr/Ph ratios for the Ekenkpon Formation are 0.49e1.00, 0.85e3.64 and 0.00e0.30 respectively. The New Netim Formation samples are characterised by medium molecular weight n-alkanes (with a maximum at n-C20) with slight even/odd carbon predominance (Fig. 9C). Phytane is higher in abundance than pristane. The n-C17/Pr, n-C18/Ph and Pr/Ph ratios vary between 0.00 and 1.00, 0.00 and 0.09 and 0.00 and 0.54 respectively. The Mfamosing Formation samples are characterised by medium molecular weight n-alkanes maximising at n-C19, slight even/ odd carbon predominance with phytane > pristane, (Fig. 9D). The n-C17/Pr, n-C18/Ph and Pr/Ph ratios vary between 0.46 and 1.00, 0.92 and 1.71 and 0.28 and 0.54, respectively. Samples from the Awi Formation show n-alkane distribution pattern with predominance of medium molecular weight compounds (n-C15 e n-C23), slight odd/even predominance and pristane > phytane in most of the samples (Fig. 9E). Generally, nC17/Pr and n-C18/Ph ratios vary between 0.31 and 0.97 and between 0.99 and 2.88 respectively. Pristane/phytane ratios vary between 0.36 and 2.28.

5a(H), 14a(H), 17a(H), 20R steranes, indicative of clay-rich source rocks (Grantham and Wakefield, 1988). A series of 20R and 20S C27 to C29 diasteranes are also present, but in lower amounts than the corresponding steranes. Samples from Awi Formation have low abundance of steranes. The C27sterane dominance over C28 and C29 counterparts (in some samples C29 dominance), was observed. Low abundance of steranes with C29 dominance relative to C27 and C28 counterparts was observed in the Mfamosing Formation samples. A few samples show C27 > C28 and C29 steranes. The Ekenkpon Formation samples have no steranes and low concentrations of diasteranes with dominance of C29steranes relative to C27-and C28-counterparts. Samples from the New Netim Formation exhibit high abundance of steranes and dominance of C27-steranes relative to C28- and C29 counterparts. The Nkporo Formation samples are characterised by moderate abundance of steranes with C27 and C29 dominance. 5. Discussion 5.1. Organic matter richness

4.3. Hopanoid hydrocarbons The hopane distributions, displayed as partial mass chromatograms m/z 191 (Fig. 9AeE), extend up to C35. The 17a(H), 21b(H)hopane (C30) and/or 17a(H), 21b(H)-norhopane (C29) are higher in abundance than the C27(Ts), and C31 e C35 homologues. The C31 e C35 homologues are resolved at the C22 position into S and R epimers. 18a(H)-18b(H)-oleanane occurs only in notable amounts in organic rich samples of the Nkporo and the New Netim Formation. Except for this compound, only minor variations in the proportions of individual hopanes can be observed from sample to sample, for instance, taking into account the Ts < Tm ratio and the low abundance of gammacerane. 4.4. Steroid hydrocarbons The sterane distributions displayed as partial mass chromatograms m/z 217 (Fig. 9AeE) are dominated by the C27, C28 and C29

From the bulk geochemical data such as TOC and SOM, (Fig. 5) most of the samples, except those at the basement boundary and from the Mfamosing Formation have TOC contents higher than 0.5wt.% with high extractibility >500 ppm, the minimum requirements for source rocks. The TOC content of Mfamosing samples is < 0.5wt.% and the extractability is <125 ppm, hence they are classified as non-source rocks. For the Ekenkpon shales the TOC content is > 0.5 wt.%, therefore, they are considered to be poorquality source rocks (Tissot and Welte, 1984; Peters and Moldowan, 1993). Samples from the New Netim Formation with exception of samples NN3b and NN3d contain a low amount (<0.5wt.%) of organic carbon. This unit exhibits a fair source characteristic for SOM (83e616 ppm) and hydrocarbons (16e 141 ppm). The black shales of Nkporo Formation are characterised by a TOC content >0.5wt.%. The extractability and hence the proportion of hydrocarbons in the extracts are also high enough to qualify the samples as fair-quality source rocks.

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5.2. Organic matter quality In order to interpret the organic data in terms of paleoenvironmental changes and quality of the OM, information about the composition of the OM which discriminate between marine and terrigenous sources is necessary (Stein, 1991). The

results of Rock-Eval pyrolysis, e.g. (HI values), offer the first approach (Espitalie et al., 1977). In immature sedimentary rocks, OM dominated by marine components has HI values of 200e 400 mg HC/g TOC or less (Stein, 1991). Pyrolysis methods, however, have their limitations in highly mature organic carbonlean sediments (Peters, 1986), therefore, interpretation should

Figure 9. Gas chromatography (gc) and two gcems (m/z ¼ 191) and (m/z ¼ 217) fragmentograms of saturated hydrocarbons in Cretaceous sedimentary rocks from the Calabar Flank, South Eastern Nigeria. A) Nkporo Formation; B) Ekenkpon Formation; C) New Netim Formation; D) Mfamosing Formation; E) Awi Formation.

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179

Figure 9. (continued).

be made with caution and supported by other methods (Stein, 1991). The Rock-Eval pyrolysis data shown in Table 2 and plotted on the modified Van Krevelen diagram (Fig. 10) indicate a clear dominance of terrigenous and/or oxidised OM in the sedimentary rocks by generally low HI values and low Tmax values (Kerogen type III). Most of the samples from Nkporo Formation are in the immature petroleum-generating range < 430  C while the rest are matured

(430  Ce465  C). These low Tmax values may be attributed to the influence of mineral matrix which affects organically lean sediments (Espitalie et al., 1980). Therefore, an improvement in HI values of 131e190 mg HC/g TOC, occurring in the New Netim Formation (Coniacian interval) (Fig. 10) may have resulted from a contribution of type II kerogen. This unit has a high potential for an improvement of the kerogen

Table 3 Identification for numbered peaks on Figure 9AeE. Compound no.

Formula

Terpanes peaks of (m/z 191) 1 C27H46 2 C27H46 3 C29H50 4 C30H52 5 C30H52 6 C30H52 7 C31H54 8 C30H52 9 C32H56 10 C31H54 11 C33H58 12 C34H60 13 C35H62 Sterane peaks of (m/z 217) 1 e 2 C27H48 3 C27H48 4 C27H48 5 C27H48 6 C28H50 7 C28H50 8 C28H50 9 C28H50 10 C29H52 11 C29H52 12 C29H52 13 C29H52

Assignment 18a(H)-trisnorneohopane(C29Ts) 17a(H)-trisnorhopane(Tm) 17a,21b(H)-30-norhopane 18a(H)-oleanane 17a,21b(H)-30-hopane 17b,21a(H)-hopane(moretane) 17a,21b(H)-29-homohopane(22S & R) 17b,21b(H) -hopane 17a,21b(H)-29-bishomohopane(22S & R) 17b,21b(H) -homohopane 17a,21b(H)-29-trishomohopane(22S & R) 17a,21b(H)-29-tetrakishomohopane(22S & R) 17a,21b(H)-29-pentakishomohopane(22S & R) Diasterane 5a,14a,17a-cholestane (20S) 5a,14b,17b-cholestane (20R) 5a,14b,17b-cholestane (20S) 5a,14a,17a-cholestane (20R) 5a,14a,17a-ergostane (20S) 5a,14b,17b-ergostane (20R) 5a,14b,17b-ergostane (20S) 5a,14b,17a-ergostane (20R) 5a,14a,17a-sitostane (20S) 5a,14b,17b- sitostane (20R) 5a,14b,17b- sitostane (20S) 5a,14a,17a- sitostane (20R)

Figure 10. Rock-Eval Hydrogen index and Tmax data plotted on a van Krevelen diagram showing kerogen type and hydrocarbon potential.

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Table 4 Molecular parameters of Cretaceous outcrop sedimentary rocks from the Calabar Flank, South Eastern Nigeria. Gas chromatography

Gas chromatography/Mass-spectrometric ratios

Sample Code

n-C17/Pr.

n-C18/Phy.

Pr./Phy.

Ts/Tm

C31-22S/ 22S þ 22R

C32-22S/ 22S þ 22R

C29-22S/ 22S þ 22R

Ol/C30-Hop.

Normoretane index

Mor./ C30-Hop.

Hop./ Sterane

NK-1 NK-2a NK-2b NK-2c NK-2d NK-2e NK-2f NK-2g NK-2h NK-3a NK-3b NK-3c NK-3d NK-3e NK-3f NK-4 NK-5 NN-1 NN-2 NN-3a NN-3b NN-3c NN-3d NN-3e EK-1 EK-2 EK-3 EK-4 EK-5 MF-1 MF-2 MF-3 MF-4 MF-5 MF-6 AW-1a AW-1b AW-1c AW-1d AW-1e AW-2a

0.24 1.02 0.39 0.40 0.44 0.41 0.51 0.53 0.99 0.28 0.36 0.40 0.47 0.35 0.48 0.34 1.00 0.00 0.00 0.47 0.56 1.00 0.47 0.42 0.49 0.00 1.00 0.00 1.00 0.00 0.96 0.00 1.00 0.46 0.73 0.35 0.54 0.31 0.41 0.47 0.97

1.16 0.92 0.52 0.56 0.77 0.65 0.66 0.68 0.32 1.43 0.88 0.85 1.01 0.73 0.31 1.01 0.98 0.00 0.00 0.89 0.86 0.8 0.68 0.99 0.85 1.15 3.64 1.27 1.02 0.92 1.65 1.06 0.98 1.71 1.01 2.13 2.88 2.1 1.73 1.51 0.99

0.76 0.70 0.33 0.31 0.15 0.55 0.62 0.90 0.35 0.76 0.83 1.31 1.19 0.76 0.54 0.78 0.24 0.00 0.00 0.23 0.47 0.15 0.49 0.54 0.12 0.00 0.3 0.00 0.28 0.28 0.38 0.00 0.39 0.54 1.22 1.74 0.47 1.17 2.01 2.28 0.36

0.16 0.46 0.44 0.45 0.38 0.43 0.54 0.49 0.55 0.11 0.29 0.30 0.31 0.37 0.49 0.08 0.12 0.00 0.51 0.55 0.57 0.46 0.29 0.42 0.59 0.15 0.13 0.09 0.06 0.76 0.58 0.39 0.00 0.00 0.81 0.00 0.00 0.51 0.00 0.14 0.00

0.55 0.56 0.56 0.56 0.60 0.57 0.58 0.57 0.56 0.61 0.55 0.55 0.54 0.53 0.55 0.49 0.53 0.61 0.58 0.57 0.93 0.93 0.94 0.61 0.59 0.94 0.93 0.94 0.44 0.55 0.58 0.56 0.53 0.53 0.57 0.58 0.61 0.58 0.58 0.59 0.00

0.53 0.54 0.54 0.53 0.56 0.55 0.57 0.56 0.52 0.53 0.55 0.56 0.54 0.52 0.52 0.36 0.55 0.54 0.57 0.56 0.56 0.53 0.57 0.56 0.52 0.52 0.58 0.51 0.83 0.55 0.57 0.54 0.58 0.55 0.59 0.61 0.62 0.55 0.59 0.64 0.00

0.28 0.33 0.32 0.34 0.35 0.32 0.34 0.30 0.35 0.28 0.31 0.32 0.31 0.30 0.31 0.24 0.40 0.00 0.36 0.34 0.35 0.37 0.40 0.39 0.31 0.32 0.39 0.40 0.19 0.55 0.56 0.58 0.51 0.47 0.00 0.45 0.48 0.37 0.40 0.44 0.00

0.12 0.26 0.27 0.22 0.30 0.23 0.29 0.17 0.26 0.09 0.09 0.10 0.10 0.10 0.16 0.10 0.00 0.00 0.00 0.11 0.10 0.15 0.29 0.18 e e e e e e e e e e e e e e e e e

0.45 0.41 0.38 0.35 0.37 0.36 0.39 0.30 0.36 0.46 0.47 0.47 0.53 0.49 0.42 0.52 0.57 0.30 0.23 0.16 0.14 0.18 0.17 0.18 0.12 0.39 0.33 0.33 0.54 0.15 0.16 0.19 0.18 0.13 0.14 0.11 0.10 0.07 0.08 0.13 0.00

0.55 0.54 0.55 0.42 0.49 0.46 0.48 0.39 0.47 0.50 0.60 0.62 0.66 0.63 0.51 0.69 0.45 0.28 0.23 0.22 0.21 0.24 0.20 0.23 0.25 0.46 0.37 0.41 0.61 0.10 0.19 0.24 0.25 0.21 0.20 0.16 0.19 0.10 0.15 0.17 0.00

3.09 3.03 4.02 4.69 4.13 3.03 2.82 2.00 3.76 4.59 7.33 6.71 5.70 3.66 8.96 14.49 2.34 1.24 0.27 2.30 2.40 0.99 1.82 1.58 4.49 3.24 3.95 1.80 46.00 5.14 5.34 4.65 2.72 8.20 5.56 9.66 4.33 12.15 5.73 12.86 0.00

quality towards type II as shown by the high abundance of hydrocarbons and high fluorescing alginites (Ekpo et al., 2012). In contrast to the relatively high extractability of the OM of the Calabar Flank, the Rock-Eval yields (Table 2) of all samples were below 10.55 mg HC/g rock. From these data, only a gas generation capability can be ascribed to the sediments. This is supported by petrographic features which characterise the Calabar Flank sedimentary rocks as type III kerogen with gas potential (Ekpo et al., 2012). 5.3. Thermal maturity The thermal maturity of Cretaceous outcrops of the Calabar Flank was assessed by Rock-Eval pyrolysis, Tmax, vitrinite reflectance values, Ro, and biomarker maturity ratios. Based on the Tmax and vitrinite reflectance %Ro values (417e460  C) and (0.39e0.62 % Ro), the sample suites are classified as immature to early mature. Generally, a gradual increase in Tmax with increasing age (Fig. 5) is observed in the Upper Cretaceous while in the lower Cretaceous the opposite trend is observed. This variation in the Tmax of immature samples of more than 20  C is due to differences in the type of OM (Peters, 1986). Tmax values for the Campanian-Maastrichian (Nkporo Formation) samples range from 417 to 433  C equivalent

to vitrinite reflectance value of 0.35e0.46% Ro and are classified as immature. The late AlbianeCenomanianeTuronianeConiacian of the Ekenkpon and New Netim Formations are characterised by marginally mature to early mature samples with Tmax values from 428 to 443  C and vitrinite reflectances of 0.38e0.47 %Ro (Fig. 5). The mean Tmax values of Mfamosing and Awi Formations are 447  C and 443  C, whereas the corresponding mean Ro values are 0.41% and 0.53%. In this case, Tmax temperatures would indicate a degree of maturity within the early oil window, whereas vitrinite reflectance is indicative of a marginally mature stage. However, the low Tmax values around 437  C might represent the true maturity stage, whereas those of up to 460  C might be caused by reworked organic matter, (Stein et al., 1995; Stein and Stax, 1996), which was not taken into account when measuring the vitrinite reflectance. The biomarker parameters used in assessing the thermal maturity of the Calabar Flank sedimentary rocks are 17b(H), 21a(H)-(moretane)/17a(H), 21b(H)-hopane, 18a(H)-22, 29,30trisnorneohopane (Ts)/17a(H)-22,29,30-trisnorhopane (Tm), 18a(H) þ 18b(H) oleanane/17a(H), 21b(H)-hopane, C29-aaa 20S/ (20S þ 20R) steranes and C31 22S/(22s þ 22R) homohopanes. The relative composition of the 17b(H), 21a(H)-(moretane) and 17a(H), 21b(H)-hopane decreases with increasing thermal maturity from 0.8 in immature bitumens to values <0.15 in mature source rocks

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181

Figure 11. Stratigraphic variations of some biomarker ratios in Cretaceous outcrop sedimentary rocks from the Calabar Flank.

(Peters and Moldowan, 1993). For the entire sample set (Table 4) this ratio decreases from 0.69 to 0.10 with increasing age from Nkporo to Awi Formation. The maturity ratio of 18a(H)-22,29,30-trisnorneohopane (Ts) relative to 17a(H)-22,29,30-trisnorhopane (Tm) is strongly influenced by the presence of minerals that catalyse structural arrangement from Tm to Ts (Rullkötter et al., 1984; Philp and Fan Zhaoan, 1987) and is OM source and facies dependent (Moldowan et al., 1986). Ts/Tm ratios in the range 0.06e0.76 do not show any trend (Fig. 11). 18a(H) þ 18b(H)-oleanane/C30-hopane (oleanane parameter, OP) has been used as a maturity indicator (Ekweozor and Udo, 1988). Values of OP in the range 0.3e0.4 indicate the peak of oil generation (Ekweozor and Udo, 1988). In the Calabar Flank, oleanane is restricted to New Netim and Nkporo Formations (Fig. 11) and values ranging from 0.10 to 0.29 (Table 4) were obtained and indicate immaturity of this sequence. The maturity related biomarker ratio C29-aaa 20S/(20S þ 20R)-sterane in the sample suite ranges from 0.09 to 0.58 and increases slightly from Nkporo Formation to Awi Formation (Fig. 11). This ratio in the range 0.44e0.58 in Mfamosing and Awi Formation samples indicates full maturity and equilibrium attainment of isomerisation (Seifert and Moldowan, 1981; Mackenzie, 1984). The predominance of the C27, C28 and C29aaa-stereoisomers of sterane (Fig. 11) is in agreement with the low maturity of the samples inferred from Tmax, Ro and other biomarkers maturity indicators. Of all biomarkers studies on thermal maturity indices, 17b(H), 21a(H)-moretane/17a(H), 21b(H)-hopane, Ts/Tm and oleanane/ C30-hopane show wide variation among the different formations and facies. These variations are presumably the result of changes in

Figure 12. Schematic mid-Cretaceous paleogeographic reconstitution of the Brazilian and West African marginal basins. Adapted from Mello et al. (1991).

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the organic starting material, eH, pH and the amount of sulphate reduction during early diagenesis. The C29-aaa 20S/(20S þ 20R), and C31 and C32e22S/(22S þ 22R) exhibited relatively little variation with facies (Table 4), indicating that these ratios are least affected by depositional environment. Therefore, these parameters are best suited for the determination of the thermal maturity of the Calabar Flank outcropping sedimentary rocks. 5.4. Organic matter source and depositional environment Depositional conditions under which sediments were deposited and preserved can be identified by the interpretation of the lithofacies as the primary and palynofacies as secondary tools (ObohIkuenobe et al., 2005). For example, evidence from ammonites and planktonic foraminifera as reported by Nyong and Ramanathan (1985) has supported the three global Oceanic Anoxic Events (OAEs) (with oxygen-deficient bottom conditions) which resulted in the deposition of dark organic-rich shales worldwide. In our study, variations in the biomarker compounds, hopanes and steranes and their ratios are useful in differentiating changes in trophic levels during deposition of organic matter through geological time (Kuo, 1994). Hopanes are derived from hopanoids in prokaryotic organisms, such as bacteria and blue green algae (Ourisson et al., 1979; Simoneit, 1986), whereas, steranes are derived from steroids in eukaryotic organisms such as diatoms, dinoflagellates, zooplanktons, phytoplanktons and higher organisms (Mackenzie et al., 1982; De Leeuw et al., 1989). The abundance of steranes has been attributed to precursor organisms rich in D7-sterols. (Peakman et al., 1989), which include green algae, sponges and asteriodea (Volkman, 1986). The ratio of hopane/sterane (Table 4) in the Calabar Flank sedimentary rocks is variable, ranging from low values (0.27e2.40) to high values (4.33e12.86) for New Netim and Awi Formations respectively. High hopane/sterane ratios in the preserved OM of Awi Formation indicate that during the early stage of deposition the sea level was probably low and the OM deposited mainly consisted of bacteria and blue-green algae. As the sea level increased, eukaryotic organisms probably became more abundant and diversified. This resulted in the decrease of the hopane/sterane ratio (Fig. 11). This observation is generally in agreement with the trend of TOC content with age (Fig. 5). A high ratio of hopane to sterane principally occurs in these brackish/fresh water sediments, such an environment being favourable for the formation of bacterial hopane and unfavourable for the preservation of steranes (Koutsoukos et al., 1991). This observation is supported by the range of carbon number of homohopanes (C31 e C35) in the Calabar Flank (Fig. 9), typical of brackish/freshwater sediments. The presence of minor proportions of C32þ homohopanes in nearly all the samples could be taken as an indication of a mildly reducing depositional environment (Villar et al., 1988). The unusually high abundance of phytane and much lower Pr/Ph ratios (Table 4) probably suggest either methanogenic and/or halophilic bacterial input or high salinity and a strong reducing depositional environment (Han and Calvin, 1969; ten Haven and Rullkötter, 1988). The absence of both 2-, 6-, 10-, 15-, 19-pentamethyleicosane (iC25) and squalene (iC30) in the sediment extracts found in methanogenic and thermacidophilic bacteria may suggest absence of bacterial input (Brassel et al., 1981; Waples, 1983., Risatti et al., 1984. Bianchi and canuel, 2011). However, a substantial algal/bacterial source input is indicated by the n-alkane distribution with Cmax between n-C14 and n-C18 (Shiea et al., 1990; Bianchi and canuel, 2011) and a low n-alkane concentration above n-C25 (Tissot and Welte, 1984) identical to our samples. The general predominance of C27 sterane over the higher homologues in some of the samples could result from the higher

contribution of zoo e and phytoplankton (Huang and Meinschein, 1979), although minor contribution of phytoplankton has been proposed from geochemical and petrographical data (Ekpo et al., 2012). The C29 steranes are derived from terrestrial plants (Huang and Meinschein, 1979). The C29 steranes dominance in most of the samples is not surprising. A dominance of higher terrestrial plant to organic matter input of the Calabar Flank sedimentary rocks is shown by the low HI. The presence and the relative abundance of 18a(H) þ 18b(H) oleanane is an important feature in the Calabar Flank outcrop sedimentary rocks. These compounds are derived from betulin (Grantham et al., 1983) and other pentacyclic triterpanes in angiosperms (Whitehead, 1973, 1974; ten Haven and Rullkötter, 1988), thought to be a higher plant marker for Cretaceous or younger sedimentary rocks. Ekweozor and Udo (1988) have noted that oleananes are not restricted to the Tertiary Niger Delta but also occur in rocks apparently not older than Late Upper Cretaceous in the neighbouring Anambra and Benue Basins. In the Calabar Flank sedimentary rocks, oleanane is restricted to the New Netim and Nkporo Formations (ConiacianeCampanioneMaastrichtian period). We conclude that organic inputs to the Calabar Flank sedimentary rocks contain variable amounts of phytoplanktonic remains, contributing substantially to a background TOC content of terrestrial origin. This is in agreement with the carbon isotope (d13C) value of 21.9& to 27.5& (Ekpo et al., 2012), typical of those reported for marine-derived Cretaceous OM (Dean et al., 1986; Katz et al., 1988) with substantial contribution of terrestrial OM which is typically in the range 23& and 33.0& (Sackett, 1964; Peters and Moldowan, 1993). 5.5. Regional geochemical comparison A comprehensive geological, tectonic, stratigraphic, geochemical and geophysical investigations on a group of oils and source rocks from Brazilian and West African marginal basins (Fig. 12) ranging in age from Lower Cretaceous to Tertiary were undertaken by Mello et al. (1991). Although the data revealed similarities among group of oils, source rocks and depositional environments in counterpart basins across the South Atlantic, there exists significant differences in the subsidence, sedimentary, thermal history and volumes of oil in place, which suggest an asymmetric rifting process that separated the South American from the African plate. The present study area, the Calabar Flank was formed by incipient rifting during this separation in Albian times (Whiteman, 1982) with basement structures that align parallel to those of the coastal basins of Gabon, Congo and Angola and the Brazilian marginal basins (Fig. 12). Our attention was particularly drawn to the similarities in the geochemical data of the source rocks and depositional environment of the Calabar Flank sedimentary rocks with that of the oils from equivalent units in the Brazilian and other West African marginal basins. 5.5.1. Awi Formation Awi Formation samples, except some samples at the basement boundary, have TOC contents significantly higher than the minimum of 0.5wt.% set for a source rock. On the contrast, only a relatively small part of the OM is pyrolysable which characterizes the kerogen as type III. The maturation status of the OM according to biomarker ratios and Tmax values equivalent to about 0.55e0.62% vitrinite reflectance, indicate onset of oil generation (Fig. 5). The geochemical, biomarker and organic petrographic studies (Mello et al., 1991) of this unit show certain features linked with deposition of OM in probably lacustrine e freshwater environment similar to the Bucomazi and Melania Formations in Brazilian and West African basins (Fig. 12). For instance, geochemical and biomarker features diagnostic of oils from these environment which are

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similar to that of the Calabar Flank sediments are: hopane/sterane >5, absence of C30 sterane, Pr/Ph > 1.0, presence of bisnorhopane and abundance of diasteranes, high relative abundance of high molecular weight n-alkanes with odd/even dominance, low d13C value(<28.0 /oo), Ts > Tm, low concentration of steranes, medium relative abundance of gamacerene and absence of C30 sterane, diasterane, b-carotane and 28, 30-bisnorhopane (Mello et al., 1991). 5.5.2. Mfamosing Formation The OM content in samples from this unit is low with relatively moderate extractability and samples contain small amounts of free hydrocarbons, hence classified as organic lean rocks. Organic petrography and Rock-Eval pyrolysis data indicate a dominance of vitrinite, characterizing the kerogen as type III. The maturity of the OM according to biomarker ratios and 0.43e0.45% vitrinite reflectance indicates immature to marginally mature organic matter (Fig. 5). Tmax seems to be influenced by higher mature reworked particles. Generally, this unit has a low petroleum potential. Geochemical, biomarker and organic petrographic characteristics of the Mfamosing Formation may classify the sediments as marine carbonates, with substantial terrestrial OM influence. Marine carbonates are characterised by Pr/Ph < 1.0, hopane/sterane <3.0, high abundance of C30 sterane, Ts/Tm < 1.0, significant abundance of 28, 30 e bisnorhopane, and low concentrations of diasteranes and C29 steranes (Mello et al., 1991). This unit can be correlated with the Limoeiro Formation in the Para Maranhao Basin in the northern Brazilian margin (Fig. 12). For instance, the geochemical and biomarker features (Mello et al., 1991) characteristics of oils from the Limoeiro Formation in the Para Maranhao Basin in the northern Brazilian margin similar to that of the Calabar Flank sediments are: phytane > pristine with an even over odd n-alkanes predominance, carbon isotopic values (d13C around 27.0 /oo for oils), low hopane/ sterane ratio, Ts/Tm < 1, presence of significant relative abundance of 28, 30-bisnorhopane and 25, 28, 30-trisnorhopane, high abundance of C29 sterane relative to their C27 counterparts (Mello et al., 1988a,b; 1989). 5.5.3. Ekenkpon Formation The Ekenkpon shales have OM sufficiently high to be considered as a fair oil source rock (Fig. 8). However pyrolisable organic matter and organic petrographic investigations indicate high abundance of vitrinitic compounds, characterizing the kerogens as type III. The maturation status of this unit according to biomarker is equivalent to 0.41e0.47% vitrinite reflectance, indicating immature OM (Fig. 5). Geochemical, biomarker and organic petrographic features of this unit are diagnostic of open marine black shale sedimentation (with a contribution of terrigenous OM) with predominance of calcareous mudstone characterised by Pr/Ph < 1.0, hopane/sterane < 1.0, presence of gammacerane, Ts/Tm < 1.0 and high relative abundance of 28, 30 e bisnorhopane (Mello et al., 1991). Equivalent units may be said to be the Azile and Anguille Formations in Gabon of Cenomanian-Turonian age in the equatorial West African Margin (Fig. 12) which are characterized by phytane > pristine and nalkane maxima around C21, low hopane/sterane, Ts/Tm < 1 and C30hopane greater than or in similar abundance to their C34 counterparts, relatively high abundance and concentrations of 28, 30bisnorhopane and 25, 28, 30-trisnohopane, relatively low abundance of diasteranes and high abundance of C29 steranes relative to their C27 counterparts (Mello et al., 1991). 5.5.4. New Netim Formation Most of the samples from New Netim Formation, contain low (<0.5%) content of TOC, which does not satisfy the requirements for a source rock. However, SOM and hydrocarbon content exhibit a

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fair source character. Rock-Eval pyrolysis and organic petrographic data indicate a dominance of vitrinites as the main maceral group and high abundance of brightly fluorescing alginites of marine origin. OM of type III kerogen therefore has been assigned to this unit. Maturity assessment from biomarker data, Tmax and Ro values of 0.45% indicate immature OM (Fig. 5). Geochemical and biomarker analyses characterize the environment of deposition of these shales as mixed lacustrine-saline-marine delta (Mello et al., 1991). This unit may correlate with the Espirito Santo Basin, in the southeastern margin of Brazil and the Cabinda and Congo Basins (Sao Tome and Principe area), in the West African Margin (Fig. 12). The geochemical and biomarker features diagnostic of these environments (Mello et al., 1991) which are similar to the Calabar Flank sediments are: dominance of high molecular weight n-alkanes, presence of 18a(H)-oleanane, C24 tetracyclic terpanes, unknown C30 terpanes derived from plants and C30 steranes (low in abundance), high abundance of diasteranes and dominance of C29 steranes relative to its C27 and C28 counterparts. 5.5.5. Nkporo Formation The black shale of Nkporo Formation has a high hydrocarbon potential and is generally characterized by sufficiently high TOC content (>0.5%) set for a source rock. The extractability and hence the proportion of hydrocarbons in the extracts is also high to qualify the samples as source rocks. Rock-Eval and organic petrographic data, however, indicate high abundance of vitrinite macerals, characterizing the OM as kerogen type III (gas prone). The maturity indicators, Tmax and biomarker ratios are equivalent to 0.42% vitrinite relectance, and indicate immature source rocks (Fig. 5). Geochemical and biomarker features of this unit characterize the environment of deposition of these shales as mixed lacustrine saline e marine delta. Equivalent units may be the Espirito Santo Basin, in the southeastern margin of Brazil and the Cabinda and Congo Basins (Sao Tome and Principle area), in the West African Margin (Fig. 12). The geochemical and biomarker features diagnostic of these environments which are similar to the Calabar Flank sediments are: dominance of high molecular weight n-alkanes, presence of 18a(H)oleanane, C24 tetracyclic terpanes, unknown C30 terpanes derived from plants and C30 steranes (low in abundance), high abundance of diasteranes and dominance of C29 sterane relative to its C27 and C28 counterparts (Mello et al., 1988a,b; 1989, 1991). 6. Conclusions 1. Rock-Eval pyrolysis, vitrinite reflectance and biomarker data of Cretaceous outcrop samples from the Calabar Flank, southeastern Nigeria confirm their maturities as pre- to early oil window, consistent with shallow burial under a normal geothermal gradient. 2. The oil source potential of the entire sample suites, except samples from Awi Formation, is low. However, an improvement in the oil source potential from the outcrop locations basinward and an increase of marine-derived OM could not be ruled out. 3. Although the OM no doubt is mainly of terrigenous origin from geochemical, carbon isotopic and petrographic evidence, the deposition in marine environment, presupposes that marine derived OM may have contributed to the source material. From organic-petrographic studies, the high abundance of alginites in New Netim Marl Formation sediments is an evidence of a marine source. 4. The presence and abundance of oleanane, a higher land plant derived biomarker in the Calabar Flank outcrop samples only occurring in New Netim and Nkporo Formations (Coniaciane Maastrichtian) is inferred to suggest the Late Upper Cretaceous age of these sediments.

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5. Awi Formation in the Calabar Flank has a high prospect for petroleum generation. Although this section onshore contains mainly gas-prone Type III kerogen, it should direct exploration interest in the southeastern Nigeria since equivalent units in Brazilian marginal basins are producing. Therefore the Calabar Flank may serve as one of the inland exploration frontier basins that would lead to a major petroleum exploration direction in Nigeria. Acknowledgement This study received great support from technical staff of the Federal Institute for Geosciences and Natural Resources (BGR), Hannover, Germany. The Deutscher Akademischer Austauschdiensts (DAAD) fellowship to B. Ekpo for his Ph.D. research, is highly appreciated. We would like to thank Dr. M. Teschner, Mr. G. Schecder, Dr. U. Siewers and Dr. J. Koch for their technical support during the analyses. Comments by the reviewers were particularly helpful, and we thank Balazs Badics and the Editor for their useful comments that significantly improved this manuscript. References Adeleye, D.R., Fayose, E.A., 1978. Stratigraphy of the type section of Awi Formation, Odukpani area, southeastern Nigeria. Nig. Tour. Min. Geol. 15, 35e37. Brassel, S.C., Wardroper, A.M.K., Thompson, I.D., Maxwell, J.R., Eglinton, G., 1981. Specific acyclic isoprenoids as biomarkers of methanogenic bacteria in marine sediments. Nature 290, 693e696. Bianchi, T.S., canuel, E.A., 2011. Chemical Biomarkers in Aquatic Ecosystems. Princeton University Press, Princeton, New Jersey, p. 396. De Ruiter, P.A.C., 1978. The Gabon-Congo Salt deposits. Econ. Geol. 74, 419e431. De Leeuw, J.W., Cox, H.C., van Graas, G., van de Meer, F.W., Peakman, J.M., Baas, J.M.A., van de Graaf, V., 1989. Limited double bond isomerization and selective hydrogenation of steranes during early diagenesis. Geochim. Cosmochim. Acta 53, 903e909. Dean, K.E., Arthur, M.A., Claypool, G.E., 1986. Depletion of 13C in Cretaceous marine organic matter: source, diagenetic, or environmental signal? Mar. Geol. 70,119e157. Ekpo, B.O., Ibok, U.J., Essien, N.E., Wehner, H., 2012. Geochemistry and organic petrographic studies of the Calabar Flank, Southeastern Nigeria. Marine Pet. Geol. 35, 252e268. http://dx.doi.org/10.1016/j.marpetgeo.2012.03.010. Ekwere, S.J., 1993. Geochemistry of subsurface limestone samples from Etankpini, Calabar Flank, southeastern Nigeria. Trop. J. Appl. Sci. 3, 9e17. Essien, N., Ukpabio, E.J., Nyong, E., Ibe, K.A., 2005. Preliminary organic geochemical appraisal of Cretaceous rock units in the Calabar Flank, southeastern Nigeria. J. Mining Geol. 41 (2), 185e191. Ekweozor, C.M., Udo, O.T., 1988. The oleananes: origin, maturation and limits of occurrence in southern Nigeria sedimentary basins. In: Mattavelli, L., Novelli, L. (Eds.), Advances in Organic Geochemistry 1987. Org. Geochem. vol. 13 (1e3), 131e140. Espitalie, J., Laporte, J.L., Madec, M., Marquis, F., Leplat, P., Paulet, J., Boutefeu, A., 1977. Methode rapide de caracterisation des roches-meres, de leur potentiel petrolier et de leur degree d’evolution. Rev. Inst. Fr. Pet. 32, 23e42. Espitalie, J., Madec, M., Tissot, B., 1980. Role of mineral matrix in kerogen pyrolysis. AAPG Bull. 64, 59e66. Grantham, P.J., Posthuma, J., Baak, A., 1983. Triterpanes in a number of Far-Eastern crude oils. In: Bjoroy, M., et al. (Eds.), Advances in Organic Geochemistry 1981. J. Wiley and Sons, New York, pp. 675e683. Grantham, P.J., Wakefield, L., 1988. Variations in the sterane carbon number distributions of marine source rock derived crude oils through geological time. Org. Geochem. 12, 61e73. Han, J., Calvin, M., 1969. Hydrocarbon distribution of algae and bacteria and microbial activity on sediments. Proc. Nat. Acad. Sci. U. S. A. 64 (2), 436e443. Huang, W.Y., Meinschein, W.G., 1979. Sterols as ecological indicators. Geochim. Cosmochim. Acta 43, 739e745. Katz, B.J., 1988. Organic-geochemical character and hydrocarbon-source potential of site 635. In: Austin Jr., J.A., Schlager, W., et al. (Eds.), Proceedings of the Ocean Drilling Program, Scientific Results, vol. 101, pp. 381e388. Koutsoukos, E.A.M., Mello, M.R., de Azambuja Filho, N.C., Hart, M.B., Maxwell, J.R., 1991. The upper Aptian- Albian succession of the Sergipe basin, Brasil: Paleoenvironmental assessment. AAPG Bull. 75, 479e498. Kuo, Lung-Chuan, 1994. Lower Cretaceous lacustrine source rocks in northern Gabon: effect of organic facies and thermal maturity on crude oil quality. Org. Geochem. 22 (2), 257e273. Mackenzie, A.S., 1984. Application of biological markers in petroleum geochemistry. In: Brooks, J., Welte, D. (Eds.), Advances in Petroleum Geochemistry, vol. 1. Academic Press, London, pp. 115e214. Mackenzie, A.S., Brassell, S.C., Eglinton, G., Maxwell, J.R., 1982. Chemical fossils: the geological fate of steroids. Science 217, 491e504.

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