Anatomy of Eastern Niger Rift Basin with Specific References of Its Petroleum Systems

An attempt is made in this paper to present the dynamics of the Eastern Niger Rift Basin (ENRB) with references to the key features and processes of petroleum systems based on published information. The Eastern Niger Basin is a superimposed rift basin with sedimentary structures emplaced during two rifts episodes. The Cretaceous episode is characterized by large, tilted normally faulted blocks trending NW-SE, that were reactivated in the Paleogene, while the Paleogene episode is characterized by normal faulted blocks that trend NNW-SSE. The rifting resulted in different basin structures with the north section dominated by asymmetric half-grabens while the south section is dominated by full-grabens. Three source rocks each belonging to three different play fairways exist: 1) The Paleogene Sokor-1 Member source belongs to second cycle syn-rift play associated with fluvial/deltaic facies; 2) Cretaceous Yogou and Donga sources from first cycle post-rift play associated with alluvial/fluvial/deltaic and marine clastic and carbonate facies; and 3) Cretaceous Yogou source from first cycle transitional play associated with mudstone and shale of transitional facies. The ENRB comprises two source-reservoir-seal assemblages: a lower assemblage of Upper Cretaceous and an Upper assemblage of the Paleogene. Except for the Yogou source which possesses a self-contained petroleum system, the rest of the source rocks release their oils into the Paleogene Sokor-1 Member reservoir sealed regionally by the Oligocene Sokor-2 Member. The Paleogene assemblage is charged from the Upper Cretaceous Yogou Formation through fractures emplaced during the rifting episodes.


Introduction
The Republic of Niger is a Sub-Saharan landlocked nation in West Africa. It is confined by seven countries; on the west by Burkina Faso and Mali, on the east by Chad, on the north by Algeria and Libya and on the south by Benin and Nigeria ( Figure 1). It has an area of 1,267,000 square km 2 [2]. The Western Basins belongs to a Paleozoic tectonic and sedimentary regime. It is a 1000 km long and 900 km wide depression [2] containing the Cambrian to Carboniferous sedimentary successions overlying a Pre-Cambrian basement of granites and metamorphic rocks. The basin contains potential petroleum system elements but has no oil discovery so far [1]. The Eastern Basin runs 700 km west-east and 1000 km north-south, extending into the Borno Basin, NE Nigeria [2] [3]. It covers an average of 29% of the Chad basin total area (691,473 km 2 of Niger's 1,267,000 km 2 land area), making it the second largest basin in the Chad Basin after Chad [4]. The Eastern Basin has two distinct tectono-stratigraphy regions: 1) the Djado Basin and 2) the Eastern Niger Rift Basin (ENRB): an extensional asymmetric rift system consisting The ENRB is part of the Chad Basin or West and Central Africa Rift system (WCARS)-a north central Africa intracratonic basin [5] of approximately 2,381,635 square kilometers [4] extending into Niger, Chad, Central Africa Republic, Cameroon, Nigeria, and Algeria [5] [6] [7]. Unlike the Western Basin, the ENRB is oil prolific and has six licensed blocks under operation out of the 35 available blocks [8].     Between 2008 and 2012, CNPC acquired first ever 3D seismic lines (13,000 km 2 ) over the Agadem Basin and more than 18,000 km 2 2D seismic lines. A total of 127 exploration wells were drilled with 97 being discovery wells.

Exploration and Development History
In 2011, the first oil was produced from Sokor and Goumeri fields. The refinery was launched in the Zinder region, with well completions, construction of surface facilities and a 462.5 km-long pipeline from the oil fields to the refinery realized.
The exploration success of CNPC in the Agadem block raised the estimated reserve to 3.5 billion barrels of oil from the 328 million barrels earlier recorded Recently, a fourth well (Eridal-1) also in the R3 acreage has proven successful.
The R1/R2 acreage, which covers 30.5% of the CNPC Agadem area contains an estimated net reserve of 812 MMBBL.  perienced tectonic reversal and uplift [9] [20] while the south remained relatively stable with well-preserved thick sediment deposits as seen in the Termit Basin with no significant scale of tectonic reversal since the rifting process in the Early Cretaceous Epoch and hence has been well preserved [9].

Tectonic and Structural Evolution of ENRB
In the Late Cretaceous, the ENRB switched from a tectonically controlled subsidence to a thermally controlled subsidence, coincidental with global sea level rise which led to marine sediments transgression from the Tethys Sea and the South Atlantic on its rifted blocks. In the Termit Basin, over 5 km thick sediments were deposited into a 150 km wide depression, while in the Tenere Basin, 4 to 6 km of marine, continental and lacustrine deposits formed during the thermal subsidence phase [9] [21].
In the Paleogene, thick Cenozoic continental sands, and shaly-sand sediments were deposited [18] unconformably on the Cretaceous deposits [22]. The Paleogene sequences north of the ENRB experienced tectonic reversal and uplift probably due to volcanism (the Gosso Lorom volcanic) along the Agadez lineament and the northwestern part of the Termit Basin [9].
Most of the WCARS Basins share similar tectono-stratigraphic history with little disparity among individual basins, which resulted from the controlling tectonic regime [23]. Late Eocene and younger sediments, rest unconformably on the older series as a result of intra-Eocene erosional and/or depositional hiatus [22]. Uplift in the WCARS was limited to the Santonian and intra-Eocene phases of intraplate compression [24].  Based on activation timing, strike and tectonic control, the fault systems in ENRB comprise two sets; 1) The Early Cretaceous basement involved faults that trend NW-SE [21].

Source Rock
The  The Sokor-1 Member consists of fluvial deltaic alternating sandstone, mudstone and shale referred to as "Alternances de Sokor" [2] [20] with an estimated thickness of 300 meters [17]. Based on its petroleum importance, the "Alternances de Sokor" is divided into 5 pay zones: E1, E2, E3, E4 and E5. Geochemical analyses of Hydrogen Index (HI) and Oxygen Index (OI) placed the Sokor-1 Member as type II2 [17] and type II-III organic matter [35]. HI versus kerogen carbon isotope, placed the Sokor-1 Member in mainly terrestrial rich organic matter [18].  [18]. The Donga source rock contains mainly type II2-III organic matter [17]. It has a relatively poor to fair source rocks despite its wide distribution and thus considered as secondary source rock [17].
The Lower Cretaceous Formation is a restricted formation of gray lacustrine mudstone found only in the western part of the Termit Basin and the Tenere Basin ( Figure 6 and Figure 9). It has TOC range of 0.45% to 1.54% and is predominantly type III kerogen. These source rocks are very poor to poor quality with no significant contribution to oil discoveries in the Termit Basin [18]. Formations belong to sub-oxic to anoxic marine environment and are richer in marine aquatic organisms such as algae and bacteria [39].
2) The Yogou (YSQ3) Formation belongs to sub-oxic to oxic environment and sub-oxic to transitional environment [38] and richer in higher plant and lower aquatic organisms in fresh-brackish water column [39].

Reservoir Rocks
The The Madama Formation has massive sandstones with thin layer of muddy sandstones and coal seam [18], top reservoir quality with 25% -35% porosity [1] and good reservoir property in its upper 100 -200 m thick sandstone as revealed by well data [20]. Its lower sequence of alternating sandstone and shale has some oil shows [20].
The Yogou (YSQ3) transition Formation, and the Yogou (YSQ1 and YSQ2) marine sandstones formations are important reservoirs for the Upper Cretaceous petroleum system [35]. The thickness of these reservoir beds varies from less than 1 m to 25 m. The Upper Cretaceous Yogou Formation has a self-contained pe-  [17] undermined by its restricted vertical and lateral extents [7], lack of regional caps and numerous faulting events [35]. In Koulele area of the Termit Basin, south of the ENRB, reservoir porosity varies from 15% to 25%, and the permeability varies from 5 to 200 mD [35].

Seal and Trap
The ENRB is a superimposed sedimentary basin with one regional seal and multiple local seals found within the Paleogene and the Upper Cretaceous petroleum assemblages. Oligocene Sokor-2 Member (lacustrine mudstone) functions as a regional seal rock for the Sokor-1 reservoirs and for the Upper Cretaceous reservoir. According to [18], the average thickness of the regional seal over the

Oil-Oil Correlation (Termit Basin)
Works of [2] and [18] carried out on oil samples from the Termit Basin using biomarker distributions and bulk stable carbon isotopic compositions identified two distinct types of oil in the Termit basin namely, Type 1 (Marine source rock origin) and Type 2 (Lacustrine source rock origin) ( Table 1). Organic geochemistry and biomarkers studies on the Termit Basin oils show that all the oils were generated by source rocks within the main phase of the oil generation staged, equivalent vitrinite reflectance of 0.58% -0.87%.
[38] conducted a geochemical study on oil samples and source rocks of the

Hydrocarbon Migration and Accumulation in the ENRB
Two source-reservoir-seal assemblages are prominent in the ENRB. Samples of oils in the Termit Basin presented by [17]  [40]. • The Lower assemblages are self-sourced type of source-reservoir-seal assemblage with relatively less migration distance. Oil generated within the Cretaceous source rocks is trapped within the same Cretaceous trap system except for where the trap is destroyed and oil re-migrates upward into the Paleogene upper assemblage.
The statics and dynamics of the Termit oil fields discussed by [41] using the relationship between the oil physical properties (Viscosity and Density) and migration distance within the Termit Basin documented that oils close to the source exhibited low density (0.85 -0.89 g/cm 3 ) and low viscosity (15 -50 mPa•s) while those far away from the source, exhibited a relative high density (0.90 -0.93 g/cm 3 ) and high viscosity (100 mPa•s) as seen in the Dinga depression and the Araga-graben.

Oil Migration Orientation and Charging Pathway in the ENRB
Geochemical parameters of Ts/(Ts + Tm), 2, 4-/1, 4-dimethyldibenzothiophene ratios and homogenization temperatures of fluid inclusion (FI) [42] can be use to determine oil migration orientation, charge pathway and charging time. [40] and [41] applied the above methods on oils from the Termit Basin. Results of over 100 homogenisation temperature of oils from the Paleocene-Eocene Sokor-1 reservoir measured and plotted show a unimodel distribution pattern which is an indication of the entrapment temperature of FI for one oil charge event in the reservoir of the Termit basin [40]. [40], puts the charge time of oil in sandstone reservoir of Paleocene-Eocene Sokor-1 at 13 Ma by converting the entrapment temperature of oil inclusion into geological age. Combining the homogenization temperatures (Th,oC) of fluid inclusions (FI) data with buri-

Impact of Fracture Style on Oil Migration in the ENRB
Fault geometries across the ENRB impact many of the oil migration pathways and patterns expressed above. In the Termit Basin three prominent structural belts are known, each with a distinct fracture system, migration pattern, trap and accumulation model [17].
Depending on the strata the fault dissects, a single fault may play a role of trap or conduit [43] or both. The ENRB polycyclic sedimentations and fracture regimes [25], with its series of basins with their asymmetric faults, traps, fault deformation and juxtaposition. Migration pathways and patterns have been impacted by the fault dynamics and the source reservoir assemblages. For a large fault throw, lateral migration is disrupted, and vertical migration along the high-angle normal fault becomes predominant, while for a small fault throw, vertical migration is secondary to lateral migration [17]. Long distance migration exists for oils sourced from the Upper Cretaceous and trapped in the Paleogene assemblages, while short migration distance exists for oil generated and trapped within the Upper Cretaceous source-reservoir assemblages. Fault seal quantitative prediction is necessary for a profound understanding of fault roles in the ENRB basins. It will enhance the interpretation and prediction in oil migration models, and reduce the risk in petroleum system assessment.

Conclusions
Out of the five phases of tectonic event in the Africa rift systems, the phase-3 Observations support that different play units within the ENRB require different exploration approaches, therefore, it is strongly suggested that the concessioned and the unconcessioned blocks in the ENRB should be reassessed using fresh geological approaches and advanced technologies for new discoveries, and more accurate detection and estimation of the available hydrocarbon deposits.