Modeling hydrocarbon generation potentials of Eocene source rocks in the Agbada Formation, Northern Delta Depobelt, Niger Delta Basin, Nigeria

The Northern Delta depobelt is a significant petroleum province in the Niger Delta Basin. Burial history and maturity levels of the Eocene source rocks in the Northern Delta depobelt have not been extensively discussed. In this study, results of Rock–Eval analysis of forty (40) subsurface samples from selected exploration wells namely Alpha_1, Beta_1 and Zeta_1 within the depobelt were used to characterize the Eocene source rocks of the Agbada Formation and also examine the hydrocarbon generation phases of the source facies. The samples possess mainly Type III/IV organic matter, regarded as gas prone to no petroleum generative potential. The vitrinite reflectance values of the Eocene source intervals range from 0.42 to 1.17 VRo %, suggesting a thermally immature to mature levels. 1-D basin models of the three wells reveal the generation of liquid hydrocarbon from the Eocene source unit in the Northern Delta depobelt during Paleogene–Neogene times with capability of charging the interbedded reservoir sand bodies. Eocene source rocks could be responsible for oil and condensate discoveries in the Northern Delta depobelt of the Niger Delta Basin.


Introduction
The Niger Delta Basin, located on the western edge of the African continent and southern part of Nigeria, covers an area of 75,000 km 2 and consists of 9000-12,000 m of clastic sediments (Ojo et al. 2012;Aminu and Oloruniwo 2012). The Niger Delta Basin is divided into five depobelts namely: Northern Delta, Greater Ughelli, Central Swamp, Coastal Swamp and Offshore depobelt (Fig. 1). The study area for this paper lies in the Northern Delta depobelt considered the oldest and as one of the productive hydrocarbon depobelt in the Niger Delta Basin. It has substantial hydrocarbon potential as oil and condensate discoveries have been reported (Esedo and Ozumba 2005;Avuru et al. 2011). Published reports on geochemical attributes, burial histories and hydrocarbon generation phases of potential source units in the Northern Delta depobelt have been suggested. The oil and gas accumulated in the late Eocene-Oligocene Agbada Formation, while the source rock intervals are interbedded organic shales within the paralic Agbada Formation.
A better understanding of the hydrocarbon generation is critical in unraveling the potential of the Eocene shaly facies. This study presents the interpretation of Rock-Eval pyrolysis results of forty sidewall samples and 1-D basin modeling study of Alpha_1, Beta_1 and Zeta_1 wells drilled in the Northern Delta depobelt of the Niger Delta Basin using available Shell Petroleum Development Company of Nigeria (SPDC) proprietary dataset with the aim of identifying the potential of the organic source facies, predict periods of thermal maturities and evaluate the hydrocarbon generating potential of the Eocene source facies.

Geological settings
The Niger Delta Basin, situated at the apex of the Gulf of Guinea on the west coast of Africa, is one of the most prolific deltaic hydrocarbon provinces in the world (Dim et al. 2014). The regressive Niger Delta comprises of a wedge of clastic sediments of up to 12 km thick formed by a series of offlap cycles (Evamy et al. 1978;Doust and Omatsola 1990). Deposition of sediments in the Niger Delta Basin started in the Eocene, and the maximum thickness of the sediment fill is about 10 km (Lewis et al. 2014). The sedimentary fill of the Niger Delta Basin is divided into three diachronous formations, namely the Akata Formation, Agbada Formation and Benin Formation (Fig. 2).
The Akata Formation is typically undercompacted, overpressured and made up of prodelta shales with occasional turbidite sands. It also provides the detachment horizon for large growth faults that define depobelts (Adeogba et al. 2005). The Agbada Formation consists of paralic, mainly shelf deposits of alternating sands, shales and mudstone. The Benin Formation is predominantly nonmarine upper delta plain sandstone. The total sedimentary sequence was deposited in a series of mega-sedimentary belts (depobelts or mega-structures) in a succession temporally and spatially with southward progradation of the Delta (Doust and Omatsola 1990).
Growth faults, rollover anticlines and diapiric structures are the prevailing structural styles in the Niger Delta Basin. Growth faults are the dominant structural features in the Niger Delta (Opara et al. 2008;Magbagbeola and Willis 2007). Most hydrocarbon-bearing structures are along proximal margins of sub basins where growth strata accumulated on blocks downdropped across major syndepositional faults and onlap adjacent anticlinal (rollover) closures (Doust and Omatsola 1990). Source rocks in the Niger Delta might include marine interbedded shale in the Agbada Formation, marine Akata Formation shales and underlying Cretaceous shales (Evamy et al. 1978;Ekweozor and Okoye 1980;Doust and Omatsola 1990). Reservoir intervals in the Agbada Formation have been interpreted to be deposits of highstand and transgressive systems tracts in proximal shallow ramp settings (Evamy et al. 1978). Structural traps formed during syn-sedimentary deformation of the Agbada Formation (Evamy et al. 1978), and stratigraphic traps formed preferentially along the delta flanks, define the most common reservoir locations within the Niger Delta complex (Rowlands 1978). The primary seal rocks are interbedded shales within the Agbada Formation. Three types of seals are recognized: clay smears along faults, interbedded sealing units juxtaposed against reservoir sands due to faulting, and vertical seals produced by laterally continuous shale-rich strata (Doust and Omatsola 1990).

Samples and methods
Vitrinite reflectance and Rock-Eval pyrolysis data of forty samples from three wells (Fig. 3) were used to determine the source rock attributes and maturity levels of the Eocene source intervals. The wells for proprietary reason were named as Alpha_1, Beta_1 and Zeta_1. The wells were drilled on the eastern part, toward the central area and the western flank of the depobelt, respectively. The studied well was modeled using PetroMod basin and petroleum system software and used to calculate the levels of thermal maturity and timing of hydrocarbon generation based on calibration of measured vitrinite reflectance (VR o ) against modeled vitrinite reflectance (EASY %R o , Sweeney and Burnham 1990). The model utilized well stratigraphic ages to reconstruct the burial history through geological time. The input data for the stratigraphic modeling include lithology of different layers, duration of deposition, age and thickness, acquired from the analysis of available well logs and stratigraphic well penetration data.
Boundary conditions define the basic energetic conditions for temperature and burial history of the source rock and, consequently, for the maturation of organic matter through time (Ben-Awuah et al. 2013). Paleo-water depth values were used to define the paleogeometry of the basin. Heat flow and sediment-water interface temperature values are the main boundary conditions applied during the modeling. A constant surface temperature of 28°C is assumed in all the wells. The heat flow history of the basin is proposed by establishing an agreement between a modeled maturity parameters and the equivalent observed maturity parameter (Shalaby et al. 2008). Eocene source rock intervals were defined for evaluation of hydrocarbon potential. The total organic carbon and the hydrogen index for the source rock unit were obtained from the Rock-Eval results. The hydrocarbon generation stages were calculated using reaction kinetics data based on Vandenbroucke et al. (1999). The models were simulated and calibrated before generating 1-D models. The simulation results assist in the model interpretation.

Result and discussion Lithology
The Eocene sediments are generally overlain by continental (sandy) Oligocene successions. The Zeta_1 well is located on the western flank of the depobelt and penetrated the early-to mid-Eocene succession; Alpha_1 well drilled on the eastern part intercepted the mid-to late-Eocene sediments, while Beta_1 situated west of Alpha_1 penetrated only the late Eocene sediments. The thickness of the Eocene sediments decreases toward the flanks of the depobelt. The late Eocene sediments are completely absent in the Zeta_1 well, suggesting the disappearance of the late Eocene toward the western flank of the depobelt. Eocene source rocks are developed within the Eocene succession of the Agbada Formation in all the wells.  (Tissot and Welte 1984).
Source rock characteristics Figure 4 shows the geochemical plots of forty (40) samples from Alpha_1, Beta_1 and Zeta_1 wells ( Table 2). The Eocene source beds within the Agbada Formation have been identified as good potential source rock because of total organic carbon (TOC) values (Alpha_1 well; TOC values, 1.21-3.1 wt%); (Beta_1 well; TOC values, 1.04-3.62 wt%); (Zeta_1 well; 1.33-2.12 wt%) which meets the standard as a source rock with good to excellent hydrocarbon-generative potential (Peters and Cassa 1994). The maximum present-day hydrogen index suggests that gas would be expelled at peak maturity. S 2 gives the amount of oil and gas which can be generated from its present stage of thermal maturation to the graphite stage. The TOC content and the pyrolysis S 2 yield values show that the Eocene source rocks are good to very good source rock with poor to fair generative potentials (Fig. 5). The kerogen typically has a low hydrogen index (HI), ranging from 16 mg HC/g TOC to 212 mg HC/g TOC, suggesting Type III and Type III/IV kerogen (Fig. 6).
T max values range from 412 to 430°C for Alpha_1 well, 416 to 434°C for Beta_1 well, 406 to 459°C for Zeta_1 well which are in reasonably good agreement with vitrinite reflectance data, indicating that the Eocene samples have entered the oil window stage. The Eocene source units in the three wells are effective gas-prone source rock that has good generative potential within the Agbada Formation based on TOC content, thermal maturity and widespread distribution.

Heat flow history
The models for the three wells assume that the heat flow values vary from 45 to 75 mW/m 2 (Fig. 7) and the paleoheat flow values generally decrease to present-day heat flow measurements. The model, using the best match of the measured and modeled vitrinite reflectance data, suggests that the present-day heat flow in the studied wells is

Hydrocarbon generation phases
The one-dimensional basin modeling of Alpha_1, Beta_1 and Zeta_1 wells was performed using Vandenbroucke et al. (1999) and Sweeney and Burnham (1990) kinetic models to infer hydrocarbon generation potential of Eocene organic-rich shaly interval. A reasonable correlation between measured vitrinite reflectance values and calculated (modeled) vitrinite reflectance values was established. In Alpha_1 well, the predicted oil-generative window from the mid-Eocene source unit occurred in Oligocene (29.86 Ma) and hydrocarbon generation from the Late Eocene source interval started in the Miocene (11.91 Ma) while liquid hydrocarbon is expected from the Eocene source unit (Fig. 8). Initial oil generation from Late Eocene source interval in Beta_1 well started during Oligocene Epoch (32.84 Ma), and late hydrocarbon generation reached during Miocene (19.63 Ma; Fig. 9). Eocene source rocks have also attained maturity from Miocene to Pliocene times (Odumodu and Mode 2016). In Zeta_1 well, Early Eocene source rocks entered the oil window phase in the Miocene (20.79 Ma) while hydrocarbon generation window from the mid-Eocene source rocks occurred in the Miocene (9.03 Ma). Liquid hydrocarbon is expected from the Eocene source units (Fig. 10). Geological factors responsible for the variation in the hydrocarbon generation time of Eocene source beds in the studied wells are influenced by overburden thickness, lithologic variation of the overburden rock, thermal maturity and the basal heat flow. Petroleum generation within the Niger Delta Basin began in the Eocene and continues today (Tuttle et al. 1999).

Implication for hydrocarbon exploration
The samples from Eocene shaly unit are excellent source rocks capable of generating hydrocarbon. The results of the modeling suggest that hydrocarbon generation from the Eocene source rocks in the Northern Delta depobelt occurred during the Paleogene-Neogene times. Regional maturity distribution and generation of oil from the Eocene source interval in the Northern Delta depobelt seems likely. Hydrocarbon generation started in the eastern and western flanks of the depobelt during Oligocene and Miocene, respectively. Short-to long-distance migration of the hydrocarbon generated from the source unit is expected to have occurred and must have charged the interbedded Eocene sand bodies and younger reservoir units; this fact

Conclusion
This study has established the importance of source rock evaluation studies and basin modeling in determining the hydrocarbon generation potentials of Northern Delta depobelt of Niger Delta Basin. Investigation of Eocene Formation indicates that most shale of the Agbada Formation as observed in the wells Alpha_1, Beta_1 and Zeta_1 are good to excellent source rocks in the Northern Delta depobelt of the Niger Delta Basin. The maximum present-day hydrogen index suggests that gas would be expelled at peak maturity. Kerogen type and total organic carbon data from Rock-Eval pyrolysis indicate that most shale units of the Eocene Formation contain mainly Type III/IV kerogen with low hydrogen index values (65-200 mg HC/g TOC). Numerical modeling of three wells in the Northern Delta depobelt indicates that the Eocene source rocks entered the oil window stage for significant hydrocarbon generation during Paleogene-Neogene times and are capable of charging the interbedded Eocene reservoir bodies. The Eocene sediments are effective source rocks for oil in the Northern depobelt of the Niger Delta Basin. This study presents information that improves our understanding of the Paleogene-sourced facies. Because of more favorable maturity, the Eocene source rock is expected to have been responsible for oil and condensate discoveries in the Northern Delta depobelt of the Niger Delta Basin.