GEOCHEMICAL CHARACTERISATION OF AGBADA FORMATION IN WELL X, OFFSHORE, NIGER DELTA, NIGERIA

GEOCHEMICAL CHARACTERISATION OF AGBADA FORMATION IN WELL X, OFFSHORE, NIGER DELTA, NIGERIA N. Asadu 1, F. A Lucas 2 and K. A. Ibe 3 1 Department of Earth Sciences, Federal University of Petroleum Resources, Effurun, 2 Department of Geology University of Benin, Benin city, Nigeria. 3 Department of Chemistry Federal University of Petroleum Resources Effurun, Nigeria. ABSTRACT Niger delta is one of the giant petroliferous provinces of the world. Following Shell-BP s 1956 commercial discovery of oil in Oloibiri, Bayelsa State, exploration and production efforts have been intensified in Niger delta and other sedimentary basins in Nigeria. Although much work have been done on the source rock of the Niger delta petroleum system, the controversy as to whether the oil in Agbada reservoirs is produced within the formation or migrated from the over pressured Akata shales still remain unresolved. Organic geochemical analysis of the shales in one ExxonMobil hydrocarbon exploratory well X was carried out in order to evaluate the source rock potentials, kerogen type and maturity status of the sediments. The source rock evaluation revealed that soluble organic matter (SOM) ranges from1940 ppm to 4220 ppm with an adequate mean value of 2758 ppm. TOC ranges from (1.38 to 12.06) wt %; HI ranges from (226 568) HC/gCorg; Tmax value ranges from (385 440) 0 C; VR0 ranges from 0.51 0.76 and PI values ranging from (0.06-0.32) with the mean transformation ratio (TR) of 0.28 wt%. These show that organic matter quantity is fair to excellent and in high concentration with excellent hydrocarbon generation potentials and made of type II and type III kerogen. Vitrinite reflectance and TMAX values also showed that the source rocks in well X are predominantly matured at intervals therefore; Agbada Formation sourced the hydrocarbon in the study area. The oil window recognized at 8100ft, where the source rock profile exhibited the highest values of (TOC) 12.06%, genetic potential (55.47), S2/S3 (10.54), (TMAX) 431( 0 C) and (VRO) 0.6%, therefore, conclude that Agbada Formation sourced the hydrocarbon in the study area. 247

INTRODUCTION Geochemical screening analyses are practical exploration tools for rapid and inexpensive evaluation of rock samples. Rock-Eval pyrolysis and TOC measurements are the most effective and inexpensive screening methods for large numbers of rock samples from wells and outcrops. There have been many discussions about the source rock for petroleum in the Niger delta, a few of these previous works have been reviewed as follows: Based on organic-matter content and type, Evamy et al., 1978, proposed that both the marine shales (Akata Formation) and the shale interbedded with paralic sandstone (lower Agbada Formation) were the source rocks for the Niger Delta oils. Ekweozor et al., 1979, used αβ hopanes and oleananes to fingerprint crude with respect to their source and proposed that the shales of the paralic Agbada Formation sourced the oil on the eastern side of the delta while the Akata and marine-paralic (Agbada formation) sourced on the western side of the delta. Ekweozor and Okoye, 1980, further constrained this hypothesis using geochemical maturity indicators, including vitrinite reflectance data, and showed that rocks younger than the deeply buried lower parts of the paralic sequence are immature. Lambert-Aikhionbare and Ibe, 1984, argued that the migration efficiency from the over-pressured Akata shale would be less than 12%, indicating that little fluid would have been released from the formation. They derived a different thermal maturity profile, showing that the shales within the Agbada Formation are mature enough to generate hydrocarbons. Ejedawe et al., 1984 used maturation models to conclude that in the central part of the delta, the Agbada shales source the oil while the Akata shales source the gas. In other parts of the delta, they believe that both shales source the oil. Doust and Omatsola, 1990, conclude that the source organic matter is in the deltaic offlap sequences and in the sediments of the lower coastal plain. Their hypothesis implies that both the Agbada and Akata Formations likely have disseminated source rock levels, but the bulk will be in the Agbada Formation. In deep water, they favor delta slope and deep turbidite fans of the Akata Formation as source rocks. (a) Aim and objectives: To use geochemical proxies to evaluate the organic matter quantity, quality, hydrocarbon generation potentials and maturity status of the sediments. (b) Location of The Study Area This study was carried out on ditch cutting rock samples from an EXXONMOBIL exploration well X, located in offshore Niger delta. Geology of the Study Area: The stratigraphy of the Niger Delta is intimately related to its structure. The development of each being dependent on interplay between sediment supply and subsidence rate. Short and Stauble (1967) recognized three subsurface stratigraphic units in the modern Niger Delta. The delta sequence is mainly a sequence of marine clays overlain by parallic sediments which were finally capped by continental sands.the 248

stratigraphy of Niger Delta Basin are as follows: (a) Benin Formation: The formation comprising over 90% sandstone with shale intercalations extends from the west across the entire Niger Delta area and southward beyond the present coast line. The thickness though variable is estimated at about 6000fts. It is coarse grained, gravelly, poorly sorted, sub-angular to well rounded and bears lignite streaks and wood fragment. The formation is characterized by structural units such as channel fills, point bars etc which indicate variability of the shallow water depositional medium. The Benin formation with very little hydrocarbon accumulation ranges in age from Oligocene to Recent. (b) Agbada Formation: The formation is a sequence of sandstones and shales with sandstone dorminant in the upper unit and thick shales in the lower unit. It is very rich in microfauna at the base decreasing upwards suggesting an increase in the rate of deposition at the delta front. The grains are coarse and poorly sorted indicating a fluvatile origin. The Agbada Formation covers the entire subsurface of the delta and may be continuous with the Ogwashi-Asaba and Ameki formations of Eocene- Oligocene age. It is over 10,000ft thick and are the major hydrocarbon bearing unit in the delta. (c) Akata Formation: The formation underlies the entire delta and forms the lower most unit. It is a uniform shale development consisting of dark grey sandy, silty shale with plant remains at the top. The Akata formation is typically overpressured and believed to have formed during lowstands when terrestrial organic matter and clays were transported to deep water areas characterized by low energy conditions and oxygen deficiency (Statcher 1995). It is over 4000ft thick and ranges in age from Eocene to Recent and is believed to have been deposited in front of the advancing delta. METHOD OF STUDY Organic Geochemical analysis involved the determination of total organic carbon (TOC), soluble organic matter concentration (SOM) and Rock-Eval pyrolysis of fifty six (56) representative shale samples from the well. Vitrinite reflectance values were also calculated from Jarvie et al 2001 relation and used for thermal maturity assessment. (A) Total Organic Carbon (TOC): Determination Procedure (using Fugro Robertson Method) STEP 1: pulverization, Labelling and weighing of samples: samples were duly pulverized, clean Sample Bottles were duly labelled with the sample intervals and samples were weighed out in the range (1.0105 0.0985) into the bottles. Step 2: Acidification: Weighed samples were taken to the heating chamber for acidification (to remove inorganic carbon). A few drops of hydrofluoric acid was added to the sample shaken and vigorously heated to dryness in the heating chamber (heating for an average of 5-10 minutes). 249

Step 3: the acidification process was repeated. Step 4: the sample bottle were half filled with distilled water. Step 5: The residue was turned into a filter paper clamped on a filter flask while the filtrate was turned into a beaker and allowed to dry in the oven for two hours. Step 6: The residues was transferred to the crucible. Step 7: The crucible was transferred to the TOC determinator and the sample weight was entered into the computer attached to the determinator and the determined carbon values was read on the computer. (B) Determination of soluble organic matter (SOM): The extraction of the soluble organic matter was done with dichloromethane in a standard soxhlet extractor and refluxed overnight. The bitumen were filtered and weighed in a glass vial. The weighed extract was measured in parts per million (ppm) and in weight percent. Extraction was done on the selected representative samples after the TOC measurements. (C) Rock-Eval pyrolysis: Is the thermal distillation of free organic compounds (mostly bitumen in source rocks, oil in reservoir rocks) from the rock matrix followed by cracking of the insoluble organic matter, kerogen. The samples were heated in an inert atmosphere (using Helium gas) to 550 0 C in a special programmed temperature. The pulverized samples were heated to a temperature of 300 0 C for 3 min to generate the first peak (S1) which represents free and adsorptive hydrocarbon present in the sample. This was followed by programmed pyrolysis to 550 0 C at 25 0 C/Min. The second peak (S2) represents the hydrocarbon generated by the thermal cracking of the kerogen. At the same time, the CO2 produced during the temperature interval was recorded as the S3 peak. Other parameters obtained from the instrument include Tmax that is temperature corresponding to the maximum S2 peak, Hydrogen Index (HI) and Production Index (PI).These organic geochemical All the analyses were carried out at the Fugro Robertson Petroleum Geochemistry Laboratory Llandudno, North Wales United Kingdom and therefore ran against their laboratory sample standards. RESULTS AND DISCUSSIONS The results of the rock- eval pyrolysis, total organic carbon (TOC) and other calculated parameters are shown in (Tables 1). The plots of the variations of the rock- eval pyrolysis data and interpretive parameters were also determined. On the basis of the variations in the lithologic characteristics and geochemical parameters within the rock succession, the studied section of well A (400-12920 ft) was divided 250

into three units that are stratigraphically well. Unit 1(Agbada Formation): This unit range in depth from 12920 to 5700ft of well X, with average TOC of 3.59 wt %, S2 is 12.96 mg HC/g rock, and S1 is 1.41 mg HC/g rock. The production index (PI) is 0.13, the hydrogen index (HI) is 364 mg HC/g TOC and oxygen index (OI) averages 109mg HC/g TOC (Table 2), the soluble organic matter content (SOM) is high with values ranging from 1940 to 4220 ppm with a mean value of 2758 ppm (Table 2). This unit is dated Oligocene to upper Miocene in age and represent Agbada Formation in this well. Unit 2 (Benin Formation): The uppermost unit is sandy and range in the depth between 5700 to the top of well X. This unit represents the Benin formation of upper Miocene to Pliocene age. The average TOC is 0.36 wt %, S2 is 0.49mg HC/g rock, and S1 is 0.75 mg HC/g rock. The production index (PI) is 0.57, and the hydrogen index (HI) is 97 mg HC/g TOC with oxygen index (OI) averaging 562mg HC/g TOC (Tables 1).. 251

OLIGOCENEE MIOCENE AGBADA FORMATION BENIN FORMATION PLIOCENEEE SAMPLE DEPTH N. Asadu et al., IJSIT, 2015, 4(3), 247-262 ROCK EVAL PYROLYSIS DATA INTERPRETIVE RATIOS S1 S2 S3 TMA X TOC PI HI OI S1+S2 S2/S3 %VRo OIL/GAS 1330 1.11 0.56 2.05 410 0.32 0.7 122 446 1.67 0.27 0.22 NIL 2580 0.38 0.42 3.94 421 0.39 0.5 72 679 0.80 0.11 0.42 NIL 0.75 0.49 3.00 416 0.52 0.6 97 562 1.24 0.19 0.32 5730 0.51 5.84 2.68 433 1.38 0.1 423 194 6.35 2.18 0.63 GAS 6000 0.69 5.23 3.66 434 1.46 0.1 358 251 5.92 1.43 0.65 GAS 6540 1.59 7.13 1.64 429 1.47 0.2 485 112 8.72 4.35 0.56 NIL 6900 0.76 6.61 2.49 426 2.27 0.1 291 110 7.37 2.65 0.51 NIL 7530 0.74 10.93 2.94 436 2.96 0.1 369 99 11.67 3.72 0.69 GAS 7860 0.59 6.12 2.15 430 1.54 0.1 397 140 6.71 2.85 0.60 GAS 8100 4.66 50.81 4.82 431 12.06 0.1 421 40 55.47 10.54 0.6 OIL&GAS 8520 1.82 24.33 3.27 435 6.66 0.1 365 49 26.15 7.44 0.67 OIL&GAS 8990 1.43 21.49 3.56 434 5.37 0.1 400 66 22.92 6.04 0.65 OIL&GAS 9000 1.72 19.85 8.66 434 8.78 0.1 226 99 21.57 2.29 0.65 GAS 9240 4.23 8.92 2.38 428 3.28 0.3 272 73 13.15 3.75 0.54 NIL 9540 0.94 9.63 3.48 432 2.76 0.1 349 126 10.57 2.77 0.62 GAS 9720 0.8 6.5 2.37 426 2.29 0.1 284 103 7.3 2.74 0.51 NIL 10050 0.82 5.89 2.26 429 2.01 0.1 293 112 6.71 2.61 0.56 NIL 10490 1.17 15.53 2.56 434 3.15 0.1 493 81 16.7 6.07 0.65 OIL&GAS 10590 1.2 12.46 3.01 439 4.04 0.1 308 75 13.66 4.14 0.74 GAS 10710 1.1 17.97 2.78 434 4.5 0.1 399 62 19.07 6.46 0.65 OIL&GAS 11310 0.98 5.63 2.08 431 1.78 0.2 316 117 6.61 2.71 0.6 GAS 11490 1.11 17.7 2.59 429 4.14 0.1 427 63 18.81 6.83 0.56 NIL 11640 1.12 6.13 2.88 438 1.74 0.2 352 166 7.25 2.13 0.72 GAS 12420 1.65 7.36 2.82 440 1.76 0.2 418 160 9.01 2.61 0.76 GAS 1.41 12.96 3.10 432 3.59 0.13 364 109 14.37 4.11 0.62 252

Table1: Variation of Rock Eval and calculated geochemical Parameters in Well X. S1 : content of free organic compounds (less than approximately C33), in mg HC/g rock S2 : amount of hydrocarbons (HC) generated by pyrolysis (plus some bitumen), in mg HC/g rock S3 : the organic carbon dioxide released to 390 0 C, in mg CO2/g rock Tmax : the temperature of maximum S2 yield in 0 C TOC : the total organic carbon in weight % HI : the hydrogen index, S2/TOC: an indicator of kerogen type, in mg HC/g Corg OI : the oxygen index, S3/TOC : an indicator of kerogen type, in mg CO2/g Corg. PI: the production index, S1/S1 + S2 is an indicator of thermal maturity in a source rock. S2/S3: used in the characterization of kerogen as surrogate for ratio of H/O. S1+S2: represents the rocks total hydrocarbon generation potential VR O: Vitrinite Reflectance. (i) ORGANIC RICHNESS: Petroleum is a generative product of organic matter disseminated in sediments and therefore the quantity of hydrocarbon generated directly correlates with organic matter concentration of the potential source rocks (Tissot and Welte, 1984). The organic richness of rocks is customarily expressed in terms of the percentage by weight of organic carbon. The minimum concentration of organic carbon sufficient enough to saturate the pore network for adequate level of expulsion efficiency from a potential source rock is 1.0% TOC, although a threshold as low as 0.5% TOC are however considered possible in gas prone systems which are largely driven by diffusion at an adequate level of concentration gradient (Rice and Claypool, 1981). 253

F0RMA DEPT S1 S3 TM TOC PI HI OI S1+S S2/S Cal TION H(FT) S2 AX 2 3 %V Ro (400 - (0.38 (0.42 (2.05 (41 (0.46 (0.4 (72 - (44 (0.8 - (0.11 (0.2 5700) - - - 0 - - 8-122) 6-1.67) - 2-1.11) 0.56) 3.94) 421 0.58) 0.66 67 0.27) 0.42 BENIN ) ) 9) ) 0.75 0.49 3.00 416 0.52 0.57 97 56 2 1.24 0.19 0.32 AGBAD A (5700 12920 ) (0.59 (5.23 (1.64 (42 (1.38 - - - 8 6 - - 4.66) 50.8 1).66) 440 ) 12.0 6) (0.0 (226 - (40 (5.92 6-493) - - 0.32 ) 33 9) 55.4 7) (1.25 (0.5-1 - 10.5 4) 0.74 ) 1.41 12.96 3.10 432 3.59 0.13 364 109 14.37 4.11 0.62 Table 2: Summary of Rock- Eval Pyrolysis data and Interpretive Ratios for well A In unit 1(Agbada formation): The TOC of the shale samples is fairly high with values ranging from 1.38 to as high as12.06 wt% with an average of 3.59 wt. % (Table 2). This value exceeds the threshold of 1% TOC with moderately high organic matter concentration (Table, 3). Also Plots of S2 versus TOC show that organic matter quantity of these source rocks is good to excellent (Figures 1) and in adequate concentration for petroleum generation. The abundance and type of organic matter in Niger Delta vary with age, depositional environment and environmental depth (Nwajide, 2013). This high TOC values may be attributed to the depositional environment. Non- marine swamp, marsh and floodplain deposits records high TOC and HI values due to their proximity to the source of organic matter. 254

FORMATIO SAMPLE WEIGHT S.O.M S.O.M TOC (wt. S.O.M/ N INTERVAL OF (ppm) (wt %) %) TOC (wt. (Feet) SAMPLE (gm) %) Upper Agbada Lower Agbada 5730 10 1940 0.19 1.38 0.14 9000 2 2350 0.24 8.78 0.26 10590 5 2520 0.25 4.04 0.62 11490 5 4220 0.42 4.14 0.10 Table 3: Soluble Organic matter concentration (SOM) Figure 1: Plot of TOC (Wt%) Vs S2 (Mghc/Grock) showing the Organic Matter Quantity in well X. Unit 3 (Benin formation): The representative shales has the lowest TOC ranging from 0.46 to 0.58wt.%, 255

with an average of 0.52wt. %., low hydrogen index (HI) with consistent high productivity index (PI). These values fall below the threshold of 1% wt.toc required for oil generation and are therefore not considered as source rock. (ii) HYDROCARBON GENERATION POTENTIALS (S1+S2): Organic carbon content (TOC) is insufficient to establish the presence of potential and or effective petroleum source rocks in view of the constraints that different organic matter types have different hydrocarbon yields for the same organic carbon content, a more direct measure of source rock capability to generate hydrocarbons is required for detailed assessment (Katz (2006) and Akande et al (2011). Rock-Eval pyrolysis data set derived from the programmed heating of samples in inert atmosphere and its interpretive ratios undoubtedly provide direct estimation of the hydrocarbons that evolved freely; considered as S1; the generatable hydrocarbons directly from kerogen cracking known as S2. (S1 + S2) referred to as the total hydrocarbon generation potential of source rocks (Dymann et al 1996). It is defined as the maximum quantity of hydrocarbons that a sufficiently matured source rock might generate. The source rocks with hydrocarbon generation potential(s1 + S2) less than 2mg HC /g rock yields little or no oil with some potential for gas; S1 + S2 from 2 to 6 mg HC /g rock indicates moderate or fair source rock potential while above 6 mg HC / g rock suggests good to excellent source rock potential. The threshold of S1 + S2 greater than 2.5 mg HC /g rock can be considered as a prerequisite for classification as a possible oil source rock (Bissada, 1982) and provide the minimum oil content necessary near the top of the main stage of hydrocarbon generation to saturate the pore network and permit expulsion. The source potential (S1+S2) of the Agbada formation range from 6.61 to an elevated peak value of 55.47mg HC /g rock with 40% of the samples in excess of the mean value of 14.37 mg HC /g rock. This is consistent with the high organic richness recorded at this interval as expressed in positive correlation between TOC and S2. The soluble organic matter (SOM) increased with depth of burial and ranged from 1940 to 4220 ppm with an adequate mean value of 2758 ppm (Table 2). Peters and Cassa (1994) showed that source rocks with SOM in the range of 0-500ppm has poor potential for petroleum generation potential, those between 500-1000 ppm is fair, 1000 2000ppm is good, 2000-4000ppm is very good while those with values above 4000ppm has excellent petroleum generation potential. These show that the Agbada Formation in this well has an excellent potential for generation of oil and gas with adequate organic matter concentration. (iii) TYPING OF KEROGEN: Rock-Eval pyrolysis data and their derivatives are could serve as important criteria for characterization of organic matter in sediments. Hydrogen index (HI) which is the ratio of S2/TOC is an indicator of kerogen type (Tissot et al, 1974). Type 1 organic matter is hydrogen rich with HI greater than 600 mg HC /g TOC and this is considered to be predominantly oil prone. Type II organic matter is characterized by HI between 350 and 600 mg HC/gTOC and this could generate both oil and gas at the appropriate level of maturity. 256

Figure 2: Plot of TOC (Wt %) Vs S2 (MgHC/Grock) showing the kerogen typing in Well X Figure 3: Plot of oxygen index (OI) versus hydrogen index (HI) on Van Krevelyn diagram showing the kerogen typing in well X Type III organic matter is characterized by low to moderate HI of between 75 and 200mg HC/g TOC 257

and could generate gas at the appropriate level of thermal maturity. Type IV organic matter normally exhibit very low HI less than 50mg HC/g TOC; produced under very oxic environment and are generally inert (Tissot and Welt, 1984). However, Peters 1986 suggested that at a thermal maturity of vitrinite reflectance value of 0.6% (Tmax 435 0 C) rocks with HI above 300mg HC/g TOC will produce oil; those with HI between 300 and 150 will produce oil and gas; while those with HI between 150 and 50 will produce gas and those with HI less than 50 are inert. The HI of the source rocks vary over a wide range. HI varies from 226-493HC/g TOC with a mean value of 370HC/g TOC indicating different kerogen types associated with these sediments. Cross plots of TOC versus S2 (Figure 6) define a predominance of type II and type III organic matter. Type II kerogen is derived primarily from the remains of bacterially reworked plankton in an anoxic environment found in moderately deep marine setting. It is oil prone but can generate gas depending on its thermal evolution. Type III kerogen is derived primarily from terrigenous plant debris deposited in shallow to deep marine setting and tend to generate dry gas. The surface plots and contour maps of TOC (wt. %) versus S2 (mg HC/g rock) versus HI (HC/g TOC), also reveal the stratigraphic distribution of kerogen type II and III in the well. Plots of oxygen index (OI) versus HI on Van Krevelyn diagram shows that most of the samples plot in the field of combined type II and III with few samples plotting in the fields of either type II or III (Figure 3). The ratio S2/S3 is also a measure of kerogen quality. S2/S3<5 has the potential to generate gas at maturity, S2/S3 (5-10) is oil and gas prone, while S2/S3>10 is gas prone. This criterion was used to determine the nature of petroleum product generated at maturity (Tables 1). (iv) MATURITY OF KEROGEN: Rock eval data is also employed in initial maturity assessment of source rocks. (TMAX, PI, and calculated VR O from Jarvie et al 2001 relation (%VR0=0.018 X TMAX - 7.16) was particularly used for this purpose.tmax value <430 C, Production Index <0.1 and Vitrinite reflectance (VRO) value<0.6%, suggests that the source rock is immature and no hydrocarbon generation has occurred. TMAX value, 430 to 465 C, Production Indices >0.1 and VRO >0.6 to 1.35% suggests a source rock that has generated hydrocarbons at some time or generating at present. TMAX values >465 C and Production Indices > 0.4 - suggests the source rock is post mature, and estimating the original petroleum potential is difficult (Peters and Cassa, 1994). On these premises, the source rocks in the well have attained a moderate level of maturation with TMAX values varying from 426 to 440 C and VRO varying from 0.51 to 0.76% with 70% of the samples in excess of the mean values of 432 C and 0.62% respectively in Agbada formation. The average productive index is also 0.13. 258

Figure 4: Plot of Tmax ( 0 c) Versus Productive Index (PI) showing the thermal maturity of kerogen and the type of product generated in Well X. Two samples in upper Agbada formation were observed to have anomalous high PI and low TMAX (0.2 and 0.3) in sample 6540 ft and 9240 ft respectively.these intervals correspond with the zones impregnated by migrated oil (Peters, 1986 and Peters and Cassa, 1994). Plot of TMAX 0 C Versus Hydrogen index (HI) shows that 70% of the source rocks studied are mature (Figure 3). It is very striking to note that at depth 8100ft, the source rock profile exhibited the highest values of total organic carbon (TOC) 12.06% and genetic potential (55.47) and S2/S3 (10.54), (TMAX) 431 0 C and (VRO) 0.6%, therefore pegging the oil window around this interval. Plot of Tmax ( 0 c) Versus Productive Index (PI) shows that some of the mature source rocks in this well are in oil generation phase while others are in gas phase (Figure 4 and Table 1). The transformation ratio (TR) defined by SOM/TOC was also used as a maturity index. It is a measure of the transformation of kerogen into hydrocarbon. Deroo et al (1988) stated that TR values between 0.002-0.016 wt% indicate no hydrocarbon generation. The mean transformation ratio (TR) for the source rocks is 0.28 wt% which is considerably higher than the minimum threshold value of 0.16 for hydrocarbon generation. The TR progressively increased from 5730ft to 10590ft showing that maturation increased with depth at this interval but decreased at 11490ft. Peters and Cassa (1994) pointed out that in situ vitrinite (R O) can be overwhelmed by the recycled particles which give impression of high maturity or caved particles which show anomalous low maturity as compared with established vitrinite reflectance (R O) trend from other depths. These situations are common with cutting rock samples used for this study. To this end, plot of R O versus depth can be used to distinguish the indigenous samples from non indigenous samples which may be caved 259

in, recycled or even inertinites and bituminous samples (figure 5). From the R O versus sample depth plot, the low R O sample at 11490 represents a caved in sample. Only the samples that tend to linearity are the indigenous samples. The linear relationship between SOM and TOC values for indigenous samples show that maturity increased with depth (figure 11), therefore TR is also a good maturity index. Figure 5: Plot of vitrinite reflectance (VR O) versus depth of samples differentiating indigenous from non indigenous vitrinite in well X SUMMARY / CONCLUSION The geochemical analysis revealed that TOC ranges from (0.46 to 12.06) wt %; HI ranges from (72 568) HC/gCorg; and PI values ranges from (0.06-0.32). These show that Organic matter quantity of the source rocks is fair to good with type II and type III kerogen. The average generative potential (S1+S2) and soluble organic matter concentration (SOM) also revealed that these source rocks have excellent hydrocarbon generation potentials with moderately high organic matter concentration. TMAX and VRO averages of the source rock intervals are 432 C and 0.62% respectively. These show that the source rocks are mature and in oil and gas generation phase. The mean transformation ratio (TR) of 0.28 wt% is considerably high for hydrocarbon generation. The oil window is placed around 8100ft where the source rock profile exhibited the highest values of (TOC) 12.06%, genetic potential (55.47), S2/S3 (10.54), (TMAX) 431( 0 C) and (VRO) 0.6%. Deductions from TOC, S1+S2. SOM, TR, TMAX and VR 0, revealed that the shales in Agbada Formation have 260

high organic matter concentration with type II and type III kerogen of excellent hydrocarbon generative potentials that are considerably mature at intervals and conclude that Agbada Formation sourced the hydrocarbon in the study area. REFERENCES 1. Akande, O. S., Ojo, O. J., Adekeye, O.A., Egenhoff, S.O., Obaje,N.J., and Erdtmann, B.D., 2011. Stratigraphic Evolution and Petroleum Potential of Middle Cretaceous Sediments in the Lower and Middle Benue Trough, Nigeria: Insights from New Source Rock Facies Evaluation. Petroleum Technology Development Journal (ISSN 1595-9104) July 2011, Vol. 1. 2. Allen, J.R.L., 1965, Late Quaternary Niger Delta, and adjacent areas-sedimentaryenvironments and lithofacies AAPG Bulletin, v.49, p.547-600. 3. Bissada, K.K., 1982. Geochemical constraints on petroleum generation and migration a review.proceedings Volume, ASEAN Council on Petroleum (ASCOPE 81) 69-87. 4. Doust, B., and Omatsola, E., 1990. Niger Delta, in, Edwards, J. D., and Santogrossi, P.A., eds., Divergent/passive Margin Basins., AAPG Memoir 48: Tulsa, American Association of Petroleum Geologists. p. 239-248. 5. Dymann, T.S., Palacos, J.G., Tysdal, R.G., Perry, W.J., Pawlewicz, M.J., 1996. Source rock potential of Middle Cretaceous rocks in south western Montana. AAPG Bull. 80, 1177 1184. 6. Ekweozor, C.M., and Okoye.N.V., 1980. Petroleum source-bed evaluation of Tertiary Niger Delta: American Association of Petroleum Geologists Bulletin, v. 64, p 1251-1259. 7. Evamy, B.D., Haremboure. J., Kamerling, P., Knaap, W.A., Molloy, F.A., and Rowlands, P.B., 1978.Hydrocarbon habitat of Tertiary Niger Delta.American Association of Petroleum Geologists Bulletin. v. 62, p. 8. Lambert-Aikhionbare, D. 0 and Ibe A.C., 1984. Petroleum source-bed evaluation of the Tertiary Niger Delta: discussion: American Association of Petroleum Geologists Bulletin, v. 68, P. 387-394. 9. Nwajide, C.S., 2013. Geology of Nigeria s sedimentary Basins. Geoscan Technical services Ltd. Awka, 565P. 10. Short, K. C., and Stauble, A.J., 1967. Outline of geology of Niger Delta: American Association of PetroleumGeologists Bulletin, v. 51, p. 761-779. 11. Stacher, P., 1995. Present understanding of the Niger Delta hydrocarbon habitat, in, Oti, M.N., and Postma, G., eds. Geology of Deltas: Rotterdam, A.A. Balkema, p. 257-267. 261

12. Tissot, B. P., and Welte, D. H., 1984, Petroleum Formation and Occurrence, Springer-Verlag: New York, 699 pp.). 13. Tissot, B. P., B. Durand, J. Espitalie, and A. Combaz, 1974, Influence of the nature and diagenesis of organic matter in formation of petroleum: AAPG Bulletin, v. 58, p. 499-506. 14. Tuttle, M.L., Brownfield, M.E.and Charpentier, R., 2004.Tertiary Niger Delta (AkataAgbada) Petroleum System (No. 701901), Niger Delta Province, Nigeria, Cameroon, and Equatorial Guinea, Africa. 15. Tuttle, M. L. W., Charpentier,R. R.and Brownfield, M. E.,1999. The Niger delta petroleum system: Niger delta province, Nigeria, Cameroon, and Equatorial Guinea, Africa: USGS Open-file report 99-50-H. 262