227

Geochemical Journal, Vol. 40, pp. 227 to 243, 2006

*Corresponding author (e-mail: nobaje@yahoo.com)

Copyright © 2006 by The Geochemical Society of Japan.

Geochemical evaluation of the hydrocarbon prospects of sedimentary basinsin Northern Nigeria

N. G. OBAJE,1* D. O. ATTAH,2 S. A. OPELOYE3 and A. MOUMOUNI1

1Department of Geology and Mining, Nasarawa State University, Keffi, Nigeria2Department of Metallurgical Engineering, Federal Polytechnic, Idah, Nigeria

3Department of Geology, Federal University of Technology, Yola, Nigeria

(Received April 25, 2005; Accepted November 9, 2005)

Sedimentary basins of Northern Nigeria comprise the Middle and Upper Benue Trough, the southeastern sector of theChad Basin, the Mid-Niger (Bida) Basin, and the Sokoto Basin. Organic geochemical and organic petrologic studiesindicate the existence of potential source rocks in the Benue Trough and the Chad Basin, with coal beds constituting majorpotential source rocks in the whole of the Benue Trough. The generation and production of liquid and gaseous hydrocar-bons from coal beds presently is world-wide indisputable.

Although TOC values and liptinite contents are relatively high in the Mid-Niger (Bida) Basin, Tmax values and biomarkerdata show that hydrocarbons are probably just being generated in the basin and may not yet have been expelled normigrated in large quantities.

Keywords: biomarkers, petroleum, coal, maceral, Benue Trough

ing of the South Atlantic (Fig. 2). Commercial hydrocar-bon accumulations have recently been discovered in Chadand Sudan within this rift trend. In SW Chad, exploita-tion of the Doba discovery (with an estimated reserve ofabout 1 billion barrels of oil) has caused the constructionof a 1070 km-long pipeline through Cameroon to the At-lantic coast. In the Sudan, some “giant fields” (Unity 1 &2, Kaikang, Heglig, etc.) have been discovered in theMuglad basin (Mohamed et al., 1999). The major sourcerocks and reservoirs are in the Aptian-Albian-Cenomaniancontinental deposits of the Abu Gabra and Bentiu forma-tions, respectively, which are similar and correlatable tothe well-developed Bima Sandstone in the Nigerian up-per Benue trough. In Niger Republic, oil and gas showshave also been encountered in Mesozoic–Cenozoic se-quences in the East Niger graben, which is structurallyrelated to the Benue-Chad-Sudan-Libyan rift complexes(Zanguina et al., 1998).

Within the sedimentary basins of Northern Nigeria,the Nigerian National Petroleum Corporation (NNPC)through its frontier exploration services arm (NAPIMS)has drilled some wells in the Nigerian sector of the ChadBasin and only gas shows were encountered. The firstwell in the Benue Trough region, Kolmani-River-1, drilledby Shell Nigeria Exploration and Production Company(SNEPCO) to a depth of about 3000 m in 1999 encoun-tered some 33 billion standard cubic feet of gas and littleoil (that has been the only well drilled by that companyin that area to date). Two other wells, Kuzari-1 and

INTRODUCTION

Nigeria’s current national petroleum reserves asset(proven) is put at 35 billion barrels of oil. Gas reserve onthe other hand has been estimated to be about 170 trillionstandard cubic feet. Current production of oil and gas inNigeria comes entirely from the Niger Delta onshore andoffshore. Some exploration campaigns have been under-taken in sedimentary basins of Northern Nigeria with theaim to expanding the national exploration and produc-tion base and to thereby add to the proven reserves asset.Sedimentary basins of Northern Nigeria comprise theMiddle and Upper Benue Trough, the southeastern sectorof the Chad Basin, the Mid-Niger (Bida) Basin, and theSokoto Basin (Fig. 1). However, these inland basins havecontinued to frustrate the efforts of many explorers, prin-cipally because of the poor knowledge of their geologyand the far distance from existing infrastructure (discov-ery must be large enough to warrant production invest-ments), and for these reasons, many international com-panies have turned their focus away from frontier onshoreto frontier deep-water and ultra deep-water offshore.

The sedimentary basins of Northern Nigeria are onepart of a series of Cretaceous and later rift basins in Cen-tral and West Africa whose origin is related to the open-

228 N. G. Obaje et al.

E G Y P TL I B Y AA L G E R I A

N I G E R

C H A DS U D A N

N I G E R I A

E T H I O P I A

Z A I R E(D.R.C.)

CA

ME

RO

ON

C. A. R.

200 KmK E N Y A

RE

DS

EA

EAST NIGER

BLUE NILE

MELUTBAGARRA

DOBA

NGAOUNDERE ANZA

BENUE

GONGOLA

YOLA

MUGLAD

EA

STA

FRIC

AN

RIF

T

NIGERDELTA

KANEM

BONGORBORNU

TERMIT/

SIRTE

Major oil discovery Major oil and gas shows

Fig. 1. Sketch geological map of Nigeria showing the inland basins and sample localities (inset: upper Benue trough magnified).Results from the Anambra Basin not presented in this study.

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

Hydrocarbon prospects of sedimentary basins in Northern Nigeria 229

Nasara-1, drilled by Elf Petroleum Nigeria Limited(TotalFinaElf) in 1999 to a depth of 1666 m and ChevronNigeria Limited (ChevronTexaco) in 2000 to a depth ofabout 1600 m, respectively, were reportedly dry.

With this development, it has become necessary toevaluate the prospectivity of this frontier region, espe-cially the availability or otherwise of favorable petroleumsystems. At the core of any petroleum system is a goodquality source rock (TOC > 0.5%, HI > 150 mgHC/gTOC,liptinite content > 15%, Tmax ≥ 430°C, Ro 0.5–1.2%,biomarker validation). However, other petroleum systemelements must include, apart from established sourcerocks, also reservoir and seal lithologies, establishabletrapping mechanisms and favorable regional migrationpathways. In this work, we have aimed at evaluating thesource rock qualities of Cretaceous–Tertiary sequencesin the sedimentary basins of Northern Nigeria (excludingthe Sokoto Basin at this stage) as an input to the under-standing of petroleum system elements in the basins.

REGIONAL GEOLOGIC SETTING

The Benue Trough of Nigeria is a rift basin in centralWest Africa that extends NNE-SSW for about 800 km inlength and 150 km in width. The trough contains up to6000 m of Cretaceous–Tertiary sediments of which those

pre-dating the mid-Santonian have been compressionallydeformed, faulted, and uplifted in several places. Com-pressional folding during the mid-Santonian tectonic epi-sode affected the whole of the Benue Trough and wasquite intense, producing over 100 anticlines and synclines(Benkhelil, 1989). Following mid-Santonian tectonismand magmatism, depositional axis in the Benue Troughwas displaced westward resulting in subsidence of theAnambra Basin. The Anambra Basin, therefore, is a partof the lower Benue Trough containing post-deformationalsediments of Campano-Maastrichtian to Eocene ages. Itis logical to include the Anambra Basin in the BenueTrough, being a related structure that developed after thecompressional stage (Akande and Erdtmann, 1998). TheBenue Trough is subdivided into a Lower, Middle and anUpper portion (Figs. 1 and 3). Reviews on the geologyand stratigraphic successions in the Benue Trough withdetails on each formation, bed thicknesses, lateral exten-sions and stratigraphic locations have been given byCarter et al. (1963), Offodile (1976), Petters (1982), Pet-ters and Ekweozor (1982), Obaje (1994) amongst others.Details on the evolution and stratigraphic framework ofthe Chad Basin have been given in Avbovbo et al. (1986)and Olugbemiro et al. (1997). The Mid-Niger Basin some-time known as the Bida or Nupe Basin is a NW-SEtrending embayment perpendicular to the main axis of

Fig. 3. Stratigraphic successions in the Benue Trough, the Nigerian sector of the Chad Basin, the Mid-Niger Basin and therelationship to the Niger Delta.

230 N. G. Obaje et al.

the Benue Trough (Fig. 1). During Campanian–Maastrichtian, the South Atlantic–Tethys seaway wasrouted through the Mid-Niger Basin and it has been mostfrequently regarded as the northwestern extension of theAnambra basin (Ladipo et al., 1994; Akande and Ojo,2002), both of which were major depocentres during thistransgression. Sediment thickness in the Mid-Niger Ba-sin is estimated to be between 3000–3500 m (Whiteman,1982; Braide, 1990). Details on the stratigraphicsuccessions in the Benue Trough, the Chad Basin and theMid-Niger Basin and as they relate to the Anambra Basinand the Niger Delta are depicted on Fig. 3.

METHODS OF STUDY

In the Middle Benue Trough, outcrop samples (mainlycoals) were collected along the bank of River Dep inJangwa near Obi/Lafia (MBJJ, OBIC). Outcrop and someshallow borehole samples of the following formations:Bima (at Lamurde: BIMA), Yolde (at Futuk and Gombe:YOLD, MYS), Dukul (at Lakun: DUKL, MDS), Gongila(at Ashaka: GONG, MGS), Pindiga (at Gombe andPindiga: PIND, MPS), Lamja (coals at Lamja: LAMCO),Gombe (coals at Doho, Haman Gari, and Wuro: UBDJ,UBHJ, UBWJ, MGMC) were collected from the UpperBenue Trough. Sixty three ditch cutting samples of shale

and coaly lithologies were collected from well Nasara-1at 30 ft interval, except where samples were not avail-able or too sandy to contain appreciable quantity of or-ganic matter. Well samples from Kemar-1 (KM-1),Murshe-1 (MS-1), Tuma-1 (TM-1), and Ziye-1 (ZY-1)constitute the study materials from the Chad Basin. Thesamples (ditch cuttings) were collected based on avail-ability and visual estimation of probable organic richness.In the Mid-Niger (Bida) Basin, outcrop samples of theLokoja and Patti formations (AHOK) were collected fromthe road cut section at Ahoko on the Lokoja–Abaji road.Attempts were made during sampling to cut back tounweathered materials, even though in most cases it wasnot possible to obtain totally fresh samples. Whateverweathering impressions that remained on the sampleswere thoroughly brushed off before subjecting them toanalyses.

Samples from all the formations were subjected toorganic geochemical and organic petrologic studies com-prising:

a) Total organic carbon (TOC) determination to esti-mate the quantity of organic matter in each sample.

b) Rock-Eval pyrolysis to determine the hydrocarbongenerative potential of the organic matter (S1, S2, S3,Tmax, and the derivatives: HI, OI).

c) Vitrinite reflectivity (Ro%) to determine the ma-

Table 1. Rock Eval pyrolysis results of samples from the Middle Benue Trough and Mid-Niger (Bida)Basin

*mgHC/gTOC; **mgCO2/gTOC.

Sample ID Locality Formation TOC(wt%)

S1(mg/g)

S2(mg/g)

S3(mg/g)

Tmax(°C)

HI* OI**

Middle Benue Trough

OBIC 6OBIC 5OBIC 4OBIC 3bOBIC 3OBIC 2bMBJJ 9MBJJ 8MBJJ 7MBJJ 6MBJJ 5MBJJ 4MBJJ 3MBJJ 2MBJJ 1

JangwaJangwaJangwaJangwaJangwaJangwaJangwaJangwaJangwaJangwaJangwaJangwaJangwaJangwaJangwa

AwguAwguAwguAwguAwguAwguAwguAwguAwguAwguAwguAwguAwguAwguAwgu

17.4075.6076.3026.4079.1070.6027.0044.2043.1061.1018.5023.80

2.6966.7017.40

0.412.603.040.843.162.273.930.260.191.930.380.720.024.380.08

21.76192.77203.84

43.51207.3171.54

41.2018.4210.8183.0522.1839.58

1.99164.29

2.49

5.372.692.521.482.502.311.65

19.1318.1213.60

5.321.230.301.33

12.49

444457452457459453452441445449444455463452457

125255267165262243153

4225

136120166

74246

14

31436336

43422229

511

272

Mid-Niger/Bida Basin

AHOK 5AHOK 3AHOK 2AHOK 1

Ahoko/LokojaAhoko/LokojaAhoko/LokojaAhoko/Lokoja

PattiPattiLokojaLokoja

2.742.792.392.73

0.070.060.060.05

2.982.391.781.71

2.302.301.922.08

429425423421

109867463

84828076

Hydrocarbon prospects of sedimentary basins in Northern Nigeria 231

turity of the envisaged source rocks.d) Maceral analysis to evaluate the relative propor-

tions of the hydrocarbon-prone macerals.e) Gas Chromatography (GC) and Gas Chromatog-

raphy-Mass Spectrometry (GC-MS) for biomarker assess-ments of the n-alkane distribution, pristane/phytane ra-tios, odd-over-even-predominance (OEP), regular steranesdistribution, transformation ratios of 17α(H)-trisnorhopanes (Tm) to 18α(H)-trisnorneohopanes (Ts) aswell as moretanes to 17α(H)21β(H)-hopanes.All samples were prepared according to standard organicgeochemical (e.g., Espitalie et al., 1977; Waples andMachihara, 1991; Pratt et al., 1992; Petersen et al., 2000;Jovancicevic et al., 2002) and organic petrologic (e.g.,Stach et al., 1982; Bustin et al., 1985; Obaje, 1994; Obajeand Abba, 1996; Taylor et al., 1998) sample preparationmethods.

RESULTS AND DISCUSSION

Middle Benue TroughIn the Middle Benue Trough, TOC contents of up to

79.1 wt% (Table 1) and a mean HI value of 281 mgHC/gTOC (Fig. 4) characterize the coals of the Awgu Forma-tion. Langford and Blanc-Valleron (1990) noted that hy-drogen indices obtained from Rock-Eval pyrolysis can bemisleading, as much of the hydrocarbons may be adsorbedby the rock matrix. Shaley source rocks may thereforeyield Rock-Eval pyrolysis-generated HIs that are less thanthe true average hydrogen index, while coaly source rocksmay have HIs that are higher than the true average. Theytherefore proposed the use of S2 versus TOC plots; theybelieved that regression equations derived from these plotswere the best method for determining the true averagehydrogen index (Av. HI) and measuring the adsorption ofhydrocarbons by the rock matrix. Tmax and Ro values inindicate maturity in the peak to late oil window. Plots onthe modified Van Krevelen diagram of samples from theMiddle Benue Trough show a mixed range of type I–typeII–type III organic matter (Fig. 5), even though the or-ganic matter could be assigned to a high potential typeIII kerogen at the diagenesis/catagenesis boundary. A cor-responding plot on the HI–Tmax diagram indicatespotentials in the oil and gas phase and a gas phase forsome of the coal samples from the Middle Benue Trough(Fig. 6). Chromatograms and mass fragmentograms of thelipid extracts show biomarkers with a unimodal distribu-tions of short and long-chain n-alkanes (C15-C28) with noobvious odd-over-even predominance (Fig. 7) indicatingthat organic matter were contributed from both algal and

y = 2.81x - 40.16

R2

= 0.83

0

50

100

150

200

250

0.00 20.00 40.00 60.00 80.00 100.00

Mid. Benue Coals

TOC (%)

S2(mg/g)

(Av. H I = 281)

0

100

200

300

400

500

600

700

800

900

0 100 200 300

Chad Basin

Upper Benue

Middle Benue

Anambra Basin

Mid-Niger Basin

HI

OI

Type I

Type II

Type III

Fig. 4. S2 vs. TOC plots of coal samples from the Middle BenueTrough with the regression equations which gave the averagehydrogen indices (Av. HI).

Fig. 5. HI vs. OI plots on the modified Van Krevelen diagramof samples from the inland basins of Nigeria, indicating a pre-dominance of type III organic matter (Anambra Basin plots wereadded from Obaje et al., 2003).

200

300

400

500

600

0 100 200 300 400 500

Middle Benue

Tmax (°C)

HI (mgHC/gTOC)

Gas

Oil & GasOil

(a)

200

300

400

500

600

0 100 200 300 400 500

Upper Benue

Tmax (°C)

HI (mgHC/gTOC)

Gas

Oil & GasOil

(b)

Fig. 6. HI-Tmax plots of samples from the Benue Trough.

232 N. G. Obaje et al.

terrestrial higher plants sources or are in an advanced stageof maturity. Pristane/phytane ratios range from 4.53 to7.33 and steranes are mainly of the C29 forms with C27/C29 ratios ranging from 0.1 to 1.0 (Table 5). These valuesindicate oxic mix up in the depositional milieu that fre-quently changed between continental, marine andlacustrine environments. The relatively high values of Ts/Tm and low moretane/hopane ratios validate the vitrinitereflectance maturity of 0.8 to 1.1 Ro% recorded for thesesamples.

Upper Benue TroughThe formations from the Upper Benue Trough have

generally low TOC and HI contents (Table 2), except thecoals of the Lamja Formation (LAMCO) and those fromDoho and Gombe (UBDJ, MGMC) within the GombeSandstone as well as some Dukul Formation samples, allof which have good to fair source rock qualities. Akandeet al. (1998) and Obaje et al. (1999) had independentlyreported TOC values of to 12.5 wt% from the Yolde For-mation and 2.4 wt% from the lower Pindiga Formation,respectively. In the Lamja Formation, TOC contents at-tain values of up to 51.1 wt% and a mean HI of 183 mgHC/

gTOC for the coals in the Upper Benue combined. Roand Tmax values indicate maturity in the middle/peak oilwindow for the coals of the Lamja Formation. Unfortu-nately, samples from the Bima, Yolde, Pindiga andGongila formations used in this study yielded poor sourcerock quality. Plots on the modified Van Krevelen diagramfor samples from the upper Benue Trough show mainlytype III organic matter with some type II attributable tothe Lamja coals. The corresponding HI–Tmax diagramindicates some potential between oil and gas with gasdominating. Majority of the samples fall into fields thathave no hydrocarbon generative potential (Fig. 6). TheLamja and Gombe coals are of special attention, espe-cially the Lamja which yielded the highest amount ofsoluble organic matter during solvent extraction.Biomarkers show a dominance of both short and long-chain n-alkanes (C14-C31) with negligible OEP. Pristane/phytane ratios range from 0.84 in the Pindiga Formationto 6.65 in the Lamja coals. C27/C29 ratios range from aslow as 0.2 in the Lamja coal to 1.9 in the Pindiga Forma-tion (Table 5) indicating rapidly changing depositionalconditions. The very low Ts/Tm ratio (0.03) and the mod-erate moretane/hopane ratio (0.18) validate the maturitylevel of 0.70–0.73% Ro.

Organic petrologic studies show moderate to high con-tents of liptinite macerals for most of the coal samplesfrom the Benue Trough (up to 40% in the Lamja Forma-tion). The liptinites comprise mainly resinite, sporinite,cutinite and bituminite from which the abundant micrinitemacerals in all the coal samples must have been gener-ated. The origin, nature and significance of micrinitemaceral to oil and gas generation have attracted muchattention. In a detailed study on the genesis of micrinite,Teichmüeller and Wolf (1977) concluded that it is relatedto liptinites (although micrinite comes under the inertinitemaceral group), and may have been generated from them(liptinites); pointing out that it appears first in the bitu-minous coal stage as a product of the coalification ofliptinites, especially bituminite, with a close link to thegeneration of petroleum. Taylor and Liu (1989), however,are of the opinion that although micrinite is more com-mon in bituminous coals, it occurs also in sub-bitumi-nous coals (confirmed in this study), within an overallRo range of 0.3–1.3%. The amount and density increasedwith rank and was thus inferred that oil generation pro-ceeds over a considerable range at varying rates. The con-centration of micrinite particles may thus offer a usefulmeans of trailing the process of hydrocarbon generationand expulsion within the Benue Trough.Nasara-1 Well (Gongola Basin, Upper Benue Trough)Table 3 shows Rock-Eval pyrolysis results for samplesfrom well Nasara-1. The TOC contents are generally poorto fair with a slight trend of decreasing values with depth(Fig. 8). However, at depths of 4,710–4,770 ft, very high

30.00 32.00 34.00 36.00 38.00 40.00 42.00 44.000

50

100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

850

900

950

Time-->

Abundance

Ion 217.00 (216.70 to 217.70): 0207299A.D

30.00 32.00 34.00 36.00 38.00 40.00 42.00 44.000

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000

Time-->

Abundance

Ion 191.00 (190.70 to 191.70): 0207299A.D

10.00 15.00 20.00 25.00 30.00 35.00 40.00 45.00 50.000

20000

40000

60000

80000

100000

120000

140000

160000

180000

200000

220000

240000

Time-->

Abundance

Ion 71.00 (70.70 to 71.70): 0207299A.D

Ion 191 (triterpanes)

Ion 217 (steranes)

Ion 71 (n-alkanes)

Rel

ativ

e in

tens

ity

Time

Pr

Ph

nC16

nC25

nC27

TsTm

χδ H

m

2728

29

Rel

ativ

e in

tens

ity

Time

OBIC 5(coal)

Fig. 7. Mass chromatograms of ions 71 (n-alkanes), 191(hopanes) and 217 (steranes) of OBIC 5 (Obi coal) from theAwgu Formation in the Middle Benue Trough.

Hydrocarbon prospects of sedimentary basins in Northern Nigeria 233

TOC contents (52.1–55.2 wt%), characteristic of coals,were recorded. Coals in the Upper Benue Trough havehitherto been known to occur only in the Lamja Forma-tion and in the Gombe Sandstone (e.g., Carter et al., 1963;Obaje et al., 1999). Since the youngest stratum penetratedby well Nasara-1 is the Pindiga Formation, these coalsprobably occur in the Yolde Formation or Bima Sand-stone. This is the first report of a coal in either the Pindiga,Yolde or Bima Formations. The precise formation in

which the coals occur has not yet been determined. Nei-ther is it clear how many similar coal intervals may occurdeeper in as-yet unpenetrated sections.

With the exception of the high TOC contents in thecoaly interval, none of the other recorded TOC valuesexceeded 1%; about one-half of them ranged between 0.50and 0.87% (Table 3). Hydrogen indices (HIs) are also lowand the highest value, apart from those in the coaly inter-val, was 160 mgHC/gTOC. Within the coaly interval by

Table 2. Rock Eval data of samples from the Upper Benue Trough

*mgHC/gTOC; **mgCO2/gTOC.

Sample ID Locality Formation TOC(wt%)

S1(mg/g)

S2(mg/g)

S3(mg/g)

Tmax(°C)

HI* OI**

UBWJ 2UBWJ 1UBHJ 4UBHJ 3UBHJ 2UBHJ 1UBDJ 2UBDJ 1MGMS 1MGMC 3LAMCO 7LAMCO 1MFS 3MFS 1DUKL 8DUKL 5DUKL 3DUKL 1MDS 13MDS 11MDS 4GONG 4GONG 3GONG 2GONG 1MGS 24MGS 7MGS 5MGS 2MGS 1PIND 10PIND 1MPS 77MPS 74MPS 72MPS 70MPS 63MPS 50MPS 20MYS 3MYS 2YOLD 6YOLD 4YOLD 2BIMA5

WuroWuroH/GariH/GariH/GariH/GariDohoDohoH/GariH/GariLamjaLamjaFikaFikaLakunLakunLakunLakunLakunLakunLakunAshakaAshakaAshakaAshakaAshakaAshakaAshakaAshakaAshakaPindigaPindigaGombeGombePindigaPindigaPindigaPindigaPindigaGombeGombeFutukFutukFutukBambam

GombeGombeGombeGombeGombeGombeGombeGombeGombeGombeLamjaLamjaFikaFikaDukulDukulDukulDukulDukulDukulDukulGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaYoldeYoldeYoldeYoldeYoldeBima

2.631.261.050.960.830.92

20.206.840.123.43

51.1050.700.070.070.610.340.360.720.530.910.450.550.530.520.590.090.160.420.500.370.710.120.230.070.640.470.520.570.300.210.050.120.300.350.07

0.010.010.010.010.010.010.620.13

0.081.472.15

0.020.010.010.030.010.020.010.020.010.010.02

0.010.010.010.02

0.01

0.020.010.020.020.060.01

0.010.01

0.060.050.030.030.030.03

35.9512.01

9.6291.7093.25

0.270.050.100.460.090.260.100.140.080.090.12

0.060.110.150.22

0.02

0.210.150.200.200.080.13

0.080.11

2.600.670.430.430.470.47

10.535.08

1.5814.1512.62

0.180.830.170.200.390.600.360.330.320.260.35

0.340.220.640.36

0.32

0.330.280.270.340.310.51

0.190.12

511515310502300282423429

432438438

429429436433434432435421417420419

421423425418

276

421419417421421424

437438

243343

178176

280179184

4515286417282226151720

1422403109

333238352662

2631

9953354557515274

462825

30242472874668161615060

8144

171510

139

52595260

102242

6334

234 N. G. Obaje et al.

contrast, HI values range from 564 to 589 mgHC/gTOC.Tmax values increase gradually with depth up to about3,000 ft; thereafter, they show little discernible trend, al-though a very high value of 514°C was recorded at thebottom of the well.

The thermal maturity represented by Tmax of 423–428°C for the coals equates to a vitrinite reflectance (Ro)of about 0.56–0.58%, which in turn corresponds to sub-bituminous A coals (Stach et al., 1982; Taylor et al., 1998).We note here and also in Obaje et al. (2004) that thematurities of coals are generally lower than those in theunderlying and directly overlying shaley intervals. How-ever the reason for this is not yet understood.

An assessment of the HI versus OI for well Nasara-1samples indicates that organic matter is predominantlyof Type III kerogen, except in the coaly interval whereType I kerogen is present. Juxtaposition of the HI versusTmax indicates that the shale samples have only gas-gen-erative potential, whereas the coal samples had oil-gen-erating potential.

Peters (1986) suggested that at a thermal maturityequivalent to vitrinite reflectance of 0.6% (Tmax 435°C),

rocks with HI above 300 mgHC/gTOC will produce oil;those with HI between 300 and 150 will produce oil andgas; those with HI between 150 and 50 will produce onlygas; and those with HI less than 50 are inert.

However, Sykes and Snowdon (2002) proposed thatcoaly source rocks are sufficiently different from marineand lacustrine source rocks in their organic matter char-acteristics to warrant separate guidelines for their assess-ment based on Rock-Eval pyrolysis. Using data from someNew Zealand coals, they concluded that the threshold foroil generation in coals occurs at Tmax of 420–430°C (Ro0.55–0.6%), and the threshold for oil expulsion is at Tmax430–440°C (Ro 0.65–0.85%).

A plot of S2 vs. TOC for shaley rocks in well Nasara-1 gave an average HI value of 45 mgHC/gTOC (Fig. 9a);the HI was 366 mgHC/gTOC for the coaly rocks(Fig. 9b). It should be noted that the average hydrogenindex of 45 mgHC/gTOC in Figure 9a is not reliable be-cause of the high scatter of the points (the regression co-efficient is 0.17). In this case, the Rock-Eval pyrolysis-generated hydrogen indices in Table 3 are more reliable.

The only evidence for assigning the interval 4710–4770 ft to a coaly lithology is the high TOC values. Allthe other data (HIs, Pr/Ph ratios, C28 steranes) point to alacustrine source rock. Equally, because no lacustrinesource rocks have such high TOC contents, and in theabsence of petrographic data at the moment, we assumethat some oils generated from a probably deeper seated

0 200 400 600

HI (mgHC/gTOC)

Gas

Oil

and

Gas

Oil

400 420 440 460 480 500 520Tmax (°C)

Oil source +Migrated oil

Beginning of hydrocarbon generation in coaly sourcerocks

Conventional begin ofhydrocarbon generation

TOC (wt%)

Dep

th (

ft)

NASARA-1

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

0.01 0.10 1.0 10

0.5

100

Gas source

Gas

sou

rce

Gas

sou

rce

y = 0.45x + 0.01

R2 = 0.17

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

0.00 0.20 0.40 0.60 0.80 1.00

(Av. HI = 45)

S 2(m

g/g)

TOC (wt%)(a)

y = 3.66x + 111.16R2 = 0.51

250

270

290

310

330

350

370

390

51.50 52.00 52.50 53.00 53.50 54.00 54.50 55.00 55.50

(Av. HI = 366)

S 2(m

g/g)

TOC (wt%)(b)

Fig. 8. TOC-HI-Tmax variations and hydrocarbon generationpotentials with depth in Nasara-1 well (note: hydrocarbons gen-erated must migrate and be trapped; therefore intervals indi-cated as gas or oil source refer to generative potential only).

Fig. 9. S2 vs. TOC plots of (a) shaley/siliciclastic and (b) coalysamples from Nasara-1 well with the regression equations whichgive the true average hydrogen indices (Av. HI).

Hydrocarbon prospects of sedimentary basins in Northern Nigeria 235

Table 3. Rock Eval pyrolysis data of samples from Nasara-1-well

Sample ID Formation TOC(wt%)

S1(mg/g)

S2(mg/g)

S3(mg/g)

Tmax(°C)

HI* OI** Depth(ft)

NAS-1NAS-2NAS-3NAS-4NAS-5NAS-6NAS-7NAS-8NAS-9NAS-10NAS-11NAS-12NAS-13NAS-14NAS-15NAS-16NAS-17NAS-18NAS-19NAS-20NAS-21NAS-22NAS-23NAS-24NAS-25NAS-26NAS-27NAS-28NAS-29NAS-30NAS-31NAS-32NAS-33NAS-34NAS-35NAS-36NAS-37NAS-38NAS-39NAS-40NAS-42NAS-43NAS-44NAS-45NAS-46NAS-47NAS-48NAS-49NAS-50NAS-51NAS-52NAS-53NAS-54NAS-55NAS-56NAS-57NAS-58NAS-59NAS-60NAS-61NAS-62NAS-63NAS-64

PindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaPindigaYolde?Yolde?Yolde?Yolde?Yolde?Yolde?Yolde?Yolde?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?Bima?

0.670.870.650.630.550.510.640.580.660.580.460.450.510.560.570.550.590.530.480.500.440.440.450.400.540.590.590.460.500.530.750.710.580.590.590.690.870.550.240.250.380.490.170.300.230.210.210.350.130.130.33

52.7055.2052.100.510.180.300.150.250.210.370.100.29

0.010.020.010.010.010.010.010.010.010.010.010.000.010.010.010.010.010.010.010.010.010.010.010.010.010.010.010.010.020.020.030.030.030.010.020.020.050.020.010.000.070.020.010.020.020.010.020.020.020.010.06

20.5622.6018.100.040.010.010.000.000.000.060.010.00

0.120.290.200.140.080.080.160.110.100.110.100.080.100.130.140.150.150.130.140.140.100.110.090.090.140.140.170.160.260.300.580.480.330.290.310.241.230.700.120.130.610.210.110.260.150.170.170.390.100.080.39

297.44314.29306.91

0.680.100.210.080.070.080.230.040.00

0.400.670.310.410.340.340.360.340.250.380.360.370.340.570.440.560.390.570.470.470.350.460.310.370.550.310.510.510.480.550.400.530.630.450.520.520.440.520.480.390.760.410.450.550.620.490.430.520.350.300.48

10.1311.1810.870.480.450.370.360.360.380.430.380.30

419420420420421423421423424424427426424420421424420424423423424424425426422419420426429427430433432433427428437442445445414463441442443435437432444444426427428423425440446444484466456457514

183331221516251915192218202324272625292823252022262429355257776857505235

142128

5052

160436386658179

1137861

119564569589134

5670542838624221

60774865626757593865788267

10277

10266

108989379

1046992

1025386

11096

1045375

1087788755195

20115619984

25918227023320115127322914619202194

253124242145182116399104

360390420450480510540570600630660690720750780810840870900930960990

10201050108011101140117012001230132013501380141014401500207025202970309037203870405040804110414042304320435046504680471047404770492049805040525052805310534054305760

*mgHC/gTOC; **mgCO2/gTOC.

236 N. G. Obaje et al.

Table 4. Rock Eval pyrolysis data of samples from the Chad Basin (the last set of figures on thesample ID refers to the depth in meters)

*mgHC/gTOC; **mgCO2/gTOC.

Sample ID Locality Formation TOC(wt%)

S1(mg/g)

S2(mg/g)

S3(mg/g)

Tmax(°C)

HI* OI**

KM-1 680KM-1-770KM-1-855KM-1-975KM-1-1070KM-1-1290KM-1-1385KM-1-1480KM-1-1620KM-1-1720MS-1-640MS-1-735MS-1-820MS-1-1005MS-1-1155MS-1-1260MS-1-1365MS-1-1440MS-1-2035MS-1-2375MS-1-2445MS-1-2515MS-1-2755TM-1-935TM-1-1125TM-1-1515TM-1-1685TM-1-1780TM-1-1810TM-1-1985TM-1-2285TM-S-2285TM-12605ZY-1-885ZY-1-990ZY-1-1210ZY-1-1325ZY-1-1880ZY-1-2085ZY-1-2205ZY-1-2405ZY-1-2685ZY-1-2840

Kemar-1 wellKemar-1-wellKemar-1-wellKemar-1-wellKemar-1-wellKemar-1-wellKemar-1-wellKemar-1-wellKemar-1-wellKemar-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellMurshe-1-wellTuma-1-wellTuma-1-wellTuma-1-wellTuma-1-wellTuma-1-wellTuma-1-wellTuma-1-wellTuma-1-wellTuma-1-wellTuma-1-wellZiye-1-wellZiye-1-wellZiye-1-wellZiye-1-wellZiye-1-wellZiye-1-wellZiye-1-wellZiye-1-wellZiye-1-wellZiye-1-well

GongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongila

1.131.110.600.860.800.760.720.770.720.590.960.890.780.960.971.050.690.830.660.790.690.550.780.330.930.790.570.920.690.770.600.920.370.710.661.070.720.590.340.230.350.670.84

0.030.020.010.020.020.020.020.020.040.020.020.020.020.030.040.040.030.020.020.020.020.010.010.010.010.050.020.030.020.030.030.060.150.020.020.060.030.060.020.010.020.020.12

0.840.430.220.320.200.220.120.180.640.080.220.230.210.690.840.380.210.270.070.040.040.020.020.100.310.280.150.240.110.090.100.330.220.540.321.340.610.340.150.090.120.261.04

0.390.440.420.450.551.030.750.591.240.750.740.540.610.460.540.670.810.570.610.930.960.730.820.640.410.420.540.590.570.420.560.620.570.500.550.500.551.130.690.380.480.590.80

435433434437440431441438447437419421429435439437438443444330322311330429431441445446440452443451290431430442441457457452482437448

74393737252917239014232627728736313211

5643

313335272616121736597648

125855844393539

124

3540705269

136105

76173128

776178485664

1186893

118139133105197

4453956483559368

15271834777

192204166139

8896

Basin have TOC values > 0.5 wt%, the minimum limitfor hydrocarbon generation (Table 4). The HI values allindicate gas-prone Type III organic matter with possibili-ties to generate gaseous hydrocarbons when juxtaposedagainst the Tmax. S2 vs. TOC plots gave an average hy-drogen index of 148 mgHC/gTOC in source rocks fromZiye-1 well, indicating a possible oil generating poten-tial (oil was not discovered in this well, but there is sucha possibility in prospects that have source rocks correlat-

or laterally located (yet to be identified) lacustrine sourcerock must have migrated and adsorbed into the coalyfacies, which were later intermittently subjected to an-oxic to suboxic biodegradation processes. It is thereforeassumed that a coaly source rock is present into whichalso some oils from a lacustrine source have migrated.

Chad BasinEighty percent of the shale samples from the Chad

Hydrocarbon prospects of sedimentary basins in Northern Nigeria 237

able to those in Ziye-1 well). Biomarkers show a domi-nance of short-chain n-alkanes with no obvious OEP andare very similar to what an oil show or oil sample wouldlook like (Fig. 10). A plot of the soluble organic matter(extract yield) against the TOC as proposed by Landaisand Connan (1980) in Jovancicevic et al. (2002) for Ziye-1-1210 (depth: 1210 m) indicate that some oils have ac-tually migrated (oil show/oil impregnation) in Ziye-1 well(Fig. 11). This diagram, however, is not suitable for de-termining expelled/migrated hydrocarbons in coals andcoaly samples, and for this reason, only plots of the ChadBasin samples can be considered reliable. Pristane/phytane ratios range from 0.80 to 2.98 that indicate an-oxic to oxic depositional environments. Steranes are domi-nantly of the C27 forms. The predominance of type-IIIorganic matter in this basin with dominantly marinedepositional environments (as confirmed by the high con-tents of C27 steranes) may be attributed to high oxic lev-els (high Pr/Ph ratios) which have downgraded organicmatter preservation in the marine system. The relativelyhigh Ts/Tm and low moretane/hopane ratios validatematurity levels that have entered the main phase of oilgeneration.

Mid-Niger/Bida BasinAlthough TOC values (Table 1) and liptinite contents

are relatively high in the Mid-Niger Basin samples, theTmax values, Ts/Tm and moretane/hopane ratios are in-dicative that hydrocarbons of mainly gaseous composi-tion (Fig. 5) are probably just being generated in the ba-sin and may not yet have been expelled nor migrated inlarge quantities. However, it is important to note at thisstage that some hydrocarbon seepages have been reportedalong the bank of River Niger around Pategi and Mokwain the Niger State of Nigeria (Philip Shekwolo, 2003,personal communications).

COAL AS A SOURCE ROCK

The subject of coal as a major source of oil and gas inmany parts of the world has been extensively reviewedand succinctly discussed by Hunt (1991) and many otherauthors. Coal has long been recognized as a source ofgas, primarily methane and carbon dioxide but its impor-tance as a source of economic accumulations of oil has

30.00 32.00 34.00 36.00 38.00 40.00 42.00 44.000

50

100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

850

900

950

1000

1050

1100

1150

1200

Time-->

Abundance

Ion 217.00 (216.70 to 217.70): 0207233A.D

32.00 34.00 36.00 38.00 40.00 42.00 44.000

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

6500

7000

7500

8000

8500

9000

9500

10000

10500

11000

11500

Time-->

Abundance

Ion 191.00 (190.70 to 191.70): 0207233A.D

10.00 15.00 20.00 25.00 30.00 35.00 40.00 45.00 50.000

10000

20000

30000

40000

50000

60000

70000

80000

90000

100000

110000

120000

130000

140000

150000

160000

170000

180000

Time-->

Abundance

Ion 71.00 (70.70 to 71.70): 0207233A.D

Ion 191 (triterpanes)

Ion 217 (steranes)

Ion 71 (n-alkanes)

Rel

ativ

e in

tens

ity

Time

Pr

PhnC

20

nC23

nC26

Ts Tm

αβH

m

27

28

29

Rel

ativ

e in

tens

ity

Time

ZY-1-1210(Ziye-1)

Fig. 10. Mass chromatograms of ions 71 (n-alkanes), 191(hopanes) and 217 (steranes) of Ziye-1-1210 (Ziye-1 well) fromthe Chad Basin (probably Gongila Formation).

Fig. 11. Soluble organic matter vs. TOC plots (based on Landaisand Connan in Jovancicevic et al. (2002)) of samples from theinland basins of Nigeria indicating migrated oil in Ziye-1 well.This diagram does not recognize the oil source rock potentialof coals and coaly samples and cannot therefore not be used toevaluate such samples.

238 N. G. Obaje et al.

been difficult to prove as coals are often interbedded withshales which are always assumed to be the source beds.Increasing evidence, however, suggests that coals andassociated type III kerogens can yield not only gas orcondensate (e.g., Tissot and Welte, 1984), but also sig-nificant quantities of oil (Murchison, 1987; Hunt, 1991;Hendrix et al., 1995). The traditional view that coals arelargely gas-prone may be the result of historical bias inthe study of North American and European Paleozoiccoals, prior to the study of Mesozoic-Cenozoic coals con-taining contributions from resinous conifers andangiosperms (Obaje and Hamza, 2000).

Pyrolysis data have revealed that the hydrocarbon rich-ness of sedimentary rocks is dependent on the amountand nature of liptinite and some vitrinite macerals (Hunt,1991; Hendrix et al., 1995). The abundance of liptinitemacerals is therefore the major criterion when consider-ing any sedimentary rock (including coal) as a potentialsource for liquid hydrocarbons. A minimum of 15–20%liptinite content (by volume) of total macerals in shales,carbonates, or coals is considered an important criterionfor a rock to be characterized as a potential oil sourcerock (Hunt, 1991). Although the concentration of long-chain aliphatic constituents has also been considered as a

Sample ID Formation Pr/Ph Ts/Tm m/αβH C27

(%)C28

(%)C29

(%)C27/C29

Anambra Basin

MAMU 22MAMU 19ENUG 13NKPO 5NKPO 4

MamuMamuEnuguNkporoNkporo

16.885.58

11.089.577.39

0.010.020.090.250.23

0.480.490.520.270.24

14.013.639.832.736.7

26.329.217.621.719.5

59.657.142.645.643.8

0.20.20.90.70.8

Mid-Niger Basin

AHOK 5AHOK 2AHOK 1

PattiLokojaLokoja

2.791.552.88

0.360.310.28

0.420.360.52

44.431.642.8

18.420.916.9

37.247.640.3

1.20.71.1

Middle BenueOBIC 5OBIC 2bMBJJ 7MBJJ 4MBJJ 2

AwguAwguAwguAwguAwgu

4.704.534.897.334.95

0.950.841.233.210.92

0.070.080.070.050.06

16.127.840.012.5

7.8

32.325.320.033.839.1

51.646.840.053.853.1

0.30.61.00.20.1

Upper BenueUBWJ 1UBHJ 4UBDJ 2MGMC 3LAMCO 1DUKL 8DUKL 1GONG 3PIND 10

GombeGombeGombeGombeLamjaDukulDukulGongilaPindiga

1.220.943.442.676.652.053.911.000.84

0.710.810.000.250.030.740.320.610.36

0.120.100.140.140.180.210.270.120.36

41.48.9

13.735.814.742.739.339.751.0

21.432.244.920.221.719.223.025.022.6

37.158.941.444.063.638.037.735.326.4

1.10.20.30.80.21.11.01.11.9

Chad BasinKM-1 680KM-1-1620MS-1-1005MS-1-1155TM-1-2605ZY-1-885ZY-1-1210ZY-1-1325ZY-1-1880ZY-1-2840

GongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongilaGongila

0.801.661.010.721.302.832.852.972.980.98

0.330.850.380.380.830.221.250.970.920.94

0.150.100.180.130.100.310.110.100.100.09

46.641.747.217.844.752.246.849.146.248.6

21.118.919.218.822.022.818.820.818.518.9

32.339.433.663.433.325.034.430.235.332.4

1.41.11.40.31.32.11.41.61.31.5

Table 5. Biomarker parameters of samples from the inland basins of Nigeria (resultsfrom the Anambra Basin as shown have not been discussed in this study)

Hydrocarbon prospects of sedimentary basins in Northern Nigeria 239

primary determinant of the oil generation potential ofcoals (Curry et al., 1994), the factors which govern theiroccurrence in different coals are poorly understood.Permian coals from the Cooper Basin in Australia, whichhave sourced commercial accumulations of oil (Curry etal., 1994), were deposited in high latitude bogs and con-tain 40–70% inertinite. Pristane/phytane ratios range from2.15 to 6.00 and HIs are moderate (up to 243 mgHC/gTOC). The extracts and pyrolysates both contain highrelative concentration of aliphatic groups. These aliphaticgroups were found to be derived from microbial biomass(bacterial and algal degradation products). The Taranakicoals (Late Cretaceous to Eocene) of New Zealand, whichalso are the source of commercial oil accumulations, weredeposited in temperate fluvial-deltaic environments (Col-lier and Johnson, 1991). HI values range from 236–365.Extracts have high pristane/phytane ratios and variableabundances of hopanoid and other non-hopanoid terpanes.The extracts and pyrolysates both contain high relativeconcentrations of aliphatic groups >nC20 which were in-terpreted to be derived directly from higher plant materi-als. The geochemical results from the studies of CooperBasin and Taranaki Basin coals show that long-chainaliphatic groups in coals can be derived directly fromhigher plant materials, from microbial activity in thedepositional environment, or from a combination of both.The geochemical data of our Benue trough coals are verysimilar to those of the Cooper Basin and the TaranakiBasin.

Coals and related continental strata with type III

kerogen provide the source for commercial oil accumu-lations in many other sedimentary basins around theworld: e.g., in the Mahakam Delta of Indonesia (Huc etal., 1986), the Karoo Basin in Tanzania (Mpanju et al.,1991), the Junggar and Tarim Basins in northwesternChina (Hendrix et al., 1995) and in the Harald and Lulitafields in the Danish Central Graben of the North Sea(Petersen et al., 2000). And in the Niger Delta of Nigeria,source rocks of dominantly type III kerogen produce thevast amounts of hydrocarbons that have accumulated inthat part of the West African continental margin. Themajor problem with hydrocarbons generated from coalysource rocks is the fact that most of such hydrocarbonsare adsorbed in the interstices of the coal matrix whichhas made effective expulsion, migration, accumulationand producibility very difficult (Barker et al., 1989). Thisis probably the case with the envisaged coaly-sourcedhydrocarbons in the Nigerian Benue Trough. Explorationfor hydrocarbons in these coals, therefore, must targetdeep coal seams that have been subjected to local andregional tectonics.

EVALUATION OF POTENTIAL PETROLEUM SYSTEMS

The build up of any prospect or of a petroleum systemrequires the availability of good quality source rocks.Additionally, the stratigraphic position of the sourcerocks, the availability of good quality reservoir and seallithologies, timing of hydrocarbon generation, favorableregional migration pathways and trapping mechanisms

11

1

1

12 21

1

1

1

2

2

2

2

2

2

Basement

BasementBasement

Basement

Horst

GrabenMigration

Gongola / Kerri-Kerri /Gombe basins

Yola / Lamurde / Laubasins

a

b

East West200 km

Fig. 12. Schematic illustrations of (a) Block faulting and the formation of horst and graben structures; juxtaposition of olderreservoir facies against younger source rock facies; (b) Down-warping, subsidence and tilting in the Maastrichtian makingprovision for more sediment accommodation in the Gongola/Kerri-Kerri/Gombe sub-basin.

240 N. G. Obaje et al.

must also be considered. In the Middle Benue Trough,juxtaposition of sandstone facies (Fig. 12a) of the Keanaand Awe formations against the Awgu Formation sourcerock can lead to some petroleum trappings in this region.Time equivalent marine and paralic sandstones (e.g., theMakurdi Sandstone) and other sandstone bodies withinthe Awgu Formation are expected to constitute additionalreservoirs. Prospects in the overlying Lafia Sandstone willbe too shallow and may lack adequate seals, but the pos-sibility of some traps within the Lafia Formation cannotbe ruled out. In the Upper Benue Trough, a similar juxta-position of sandstone facies against shaley and coalysource rocks as a result of block faulting that producednumerous horst and graben structures in this basin canprovide good drainage for generated hydrocarbons. In thisway, younger shaley and coaly source rocks can generatehydrocarbons that can be trapped in the underlying (butnow juxtaposed) very thick and laterally extensive (butcompartmentalized as a result of the block faulting) BimaSandstone (Fig. 12a). Shelf sandstones within the Pindiga,Dukul, and Gongila formations may also constitute addi-tional reservoir lithologies. Just like in the very shallowPaleocene Amal Formation in which significant volumeof oil has been discovered in the Muglad Basin of Sudan(Schull, 1988; Mohamed et al., 1999), possibilities ofshallow prospects within the Paleocene Kerri-Kerri For-mation in the Upper Benue Trough cannot be ruled out.Volcanic activities locally occur in this basin, but noneof the studied samples from this area has produced an

overcooked facies (Ro > 2.5%). In the Chad Basin, sourcerocks are mainly in the Gongila Formation (this study andOlugbemiro et al., 1997) and in the Fika Shale (Pettersand Ekweozor, 1982). Reservoirs may be provided bysandstone facies in the same Gongila and Fika formationsand in the Gombe Sandstone, where deposited. Most ofthe hydrocarbons in the Nigerian sector of the Chad Ba-sin may have been lost as result of the Tertiary hiatus(non-deposition). Source rocks, reservoirs and seals inthe Mid-Niger (Bida) Basin are in the Lokoja Sandstoneand in the Patti Formation (if hydrocarbons have beengenerated). Prospects in this basin get better towards thecenter of the basin in the Bida area.

With respect to the exploration and drilling campaignsso far undertaken, Maastrichtian tectonism has tilted andshifted the center of sedimentation in the Upper BenueTrough to the west in the so-called Gombe-Kerri-Kerrior Gongola sub-basin (Fig. 12b). The Gongola sub-basintherefore contains the thickest pile of sediments in theUpper Benue Trough and constitutes the more favorablesub-sector for exploration in that region. This is confirmedby Shell’s subcommercial success in Kolmani-River-1well (Fig. 13). Chevron’s Nasara-1 well was too shallowand was located on an anticlinal core of the Pindiga For-mation that was supposed to be the source rock (not cor-roborated in this study) for hydrocarbons that would havebeen generated for the targeted prospect. This is prob-ably responsible for the dry hole encountered in that cam-paign.

Fig. 13. Stratigraphy, structures, possible migration patterns and trapping mechanisms in the Upper Benue Trough (for theindicated section and horst trap) in relation to some exploratory wells drilled in the area.

Bima

Bima

Sill

SillDukul

Bima

Hiatus

Bima

YoldeYolde

JessuSekuliye

YoldeYolde

Gongila

PindigaGombe

Kerri-Kerri

W E

Ashaka GombeKolmani River-1

wellPindiga/Futuk

(Nasara-1 well) Biliri Lakun Lafiya-Lamurde

Yola sub-basinGongola sub-basin

Dadiya Syncline Lamurde Anticline

Volcanic

B a s e m e n t

Shell's subcommercial (33bcf) gas discovery

Chevron's target (dry) Migration

B a s e m e n t B a s e m e n t

SW

6000m

Hydrocarbon prospects of sedimentary basins in Northern Nigeria 241

SUMMARY AND CONCLUSIONS

Sedimentary basins in Northern Nigeria have beenhighly under-explored principally because of the poorknowledge of their geology, far distance from existinginfrastructure and the prolificity of oil in the Niger delta.These basins constitute one set of a series of Cretaceousand later rift basins in Central and West Africa whoseorigin is related to the opening of the South Atlantic.Commercial hydrocarbon accumulations have recentlybeen discovered in Chad and Sudan within this rift trend.This study has analyzed the quality of source rocks in thesedimentary basins of Northern Nigeria as a preliminarystep to understanding petroleum systems that may beavailable in the basins. At the core of every petroleumsystem is a good quality source rock. Coal beds consti-tute the greater part of the source rocks in most parts ofthe basins. Coal beds and type III generally are currentlywell recognized as effective source rocks and being seri-ously considered in many exploration activities. In theMiddle and Upper Benue Trough, good to fair source rockqualities characterize the coal beds of the Awgu Forma-tion and the Lamja Formation respectively, while fair topoor source rock qualities are inherent in the Chad basin.Our geochemical data indicate that some oils have beengenerated and migrated into some intervals penetrated byNasara-1 well and may have accumulated somewhere inthe basin. Similarly, some oil impregnations (oil shows)were recorded in Ziye-1 well at a depth of 1210 m. Gen-erated petroleum may not yet have reached the thresholdfor hydrocarbon expulsion in the Mid-Niger (Bida) Ba-sin. A review of petroleum system elements in the basinsindicate that commercial prospects may exist in sedimen-tary basins of Northern Nigeria. Although oil has not yetbeen discovered in commercial quantities in these basins,our biomarker spectra constitute an important data bankthat can be used to trace the source rocks for whateverhydrocarbons (oil and/or gas) that may be discovered inthese basins as exploration efforts continue. ChevronOverseas Petroleum Incorporation (COPI)’s explorationprogram in central Sudan was a classical textbook exam-ple of a successful drilling campaign, from concept toexploration and development, in an untested, remote, highrisk, high cost area (Kaska, 1989). With relentless andrejuvenated geological and geophysical studies, particu-larly with respect to the evaluation of potential petroleumsystems, commercial success may also be achieved in theNigerian sector of Africa’s inland basins, even if it maytake some time to put all the elements together. Apart fromthe samples from Nasara-1 well (Gongola Basin) andthose from the Chad Basin, all other samples analyzed inthis study were obtained from outcrops and some shal-low boreholes. Outcrop samples having undergone manyexogenic transformations (weathering, contaminations,anthropogeny) may not have yielded very reliable source

rock evaluation data, but being the only types of samplesavailable for study in this region at the moment, they nev-ertheless have constituted preliminary useful data, sinceduring sampling, attempts were made to cut back tounweathered materials. We recommend that a deep re-search well be drilled in each sector of Nigeria’s inlandbasins to furnish a better understanding of the stratigraphy,sedimentology and geochemistry of the yet chieflyunpenetrated deeper sections.

Acknowledgments—The greater part of this work was carriedout during an Alexander von Humboldt fellowship tenure ofthe first author at the Federal Institute for Geosciences andNatural Resources (BGR), Hannover-Germany, in 2002/2003.The organic geochemistry and organic petrology team at BGRHannover (Dr. Hermann Wehner, Dr. W. Hiltmann, Mrs. A.Balke, Mrs. Jolanta Kus, Mrs. A. Tietjen, Mrs. Monika Weiss,Mrs. A. Vidal) are gratefully acknowledged for assisting in thedata generation.

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