Sage Journals: Discover world-class research

Abstract

Hydrocarbon potentials of lignites and shales of Oligocene-Miocene Ogwashi-Asaba Formation outcropping along springs at Issele-Uku and Azagba-Ogwashi areas of Anambra Basin, Southern Nigeria were investigated through total organic carbon (TOC), Rock-Eval pyrolysis and organic petrology analyses. Lignite has an average TOC of 47.20 wt.% and shale of 9.15 wt.%, suggesting good to excellent source rocks. Sporinite, resinite, and humodetrinite are the dominant sub-maceral. Ratios of average huminite, liptinite, and inertinite maceral group (H:L:I) in lignite from Nnem-Agadi, Iyiodo, Mgbala, and Nkpunkpa are 55:35:10, 66:24:10, 62:25:13, and 58:30:12, respectively, while for shales in Nnem-Agadi is 57:28:15 and Iyiodo is 55:20:15. Average hydrogen index (HI) of lignite is 436 mgHC/gTOC, and shale is 218 mgHC/gTOC. HI of 783 mgHC/gTOC in one lignite from Nnem-Agadi indicates Type I oil-prone kerogen typical of algae-sourced organic matter, whereas Type II oil and gas kerogen is present in both lignites and shales. Type III gas-prone kerogen is found only in shale. Genetic potential of 106.95 kgHC/t) in lignites and 20.87 kgHC/t in shales indicate excellent and moderate oil and gas potentials. All the source rocks are immature at the current outcrop positions but could have possibly attained maturity in the deeper subsurface area of the basin and contributed to the petroleum systems in the Anambra Basins. Ogwashi-Asaba formation has similar source rocks and organic matter types with the ones generating mixed marine and terrestrial oil within Agbada Formation, in the Niger Delta Basin. These source rocks are significant Oligocene-Miocene conventional and unconventional hydrocarbon resources depending on their current depth in the rift basins in West and Central Africa.

Keywords

Lignite Shale Anambra Basin Niger Delta Basin source rock

Introduction

Anambra Basin located in the southern Benue Trough of Nigeria is one of the Nigeria inland basins that share a boundary with the northern end of the Niger Delta Basin (Figure 1). It consists of about 8 km thick Upper Cretaceous to Tertiary sediments covering an area of about 40,000 km² (Genik, 1992). The basin is characterized by enormous lithologic heterogeneity in both lateral and vertical extensions derived from a range of paleoenvironmental settings from Campanian to recent (Akande et al., 2015). Some of the lithologies in the basin cut across siliciclastic, carbonate, and organic sedimentary rocks among which coal is one of its largest well-known deposit in Africa with proven reserves exceeding 300 million tons (Orajaka et al., 1990). The motivations for this study were derived from controversy of mixed oil from marine and terrestrial sources of the Niger Delta Basin (Evamy et al., 1978; Ekweozor et al., 1979; Ekweozor and Okoye, 1980; Lambert-Aikhionbare and Ibe, 1984; Bustin, 1988) and the recent findings of the contribution of oil by some coaly units in the Agbada formation which is the lateral equivalent of Ogwashi-Asaba formation in the Anambra Basin (Akande et al. 2015). This study provides more data to understand possible sources of mixed marine and terrestrial oil in the Niger Delta vis-à-vis the hydrocarbon type possible in the Anambra Basin. Niger Delta and Anambra Basin have similar evolution and sedimentation history tied around the separation South America and African continental plates, opening of Atlantic Ocean, and failed arm of the triple rift system. The Paleogene-Neogene sediments of the Anambra Basin and Niger Delta have the same provenance and transportation history which was controlled by both transgression and regression events. There is no existence of outcrop rocks in the Niger Delta Basin, so most of the geological studies in the Niger Delta were carried out on cores and ditch cutting coupled with pilot studies from the neighbouring Anambra Basin. The Nigeria Federal Government pursuit of increasing the national hydrocarbon reserve and power generation which has led to the recent renewed interest in exploration activities for commercial unconventional or conventional hydrocarbon resources in Nigeria's inland basins is also part of the objectives of this study. The main prerequisite for both conventional and unconventional hydrocarbon resources is the presence of organic-rich source rocks such as shales, coal, or limestones which are either mature or immature. Niger Delta is prolific in hydrocarbon production whereas the oil and gas discovery in the contiguous Anambra Basin is very low. About five of the twenty exploratory wells drilled in the Anambra Basin encountered hydrocarbons with one oil and four gas fields (Nwachukwu, 1985) indicating an existing working petroleum system in the basin. All these findings and knowledge of the Anambra Basin and its contiguous oil producing Niger Delta Basin demand further assessment of the organic matter quantity, quality, and maturity of potential source rocks of Ogwashi-Asaba formation in Anambra Basin to shed more light on its spread in the basin and possible significant potential for oil and gas generation as its the deep subsurface equivalent Agbada Formation, Niger Delta. The results should help in increasing knowledge of the source rocks in the Anambra Basin, reducing risk and inform more on the exploration strategy in the two basins.

Figure 1.

Geological and geographical map of Anambra Basin showing the sample locations (1. Mgbala; 2. Nkpunkpa; 3. Iyiodo; 4. Nnem-Agadi) in Issele-Uku and Ogwashi-Azagba Areas. (Modified after Iserhien-Emekeme, 2014).

This study evaluated the petroleum potentials of lignite and shale outcropping in the Issele-Uku and Ogwashi-Azagba areas of the Ogwashi-Asaba Formation, Anambra Basin. The results thus revealed the extent of Ogwashi-Asaba source rocks and their capacity in contributing to the petroleum systems of the Anambra Basin where they are deeply buried to maturity. They are currently significant unconventional hydrocarbon resources in the shallow subsurface to surface areas where they were mapped. Their organic richness further characterizes the study area of the Ogwashi-Asaba Formation to consist of better potential source rocks than its lateral subsurface equivalent Agbada Formation in the Niger Delta (Short and Stauble, 1967). The study areas cover the Iyiodo, Nnem-Agadi, and Nkpunkpa Springs in the Obomkpa and Mgbala Spring in the Okpanam area of Issele-Uku, Southern Nigeria within latitudes 6^°00'N and 6^°30'N and longitudes 5^°30'E and 6^°00'E (Figure 1) characterized by an equatorial bimodal pattern of climatic setting.

Geology and Stratigraphy of Anambra Basin

Anambra Basin belongs to the southern Benue Trough which is a subdivision of Benue Trough formed as a result of rifting events that separate the South American and African plates in the late Jurassic and early Cretaceous. Burke et al. (1970) suggested the existence below the Niger Delta an extension of southern Benue Trough where the triple junctions are which indicates the existence of a spreading ridge active from Albian to Santonian. Whereas the Benue Trough was considered the third failed arm (or aulacogen) of a three-armed rift system related to the development of hot spots (Olade, 1975 and Wright, 1976). The oldest sedimentary rocks in Southern Benue Trough comprise the Albian to Santonian Abakaliki successions comprising the Albian Asu River Group (micaceous sandstone, siltstone, and limestone) succeeded by Albian-Cenomanian Odukpani Formation, a shoreline carbonates followed by a Turonian-Coniacian Eze-Aku Formation overlain by the Awgu Shale (Table 1) (Reyment, 1965).

Table 1.

Stratigraphic chart of Cretaceous to quaternary sequence in southeastern Nigeria (modified from Nwajide and Reijers, 1996).

Period	Epoch/stage	Formation
Quaternary	Holocene	Benin formation
Quaternary	Pliestocene	Benin formation
Neogene	Pliocene	Ogwashi-Asaba formation
Neogene	Miocene	Ogwashi-Asaba formation
Paleogene	Oligocene	Ameki/Nanka/ Nsughe Sandstones
	Eocene	Imo formation Nsukka formation
	Paleocene	Imo formation Nsukka formation
Cretaceous	Maastrichtian	Ajali formation Mamu formation
	Campanian	Nkporo/Oweli/Enugu Shale
	Santonian	Nkporo/Oweli/Enugu Shale
	Coniacian	Awgu formation
	Turonian	Eze-Aku formation
	Cenomanian	Odukpani formation
	Albian	Asu-River group
	Aptian Barremian Hauterivian	Unnamed units
Precambrian		Basement complex

These depositional cycles in the Benue Trough were interrupted by the widespread Santonian episode of compressional deformation and magmatism leading to the displacement of the depositional axis of the southern Benue Trough westward and the Anambra Basin subsided. Sediments derived from erosion of the Abakaliki anticlinorium and the ancestral Niger River filled the Anambra Basin, which was hitherto a shallow shelf area. The bulk of the Campanian-Maastrichtian predominantly deltaic sequence accumulated in the Anambra Basin. The sequence in Anambra Basin starts with the Upper Campanian transgressive cycle represented by the Nkporo Shale and the Paralic equivalent Enugu Shale, succeeded by the Maastrichtian-Danian deltaic coal-bearing Mamu, Ajali, and Nsukka formations. These pass on to the early late Paleocene marine transgression consisting of the Imo, Ameki, and Ogwashi-Asaba Formations (Table 1) (Murat, 1972). By Eocene, the Anambra Basin was filled and the Niger Delta Basin sedimentation progressed southward through the Anambra shelf (Bullard et al., 1965; Stoneley, 1966).

Methods

Eight lignites and seven shales from the springs in Okpanam (Mgbala spring), Ogwashi-Azagba, area, and Obomkpa (Iyiodo, Nnem-Agadi, and Nkpunkpa) Issele-Uku were prepared for Leco TOC/Rock-Eval Pyrolysis. 100 mg of the shale and lignite samples were subjected to heating in an inert medium under a programmed temperature pattern with the characterization of four peaks. S₁ which is the first peak represents hydrocarbon already present in the sample which is mainly released at temperatures about 300°C and represents the free hydrocarbons (in mg) liberated per gram of rock. The second peak, S₂ represents hydrocarbons generated through the thermal cracking of kerogen at temperatures in the range of 300°C to 650°C, while S₃ peak represents the CO₂ which is generated from the kerogen at the same time the S₂ hydrocarbon is being generated. The Rock-Eval pyrolysis technique is based on the methodology described by Espitalié et al. (1985).

Organic petrology was carried out on 11 shales and 12 lignite samples after air drying them, crushed and sieved with 2 and 1.18 mm mesh separately. About 5 g of the retained crushed samples in the 1.18 mm sieve were covered with epoxy resin inside a small rubber mold. The sample is removed and grounded after 24 h of hardening. Grinding was done in stages using Carborundum grits of 230, 400, 600, and 1000 were used one after the other to grind the sample in water on a polishing machine until a flat and smooth surface was achieved. The sample was polished using Magnesium oxide powder and water on Struers oxide polishing suspension for at least thirty minutes (30 min) on the polishing machine. Final polishing was done using glycerol on velvet cloth to obtain a smoother polished surface on each of the well-labeled samples. The samples were observed and photographed under a reflected and fluorescent light microscope.

Results

Sedimentology

The rock types of the mapped sections of the Ogwashi-Asaba Formation along the river channels in the study areas consist of shale, lignite, claystone, siltstone, sandstone, and conglomerate (Figure 2).

Figure 2.

Lithologic sections of the Ogwashi-Asaba formation exposed at (a) Mgbala River, Okpanam; (b) Iyiodo spring, Obomkpa; (c) Nnem-Agadi River, Obomkpa; (d) Nkpunkpa Spring, Obomkpa.

Lithologic description of Mgbala river section

Mgbala section is located within N 06^°14^' 36.0”, E 006^° 38^' 57.7”, and about 14 m thick including the overburden. The rock types include massively bedded lignite at the base overlain by thin-bedded reddish-brown claystone succeeded by cream to red siltstone overlain by ferruginized coarse-grained sandstone before being capped by the matrix-supported conglomerate (Figure 2(a)). Lignite seam at the base is massive and about ca. Four meter thick with dark brown colour. The overlying claystone is 0.32 m thick and reddish brown in colour and the succeeding siltstone is massive cream to reddish colour and about 2.5 m thick. Two distinct beds of matrix-supported conglomerates and sandstones mapped above and succeeding the siltstone are 0.3 and 0.28 m thick, respectively. The conglomerate grains are well-rounded and have a smooth texture characteristic of deposits in a fluvial setting. They are separated by about 2.7 m thick covered section. The Mgbala section, however, has a total thickness of about 14 m.

Lithologic description of Iyiodo section

The section exposed at the Iyiodo spring is within coordinates of N006^°24' 59.9” and E006^°29' 56.6” on an elevation of 151 m. Iyiodo lignite bed is about 0.7 m (Figure 2(b)), black, and massive with an earthy texture. Basal shale bed is a carbonaceous coaly shale and is 1.3 m thick while the one overlying the lignite is silty carbonaceous shale of about 2.5 m thick. A 1.5 m thick soil with vegetation covered this section. The total thickness of the Iyiodo section is about 6.0 m.

Lithologic description of Nnem-Agadi river section

This section lies within N 06^° 24' 58.0”, E 006^° 29' 03.6” with ca. 5 m thickness consisting of only lignite and shale rock types (Figure 2(c)). Lignite was mapped as two distinct units at the base with thicknesses of 1.03 and 1.66 m, respectively. Shales, however, are both carbonaceous and coaly at two different intervals with thicknesses ranging from 0.49 m at the top to 1.98 m. The lignites are generally brownish-black, massive, and varying from woody to earthy texture. The shales are massive and sandy at the basal part of the section while the upper unit is distinctively laminated and carbonaceous.

Lithologic description of Nkpunkpa river section

The 7 m exposed Nkpunkpa section comprises lignite and shale. The lignite bed at the base is about 1 m thick. It is black and massive with an earthy texture. It is overlain by about 5 m of massive carbonaceous shale and capped by vegetation (Figure 2(d)).

Leco TOC

Shale samples from Iyiodo and Nnem-Agadi have total organic carbon (TOC) ranging from 3.9 to 5.6 wt.% and 7.5 to 17 wt.% along with the Nkpunkpa sample which is 1.3 wt.%. The total average TOC value for the shales is 9.15% (Table 2). TOCs of the lignite samples from Iyiodo, Nnem-Agadi, and Mbgala range from 24 to 36 wt.%, 31.2 to 70.4 wt.%, and 25.4 to 44.5 wt.%, respectively, and 53.2 wt.% of Nkpunkpa sample. The average TOC for all the lignites is 47.20 wt.% (Table 2). The highest concentrations of organic carbon are in the lignite from Nnem-Agadi with the highest value of 70.7 wt.%, and an average of 51.45 wt.%. Their potential for either oil or gas cannot be concluded on only high TOC values but further with kerogen type (Peters and Cassa, 1994).

Table 2.

Leco TOC and rock-eval data of lignite and shale samples from the Issele-Uku and Azagba Ogwashi areas, Ogwashi-Asaba formation, Anambra Basin.

Sample	Location	Lithology	TOC	S ₁	S ₂	Tmax	S ₃	HI	OI	PI	S₁ + S₂
IY01T	Iyiodo	Shale	5.6	0.5	3.8	410.0	2.6	66.0	46.0	0.11	4.3
IY03M	Iyiodo	Shale	3.9	1.5	12.2	427.0	1.2	316.0	30.0	0.11	13.7
IY02T	Iyiodo	Impure lignite	36.8	7.5	131.9	421.0	13.4	358.0	36.0	0.05	139.4
IY02B	Iyiodo	Impure lignite	24.0	7.4	129.8	425.0	4.9	540.0	20.0	0.05	137.2
MGB01B	Mgbala	Impure lignite	25.4	7.3	123.4	424.0	7.1	485.0	27.0	0.06	130.7
MGB01T	Mgbala	Lignite	44.5	7.9	119.3	417.0	17.9	268.0	40.0	0.06	127.2
NK01T	Nkpunkpa	Lignite	53.2	10.5	193.0	411.0	17.3	362.0	32.0	0.05	203.5
NKO2M	Nkpunkpa	Shale	1.3	0.2	0.3	413.0	0.4	21.0	31.0	0.33	0.4
NMO1T	Nnem-Agadi	Lignite	52.7	12.0	208.3	422.0	15.7	394.0	29.0	0.05	220.3
NMO1M	Nnem-Agadi	Lignite	70.4	18.4	551.4	430.0	11.9	783.0	16.0	0.03	569.8
NM02T	Nnem-Agadi	Shale	10.2	2.4	44.3	429.0	2.4	434.0	23.0	0.05	46.7
NM02B	Nnem-Agadi	Shale	7.5	1.6	29.8	429.0	2.2	395.0	29.0	0.05	31.4
NM03M	Nnem-Agadi	Shale	17.0	2.3	29.1	417.0	9.6	171.0	56.0	0.07	31.4
NM04M	Nnem-Agadi	Impure lignite	31.2	5.7	93.2	420.0	12.7	298.0	40.0	0.06	99.0
NM05M	Nnem-Agadi	Shale	13.3	1.2	17.0	415.0	7.4	128.0	55.0	0.06	18.2

TOC (wt.%), S₁ free oil (mgHC/g rock), S₂ Kerogen yield (mgHC/g rock), Tmax (^oC), S₃ (mgCO/g rock), HI-Hydrogen Index (mgHC/gTOC), OI, oxygen index; PI, production index; GP, genetic potential (S₁ + S₂).

Maceral

Maceral, the “mineral” constituents of coal were developed by coal petrologists to describe the materials from which they were derived. They are the combustible material in coal that contains more than 50% by weight of carbonaceous material formed from the compaction of variously altered plant remains (Schopf, 1956; Akande et al. 1992). Maceral's shapes and structures can be related to specific plant organs, genera, and species and are mainly grouped into vitrinite or huminite (H), liptinite (L), and inertinite (I). Petrological examination of a candidate petroleum source rocks (Figure 3) gives deeper and better insight into the quality of their organic matter by the way of assessing the percentage of their vitrinite, liptinite, and inertinite maceral constituents. The petrographic composition of lignites and shales in this study was used for organic matter type classification in conjunction with hydrogen index values. The average ratios (H:L:I) in lignite from Nnem-Agadi is 55:35:10, in Iyiodo, is 66:24:10, Mgbala is 62:25:13, Nkpunkpa is 58:30:12 and shales in Nnem-Agadi is 57:28:15 and Iyiodo 50:35:15. Liptinites are derived primarily from leaf cuticle, spores, pollen, algae, plant waxes, resins, fats, and oils remains and usually has high H/C ratios. Liptinite constituents need to be up to about 15% to 20% in coals, the equivalent of HI at least 200 mg HC/g TOC and an atomic H/C ratio of 0.9 prior to catagenesis to generate and expelled oil (Hunt, 1991). The liptinite percentage in all the source rocks ranges from 20% to 51%. The huminite (vitrinite) group, derived from lignin and cellulose-containing plant organic matter has the potential for generating gas. These are Type III kerogen, formed from humic organic matter, which is hydrogen poor and is the main precursor for gas.

Figure 3.

Photomicrograph of (a) of Mgbala lignite in reflected light; (b) Mgbala lignite in ultraviolet light; (c) Iyiodo shale in reflected light with laminated fabric and liptinitic macerals; (d) Iyiodo shale in ultraviolet with pale yellow resinites; (e) Nnem-Agadi shale in reflected light with sporadic distribution of resinite particles; (f) Nnem-Agadi shale in ultraviolet light showing fluorescing yellowish to brownish fluorescence liptinite macerals; (g) Nnem-Agadi lignite in reflected light showing aggregates of huminites, liptodetrinites in a matrix of dominantly liptinites; (h) Ultraviolet light showing yellowish fluorescing resinites and broken fragments of sporinite; (i) Nnem-Agadi lignite a reflected light with indistinguishable macerals; (j) Ultraviolet light with threads of sporinite, resinites and alginite (A-Algae; S-Sporinite; R-Resinite; LP-Liptodetrinite; HD-Humodetrinite).

Hydrogen Index

Hydrogen index (HI) derives from S₂ and TOC (HI = [100 × S₂]/TOC) reveals available hydrogen ions to combine with the organic carbon for the production of either gas or oil. Relatively high hydrogen content in kerogen (HI) generally corresponds to higher oil generative potential (Peters and Cassa, 1994). The hydrogen index of the shales from all the study areas ranges between 66 and 434 mgHC/gTOC while that of the lignites ranges from 268 to 783 mgHC/gTOC.

The lignite from Nnem-Agadi (NM01M) has the highest hydrogen index value of 783 mgHC/gTOC (Table 2) indicative of a bog head coal or sapropelic commonly form from the accumulation of algae and less input from the higher plant in an anoxic environment condition. All other lignites are also rich in organic matter with characteristic features of Type II oil and gas kerogen from HI values ranging between 268 and 540 mgHC/gTOC. Shales with kerogen characteristics of Type II oil and gas prone are essentially that of Nnem-Agadi, NM02B, and NM02T with HI 434 and 395 mgHC/gTOC, respectively, and Iyiodo (IY03M) with 316 mgHC/gTOC.

Thermal maturity

Tmax values from pyrolysis of shales and lignites in this study which range between 410^oC and 430^oC reveal that the maximum temperature the source rocks have been exposed to over time is insufficient for hydrocarbon generation. The pyrolysis method of Espitalie et al. (1977), utilizes the parameters S₁ and S₂, which is indicative of the degree of thermal maturity (Peters, 1986). The ratio S₁ (S₁ + S₂) is also referred to as the transformation ratio or production index and both the shales and lignites have values ranging from 0.05 to 0.11 (Table 2).

Genetic potential

The Rock-Eval result (Table 2) shows that two Iyiodo shales have genetic potential values of 4.3 and 13.7 kgHC/t (mean = 8.97 kgHC/t). Two lignite samples from Iyiodo as well recorded 137.20 and 139.35 kgHC/t (mean = 138.28 kgHC/t) while at Mgbala, the lignites have genetic potential values of 127.17 and 130.69 kgHC/t (mean = 128.93 kgHC/t). Nkpunkpa shale is have value of 0.44 kgHC/t while the 1 m thick Nkpunkpa lignite have genetic potential value of 220.26 kgHC/t. At the Nnem-Agadi, the four shale samples have genetic potential values ranging from 18.21 to 46.66 kgHC/t with a mean value of 31.93 (kgHC/t and the lignites, however, have genetic potential values ranging from 98.95 to 569.76 kgHC/t with mean value of 296.32 mgHC/t.

Discussion

Hydrocarbon potential

The organic matter in a source rock is expressed in weight percent (wt.%) of the total organic carbon. It is the most common basic and first parameter used in screening or determining the organic richness of a classic petroleum source rock (Brooks et al., 1987). TOC values such as 0.5 wt.%, are taken as the minimum TOC value for a fair clastic source rock, 4.0 wt.% and above is regarded as excellent (Peters and Cassa, 1994). All the lignites and shales have the minimum required TOC to be classified as a good source rock. The TOC value for shales ranges between 1.0 and 17.3 wt.% while lignite values range between 24.0 and 70.4 wt.%. All the lignites and shales are potential source rocks with a good to an excellent quantity of organic matter. Although four of the lignites with TOC below 40 wt.% are probably the impure ones (Akande et al. 2015).

Maceral constituents show the dominance of huminites such as humodetrinites, collinites, and telinites. The liptinite is essentially the sporinites, and resinites (Figure 3 a-k) while inertinite is mainly inertodetrinite, and fusinite. The average ratios (H:L:I) in the lignite from Nnem-Agadi gives 55:35:10, in Iyiodo 66:24:10, Mgbala is 62:25:13, Nkpunkpa is 58:30:12 and shales in Nnem-Agadi is 57:28:15 and Iyiodo 50:35:15. The range of 24% to 35% of liptinite in lignites and shales suggest a reasonable amount of Type II oil and gas prone kerogen in all the rock with dominance of Type III gas prone kerogen. Tissot et al. (1987) extended the use of the Van Krevelen plot (Figures 4 and 5) from coals to include kerogen dispersed in other sedimentary rocks.

Figure 4.

Van Krevelen diagram of hydrogen index against oxygen index showing the various kerogen type in the source rocks (modified after Van Krevelen, 1993).

Figure 5.

Tmax (^oC) versus hydrogen Index (mg/gTOC), showing the maturity level and kerogen types in the source rocks (modified after Van Krevelen, 1993).

This helps to further evaluate the origin of organic matter such as in marine organisms and algae which are composed of lipid and protein-rich organic matter with an H to C ratio higher than carbohydrate-rich constituents of land plants. The dominance of hydrogen-rich sporinite and resinite (Figure 3) along with the reasonable HI values (Table 2) support the presence of Type II kerogen capable of generating oil and gas at maturity in almost all the shales and lignites with HI values of 268 to 783 mgHC/gTOC. The upper units of Nnem-Agadi (NM03M and NM05M) and Iyiodo (IY01T) have Type III gas-prone kerogen with HI ranging between 60 and 171 mgHC/gTOC. Type III kerogen is composed of terrestrial organic materials that lack fatty components (Waples, 1985) with cellulose and lignin as the major contributors. The shales have a predominance of huminites with a notable presence of the liptinite group macerals, indicating Type III kerogen capable of generating gas. There are exceptions in Nkpunkpa shale with Type IV (HI-21 mgHC/gTOC) a non-generative organic matter. The Van Krevelen plot of HI versus OI further suggests that most of the studied lignites and shales plot within Types II and III oil and gas zone with the exception of the Nkpunkpa shale that is inert. This suggests that Ogwashi-Asaba Formation has more potential for petroleum generation also in the Issele-Uku area and will generate hydrocarbon when mature.

Temperature and burial are part of the natural factors responsible for the chemical alteration of organic matter within a sedimentary rock over time. PI values of 0.10, 0.25, and 0.40 approximately correspond to the beginning of oil window, peak oil window, and end oil window, respectively (Tissot and Welte, 1984, Peters and Moldowan, 1993). The production index values between 0.03 and 0.07 of all the lignites and shales (Table 2) suggest that the organic matters are immature supported by the low Tmax value (Figure 6) They are thermally immature at the outcrop level, however, there is an exception with the Type IV inert Nkpunkpa shale with a PI value of 0.33 probably supporting that the organic matter has been severely oxidized or reworked. Tissot and Welte (1984) suggested that the value of S₁ represents a part of the initial organic matter's potential that has formed hydrocarbons and the S₂ value is the residual potential. Total S₁ + S₂ (usually expressed in kgHC/ton) represents the total genetic potential of a petroleum source rock. The thermal maturity of the shales and coals of the Anambra Basin has also been discussed by several authors (Akande et al., 1992a; Akande et al., 1992b; Unomah and Ekweozor, 1993; Akaegbobi and Schmitt, 1998; Akaegbobi et al., 2000).

Figure 6.

Plot of production index against Tmax (^oC) showing the hydrocarbon drained region base on the maturity of the sample. The source rocks are all immature.

Generally, the shales have a genetic potential value ranging from 0.44 in poor Nkpunkpa sample to 46.66 in Nnem-Agadi with an average value of 20.87 kgHC/t while the lignites have genetic potential values ranging from 98.95 in Nnem-Agadi to 569.76 kgHC/t also in Nnem-Agadi with an average value of 106.95 kgHC/t. This suggests that all the lignites in the study area have excellent potential for liquid hydrocarbon generation while the shales have moderately good potential for both oil and gas generation. Nnem-Agadi obviously is the most prospective area for an excellent petroleum source rock.

Relationship between petroleum source rocks of Anambra and Niger Delta Basins

Ogwashi-Asaba Formation is a surface lateral equivalent of the Agbada Formation in the Niger Delta, (Short and Stauble, 1967), consisting of shales and lignites which are confirmed potential source rocks for petroleum generation. The results from the Issele-Uku area reveal a good to excellent petroleum source rock with moderate organic richness. Average HI values of 218.7 and 436 mgHC/gTOC of the shales lignites, respectively, confirmed the presence of mixed kerogen Type II/III capable of producing marine and terrestrial sourced oil and gas in Anambra Basin such as it has been established in the Niger Delta. This outcome of marine and terrestrial oil potentials in the Anambra Basin has significant similarities in geochemistry results from the extracts from the onshore Niger Delta oil (Ekweozor and Okoye, 1980; Katz, 2006). Samuel et al. (2009) reported that the source rocks of the onshore Niger Delta have received significant terrigenous land plant contributions. This observation supports the origin of the mixed onshore Niger Delta oils as reported in Sonibare et al. (2008), Akinlua and Ajayi (2009), Samuel et al. (2009), and Akande et al. (2015). However, from the present study, it is possible that the source rock facies of the Issele-Uku area is similar to that of Ihioma and Oba, Ogwashi-Asaba formation in Akande et al. (2015) that was suggested to be contributing a substantial amount of hydrocarbons into the onshore Niger Delta oil at great depths. According to Sonibare et al. (2008), both saturated and aromatic hydrocarbon molecular composition of Niger delta oil revealed that the oil was generated in source rocks containing mixed kerogen (marine and terrestrial) deposited in a deltaic depositional environment. More affirmatively, this study also supports the suggestion by Akande et al. (2015) that candidate source rocks for the mixed origin of Niger Delta oils may also include the coaly facies of the Agbada formation. Akande et al. (2015) suggested that the coaly facies in the matured sections of the Agbada formation could also have contributed some quantified amounts of hydrocarbon into proximal reservoirs where coaly shale source rocks interbedded with oil-bearing Agbada reservoirs as in the Olomoro field of the western Niger Delta reported in Doust and Omatsola (1990). Likewise, the existence of Type I kerogen (NM01M in Table 2), an overwhelmingly high HI value of 783 mgHC/gTOC with the capacity to generate and expel oil along with Type II/III mixed oil and gas kerogen of the lignite and shale in the study area give credence to the potential hydrocarbon resources of Anambra Basin. The candidate petroleum source rocks will have probably been generated within the deeper subsurface area of the Anambra Basin while the shallow-placed immature equivalent is a good source of coalbed methane and shale gas. These Paleogene-Neogene source rock facies could be tested in the other rifted basins of West and Central Africa.

Conclusions

The sedimentology and organic geochemical studies of the Oligocene-Miocene Ogwashi-Asaba Formation in the Issele-Uku area, Southern Nigeria summarily reveals that:

The dominant rock types in the study region are shale and lignite with some conglomerate, sandstones, siltstone, and siltstone.

Shales and lignites of Issele-Uku and Ogwashi-Azagba areas represent good to excellent petroleum source rocks for Anambra Basin where they are deeply buried.

A high proportion of liptinite (Type II oil-prone Kerogen) in the lignites of all the studied samples suggests their potential for oil generation, while the predominance of huminite (Type III gas-prone kerogen) in the shales suggests the potential for oil and gas.

783 mgHC/gTOC hydrogen index and maceral constituents indicate presence of Type I oil-prone kerogen in one of the lignites and mixed Type II/III oil and gas-prone kerogen in the shale source rocks.

The shale and lignites have the minimum organic richness needed for an unconventional resource

The organic-rich intervals of coal and shale successions within the paralic Ogwashi-Asaba Formation may be contributing to the oil and gas of the Niger Delta through its subsurface equivalent Agbada Formation.

The Oligocene-Miocene deltaic organic-rich shales and lignites of Issele-Uku and Ogwashi-Azagba, Anambra Basin, and prolific Agbada Formation in the Niger Delta may be significant in other rifted basins of West and Central Africa countries for hydrocarbon exploration.

Footnotes

Acknowledgements

The authors wish to appreciate Pastor (Dr) and Mrs. M. O Awojobi for their support for this research work,Prof. S. O. Akande for his selfless effort,guidance,and keen interest in supervision,and Prof. O. A. Adekeye for good counsel and encouragement.

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research,authorship,and/or publication of this article.

Funding

The author(s) received no financial support for the research,authorship,and/or publication of this article.

ORCID iD

J A Adeoye

References

Akaegbobi

Nwachukwu

Smith

(2000) Aromatic carbon distribution and calculation of oil and gas volume in post santonian shale and coal, Anambra Basin, Nigeria. In: Mello

Katz

(eds) Petroleum Systems of South Atlantic Margin. USA: AAPG Memoir. 73. pp. 233–245.

Akaegbobi

Schmitt

(1998) Organic facies, hydrocarbon source potential and reconstruction of the depositional paleoenvironment of the campano-maastrictian Nkporo shale in the Cretaceous Anambra Basin, Nigeria. NAPE Bulletin 13(1): 1–19.

Akande

Adeoye

Erdtmann

(2015) Petroleum source rock potential of the oligocene-miocene Ogwashi- Asaba, Southern Anambra Basin, Nigeria. Petroleum Technology Development Journal 5(1): 4–34.

Akande

Hoffknecht

Erdtmann

(1992) Rank and petrographic composition of selected upper cretaceous and tertiary coals of Southern Nigeria. International Journal of Coal Geology 20: 209–224.

Akande

Hoffknecht

Erdtman

(1992a) Rank and petrographic composition of selected upper Cretaceous and tertiary coals of Southern Nigeria. International Journal of Coal Geology 20(3-4): 209–224.

Akande

Hoffknecht

Erdtman

(1992b) Upper Cretaceous and tertiary coals from Southern Nigeria composition, rank, depositional environment and their technological properties. NAPE Bull 7(i): 26–38.

Akande

Lewan

Egenhoff

, et al. (2015) Source rock potential of lignites and interbedded coaly shale of the Ogwashi- Asaba formation, Anambra Basin, as determined by sequential hydrous pyrolysis. International Journal of Coal Geology 150: 224–237.

Akinlua

Ajayi

(2009) Geochemical characterization of Central Niger Delta oils. Journal Petroleum Geology 32: 373–382.

Brooks

Cornford

Archer

(1987) The role of hydrocarbon source rocks in petroleum exploration. In: Brooks

Fleet

(eds) Marine Petroleum Source Rocks. London: Geological Society Special Publication 26, pp. 17–48.

10.

Bullard

Everett

Smith

(1965) The fit of the continents around the Atlantic. Philosophical Transactions of the Royal Society of London. Series A, Mathematical and Physical Sciences, 258: 41–51.

11.

Burke

Dessauvagie

Whiteman

(1970) Geologic history of the Benue valley and adjacent areas. In: Dessauvagie

TFJ

Whiteman

(eds) African Geology. Ibadan: Ibadan University Press, pp.187–205.

12.

Bustin

(1988) Sedimentology and characteristics of dispersed organic matter in tertiary Niger Delta. Origin of source rocks in deltaic environments. American Association of Petroleum Geologists Bulletin 72: 277–298.

13.

Doust

Omatsola

(1990) Niger Delta. In: Edwards

Santogrossi

(eds) Divergent/Passive Margin Basins. Tulsa: American Association of Petroleum Geologists Vol. 48, pp. 201–238.

14.

Ekweozor

Okogun

Ekong

DEU

, et al. (1979) Preliminary organic geochemical studies of samples from the Niger Delta (Nigeria) II. Analyses of shale for triterpenoids derivatives. Chemical Geology 27: 29–37.

15.

Ekweozor

Okoye

(1980) Petroleum source-bed evaluation of tertiary Niger Delta. American Association of Petroleum Geologists Bulletin 64: 1251–1259.

16.

Espitalie

Deroo

Marquis

(1985) La pyrolyse rock-eval et ses applications. Partie 1. Revue de 1’lnstitut Francois du Petrole 40(5): 563–579.

17.

Espitalie

Laporte

Madec

, et al. (1977) Methode rapide de caracterisation des roches meres, de leur potential petrolier et de leur degre d’evolution. Rev. Inst Fr. Per 32(1): 23–42.

18.

Evamy

Haremboure

Kamerling

, et al. (1978) Hydrocarbon habitat of tertiary Niger Delta. AAPG Bulletin 62(1): 1–39.

19.

Genik

(1992) Regional framework, structural and petroleum aspects of rift basins in Niger, Chad and Central African Republic (C.A.R.). Tectonophysics 213: 169–185.

20.

Hunt

(1991) Generation of gas and oil from coal and other terrestrial organic matter. Organic Geochemistry 17: 673–680.

21.

Iserhien-Emekeme

(2014) Vertical electrical sounding of water-bearing sub-surface of Issele-Azagba in Southern Nigeria. Natural Resources 5: 772–781. Science Journal of Environmental Engineering Research 2(20):1–8.

22.

Katz

(2006) Significance of ODP results on deep-water hydrocarbon exploration eastern equatorial Atlantic region. Journal of African Earth Sciences 46: 331–345.

23.

Lambert-Aikhionbare

Ibe

(1984) Petroleum source-bed evaluation of the tertiary Niger Delta: discussion. American Association of Petroleum Geologists Bulletin 61: 961–981.

24.

Murat

(1972) Stratigraphy and paleogeography of the cretaceous and lower tertiary in southern Nigeria. In: African Geology. Nigeria: University of Ibadan press, pp. 252–266.

25.

Nwachukwu

(1985) Petroleum prospects of Benue trough, Nigeria. AAPG Bulletin 69(4): 601–609.

26.

Nwajide

Reijers

TJA

(1996) Geology of southern anambra basin. In: Reijers

TJA

(ed) Selected Chapters on Geology. Warri, Nigeria: SPDC Corporate Reprographic Services, pp. 131–148.

27.

Olade

(1975) Evolution of Nigeria’s Benue trough (aulacogen): a tectonic model. Geological Magazine 112(6): 575–583.

28.

Orajaka

Onwuemesi

Egboka

BCE

, et al. (1990) Nigerian coal. Mining Magazine 162: 446–451.

29.

Peters

(1986) Guidelines for evaluating petroleum source rock using programmed pyrolysis. American Association of Petroleum Geologists Bulletin 70: 318–386.

30.

Peters

Cassa

(1994) Applied source rock geochemistry. In: Magoon

Dow

(eds) The Petroleum System — From Source to Trap. Memoir: American Association of Petroleum Geologists 60:93–120.

31.

Peters

Moldowan

(1993) The Biomarker Guide, Interpreting Molecular Fossils in Petroleum and Ancient Sediments. Englewood Cliff, New Jersey: Prentice Hall. 363 pp.

32.

Reyment

(1965) Aspects of the Geology of Nigeria. Ibadan, Nigeria: University of Ibadan, pp. 145.

33.

Samuel

Cornford

Jones

, et al. (2009) Improved understanding of the petroleum systems of the Niger Delta Basin, Nigeria. Organic Geochemistry 40: 461–483.

34.

Schopf

(1956) A definition of coal. Economic Geology 51(6): 521–527.

35.

Short

Stauble

(1967) Outline of geology of Niger Delta. AAPG Bulletin 51(5): 761–779.

36.

Sonibare

Alimi

Jarvie

, et al. (2008) Origin and occurrence of crude oil in the Niger Delta, Nigeria. Journal of Petroleum Science and Engineering 61: 99–107.

37.

Stoneley

(1966) The Niger Delta region in the light of the theory of continental drift. Geological Magazine, 103: 386–397.

38.

Tissot

Pelet

Ungerer

(1987) Thermal history of sedimentary basins, maturation indices, and kinetics of oil and gas generation. AAPG Bulletin 71: 1445–1466.

39.

Tissot

Welte

(1984) Petroleum Formation and Occurrences, Second Edition Berlin: Springer-Verlag.

40.

Unomah

Ekweozor

(1993) Petroleum source rock assessment of the Campanian Nkporo shale, lower Benue trough, Nigeria. NAPE Bulletin 8: 172–186.

41.

Van Krevelen

(1993) Coal, Typology-Physics-Chemistry-Constitution, 3rd Ed. Amsterdam: Elsevier, p. 979.

42.

Waples

(1985) Geochemistry in Petroleum Exploration. Boston, 232: International Human Resources Development Corporation.

43.

Wright

(1976) Origin of the Benue trough—a critical review. In: Kogbe

(ed) Geology of Nigeria. Lagos: Elizabethan Publ. Co., pp.309–317.

Hydrocarbon potential of shales and lignites of Oligocene-Miocene Ogwashi-Asaba formation exposed in Issele-Uku of Anambra Basin,Southern Nigeria as both conventional and unconventional resources

Abstract

Keywords

Introduction

Geology and Stratigraphy of Anambra Basin

Methods

Results

Sedimentology

Lithologic description of Mgbala river section

Lithologic description of Iyiodo section

Lithologic description of Nnem-Agadi river section

Lithologic description of Nkpunkpa river section

Leco TOC

Maceral

Hydrogen Index

Thermal maturity

Genetic potential

Discussion

Hydrocarbon potential

Relationship between petroleum source rocks of Anambra and Niger Delta Basins

Conclusions

Footnotes

Acknowledgements

Declaration of conflicting interests

Funding

ORCID iD

References