geochemical characterization and paleoenviroment of turonian dukul formation, ne nigeria

8/12/2019 Geochemical Characterization and Paleoenviroment of Turonian Dukul Formation, Ne Nigeria

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Scientific Research Journal (SCIRJ), Volume I, Issue II, September 2013 5ISSN 2201-2796

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2013, Scientific Research Journal

GEOCHEMICAL CHARACTERIZATION AND

PALEOENVIROMENT OF TURONIAN DUKUL

FORMATION, NE NIGERIA

Uzoegbu, M. Uche

Dept.Geology Programme, Abubakar Tafawa Balewa University, P. M. B 0248, Bauchi, Nigeria.

(+234) 08030715958; 08026827872E-mail: [email protected] [email protected]

Obaje, N. George

Department of Geology and Mining, Ibrahim Badamosi Babangida University, Lappai,

Niger State. E-mail:[email protected]

Ekeleme, I. Aquila

Petroleum Trust and Development Fund, Chair, Department of Geology and Mining, University of Jos, PMB 2084, Jos, Nigeria.

E-mail:[email protected]

Abstract- The Upper Benue rift comprising the Gongola and Yola Basins in Nigeria consist of the Aptian-Albian Bima Formation.

The Yolde Formation (Cenomanian-Turonian), Gongila/Pindiga/Dukul Formation (Turonian-Coniacian) and Gombe Formation

(Campanian-Maastrichtian). Shale from Turonian strata of the Dukul Formation has been characterized by petrological and

geochemical techniques. The aims of this study were to assess the quality of its organic matter, evaluate its thermal evolution and

highlight its potential as a source rock. The total organic carbon (TOC) (0.58wt%) of the shale constitutes that of a poor to fairly source

rock with gas-prone kerogen indicated by Rock-Eval S2/S3 (0.60). The low oxygen index (OI) (0.98 mgCO 2g-1TOC) and the presence of

biomicritic limestone suggest deposition under low energy environments. The plots of HI against T maxand predominance of vitrinite

rich macerals classified the organic matter as Type III kerogen. The poor concentration of OM is thought to account for its current

hydrogen index (35.0 mgHCg-1

TOC). The predominance of Type III kerogen in the Dukul Formation suggests their potential togenerate gas in the deeply buried sections. The Tmaxvalues from the pyrolysis of the shales of the Dukul Formation ranges from 431 to

442oC whereas Roof the shales ranges from 0.57 to 0.75%. These values correspond to maturity levels within the oil formation.

IndexTermsBenue Trough, Source rock, Kerogen type, pyrolysis, Maturity, Turonian.

I.INTRODUCTION

The Benue rift basin is a sediment-filled northeast trending structure in Nigeria (Cratchley and Jones, 1965; Burke et al., 1970). It

is divided geographically into the lower, middle and upper Benue regions (Fig. 1) and has been a subject of several publications

and discussions (King, 1950; Grant, 1971; Burke and Whiteman, 1973; Olade, 1975; Odebode, 1988). Although the associated

basins are thought to have formed from extensional processes, recent studies by Benkhelil (1982, 1987, 1989) suggest the

importance of sinistral wrenching as a dominant processes for the structural readjustment and geometry of the different subbasins.Two subbasins, the NNE/SSW trending Gongola and the E/W trending Yola Basins, are delineated in the Upper Benue Trough

(Fig. 2).The petroleum geology of the upper Benue rift basins (Gongola and Yola basins) has been of great interest to geologists

working in the Benue Trough, in the past few years (Idowu and Ekweozor, 1993; Obaje et al., 1999). This study is part of on-going

project to understand the depositional environments and petroleum potentials of the region (Akande et al., 1998a, 1998b; Ojo and

Akande, 1998; Ojo, 1999). In the present work, source rock samples from the boreholeand outcrop sections of the Dukul Formation

in the Yola Basin (Fig. 1) were investigated. The paleoenvironment of the Turonian Dukul Formation based on the

sedimentological descriptions and palynofacies analysis of outcrop sections, are investigated. The source rock potential and thermalmaturity are evaluated on the basis of total organic carbon, Rock-Eval pyrolysis, infrared spectroscopy and vitrinite reflectance

measurements on 12 samples from shallow water borehole and outcrop sections.
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Scientific Research Journal (SCIRJ), Volume I, Issue II, September 2013 7

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CF

BF

UPPER

B

ENUE

Gon

gola

Arm

Yola

Arm

MIDDLE

BENU

E

LOWER

BENUEAnambra

Basin

Enugu

Makurdi

Lafia

Abakaliki

Calabar

NIGERDELTA

COMPLEX

CAM

ER

OON

NIGERDELTA

COMPLEX

Portharcourt

CHAD (BORNU) BASIN

Maiduguri

BF

Tertiary-Recentsediment

Tertiary volcanics

Cretaceous

Calabar FlankCF

Benin Flank

Precambrianbasement

Major (reference) town

Sampled locality

BAUCHI

ATLANTIC

OCEAN

NN

Lau

Lamrude

0 50 100Km

Fig. 2: Geological map of the Benue trough (inset: map of Africa and Nigeria indicating separation of Africa from

South America, geological subdivisions of the Benue trough)

II.REGIONAL STRATIGRAPHIC SETTING

Cretaceous successions in the Upper Benue Trough are flanked by the Precambrian-Late Paleozoic basement gneisses and granitewhich occur as inlier on occasion (e.g the Kaltungo inlier). The Precambrian basement rocks are overlain by the Albian Bima

Sandstone as the oldest Cretaceous sediment in the region. This is overlain by the transitional Yolde Formation (Cenomanian-

Turonian), and succeeded by the marine Turonian to Coniacian Pindiga Formation, Gongila Formation in the Gongolat Basin and

its lateral equivalents; the Dukul, Jessu and Numanha formations in the Yola Basin (Fig. 3). These successions are overlain by the

Campanian-Maastrichtian Gombe Sandstone in the Gongola Basin and the lateral Lamja Sandstone (lateral equivalents) in the YolaBasin. The Tertiary Kerri-Kerri Formation capped the succession west of Gombe in the Gongola Basin.

III.LITHOSTRATIGRAPHY

The Dukul Formation was defined by Carter et al. (1963) as comprising a sequence of shale and thin limestone intercalations with a

type locality at Dukul in the north-eastern part of Dadiya syncline. In this study, the formation was found to be composed of greyshales with thin limestone and siltstone beds. The thin limestone beds are evenly distributed in the studied section at Lakun which

has a thickness of 30 m (Fig. 4A). The thin siltstone beds occur in the middle and towards the top of the Kutari and Lakun sectionsrespectively. The entire sections at these two localities form part of the Dukul Formation. The overlying Jessu Formation is a

marginal marine unit. The upper boundary of the Dukul Formation in the Lakun (Fig. 4A) and Kutari sections was not encountered.

At Dukul the formation measures about 60 to 91 m (Carter et al. (1963) and 80 m (Zaborski, 1990). A good section of the unit is

also exposed at Jessu. In all these sections, the lithofacies of the unit is composed of shales with thin interbedded limestone, whichmay measures a few centimeters to a maximum of 1m, and siltstones. The section of the unit described by Ojo and Akande (2000)

from Dukul contains thicker beds of limestone when compared with the other sections from the area. They reported a basal

limestone which measures about 2.2 m and an upper limestone bed intercalated between shales. The second limestone bed

measures about 2.1 m. The limestones are grain supported and rich in bivalves and gastropods. The section at Jessu consists mainly

of shale, siltstone and limestone intercalations. The limestone have average thickness of about 0.5 m, they are grey and grain to

mud supported. The shales have average thickness of 0.45 m (Ojo and Akande, 2000). The siltstone beds occur near the top and at


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the base of the section. The limestones are rich in macrofossils as demonstrated by the frequency occurrence of bivalve shells and

shell fragments. The limestones, shales and siltstones are grey or dark grey in colour, the shales are weathered. Generally, the

limestone occurs as two subfacies at Dukul and Jessu. These are shelly and crystalline limestone subfacies. The shelly limestone is

highly fossiliferous with macrofossils and occurs more frequently at both localities. The other subfacies is also fossiliferous,

indurated and occurs as bands. Oysters, mainly Exogyra, constitute the dominant fossils. Ostrea praelonga and Costugyra

olisiponensisare common. Ammonites, other unidentified pelecypods and gastropods are common. Common pelecypods include

members of the Neithea or Spondylusgroup. Some siphonate gastropods are also common. The associated common ammonites

belong to the genera VascocerasandHoplitoides.

The stratigraphic relationship is well illustrated by the Geological Survey of Nigeria (GSN) borehole N0. 1612 at Numan in the

Yola Basin of the Upper Benue Trough (Fig .4). This borehole penetrated the Dukul Formation and its bounding stratigraphic units

the Yolde andJessu Formations (Fig. 4B). The Dukul Formation occurs at 58-104.9 m. The unit has a total thickness here of 46.9 m

and it comprises grey shale with limestone interbeds in upper part (58-89.8 m). The rest of the formation consists of siltstone and

grey shale (89.8-104.9 m). The upper and lower boundaries of the formation are placed at the base and top of the sandstone bedrespectively. The stratigraphic contacts between the Dukul Formation and its vertically adjacent units are abrupt which is

suggestive of changes in depositional environments at the onset and close of its sedimentation. This abrupt character of the lower

boundary of the formation is supported by the evidence from a section of the unit described by Allix (1983) where the contact

between the Dukul and the underlying Yolde Formation is sharp. The above description of the lithofacies of GSN BH 1612 is in

agreement with that of Preez et al. (1965).


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AGE

LOWERBENUE

UPPERB

ENUE

M

IDDLEBENUE

CHAD/BORNUM

ID-NIGER

Quaternary

Miocene

Pliocene

Oligoce

ne

Eocen

e

Paleoce

ne

Campa

nian

Maastrichtian

Santonian

Coniacian

Turonian

Cenom

anian

Abian

Pre-Abian

ANAMBRA

BASINNIGERDELTACrossRiverGroup

Benin

Agbada

Akata

Nanka

Ameke/Imo/

Nsukka

Ajali/Owelli/

Mamu

En

ugu/Nkporo

Agbani

Nkalagu

Agbala

Odukpani

Volcanics

Hiatus

Volcanics

Hiatus

Lokoja

Ke

rri-Kerri

Go

mbe

Fika

YolasubGo

ngolasub

Chad

Hiatus

Gombe

Fika?

Gongila

Bima

Fika

Fika

Bima

Gong

ila

Pindig

a

Yolde

Lamja

Numanha

Sekuliye

Jessu

Dukul

Makurdi

AGWU

E

zeaku/Konshisha/

Wadata

Keana/Awe

Ar

ufu/Uomba/Gboko

Enugu/Nkporo

B

asem

entC

om

plex

Basement

Complex

Batati

Enagi

Pati

Lokoja

Unconformity

S

andstone

(

continental)

Siltstone

(c

ontinental)

Shale

(Marine)

Ironstone

(Continenta

l)

Transitionalboundary

Limestone

(Marine)

Coal

Majorunconformity

(fortheSantoniandeformation)

Claystone,mudstone,shale

(Continental)

Interfingeringmarinesand

stone

Asu

River

Group

Mfamosing/

Abakaliki

Fig.3:StratigraphicsuccessionintheBenuetrough,

theNigeriansectoroftheChadBasin,

theMid-NigerBasinandrelationshiptotheNigerdelta(afterObajeetal.,

2006).


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Y

OLDE

FORMATION

DUKUL

FORMATION

DUKUL

FORMATIO

N

JESSU

FORMATION

Siltstone

Shale with ironstone concretion

LEGEND

Shale with mudstone bands

Shale with limestone interbeds

Limestone

Sandstone

Shale

BA

29.3

30 m

27

26.7

25.1

24.6

22.4

21.8

2120.6

18.1

20

19.4

17.4

13.413.112.912.4

1110.4

8.7

8

6.6

6.25.4

54.443.6

1.5

1

0 m

2

0 m

1.6

33.2

33.6

40.4

47.7

36.7

38

89.8

104.9

95.5

107.5

116.5

131.2

133.9

195.3

196.6m

Clay

Fig. 4: Lithologic profile of Dukul, Jessu and Yolde Formations at Lakun (A), G.S.N borehole N0. 1612 at Numan (B).

IV.MATERIALS AND METHODS

Ten fresh outcrop sections of the Dukul Formation of limestones and shales located at Lakun and Kutari (Fig. 4A) and Five shalesamples (ditch cutting) from a shallow borehole (GSN BH 1612) located at Numan (Fig. 4B) and penetrating Dukul and Yolde


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Formations were selected and subjected to petrographic and organic geochemical techniques. Care was taking to avoid weathered

portions of the outcrop and to obtain material sufficient for various geochemical analyses. The samples were hard, thickly

laminated but not fissile, with texture indicative of low permeability. This macro-structure suggests minimum risk of organic matter

oxidation.

In the laboratory, the samples were reshaped using a rotating steel cutter to eliminate surface that could be affected by

alteration. Chips were cut from the samples and dried in an oven at 105oC for 24 hours. Chips cut perpendicular to bedding were

embedded in epoxy and polished following the procedures of Taylor et al. (1998) to yield polished blocks for reflectance andfluorescence studies using scan electronic microscope. Another portion of the dried sample was pulverized in a rotating disc mill to

yield about 50 g of sample for analytical geochemistry. The total organic carbon (TOC) and inorganic carbon (TIC) contents were

determined using Leco CS 200 carbon analyzer by combustion of 100 mg of sample up to 1600oC, with a thermal gradient of

160oC min

-1; the resulting CO2 was quantified by an Infrared detector.

The sample with known TOC was analyzed using a Rock-Eval 6, yielding parameters commonly used in source rock

characterization, flame ionization detection (FID) for hydrocarbons thermal conductivity detection (TCD) for CO 2.

The selected samples were crushed to less than 2 mm and impregnated in epoxy resin for quantitative reflected light

microscopy. Kerogen concentrates of the samples with sparse organic constituents were prepared, mounted and polished. Vitrinite

reflectance was measured using Reichert Jung Polyvar photomicroscope equipped with Halogen and HBO lamps, a photomultiplier

and computer unit at the Bundesanstaft fr Geowissenschaften und Rohstofte (BGR), Hannover, Germany. Mean random

reflectance of vitrinite using monochromatic (546 nm) non polarized light in conjunction with a x 40 oil immersion objective.

About 20 to 25g of each sample was analyzed for microfossil content. The samples were washed and treated with hydrogen

peroxide (H2O

2) and sodium bicarbonate (Na

2CO

3). The treated samples were dried in an oven. The dried samples were further

sieved through a 212 m mesh for easy picking. The picking, counting and identification of microfossils were done using reflectedlight under a binocular paleontological microscope. The identified microfossils were studied and classified.

V.RESULTS AND DISCUSSION

Organic Matter Concentration

The amount of organic carbon (TOC) is a measure of the quantity of organic matter (OM) in the source rocks (Tissot and Welte,

1984). As shown in Table 1, the Total Organic Carbon (TOC%) for the Turonian shales in the Dukul Formation vary from 0.25 to

1.15%. The average TOC value 0.58wt% for the Dukul shales indicates a moderate organic matter concentration (Hunt, 1979;

Tissot and Welte, 1984). In the Numan borehole, within depth interval of 70 to 180m, a vertical down hole variation in TOC values

of the shaly horizons which reflects changing paleoenvironments is observed (Ojo and Akande, 2002). An exceptionally high value

of TOC (12.9%) was recorded at depth of 93m in this borehole (Fig. 4B). This interval, interpreted as swamp facies (Akande,

1998a; Ojo, 1999) is probably rich in organic matter due to its proximity to organic sources (Bustin, 1988; Bustin andChonchawalit, 1997). The source rocks of the prodelta facies at the basal part of the deltaic cycles in the section (140-220m) have

lower organic matter concentration (0.21 to 0.89%) averaging 0.44% in a sample. The TOC values of the source rock facies of the

Dukul Formation in the Numan borehole, within depth interval of 16.50m average 0.37% in 4 samples. Higher TOC values in the

Dukul Formation were obtained in the outcrop sections at Lakun and Kutari areas where the average TOC is 0.77%. The lateral

variation in organic content probably reflects localized changes in organic productivity and preservation. The HI values for the

Dukul Formation range from 17 to 64mgHC/g TOC.


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Types and Quality of Organic Matter

The quality of organic matter (OM) in the source rock facies of the Dukul Formation was done by using Rock-Eval generated data(HI and Tmax) and infrared spectroscopy generated data (A-factor and C-factor).

The shale samples of the Dukul Formation plot mainly along the gas prone kerogen evolutionary pathway as indicated by the

plot of HI against Tmax(Fig. 5). This confirms that a substantial proportion of the organic matter is of terrestrial origin with gas

potential despite their marine environment of deposition. This view is further supported by the ratios of A-factor and C-factor (1.3),

which shows predominance of gaseous prone type III organic matter in the shales of the Dukul Formation. They contain relatively

high carbonyl/carboxyl groups and moderate aliphatic groups (Ojo and Akande, 2002).

0

100

200

300

400

500

600

0 100 200 300 400 500

Series1

GASOIL & GAS OIL

HI (mg HC/g TOC)

Tmax

(oC)

DUKUL

This is further supported based on the Mukhopadyay and Hatcher (1993) classification of kerogens relative to HI and OI, all of the

samples plots within Type III field, where desmocollinite (collodetrinite) is dominance macerals as a good potential for the

generation of gas (Fig. 6). The gas-prone nature of this rock rules out Type II kerogen, which usually shows S2/S3greater than 5,

while the maturity from vitrinite reflectance as well as Tmaxsuggest that the current HI results from thermal evolution of a Type III

Table 1: Rock-Eval pyrolysis, vitrinite reflectance and infrared spectroscopy data of samples from Dukul Formation. A-

factor = I (2930cm-1) + (2860cm-1)/ I (2930cm-1) + (2860cm-1) + I (1630cm-1); C-factor = 1(1710 cm-1)/I (1710 cm-1) +

(1630cm-1), where I is the intensity corresponding to peak heights at their respective wave numbers. HGP = A-factor x

TOC x 10, (Ganz and Kalkreuth, 1987)

Fig. 5: Classification of kerogens of the Dukul Formation on the HI Tmax


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kerogen, with initial HI between 600 mgHC g-1

TOC and 850 mgHC g-1

TOC (Lafargue et al., 1998). Low TOC contents (as low as

0.58 wt %) and HI between 17 and 64 mg HC/g TOC characterize the shale beds of the Dukul Formation. The regression equation

based on the S2vs. TOC diagram gave an average HI value of 35 mg HC/g TOC for the Dukul shales (Fig. 7). A plot of S2vs. TOC

and determining the regression equation has been used by Langford and Blanc-Valleron (1990) as the best method for determining

the true average HI and measuring the adsorption of hydrocarbons by rock matrix.

0

100

200

300

400

500

600

700

0.00 2.00 4.00 6.00 8.00 10.00

Series1

Type I

Type II

Type III

DUKUL

OI (mgHCg-1 TOC)

HI(mgHCg-1

TOC)

0.00

0.20

0.40

0.60

0.80

1.00

0.00 2.00 4.00 6.00 8.00 10.00 12.00

y = 0.3471 x 0.1051

R2 = 0.365

TOC (wt %)

S2mgHCg-1

rock

DUKUL

Peters (1986) has suggested that at a thermal maturity equivalent to vitrinite reflectance of 0.6% (Tmax435oC), rocks with HI above

300 mg HC/g TOC produce oil, those with HI between 300 and 150 produce oil and gas, those with HI less than 50 are inert. The

Fig. 6: Composite HI OI classification of kerogen types of source rocks in the Dukul Formation

Fig. 7: Classification of kerogens of the Dukul Formation on the S2 TOC


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TOC is a primary parameter in source rock appraisal, with a threshold of 0.5-1 wt% at the immature stage for potential source rocks

(Tissot and Welte, 1984; Bordenave et al., 1993; Hunt, 1996). The value of 0.58 wt% of the shale studied falls within this

threshold. High TOC of 4.45 wt% was obtained in Mamfe basin and this value exceeds the threshold for oil generation (Eseme et

al., 2006). However, high TOC is not a sufficient condition for oil generation. Coals usually have high TOCs that exceed 50 wt%

but do not generate oil except when rich in liptinite, indicating the relevance of maceral composition. In contrast, deltaic sediments

may have TOCs below 1 wt% but generate commercial accumulations of petroleum due to deposition of large volumes of

sediments, as seen in the Niger Delta. High TOC content in shales indicates favorable conditions for preservation of organic matter

produced during deposition. This may related to the redox condition, with high oxygen favoring organic matter oxidation, but alsoamount of organic matter produced.

Thermal Maturity

Shale samples of the Dukul Formation in the study area have Tmaxvalues in the range of 431 to 442oC and vitrinite reflectance

values 0.57 to 0.75 Ro% (Table 1). These values correspond to maturity levels within the oil formation zone (Espitali et al., 1984;

Ramanampisoa and Radke, 1992; Plumer, 1994; Gries et al., 1997). Average Tmaxand vitrinite reflectance of the Dukul Formation

indicate a fairly increasing thermal evolution from the youngest Jessu Formation to oldest Yolde Formation. The thermal maturity

levels attained by the source rock facies in the Yolde basin compared to the immaturity status of their stratigraphic equivalents

(Pindiga and Gongila Formations) in Gongola Basin (Alkande et al., 1998a; Ojo, 1999) suggest possible influence of additional

reheating by Tertiary Volcanics in the Yola Basin.

The production index (PI) is used to assess the generation status of source rocks but is often useful when homogeneous source

rocks of different rank are compared, in which case it is characterized as the transformation ratio (Bordenave et al., 1993). Hunt

(1996) suggested that a PI from 0.08 to 0.4 is characteristic of source rocks in the oil window. The value of 1.2 of this shale is

consistent with its vitrinite reflectance of 0.65%Ro. This maturity is also consistent with the fairly well fluorescing organic matter

as well as Rock Eval Tmaxof 436oC, reaching the 431-442

oC for high sulphur mature source rocks containing Type III (Bordenave

et al., 1993; Hunt, 1996). The PI is not affected by expulsion (Rullktter et al., 1988) and this will not limits its use as an indicator

of the organic matter transformation because generation may start for rocks with Type II at 0.55%Ro(Leythaeuser et al., 1980).Rullktteret al. (1988) used a mass balance scheme to show that, at 0.68% Ro, the transformation ratio in the Posidonia shale from

northern Germany had reached 30%.

Hydrocarbon Source Rock Potential

The assessment of source rock potential in the study area is based primarily on the TOC, genetic potential (Tissot and Welte, 1984;

Dyman et al., 1996) and organic matter maturity. With average TOC values of 0.51, 0.58, 0.53 for the Yolde, Dukul and Jessu

formations respectively (Ojo and Akande, 2002) which met the minimum of 0.5% required for petroleum source beds (Tissot andWelte, 1984), the source rock units are nevertheless lean in terms of organic matter concentration. This poor organic matter

concentration may be due to deposition under oxic conditions in the Cenomanian-Turonian times (Unomah and Ekweozor, 1987;

Olugbamiro et al., 1997; Demaison and Moore, 1980; Abubakar, 2000).Generally, the genetic potential (S1 + S2 < 1.0 mg HC/g rock) and hydrocarbon generation potential (HGP) A-factor x 10 < 10)

for the Yolde, Dukul and Jessu formations are low (Table 1), except for the suggested organic rich deltaic swamp facies of the

Yolde Formation with a genetic potential of 26.59 HG 5 rock and HGP 65 (Ojo and Akande, 2002). Despite the favorable thermal

conditions to hydrocarbon generation, rich source rocks were not encountered. The TOC, HI, genetic potential and HGP indicates

that the source rocks have a poor potential for generating economic amount of petroleum (Dyman et al., 1996; Ramanampisoa and

Radke, 1992; Tissot and Welte, 1984).

Using Espitali et al. (1984) classification, Ojo and Akande(2002) plotted HI against Tmax which indicates that source rocks

of the Yolde, Dukul and Jessu formations are dominated by type III (gas prone) kerogen derived from terrestrial plants excepts forthe swamp facies of the Yolde Formation with some indication of type II (oil prone) kerogen. The predominance of type III

kerogen in the shales is further supported by the of A-factor against C-factor from infrared data and the predominance of vitrinite

and inertinite maceral (Akande et al., 1998a) which classified the shales as having gas-prone type III kerogen. The relative high

amount of liptinite maceral in some samples of the Yolde Formation gives indication of type II and type III kerogen admixtures. It

has been documented that only rocks which have abundant hydrogen-rich macerals (liptinite) can yield sufficient hydrocarbon for itto be effective source rock (Saxby, 1980; Snowdon and Powell, 1982; Thompson et al., 1985). Type III and IV kerogens arevitrinite-rich and also contain residual carbons which are regarded as gas producers with much less oil potential (Littke and ten

Haven, 1989).

Biostratigraphy

The limestone of the Dukul Formation are highly fossiliferous, the shales contain less fossils. The macrofossils include ammonites,

bivalves and gastropods. Ammonites are common in certain horizons in the Upper Benue Trough. This has been documented by

previous workers (Barber, 1957; Carter et al., 1963; Hirano, 1983, Meister, 1989; Zaborski, 1990, 1993ab, 1995, 1996; Courvilie,1992). The following ammonites were found in this study in the limestones of the Dukul Formation at Lakun and Kutari villages:

Vascoceras globosum costatum (Reyment), V. globosum (Reyment), Pseudovascoceras nigeriense (Woods), pseudaspidoceras

pseudonodosoides (Choffat), Thomasites gongilensis (Woods), Wrightoceras wallsi (Reyment) and Pseudolissolia nigeriensis


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(Woods). The fauna in this location can be subdivided into a lower Vascoceraszone and an upper Hoplitoides ingenszone. The

latter ranges into the Middle Turonian. Other mollusks that occur in the Dukul Formation include oysters commonly represented by

Ostrea sp andExogyra sp which form the bulk of the fossils of some the limestones (Uzoegbu, 2003).

Ostracods and foraminifera were also studied from the formation. The ostracod assemblage is more diverse than that of than

that of the foraminifers. The following ostracod species have been identified. Ovocytheridea apiformis Aposotlescu, O.

symmetricaReyment, O. ashakaensis Okosun, O. reniformis Van den Bold, Cythereis gabonesis Neufvilie, C. vitilliginosa

reticulata Apostlescu, Brachcythere ekpo Reyment, Hutsonia ascalapha Van den Bold, B. sapucariensis Krommelbein,Protobuntonia semicostellotaGrekoff, Cytherellasp andDumontinasp. Figure 8 shows some of the ostracods found in the Dukul

Formation. The foraminiferal assemblage includes the following: Ammotium nkalagum Petters, A. bauchensis Petters, A.

pindigensisPetters,Millaminasp,Heterohelixsp andHaplophragmoides bauchensisPetters (Fig. 9). Some

Fig. 8: Some ostracods in the Dukul Formation: 1. Brachcytheridea sp.; 2. Cytherella sp.; 3. Ovocytheridea

sp.;4. Ovocytheridea sp.; 5. Cytherella sp.; 6. Cytherella sp.; 7. Ovocytheridea sp.; 8. Cythereis sp.; 9.

Cythereis sp.; 10.Cytherell a sp.; 11. Rostrocytheridea sp.; 12. Cytherella sp.; 13Ovocytheridea sp.; 14.

Cytherella sp.; 15. Cytherella sp. (All magnifications x 200)


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Ostracods Foraminifera

DUKUL

FORMATION

Formation

Lithology

SampleDepth(m)

Ovocytherideaapiformis

O.symmetrics

Cythereisgabonens

is

Buntoniasemicoste

lata

Cytherellasp.

Hutsoniaascalapha

Clithrocysenegali

O.reniformis

O.nuda

Cythemeisv.reticlata

Dolocytherideasp.

Dumantinasp.

Ammobaculitiessp.

A.nkalagun

A.

baunchensis

Herohelixsp2.

Herohelixsp1.

17.4

12.4

21.8

25

27.6

29.5

O

O

O

O

O

O

O

O

O

O

O

O

O

O

O

O O O

O

O O

O O O

O

O

O

O

O

O

of the foraminifera found in the Dukul Formation are shown in Figure 10. Some of the benthonic and planktonic foraminifera found

in the Upper Benue Trough are illustrated in Figures 11 and 12 respectively. The ostracod and foraminiferal assemblages aresimilar to those from the Pindiga Formation (Okosun, 1998) and the Fika Shale (Okosun 1992). The ammonite evidence from the

Dukul Formation suggests an Early to possibly basal Middle Turonian age. The ostracods have long ranges which indicate a

Cenomanian-Turonian age. On the basis of the more age definitive ammonites evidence, the Dukul Formation can be dated Earlyto basal Middle Turonian.

Fig. 9: Distribution of ostracods and foraminifera in Dukul Formation at Lakun, Lithology as in

figure 4A


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Fig. 10: Some foraminifers in the Dukul Formation: 1. Heterohelixsp.; 2. Heterohelixsp.; 3. Heterohelixsp.;

4. Haplophragmoids sp.; 5. Ammotium sp.; 6. Ammobaculitessp.; 7. Ammobaculitessp.; 8. Ammobaculitessp.;

9. Haplophragmoids sp.; 10. Ammobaculitessp. (All magnifications x 350)


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Fig. 11: Some Benthonic foraminifera from Cenomanian-Turonian sequences in the Upper Benue Trough. 1,2

Ammobiculites coprolithi formi s; 3 Ammobicul ites bauchensis; 4 Ammobiculites benuensis; 5 Ammobiculites

pingigensis; 6 Ammotium bornum; 7 Ammotium nwalium; 8 Ammotium sp.; 9 Bathysiphon sp.; 10 Reophax

quineana; 11 Reophax minuta; 12 Textulari sp.; 13 Saccammina sp.; 14 Trochammina cf. Taylorana; 15

Trochamminasp.; 16 Milliamminasp.; 17 Haplophragmoides saheliense; 18,19 Haplophragmoides bauchensis; 20

Gavelinelta sp.; 21 Bolivina sp.; 22 Fursenkeina nigeriana; 23 Nonionella sp.; 24 Quinquloculina sp. ( Allmagnifications x 200) (After Abubakar, 2000)


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Paleoenvironment

The paleoenvironment of the Dukul Formation in the study area is inferred based on the lithofacies from the eleven samples,

population and diversity of the microfaunas (foraminiferal and ostracods) their assemblages and vertical distribution. The

lithofacies (Fig. 4) include fine-grained dark grey fossiliferous limestone (sandy biomicrite) at the base and black shale. Most of the

Fig. 12: Some planktonic foraminifera from the Cenomanian Turonian sequences of the Upper Benue

Trough. 1,2,4 Heterohelix glubulosa; 3,5 Heterr oheli x reussi; 6,7 Heterohelix moremani; 8 Guemblitria

cenoman; 9 Hedbergell a cf. delr ioensis; 10 Hedbergella planispira(All magnifications x 200 (After Abubakar,

2000).


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planktonic foraminifers are dwarfed with their last chambers pyritized especiallyHeterohelix. Also the tests of the few arenaceous

benthics and the ostracods found in association with the planktonics are dark grey to black due to pyritization.

The presence of biomicritic limestone is an indication of deposition under low energy environments (open shelf below wave

base or restricted lagoon). Pyrite is an early diagenetic mineral that forms when the overlying sediments is being deposited. The

pyritization of the foraminifers and ostracods probably took place shortly after death when individuals were buried a few

millimeters of centimeters below the surface, where reducing conditions prevented the complete decomposition of the organic

matter (Oertli, 1971). Due to the high amount of pyrite formed, it probably replaced the calcite that originally formed the test,which gave some of the tests their black coloration.

Successive units overlying the black shale are alternations of black to dark grey shale with grey marl beds and finally overlain

by grey mudstone bed. The sequence in this section shows shoaling-up. The presence of a large number of agglutinated benthicforaminfers supports the shoaling-up sequences. The presence of black shale with a large population of planktonic foraminifers and

ostracods with few benthics indicates deposition in deeper marine conditions under an oxygen depleted highly reducing

environment. Oertli (1971) suggested that anoxic conditions in a basin are indicated by poor benthonic faunas and a large

population of planktonic foraminifers (Petters, 1982).

The sediments of Dukul Formation in the study area based on lithofacies and microfaunal association show deposition in littoral

to open marine shelf paleoenvironments.

VI.CONCLUSION

The Turonian Dukul Formation in the Yola Basin contain source rocks that generally have potential less than 2, 000 ppm,suggesting that they cannot generate economic amount of hydrocarbons. The predominance of terrestrially derived organic matter

(Type III kerogen) within the various source rock horizons suggests that the Yola Basin region is gas prone. Thermal maturity

indicators such as measured vitrinite reflectance and Tmax indicate that the source rocks are thermally mature. There is

predominance of allochtonous type III organic matter and low concentration of organic matter in the middle Cretaceous Dukul

shales which suggest prevalence of oxic condition contrary to the earlier proposed mid Cretaceous anoxic model in the BenueTrough based mainly on foraminiferal content. The Dukul Formation can be dated Early to basal Middle Turonian based on

definitive ammonites evidence and its sediments also showed deposition in littoral to open marine shelf paleoenvironments based

on lithofacies and microfaunal associations.

ACKNOWLEDGMENT

Gratitude is expressed to Prof. N.G. Obaje for having patiently supervised my M.Sc. work. The Alexander von Humboldt

Foundation is gratefully acknowledged for a fellowship award to my supervisor which enabled the analyses of some of my samplesat the Federal Institute for Geosciences and Natural Resources in Hannover (Germany).

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