PETROLEUM POTENTIAL OF CAMPANO-MAASTRICHTIAN SHALES OF ANAMBRA BASIN , SOUTH ASTERN NIGERIA

Over 6,000 meters thick terrigeneous sediment (mainly shale/ siltstones/lithologies) of campano – Maastrichtian age has been recorded in the Anambra basin. These shale/siltstones lithologies have been reported to be rich in organic matter and had fulfilled other relevant condition for hydrocarbon source rock potential. However, only few patches of hydrocarbon shows have been documented elsewhere in the basin. This work attempts to critically evaluate the hydrocarbon source potential of the organic rich shale sediments in the basin. A sample set of 40 ditch cuttings of manly shale lithologies retrieved at different depths intervals from 2 well were subjected to standard geo-chemical and organic petrography investigations. The samples were analyzed for the total carbon content (TOC), extract yield, organic matter types and organic maturity level. As screening criteria, all the sample set were subjected to TOC measurement (LECO). The TOC values range from 0.81-1.40% (AKU2) and from 0.82-1.81% (AMA.1) most of the samples meet up with minimum required TOC value ().5%) for a siliciclastic sediments to be hydrocarbon prone. Extract yield range from 30.0 to 180.5 ppm (AKU2) and 30.0 to 128ppm (AMA 1). The Rock-Eval Pyrolysis data HI vs OI revealed that the samples fall within types II & III kerogen. This corroborates with the results of the maceral analysis. The maceral composition is mainly vitrinitic and liptinitic of terrestrial origin, which are over 65 volume percent. The shales are moderately rich in organic matter. Extract yields and the bitumen ratio (mg HC/g TOC) revealed that these samples are at immature stage of Hydrocarbon generation. This is also supported by Tmax values of between 430-490 0 C.


INTRODUCTION
Anambra basin is a cretaceous depocenter containing thick sequences of elastic sediment ranging from bituminous shales lignites through sandstone and marl and it's Paleo-geographical strategic positioning as the proto-Niger Delta provides and ideal ground for geochemical evaluation of shales as oil/gas prone source rock.Various published work e.g Ekweozor and Gormly [1983) Petters and Ekweozor (1982) have revealed that the Campano-Maastrichtian Nkporo shale exhibit characteristics of potential hydrocarbon source system for a series of oil/gas and condensate shows found within Ajali sandstone The study area is roughly a triangular Sedimentary basin.It covers about 40,000 sq km. the southern boundary coincides with the Northern boundary of the Niger Delta basin.Anambra Basin extends northward beyond lower Benue River, but this view deals chiefly with the southern portion of the basin.
The two well studied are located within Enugu, southeastern part of Nigeria.The studied area is within Anambra basin, it covers an area of approximately 218 square kms bounded by Latitudes 5.5 0 and 6.5 0 north and longitude 6.5 0 and 7.5 0 east.Fig1 Since the discovery of petroleum in Niger Delta by Shell Petroleum Company of Nigeria in 1956, an increase in commercial exploration and exploitation have been going on with focus on the detection of suitable reservoir rocks and location of structural traps using geophysical methods.Recently, efforts are now on source rocks and their maturity.
There are a good number of research and geological studies in Niger Delta and Anambra Basin.Most of these works were carried out by oil companies operating in the area, but with only very few publication on source rock which have proved to be great geological interest and controversial Akaegbobi (1995) Ekweozor & Gormly (1983).This allows the assumption that the formation of the petroleum hydrocarbon took place under low temperature condition.It could also be possible that the migration effect (Impregnation) of the petroleum hydrocarbon might have influenced the low vitrinity reflectance.
The Tectonic conditions of Anambra Basin make it ideal for study.In this respect, the organic geochemical investigation could be used to: • Determine the Organic richnes of the shale sediments • Determine the quality of the kerogen.

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Determine the sediment maturity and finally.

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Evaluate the hydrocarbon potential of the basin sediments.
The two wells basic for selection because they both penetrated through the entire sediments of Anambra basin and located within the basin, in particular the Akukwa-II and Amansiodo-I wells fig 2. The sediments selected are organic-rich.They are Nkporo shale sediments at various depths ranging from 1,400meters to 4,000 meters fig3 and fig 4 .GEOLOGICAL SETTING; there are a lot of hypothesis about the origin of Benue Trough, but the most acceptable model is that of the plate tectonic concepts which appears to account more satisfactorily for the present arrangement of transform features zones in the gulf of Guinea region.The Anambra basin (covering an area of about 2.18 Sqkm) is located in south central part of Nigeria.Extending northwards in the lower Benue River.The basin forms a boundary with tertiary Niger Delta basin to the south.As one of the component basin of the Benue Aulacogen, the Anambra basin reflects the features of the break-up of the Gondwana supracontinent.Olade (1975), Akaegbobi et al [2000].The basin summary has been given by various workers, Agagu (1986), Agagu and Eweozor (1980), Agagu etal (1986) Ekweozor and Gormly (1983); Avbovbo (1978a).The sediment infill of the southern Nigeria Basin has been controlled by three main tectonic phases.The riftlike Benue Abakaliki trough was formed during the first tectonic phase (Albian) and filled by the sediment of three major cycles.The second phase resulted in the folding and in subsidence of the Anambra Basin which Subsequently was filled by second sedimentary cycles.The Nigeria Delta Basin was however formed during the third phase (upper Eocene).The cretaceous Anambra depositional site reflect a mega-facies region receiving sediments within two depositional cycles ranging from campanian to Eocene Reyment, (1965).The sediments are mainly continental fluvio-deltaic and shallow marine sedimentation millieux.Azu river group, Odukpani Formation, Eze Aku shale groug, Awgu shale, Nkporo shale, Mamu formation, Ajali sandstone, Nsukka formation, Imo shale and Ameki group.Fig; 2.

MATERIALS AND METHODS
Anambra basin has received considerable geological interest since 1903, when exploration for coal deposits in the basin were published by Bain (1924 and1930), Wilson and Bain (1928).Based on the fact that geology and stratigraphy of the Benue trough has been well established and many works of the Anambra basin has been published.For this work, subsurface sample materials were selected for study.The samples are mainly ditch cuttings from two deep appraisal wells (Ama-1 and Aku-11) located at the south western part of the Basin, The samples are from the Geological survey Agency, Kaduna.These wells penetrated all the formations in the Basin; of interest are the capanomaastrichtian sediments.The depth examined for Amansiodo-I well is between 1,400meters to 2,000 meters and 3,330 meters to 3,900 meters for Akukwa-II well

ANALYTICAL METHODS
Evaluation of the source rock basically requires the measurement of three parameters which are, The quality, quantity and maturity of organic matter.In other to characterize organic matter disseminated in the sediments, the following organic geochemical methods were applied.

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Extraction of soluble organic matter using Soxhlet Extraction method.

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Maceral Analysis, was done using reflected light microscope quipped with white incident light and blue light irradiation.Since the values of S1 peak for both wells is less than 2mgHC/g rock.This revealed little or no source potential for oil but some potential for gas.

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Values of S2 peak -revealed high amount of C0 2 released after the whole reaction, this is equivalent to the amount of oxygen in the sample.Fig. 7; plots of Hl vs T max.Ama-1 and Aku -11 wells.

O. A. ADEAGBO
Ama-1 well plots within Type II and III kerogene.That of Aku -II well is outside the field, this may be due to the contamination of the samples.Fig. 8; plots of HI vs 0I for Ama-1 well and Aku-II wells.Ama-1 plots within Type II and III.That of Aku -II well is outside the field.Fig. 9; plot of HI vs TOC, Ama-1 and Aku-11 wells.The plots revealed increase TOC with increasing HI for both wells.Fig. 10; plot of Bitumen ratio (mgExt/gTOC) vs depth for Ama-1 and Aku -II wells.The plots show.a decrease in BR(Bitumen ratio) with increasing depth for both wells. .A plot of Hl against TOC for both Ama -1 and Aku -II wells.The values for Ama-I is (0.09%-1.8%) with only a sample having value less than 0.5%.Aku -II values range from (0.69% to 9.94%).The Hl of Ama-I well were found to be lower than that of Aku-II well this is due to the depth of burial.
Fig 10:.The plot of Bitumen ratio against depth Show no variation in the extractable organic matter (EOM) or bitumen from the samples.The bitumen ratio in Ama-I well vary from 2.78 to 7.07 and Aku-II from 2.14 to 9.45 with a point having a value of 22.28.There is no clear or definite trend of the extractable yield with depth which is of course a function of geothermal gradient and temperature.However there is a slight increase of the value at depth 3,514 meters in Aku-II well.
PETROLEUM POTENTIAL OF CAMPANO-MAASTRICHTIAN SHALES OF ANAMBRA BASIN,Fig 11:.The plot of SOM against depth.In Ama -I well, the values of SOM range from (30.0 to 80.0ppm) with a high value of 128ppm at a depth of 1,640 meters.The same variation was in Aku-II well with values ranging from 30.0ppm to 96.4ppm with a high value of 180.5ppm at a depth of 3,514 meters.The plots of Ama -I well show a slight increase with increasing depth which shows that it is a function of geothermal gradient and temperature, on the contrary the plot of Aku-II show also a slight decrease in SOM values with increasing depth this is also a function of geothermal gradient and temperature.
Fig 12:-The T-max ( 0 C) is a pyrolysis parameter that respond to the thermal maturity of kerogen, it is the temperature corresponding to the maximum hydrocarbon pyrolytic yield i.e maximum of S 2 peak in the Rock-Eval Pyrogram.The T-max varies as a function of the thermal maturity of organic matter (TISSOT and ESPITALIE 1974).T max is also linked to the kinetics of the cracking of the organic mater contained in the kerogen (AKAEGBOB I995).
Fig 3 & 4. The PETROLEUM POTENTIAL OF CAMPANO-MAASTRICHTIAN SHALES OF ANAMBRA BASIN, well were drilled to evaluate the reservoir qualities of Ajali Sandstone and source rock qualities of Asaka/Nkporo shale.
Fig.6.piechart of meceral Analysis.The chart shows that vitrinite and inertinite percentage are higher than Liptinite percentage.This indicated mainly terrigeneous plants and woody source which is prone to the generation of gas.
Fig 7. is an evolution diagram drawn to assess the extent of thermal effect on the organic matter and to cross check the validity of the hydrogen index (Hl) of the kerogens as a function of T-max.Most of the samples from Amansiodo-1 well plot along the type II kerogen evolution pathway except one which follow the type III kerogen pathway.The Aku -II well samples plotted outside the field this may be due to sample contamination.Most of the samples of Ama-1 well are relatively immature plotting below and around 0.5% Rm boundary line and majority having T-max value quite below 450 0 C. Fig 8:-The samples from Ama -1 well have very low values of Hl and high values of 01 and plot mainly along the type III and II kerogen evolutionary pathway.The low hydrogen index Hl values point to type II and III organic matter deposited perhaps in an oxidizing environment.The high values of OI may equally be due to relatively high content of carbonate minerals with lower TOC values (<2%).It must be noted that all the samples are relatively immature and are no source rocks.The plots of Akukwa -II are generally outside the field, this may be due to sample contamination.Fig 9:

For
Ama-I well the T-max values range is from 426 0 C -471 0 C, for Aku-II well T-max values range is from 415 0 C -496 0 C.In both well the T-max was found to vary slightly with depth; it increases with increasing depth, this show that the T-max is a function of the geothermal gradient and the temperature.From the diagram of the relationship between T-max, kerogen types and oil and gas windows (after BORDENAVE et al 1993), the oil generating window for a type III kerogen is from 430 0 C to 470 0 C and for a type II kerogen is from 430 0 C to 455 0 C. The T-max results of the two wells vary from one sample to the other.The T-max values of up to 471 0 C were observed for the Ama-I well and up to 496 0 C for Aku-II well.Since the threshold of hydrocarbon generation (THG) for kerogen II and III is 430 0 C T-max the samples from both well are thermally matured to generate oil and gas.PETROLEUM POTENTIAL OF CAMPANO-MAASTRICHTIAN SHALES OF ANAMBRA BASIN,