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Source-rock investigation of the Turonian-Maastrichtian Fika shale from Wireline-logs, Chad basin, Nigeria.

Introduction

The analysis of the stratigraphic sequence includes studying the source, reservoir and cap rocks. A petroleum source rock may be defined as fine-grained sediment that in its natural setting has generated and released enough hydrocarbons to form a commercial accumulation of oil or gas. Source rocks are mostly formed of fine-grained sediments such as mudstones and shales, or micritic limestones (Tissot, and Welte, 1984). Mud rocks are the most abundant of all lithologies, constituting some 45% to 55 % of sedimentary rock sequences (Tucker, 1981). The main content of mud rocks are the clay minerals and silt-grade quartz. Since they are largely detrital, the clay mineralogy to a greater or lesser extent reflects the climate and geology of the source area (Millot, 1970).

The use of petrophysical technique arises out of the need to assess source rocks for basin studies in various geological settings, where the database is restricted to basic log data and little or no geochemical information and to provide an integrated "running" assessment of source capability for volumetric determinations.

The important constituent of source rocks is organic matter (OM). A rule of thumb, used by petroleum geochemists, is that rocks sourcing commercial amounts of hydrocarbons normally have a TOC (Total Organic Carbon) value of more than 1% (by weight) although their ultimate commerciality depends on other factors such as organic matter type and expulsion/drainage efficiency. Typically, TOC varies from less than 1% in poor source rocks to over 20% in rich so-called oil shales.

A number of log techniques has been developed and demonstrated the use of well logs in determining variations and absolute quantities of OM. A review of all techniques, which based on either individual standard log or combination of many logs, was summarized by Aly and Mahmoud, (1994); Aly, (1995); and Ali, (2002). In this work, the relation between density, gamma ray and porosity logs as established for determining the TOC inherited in the evaluated units as shown by Schmoker, et al. (1983) was employed for the investigation of the TOM and TOM content of Fika shale. Fika shale is suspected to be the main source rock in Chad basin (Okosun, 1995).

According to Jones (1980), a majority of the world's oil accumulations originated in source rocks with a TOC content in excess of 2.5 wt%--i.e., the Kimmeridgian shale in the northern North Slope (Prudhoe Bay) in Alaska; the Bakken and Woodford shales of the Paleozoic in the U.S. midcontinent region; the Silurian shales of Algeria; the Duvernay shale of the Devonian in Alberta, Canada; the Cretaceous La Luma formation in Venezuela; and the source rocks of the Middle East and Siberia, USSR. In contrast, in several Tertiary delta systems--e.g., the Mississippi River of the U.S. gulf coast and Niger Rivers of Africa--the source rocks underlying potential reservoirs exhibit TOC content ranging from 0.3 to 0.5 wt%.

The study area is located in the Borno basin (Figure 1). The data used in this study were obtained from the Nigerian National Petroleum Corporation (NNPC) database available in the Department of Geology, Obafemi Awolowo University, Ile-Ife. They include a suite of well log data from twenty-three (23) wells in Borno basin, out of which twelve wells was selected for this work. They are composite logs that consist of lithology logs (Gamma ray), and porosity logs (Bulk density).

[FIGURE 1 OMITTED]

Carter et al. (1963) showed that an anticline and a syncline at Dumbulwa and Mutwe both of which trend NW-SE constitute the dominant folds within Borno basin. The also gave the geological age of the formations in the basin. Also, Agagu and Ekweozor (1980) suggested that basal and interfingering sandstones in the Chad basin and the Benue trough are among the potential hydrocarbon traps. Reyment (1980) discovered some mulluscan species which was common both in northeastern Nigeria and eastern Niger Republic. Thus, the two areas can be correlated. In addition, Peters and Ekwezor (1982) showed from their preliminary investigations that the Borno basin meets the required conditions for hydrocabon generation and accumulation with Fika shale with a minimum of 0.7% of TOC. Genik (1992) presented a model for the regional framework and tectonic evolution of the Cretaceous--Paleogene rift basins of Niger, Chad and the Central African Republic (C.A.R). Okosun (1995) reviewed the geology of Borno basin, identifying five (5) main formations namely; Bima sandstone, Gongila Formation, Fika shale, Kerri Kerri and Chad formation. He concluded that the geological condition of the basin favours the discovery of hydrocarbons.

The aims and objectives of this study are to determine the Total Organic Content (TOC) of Fika shale using Porosity, density and gamma ray Logs. And so as to determine its source (petroleum generation) potential, and to know why the Nigerian portion of Chad basin are not yet producing while Niger republic and Chad portion (Termit Basin) is producing hydrocarbon.

Geology of Borno (CHAD) Basin

The Borno Basin is considered by most authors to be part of the much larger Chad basin (Fig 1). By far the greater part of the Chad basin is located in the north outside Nigeria in the republic of Niger, Chad and Cameroon. It is a part of the western Central African Rift system (WCAS) that was formed in response to the mechanical separation of the African crustal blocks in the mechanical separation of the African crustal blocks in the Cretaceous (Genik, 1992). The basin belongs to the West Africa Rift Sub-system (WAS) component as WCAS. The area is covered by sand and lack outcrops. Furthermore, the Borno Basin is Nigerian part of Chad basin located in the extreme north east part of the country. It extends from Maiduguri in the east, covering some part of Kano state and Katsina state. It is between latitudes 8[degrees] and 14[degrees] and longitudes 110 and 140 (Okosun, 1995).

The Nigerian National Petroleum Corporation (NNPC) has shot several kilometers of seismic lines and also drilled many wildcat wells for the exploration of hydrocarbon in the basin. The Borno Basin is a sediment-filled (broad) depression straddling northeastern Nigeria and adjoining parts of chad Republic. It is separated from the Upper Benue Basin by the Zambuk Ridge. The sedimentary rocks have a cumulative thickness of over 3,600 meters and consist of thick basal continental sequence overlain by transitional beds followed by a thick succession of Quaternary limnic, fluviatile and eolian sands and clays. Outcrops of older beds are rare as they are covered in most parts by desert-blown sediments.

According to Peters (1978) and Okosun (1995), five stratigraphic units Bima Sandstone, Gongila Formation, Fika Shale, Kerrikerri and Chad Formations were recognized in Bornu basin (Fig. 2). Bima Sandstone is the oldest stratigraphic unit in the area. It was deposited under continental environments. The formation consists of thin to thick beds of fine to coarse grained sandstone of variable colour from white, brown, reddish brown to grey. The coarse grained textures are more common towards the bottom of boreholes (Okosun, 1995). Thin bands of clay and siltstone varying in colour from red to grey or brown occur as intercalations with the sandstone. The formation is feldspathic towards the bottom of the boreholes. Current bedding is an important feature that is observable on outcrops of the formation. The current beddings are planer with lenticular, tabular and wedge-shaped varieties. Deformation features which are occasionally found on the outcrops are perhaps due to the effect of gravitational loading. Bima sandstone lies unconformably on the Basement Complex; it was derived from the degradation of the basement rocks. The name Continental Intercalaire embraces generally all the sediments derived from the Basement Complex between the Permian and Albian times in response to uplift and weathering. The Bima Sandstone thus represents the upper part of the Continental Intercalaire in Nigeria. (Okosun, 1995). The formation is diachronous and probably of Albian--Turonian age (Carter et al. 1963).

[FIGURE 2 OMITTED]

The Gongila Formation is a transitional sequence between the underlying continental Bima Sandstone and the overlying marine Fika Shale. The formation consists of a sequence of sandstones, clays, shales and limestone layers. It varies laterally in lithology. For example, Northwest of Ashaka, it contains massive grey limestones overlain by sandstones, siltstone, thin limestones and shales with shelly limestones. To the south at Kupto, however, a thick limestone is overlain by sandstones, mudstones, and shales which pass upwards into shales with limestones (carter et. al., 1963). The sandstone texture is fine to coarse grained. Volcanic intrusives which occur as diorite sills are present at several horizons of the formation (Okosun, 1995). The maimum thickness recorded for this formation is 1410 meters. The limestone horizons are richly fossiliferous with abundant ammonites, pelecypods and echinoid remains. On the basis of these, Carter et al. assigned an Early Turonian age to the Formation.

The Fika Shale is a fully marine unit. This formation consists of blue-grey shale, occasionally gypsiferous, with one or two impersistent limestone horizons. A maximum thickness of 890 meters has been penetrated by boreholes near Maiduguri. Volcanic intrusives which occur as diorite sills are also present at several horizons of the formation (Okosun, 1995). Fossils of the Fika shale consist mainly of fish remains and fragments of reptiles suggesting a Cenomian to Maastrichtian age (Dessauvagie, 1975). However, Dessauvagie (op. cit.) suggests a pre-Santonian upper age limit for the formation based on stratigraphic evidence. The formation is diachronous and has been assigned a Turonian--Maastrichtian age (Carter et al., 1963).

Kerri-Kerri Formation consists of loosely cemented, coarse to fine-grained sandstone, massive claystone and siltstone; bands of ironstone and conglomerate occur locally. The sandstone is often cross bedded. The sediments are lacustrine and deltaic in origin and have a maximum thickness of over 200 meters (du Preez and Barber, 1965). The coal in the formation has yielded Palynomorphs which dated Paleocene by Shell-BP palynologists later. Chad formation is the youngest stratigraphic unit in the area. This consists of yellow, grey clay, fine to coarse-grained sand with intercalations of sandy clay and diatomites. The formation varies considerably in thickness and on the western shore of Lake Chad. It is estimated to be about 800 meters thick. The formation is underlain by the basement rocks at the periphery of the basin. It is underlain by the Kerri Kerri Formation and Fika shale in the shallow part of the basin and east of Maiduguri towards the basin centre respectively.

Vertebrate remains (Hippopotamus imaguncula) and diatoms collected from the formation indicate an Early Pleistocene (Villafranchian) age. However, because of the considerable thickness of the formation below the Hippopotamus horizon, its age is considered to be Pliocene--Pleistocene (Barber, 1965).

Materials and Methods

In the Source rock evaluation of Fika shale in Borno basin, twelve well logs (wild cat wells) ran by the Nigerian National Petroleum Corporation (NNPC) were interpreted. The wells include the followings: Faltu, Herwa, Kasade, Kasade, Kinasar, Krumta, Kutchali, Murshe, Ngamma East, Ngor North, Wadi and Ziye wells. Each well studied has its own uniqueness, in terms of total depth, thickness of source rock (Fika Shale) and other parameters. Total organic carbon (TOC) is the first thing to bear in mind when analyzing a well-log for source rock analysis is that Total organic carbon (TOC) content present in potential source rocks significantly affects the response of various well logs (Ferti and Chillingar, 1988). Sediments can be regarded as consisting of heavy and light fractions.

In this study, well-logging analysis was utilized for determining the shale volumes and identifying the source rocks, as well as discriminating the source rocks from the non-source rocks. With the aid of gamma ray log, Fika shale was identified and correlated among the twelve wells to give an idea of the possible continuity of the source rocks at different depths in the area. The similarity in these signatures across the wells made the correlation possible with a high degree of accuracy. Once the source rocks had been identified, different petrophysical and source rock parameters were determined for each Fika shale in all the wells. The total organic matter (TOM) of a rock is measure of concentration (weight %) of the dead ancient organisms. This concentration gives the rock potentiality for hydrocarbon generation. The total organic carbon (TOC) is a relection of the amount of TOM in sediment. The total organic carbon generated in the shale has been calculated utilizing Schmoker and Hester's equation (1983), as follows:

TOC(wt%)= (154.497/[[rho].sup.b]) - 57.261 (1)

where:

Toc is the total organic carbon per weight (wt%.)

[[rho].sup.b] is the bulk formation density as measured by density logs.

The result obtained for TOC was then converted to TOM values by means of the correction factor, 1.72.

Thomas (1979) classified the potential of source rock, on the basis of organic carbon content, as follows: 0.5 % is considered to be poor. 0.5 % to 1 % is fair, 1 % to 2 % is good and greater than 2% is excellent. Also, Basu et al. (1980) concluded that, the source rock which is less than 0.5% organic carbon content is considered poor and that of 0.5 % to 2 % is considered to be very good source rock. The classification was adopted in this study. The porosity values were estimated using Asquith and Gibson (1984) formula. Also, the volume of shale was computed using the empirical relation of gamma ray method (Dresser Atlas, 1979).

Discussion of Results

Total Organic Carbon (TOC) and Total Organic Matter (TOM) determined from the density log correlates with laboratory values obtained by Petters et. al., (1982), Okosun (2000) and Ehinola et. al., (2002) for Fika shale in Chad basin area. From the TOC and TOM derived for the study area (see Figs. 3 and 4), it is obvious that both TOC and TOM increases northeastward of the study are towatds Chad and Niger Republic. One can see this from the closure in the northeastern part of the area. It must be noted that the high density of the contour lines observed in the southern part of the study area is due to closeness of the wells in the area.

[FIGURE 3 OMITTED]

[FIGURE 4 OMITTED]

Also, the log of TOC with depth (Fig. 5-7) shows that average TOC values of Fika shale is more than 1 wt%. Increase in TOC with depth was also noticed in Krumta, Ngornorth, Wadi and Ziye wells. Also, The Plot of TOC versus Gamma ray and Bulk density logs (Figs. 8-10) shows linear relationship between TOC and gamma ray log (which is very well defined in Kasade, Krumta, Murshe and Wadi wells) with maximum [r.sup.2] of 0.280. But this linear relationship (increase of TOC with increase in GR), is not well defined in some other wells. The relationship would have been more understood with spectral gamma ray data. The plot of TOC versus RHOB shows inverse relationship between TOC and RHOB in all the studied wells. The underlying reason for the better accuracy of the density log is that density, unlike radioactivity, is an inherent property of organic matter (Schmoker, 1981). Detailed well to well discussion of the results for wells Faltu, Herwa, Kasade, Kasade, Kinasar, Krumta, Kutchali, Murshe, Ngamma East, Ngor North, Wadi and Ziye wells follow. For all the wells, the gamma ray (GR) and spontaneous potential (SP) well-logs data obtained were used in delineating the Fika Formation. Also, the shale volume correction was made using Steiber (1973) equation.

Faltu Well

In this well, Fika shale was correlated to be at the depth from 1300m-1830m. It has an average porosity of 33%. The Shale volume (Vsh) ranges between 11% and 99%. This confirms that shally to shale zone is predominant there (Ghorab et. al., 2008). The concentrations of organic matter of Fika shale interval are between 2.3 and 30.89 wt%. The total organic carbon content (TOC) was found to be between 10 and 75.1 wt% (it peaked in the interval 1500m--1520m from the log of TOC against depth (Fig. 5a) in the Fika shale intervals. This result shows that the shale is an excellent source rock (Table 1).

Herwa Well

It's Fika shale exit at the depth from 1569m-2501m. It has an average porosity of 24%. The Shale volume (Vsh) ranges between 10% and 99% in Fika shale interval. This confirms that we dealt with shally to shale zone (Ghorab et. al., 2008). The concentrations of organic matter of Fika shale interval are between 2.9 and 28.89 wt%. The total organic carbon content (TOC) was found to be between 8 and 92.3 wt% (which peaked in the interval 2180m-2200m from the log of TOC against depth (Fig. 5b) in the Fika shale intervals. This shows that the shale is an excellent source rock (Table 2).

Kasade Well

Kasade well information showed that Fika shale in it exist at a depth ranging from 925m-1177m. It has an average porosity of 21%. The Shale volume (Vsh) ranges between 11 and 99 wt%. This confirms that shally to shale zone is predominant there (Ghorab et. al., 2008). The concentrations of organic matter of Fika shale interval are between 2.10 and 25.77 wt%. The total organic carbon content (TOC) was found to be between 6 and 100 wt% in the Fika shale intervals (Fig. 5c). This shows that the shale is an excellent source rock (Table 3).

Kinasar Well

The delineated information from this well showed that its Fika shale occur at the depth ranging from 1653m-2498m. It has an average porosity of 12%. The Shale volume (Vsh) ranges between 11% and 99%. This confirms that the shally to shale zone is predominant there (Ghorab et. al., 2008). The concentrations of organic matter of Fika shale interval are between 1.9 and 12.92 wt%. The total organic carbon content (TOC) was found to be between 1.04 and 40.7 wt% in the Fika shale intervals (Fig. 5d). This shows that the shale is an excellent source rock (Table 4).

[FIGURE 5 OMITTED]

Krumta Well

The Fika shale in this well occurs between 650m-1415m depth. Also, it has an average porosity of 20%. The Shale volume (Vsh) ranges between 11% and 99%. This confirms that we dealt with shally to shale zone (Ghorab et. al., 2008). Also, the concentrations of organic matter of Fika shale interval are between 3.1 and 22.98 wt%. The total organic carbon content (TOC) was found to be between 7.11and 30.9 wt% in the Fika shale intervals. This shows that the shale is an excellent source rock. From the TOC-Depth log (Fig. 6a), TOC is seen to relatively increase with depth (Table 5).

Kutchali Well

In this well, the Fika shale was correlated to be at the depth ranging from 1518m-2076m. It has an average porosity of 24%. The Shale volume (Vsh) ranges between 9% and 99%. This confirms shally to shale zone is predominant there (Ghorab et. al., 2008). The concentrations of organic matter of Fika shale interval are between 2.5 and 29.3 wt%. The total organic carbon content (TOC) was found to be between 2.9 and 26.16 wt% in the Fika shale intervals. This shows that the shale is an excellent source rock. From the TOC-Depth log (Fig. 6b), TOC is seen to relatively increase with depth up to 1740m, and the decrease a little (Table 6).

Murshe Well

The Fika Formation in this well occurs at the depth ranging from 1140m-1717m. It also has an average porosity of 11%. The Shale volume (Vsh) ranges between 10% and 99%. This confirms that shally to shale zone is predominant there (Ghorab et. al., 2008). Also, the concentrations of organic matter of Fika shale interval are between 2.3 and 19.05 wt%. The total organic carbon content (TOC) was found to be between 2.8 and 18.03wt% in the Fika shale intervals (Fig. 6c). This shows that the shale is an excellent source rock (Table 7).

Ngamma East Well

Fika Formation in this well correlated to be at the depth ranging from 1050m-1514m. It has an average porosity of 23%. Its shale volume (Vsh) ranges between 11% and 99%. This confirms that shally to shale zone is predominant there (Ghorab et. al., 2008). The concentrations of organic matter of Fika shale interval are between 2.2 and 26.89 wt%. The total organic carbon content (TOC) was found to be between 1.47 and 29.04 wt% in the Fika shale intervals (Fig. 6d). This shows that the shale is an excellent source rock (Table 8).

[FIGURE 6 OMITTED]

Ngornorth-01 Well

The existence of Fika Formation in this well was found to be at the depth ranging from 1200-2090m. It has an average porosity of 35%. The Shale volume (Vsh) ranges between 10% and 99%. This confirms that shally to shale zone is predominant there (Ghorab et. al., 2008). The concentrations of organic matter of Fika shale interval are between 2.3 and 55.59 wt%. The total organic carbon content (TOC) was found to be between 6.9 and 83.3 wt% in the Fika shale intervals. This shows that the shale is an excellent source rock. From the TOC-Depth log (Fig. 7a), TOC was seen to relatively increase with depth (Table 9).

Tuma Well

Its Fika shale occur at the depth ranging from 1037-2050m. It has an average porosity of 20%. The Shale volume (Vsh) ranges between 10% and 99% in Fika shale interval. This confirms that we dealt with shally to shale zone (Ghorab et. al., 2008). Also, the concentrations of organic matter of Fika shale interval are between 9.8 and 23.22 wt%. The total organic carbon content (TOC) was found to be between 5.8% and 71.1 wt% in the Fika shale intervals. This shows that the shale is an excellent source rock. From the TOC-Depth log (Fig. 7b), TOC is seen to peak between 1500m and 1520m (Table 10).

Wadil Well

In this well, Fika shale was found at the depth ranging from 825-1457m. This shale has an average porosity of 26%. The Shale volume (Vsh) ranges between 11% and 99% in Fika shale interval. This confirms that shally to shale zone predominates (Ghorab et. al., 2008). The concentrations of organic matter of Fika shale interval are between 5.2 and 28.58 wt%. The total organic carbon content (TOC) was found to be between 8.5 and 46.43 wt% in the Fika shale intervals. This shows that the shale is an excellent source rock. From the TOC-Depth log (Fig. 7c), TOC is seen to relatively increase with depth (Table 11).

Ziye Well

This well information showed that the Fika shale occur at depth ranging from 1750m-2570m. It has an average porosity of 10%. The Shale volume (Vsh) ranges between 11% and 99% in Fika shale interval. This confirms that we dealt with shally to shale zone (Ghorab et. al., 2008). The concentrations of organic matter of Fika shale interval are between 2.3 and 15.13 wt%. The total organic carbon content (TOC) was found to be between 2.3 and 52.54 wt% in the Fika shale intervals. This shows that the shale is an excellent source rock. From the TOC-Depth log (Fig. 7d), TOC is seen to relatively increase with depth (Table 12).

[FIGURE 7 OMITTED]

[FIGURE 8 OMITTED]

[FIGURE 9 OMITTED]

[FIGURE 10 OMITTED]

The results of the evaluation of the combined TOC and TOM from a suite of wireline logs carried out in this study suggest that the investigated area has moderate to low hydrocarbon potentials based on the derived petrophysical parameters that was obtained. The series of gas and oil shows reported in some of the wells drilled by Nigeria National Petroleum Company (NNPC) so far attest to this proposition. Also, the derived TOC and TOM values for the Fika shales delineated from the well-logs point to a matured gas-prone basin rather than oil-prone. However, the most plausible explanation could be adduced to the non-discovery of commercial hydrocarbon in this basin is that possibly the effect of granitic and/or volcanic intrusions or plugs that is ubiquitous within this basin. Several lamellae of volcanic materials were found in all the core samples retrieved from the wells. The implications of the occurrence of these materials within the basin are two folds: First, it is logically deduced that possibly the heat and temperature from the intrusive materials might have over-cooked both the matured total organic contents (TOC) and total organic matters (TOM) present within the materials thereby turning them to gas. This observation might account for the presence of prominent gas shows found in some of the wells drilled so far. Also, considering the fact that hydrocarbon would normally migrates up-dip, it is expected that the Nigerian sector of the basin should have considerable hydrocarbon deposits because it is located in the up-dip side of this basin while Niger and Chad republics are in the down-dip side. Moreover, the sedimentary formation found in the Nigerian sector is less than 2.5km in thickness. In-addition, if hydrocarbon was actually generated within the Fika shale and expelled, it is expected that it would have migrated up-dip to the Nigeria side since the Fika shale found in Nigeria, Niger and Chad were deposited penecontemporaneously having the same organic constituents as reported by Genik (1993). Secondly, the sedimentary deposits present in the Nigerian sector of the basin occur at relatively shallow depths compared to the equivalent Termit basin in Niger and Chad republics that is producing both oil and gas. As reported by Genik (1993), the sediments thicknesses both in Niger and Chad republics are located within thick sedimentary sequence. Also, the effect of the volcanic intrusions is minimal in the down-dip sides. This might explain why there are hydrocarbon discoveries in Sadigi-2, Kumai-1 and Kanem-1 wells drilled in these neighboring countries.

Conclusion

The concentrations of total organic matter of Fika shale intervals are between 2.1 and 55.59 wt% with an average of 15.6 wt%. While the concentrations of total organic carbon of Fika shale intervals are between 1.89 and 32.7 wt% with an average of 12 wt%. The results indicate that the total organic carbon contents (TOC) of Fika shale exceed the kerogen threshold of 0.5 wt% for generation of crude oil. The result also indicates that TOM of Fika shale exceeds the kerogen threshold of 1wt%. Hence, the Fika shale formation could be considered a very good source rock. The trend of the average TOC and TOM values tend to increase northeastward of the study area i.e. towards Chad and Niger republic. Also, the porosity values derived for the wells ranges between 3 and 38%. The increase in porosity in some of the wells with depth suggests the effect of the granitic and/or volcanic intrusions within the basin, which might have made the shale very brittle and soft. It is obvious that Termit basin in Niger republic is located in the deep area (Genik, 1993). This may explain why there are hydrocarbon discoveries in Sadigi-2, Kumai-1 and Kanem-1 wells. The sedimentary thicknesses reported from integrated geophysical and geological surveys exceed 6 km both in Niger and Chad Republic. However, the occurrence of the volcanic intrusions found in Chad basin might have contributed to over-cooking of the organic contents present within Fika shale thereby turning it togas. We conclude that the hydrocarbon potential of the investigated basin is low to moderate; and most likely if hydrocarbon discoveries were made, it would be mostly gas.

Acknowledgement

Nigerian National Petroleum Corporation (NNPC), Lagos Nigeria is appreciated for releasing the data used for this study. Also, the computing facilities provided by Shell Petroleum Development Company Nigeria to the Geology Department, Obafemi Awolowo University, Ile-Ife, Nigeria is acknowledged.

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[23] Reyment, R.A., 1980. Biogeography of the Saharan Cretaceous and Paleocene epicontinental transgression. Cret. Res. 1, p. 299-327.

[24] Reyment, R.A. and Dingle, R.V., 1987. Paleogeography of Africa during the Cretaceous Period. Palaeogeogr..Palaeoclimatol., Palaeoecol., 59: 93-116.

[25] Schmoker, J.W., 1979. Determination of organic content of Appalachian Devonian shales from formation-density logs. AAPG Bull., v. 63, p. 1504-1509.

[26] Schmoker, J.W., 1981. Determination of organic-matter content of Appalachian Devonian shales from Gamma-ray logs. AAPG Bull., v. 65, p. 1285-1298.

[27] Schmoker, J.W and T.C. Hester, 1983. Organic Carbon in Bakken Formation, United States Portin of Williston Bason. AAPG Bull., p. 2165-2174.

[28] Thomas, B.M., 1979. Geochemical analysis of hydrocarbon occurances in North Perth Basin, Australia: AAPG. Bull., (63): 1092-1107.

[29] Steiber, R.G., 1973. "Optimization of shale volumes in open hole.

[30] Tissot, B. P. and Welte, D. H., 1984. Petroleum Formation and Occurrence. Springer, Berlin, 2nd Ed.

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* AA. Adepelumi, D. E. Falebita, A. O. Olorunfemi and S. I. Olayoriju

Department of Geology, Obafemi Awolowo University, Ile-Ife, Osun State, Nigeria

* Corresponding author's Email: aadepelu@oauife.edu.ng or adepelumi@yahoo.co.uk
Table 1: Average petrophysical parameters for faltu-01 well.

Source Depth Range Thickness IGR
rock (m)

Fika1 1300-1377 77 0.5097
Fika2 1386-1440 54 0.55
Fika3 1445-1471 26 0.6
Fika4 1523-1746 223 0.66
Fika5 1750-1830 80 0.66

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.24 0.34 18.17 30.889
Fika2 0.27 0.33 17.55 29.835
Fika3 0.31 0.31 16.06 27.302
Fika4 0.38 0.31 16.58 28.186
Fika5 0.38 0.3 15.82 26.894

Table 2: Average petrophysical parameters for herwa-01 well.

Source Depth Thickness IGR
rock Range (m)

Fika1 1569-1587 18 0.49
Fika2 1624-1699 75 0.55
Fika3 1703-1803 100 0.54
Fika4 1810-1861 51 0.48
Fika5 1934-2083 149 0.53
Fika6 2095-2231 136 0.52

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.21 0.18 9.59 16.303
Fika2 0.26 0.24 12.91 21.947
Fika3 0.25 0.22 11.41 19.397
Fika4 0.2 0.22 11.74 19.958
Fika5 0.25 0.24 12.7 21.59
Fika6 0.24 0.29 16.99 28.883

Table 3: Average petrophysical parameters for kasade-01 well.

Source Depth Thickness IGR
rock Range (m)

Fika1 925-1011 86 0.34
Fika2 1018-1090 72 0.33
Fika3 1101-1177 76 0.3

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.15 0.29 15.16 25.772
Fika2 0.12 0.24 10.64 18.088
Fika3 0.17 0.09 5.41 9.197

Table 4: Average petrophysical parameters for kinasar-01 well.

Source Depth Thickness IGR
rock Range (m)

Fika1 1659-1729 70 0.4
Fika2 1735-1797 62 0.36
Fika3 1812-1856 44 0.45
Fika4 1878-1968 90 0.43
Fika5 2205-2234 29 0.34

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.15 0.14 6.7 11.39
Fika2 0.14 0.13 66.27 10.659
Fika3 0.19 0.12 55.89 10.013
Fika4 0.18 0.08 44.06 6.902
Fika5 0.15 0.16 7.6 12.92

Table 5: Average petrophysical parameters for krumta-01 well.

Source Depth Thickness IGR
rock Range (m)

Fika1 654-875 221 0.65
Fika2 882-1118 236 0.56
Fika3 1128-1292 164 0.52
Fika4 1302-1415 113 0.43

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.37 0.25 12.99 22.083
Fika2 0.28 0.23 12.03 20.451
Fika3 0.24 0.26 13.52 22.984
Fika4 0.24 0.14 9.77 16.609

Table 6: Average petrophysical parameters for kutchali-01 ell.

Source Depth Thickness IGR
rock Range (m)

Fika1 1564-1670 106 0.29
Fika2 1676-1712 36 0.28
Fika3 1730-1946 216 0.3
Fika4 1958-2076 118 0.31

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.11 0.28 14.78 25.126
Fika2 0.11 0.33 17.22 29.274
Fika3 0.12 0.25 13.17 22.389
Fika4 0.12 0.19 10.02 17.034

Table 7: Average petrophysical parameters for murshe-01 well.

Source Depth Thickness IGR
rock Range (m)

Fika1 1140-1168 28 0.28
Fika2 1187-1277 90 0.36
Fika3 1293-1372 79 0.33
Fika4 1396-1573 177 0.37
Fika5 1590-1717 127 0.31

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.11 0.21 11.21 19.057
Fika2 0.15 0.16 9.92 16.864
Fika3 0.12 0.11 7.57 12.869
Fika4 0.13 0.12 8.16 13.872
Fika5 0.12 0.08 6.82 11.594

Table 8: Average petrophysical parameters for
ngamma east well.

Source Depth Thickness IGR
rock Range (m)

Fika1 1069-1133 64 0.28
Fika2 1158-1280 126 0.4
Fika3 1296-1408 112 0.46
Fika4 1415-1514 99 0.46

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.11 0.3 15.82 26.894
Fika2 0.2 0.26 13.45 22.865
Fika3 0.21 0.19 11.2 19.04
Fika4 0.2 0.17 9.33 15.861

Table 9: Average petrophysical parameters for ngornorth-01 well.

Source Depth Thickness IGR
rock Range (m)

Fika1 1222-1392 170 0.48
Fika2 1400-1509 109 0.46
Fika3 1530-1630 100 0.4
Fika4 1685-1805 120 0.36

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.22 0.25 13.21 22.457
Fika2 0.2 0.26 13.76 23.392
Fika3 0.17 0.38 22.78 38.726
Fika4 0.14 0.48 32.7 55.59

Table 10: Average petrophysical parameters for tuma-01 well.

Source Depth Thickness IGR
rock Range (m)

Fika1 1078-1192 114 0.43
Fika2 1272-1382 110 0.41
Fika3 1529-1569 40 0.48
Fika4 1770-2047 277 0.46

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.18 0.26 13.63 23.171
Fika2 0.17 0.26 13.66 23.222
Fika3 0.22 0.14 9.9 16.83
Fika4 0.21 0.13 9.1 15.47

Table 11: Average petrophysical parameters for wadi-01 well.

Source Depth Thickness IGR
rock Range (m)

Fika1 833-949 116 0.47
Fika2 963-1221 258 0.43
Fika3 1231-1334 103 0.4
Fika4 1442-1457 15 0.44

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.23 0.32 16.81 28.577
Fika2 0.18 0.24 13.62 23.154
Fika3 0.16 0.21 11.01 18.717
Fika4 0.19 0.11 9.2 15.64

Table 12: Average petrophysical parameters for ziye-01 well.

Source Depth Thickness IGR
rock Range (m)

Fika1 1788-1940 152 0.48
Fika2 1954-2103 149 0.51
Fika3 2120-2347 227 0.5
Fika4 2436-2548 112 0.49

Source Vshale [[empty set].sub.d] TOC TOM
rock (wt%) (wt%)

Fika1 0.23 0.11 8.9 15.13
Fika2 0.25 0.07 6.21 10.557
Fika3 0.24 0.08 5.99 10.183
Fika4 0.21 0.12 8.01 13.617
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Author:Adepelumi, A.A.; Falebita, D.E.; Olorunfemi, A.O.; Olayoriju, S.I.
Publication:International Journal of Petroleum Science and Technology
Date:Jan 1, 2010
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