Scirj geochemical characterization and paleoenviroment of turonian dukul formation, ne nigeria by SciRJ org

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

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; 08026827872 E-mail: muuzoegbu@yahoo.com or muuzoegbu@gmail.com

Obaje, N. George Department of Geology and Mining, Ibrahim Badamosi Babangida University, Lappai, Niger State. E-mail: nobaje@yahoo.com

Ekeleme, I. Aquila Petroleum Trust and Development Fund, Chair, Department of Geology and Mining, University of Jos, PMB 2084, Jos, Nigeria. E-mail: ifeomaokafor19@yahoo.com

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 mgCO2g-1TOC) and the presence of biomicritic limestone suggest deposition under low energy environments. The plots of HI against T max and 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-1TOC). The predominance of Type III kerogen in the Dukul Formation suggests their potential to generate gas in the deeply buried sections. The Tmax values from the pyrolysis of the shales of the Dukul Formation ranges from 431 to 442oC whereas Ro of the shales ranges from 0.57 to 0.75%. These values correspond to maturity levels within the oil formation. IndexTermsâ&#x20AC;&#x201D;Benue 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 thermal maturity 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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STUDY LOCATION

Fig 1: Geological map of Nigeria showing the study location in the Upper Benue Trough (modified from Obaje et al 2004).

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CHAD (BORNU) BASIN

BAUCHI

u La

UP G P E ongol a R Arm BE NU E

Maiduguri

â&#x20AC;&#x201C;

mr La

A LT DE R EX GE PL NI OM C

GE CO R D MP EL LE T A X

Anambra Basin

Lafia

E ENU EB L D MID

Makurdi

LOWER BENUE

Enugu

la Yo

Arm

Abakaliki Tertiary-Recent sediment

CF Calabar

ATLANTIC OCEAN

e ud

100 Km

Calabar Flank

Tertiary volcanics

Precambrian basement

Cretaceous

Major (reference) town

Portharcourt

Benin Flank

Sampled locality

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 granite which 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 (CenomanianTuronian), 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 Yola Basin. 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 grey shales 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 sections respectively. 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, which may 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 olisiponensis are common. Ammonites, other unidentified pelecypods and gastropods are common. Common pelecypods include members of the Neithea or Spondylus group. Some siphonate gastropods are also common. The associated common ammonites belong to the genera Vascoceras and Hoplitoides. 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 itâ&#x20AC;&#x2122;s 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 bed respectively. 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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Nanka Ameke/Imo/ Nsukka

Akata

la gi n o

Coal

Limestone (Marine)

Transitional boundary

Basement Complex

Lokoja Lokoja

Pati

Enagi

Batati

MID-NIGER

Interfingering marine sandstone

Major unconformity (for the Santonian deformation) Claystone, mudstone, shale (Continental)

Bima

Gongila

Fika

Gombe Fika ?

Hiatus

Chad

CHAD/BORNU

Fig. 3: Stratigraphic succession in the Benue trough, the Nigerian sector of the Chad Basin, the Mid-Niger Basin and relationship to the Niger delta (after Obaje et al., 2006).

Siltstone (continental)

Bima

Fika Fika

Gombe

Kerri-Kerri

Yolde

Lamja Numanha Sekuliye Jessu Dukul

Hiatus

Volcanics

Yola sub Gongola sub

UPPER BENUE

B a s e m e n t C o m p l e x

Arufu/Uomba/Gboko

Keana / Awe

AGWU Ezeaku/Konshisha/ Wadata

Makurdi

Enugu/Nkporo

Hiatus

Volcanics

MIDDLE BENUE

Shale (Marine) Ironstone (Continental)

Mfamosing/ Abakaliki

Odukpani

Agbala

Nkalagu

Agbani

Enugu/Nkporo

Ajali/Owelli/ Mamu

Asu River Group

Sandstone (continental)

Benin

Agbada

Unconformity

Pre-Abian

Abian

Cenomanian

Turonian

Coniacian

Santonian

Campanian

Maastrichtian

Paleocene

Eocene

Oligocene

Miocene

Pliocene

Quaternary

Cross River Group

ANAMBRA NIGER DELTA BASIN

LOWER BENUE

a Pin dig

AGE

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FORMATION

0m 2

FORMATION

8 8.7

10.4 11 12.4 12.9 13.1 13.4

JESSU

40.4

47.7

36.7 38

FORMATION

3.6 4 4.4 5 5.4 6.2 6.6

33.2 33.6

89.8

DUKUL

0m 1 1.5

1.6

95.5

19.4 20 20.6 21 21.8 22.4 24.6 25.1 26.7

107.5

LEGEND 116.5

Shale with ironstone concretion Siltstone 131.2 133.9

YOLDE

DUKUL

17.4 18.1

FORMATION

104.9

Limestone Sandstone

29.3 30 m

Shale with mudstone bands Clay Shale with limestone interbeds

195.3 196.6m

Shale

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 shale samples (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 105 oC 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 and fluorescence 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 1600 oC, 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 für 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 (H2O2) and sodium bicarbonate (Na2CO3). The treated samples were dried in an oven. The dried samples were further sieved through a 212 µm mesh for easy picking. The picking, counting and identification of microfossils were done using reflected light 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 and Chonchawalit, 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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Table 1: Rock-Eval pyrolysis, vitrinite reflectance and infrared spectroscopy data of samples from Dukul Formation. Afactor = 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)

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). 600

500

GAS OIL & GAS

OIL

T max (oC)

400

DUKUL

300

Series1

200

100

0 0

100

200

300

400

500

HI (mg HC/g TOC)

Fig. 5: Classification of kerogens of the Dukul Formation on the HI â&#x20AC;&#x201C; Tmax 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 S 2/S3 greater than 5, while the maturity from vitrinite reflectance as well as Tmax suggest that the current HI results from thermal evolution of a Type III

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kerogen, with initial HI between 600 mgHC g-1TOC and 850 mgHC g-1TOC (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 S2 vs. TOC diagram gave an average HI value of 35 mg HC/g TOC for the Dukul shales (Fig. 7). A plot of S2 vs. 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. 700

Type I

HI (mgHCg-1 TOC)

600

Type II

500

400

DUKUL Series1 300

200

100

Type III 0 0.00

2.00

4.00

6.00

8.00

10.00

OI (mgHCg-1 TOC)

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

1.00

0.80

S2 mgHCg-1 rock

y = 0.3471 x – 0.1051 R2 = 0.365 0.60

DUKUL

0.40

0.20

0.00 0.00

2.00

4.00

6.00

8.00

10.00

12.00

TOC (wt %)

Fig. 7: Classification of kerogens of the Dukul Formation on the S2 – TOC Peters (1986) has suggested that at a thermal maturity equivalent to vitrinite reflectance of 0.6% (T max 435oC), 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

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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 also amount of organic matter produced. Thermal Maturity Shale samples of the Dukul Formation in the study area have T max values 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 (Espitalié et al., 1984; Ramanampisoa and Radke, 1992; Plumer, 1994; Gries et al., 1997). Average Tmax and 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 Tmax of 436oC, reaching the 431-442oC for high sulphur mature source rocks containing Type III (Bordenave et al., 1993; Hunt, 1996). The PI is not affected by expulsion (Rullkӧtter 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%R o (Leythaeuser et al., 1980). Rullkӧtter et 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 and Welte, 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 Espitalié 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 for the 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 it to be effective source rock (Saxby, 1980; Snowdon and Powell, 1982; Thompson et al., 1985). Type III and IV kerogens are vitrinite-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 Vascoceras zone and an upper Hoplitoides ingens zone. The latter ranges into the Middle Turonian. Other mollusks that occur in the Dukul Formation include oysters commonly represented by Ostrea sp and Exogyra 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 semicostellota Grekoff, Cytherella sp and Dumontina sp. 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. pindigensis Petters, Millamina sp, Heterohelix sp and Haplophragmoides bauchensis Petters (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. Cytherella sp.; 11. Rostrocytheridea sp.; 12. Cytherella sp.; 13 Ovocytheridea sp.; 14. Cytherella sp.; 15. Cytherella sp. (All magnifications x 200)

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Herohelix sp2.

Herohelix sp1.

A. baunchensis

Ammobaculities sp.

A. nkalagun

Dumantina sp.

O O

Dolocytheridea sp.

Cythemeis v. reticlata

O. nuda

Foraminifera

O. reniformis

Clithrocy senegali

Hutsonia ascalapha

Cytherella sp.

Buntonia semicostelata

Cythereis gabonensis

O. symmetrics

Ovocytheridea apiformis

Sample Depth (m)

Lithology

Formation

Ostracods

DUKUL

FORMATION

12.4

17.4

21.8

O O

O O O

27.6

29.5

O O O

O O

Fig. 9: Distribution of ostracods and foraminifera in Dukul Formation at Lakun, Lithology as in figure 4A 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 are similar 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 ammoniteâ&#x20AC;&#x2122;s evidence, the Dukul Formation can be dated Early to basal Middle Turonian.

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Fig. 10: Some foraminifers in the Dukul Formation: 1. Heterohelix sp.; 2. Heterohelix sp.; 3. Heterohelix sp.; 4. Haplophragmoids sp.; 5. Ammotium sp.; 6. Ammobaculites sp.; 7. Ammobaculites sp.; 8. Ammobaculites sp.; 9. Haplophragmoids sp.; 10. Ammobaculites sp. (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 coprolithiformis; 3 Ammobiculites 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 Trochammina sp.; 16 Milliammina sp.; 17 Haplophragmoides saheliense; 18,19 Haplophragmoides bauchensis; 20 Gavelinelta sp.; 21 Bolivina sp.; 22 Fursenkeina nigeriana; 23 Nonionella sp.; 24 Quinquloculina sp. ( All magnifications x 200) (After Abubakar, 2000)

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Fig. 12: Some planktonic foraminifera from the Cenomanian â&#x20AC;&#x201C; Turonian sequences of the Upper Benue Trough. 1,2,4 Heterohelix glubulosa; 3,5 Heterrohelix reussi; 6,7 Heterohelix moremani; 8 Guemblitria cenoman; 9 Hedbergella cf. delrioensis; 10 Hedbergella planispira (All magnifications x 200 (After Abubakar, 2000). 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

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planktonic foraminifers are dwarfed with their last chambers pyritized especially Heterohelix. 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 benthic foraminfers 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 Benue Trough based mainly on foraminiferal content. The Dukul Formation can be dated Early to basal Middle Turonian based on definitive ammonite’s evidence and it’s 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 samples at the Federal Institute for Geosciences and Natural Resources in Hannover (Germany). REFERENCES [1] Abubakar, M.B. (2000). Cenomanian-Turonian anoxic event and potential petroleum source rocks of the Upper Benue Trough, Nigeria. Unpub. M.Sc thesis, Abubakar Tafawa Balewa University, Bauchi, 54-62. [2] Akande, S.O. and Erdtmann, B.D. (1998). Burial metamorphism (thermal maturation) in Cretaceous sediments of the southern Benue trough and Anambra Basin, Nigeria. Amer. Assoc. Petrol. Geol. 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