Introduction

Since the first hydrocarbons were encountered at Oloibiri-1 well in 1958, extensive exploration studies and research activities have been executed in the Niger Delta Basin. A very significant proportion of these studies have been focused on the petroleum system, on the source rock properties and the thermal history and hydrocarbon maturation of the basin (Weber and Daukoru 1975; Nwachukwu 1976; Frost 1977; Evamy et al. 1978; Avbovbo 1978; Ekweozor et al. 1979; Ekweozor and Okoye 1980; Lambert-Aikhionbare and Ibe 1984; Bustin 1988; Doust and Omatsola 1990; Chukwueke et al. 1992; Ekweozor and Daukoru 1994; Stacher 1995; Haack and Sundaraman 1997; Akpabio et al. 2003, 2013; Odumodu 2011; Odumodu and Mode 2014, 2015). In spite of these numerous studies, the principal source rock responsible for the generation of the huge accumulation of hydrocarbons in the Niger Delta Basin remains a subject of controversy (Nwajide 2013). Some workers attribute the source of the generated hydrocarbons in the Niger Delta, solely to the Akata Formation. Other workers suggest variable contributions from the Agbada and Akata formations, and also some Late Cretaceous to early Tertiary source rocks. A better understanding of the thermal history and hydrocarbon maturation of the basin would further enhance the current drive to increase the dwindling oil reserves in the Niger Delta Basin. In order to increase the hydrocarbon reserves, it is necessary to deploy tools and techniques that will reduce exploration risks in the basin. One of such tools that may be deployed in this regard is 1D basin modeling. 1D basin modeling deals with a single point in a basin such as a drilled well to determine the maturity history of one or several source rocks at the well location. Although, 1D basin modeling is unable to imply lateral variation in lithology, fluid flow, petrophysical parameters, and calculation of charge volumes in a basinal sense, as no lateral parameter information is available. However, it is easy to calibrate, easy to run, and comparatively much economical (Hantschel and Kauerauf 2009). The objective of the present study is to evaluate the hydrocarbon generation potentials and time of generation for Paleocene to Lower Miocene source rock horizons from four wells in the Niger Delta Basin using 1D Petromod modeling software.

Geological background

The Niger Delta is located in the Gulf of Guinea, in West Africa, at the culmination of the Benue Trough (Fig. 1a). The study area lies within the Niger Delta and is located within the three depobelts as shown in Fig. 1b. The Niger Delta is bounded in the north, by the Anambra and Abakaliki basins, the Cameroun volcanic line to the west, and the Gulf of Guinea to the south. It covers an area of approximately 75,000km2 and contains up to 12,000 m of sediments. The structural evolution of the Niger Delta began with the formation of the Benue Trough system in the Late Jurassic–Early Cretaceous as a failed arm of a triple rift junction, associated with the opening of the South Atlantic (Burke and Dessauvagie 1971; Olade 1975; Whiteman 1982). Its evolution was controlled by three major tectonic events which also influenced the three main cycles of sedimentation; the Abakaliki–Benue Trough, the Anambra Basin, and the Niger Delta Basin (Murat 1972).

Fig. 1
figure 1

a Map of Nigeria sedimentary basins showing the location of the study area. b Map of the study area showing the three depobelts and wells used for the study

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After the initial rifting events, the first sedimentary cycle began with the deposition of the Asu River Group and the Eze-Aku Shale. The Awgu Shale was laid down at the end of the first sedimentary cycle. The second sedimentary cycle was initiated with a gentle widespread compressive folding and uplifting of the Abakaliki–Benue Trough during the Santonian, followed by downwarping of the Anambra Platform and the Afikpo Platfom on the flanks of the anticlinoriom to form the Anambra Basin and the Afikpo Syncline to the west and east, respectively. Subsequently, these basins were filled by two deltaic sedimentary cycles from the Campanian through to Paleocene. The third sedimentary cycle resulted from the uplift of the Benin and Calabar Flanks during the Paleocene–Early Eocene (Murat 1972). These movements initiated the progressive outbuilding of the Niger Delta along the Northeast–Southwest fault trend of the Benue Trough.

The stratigraphic section of the Niger Delta has been described in several studies. A composite stratigraphic column of the Niger Delta is illustrated in Fig. 2. The Niger Delta lithostratigraphic succession comprises of three subsurface units which are strongly diachronous: Akata, Agbada, and Benin formations. The three formations are Eocene to Recent in age and were deposited in marine, paralic, and continental environments, respectively. These formations overlie stretched continental and oceanic crusts (Heinio and Davies 2006). These prograding depositional facies can be distinguished mainly on the basis of sand/shale ratios. The Akata Shale and the shales in the lower part of the Agbada Formation are widely accepted as the most important source rocks for oil and gas in the Niger Delta (Evamy et al. 1978; Doust and Omatsola 1990; Lambert-Aikhionbare and Ibe 1984). The Agbada Formation contains the main reservoirs of interest for oil exploration in the study area. The upper shaly beds in the Agbada Formation form important regional seals. The growth faults and roll-over anticlines, stratigraphic, and structural traps form the major trapping mechanisms in the Niger Delta.

Fig. 2
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Regional stratigraphy of the Niger Delta (Lawrence et al. 2002; Corredor et al. 2005)

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Database and methodology

Burial history analysis

Model construction

The conceptual model used in basin modeling is derived from the geological evolution of the basin under consideration and is thus based on the geological framework of the study area (Underdown and Redfern 2007). This therefore gives the temporal framework that is required to structure the input data for computer simulation. Stratigraphic analysis provides one of the most important inputs to the conceptual model. The sedimentation history is then subdivided into a continuous series of events, each with a specified age and duration of time. Each of these stratigraphic events represents a time span during which deposition (sediment accumulation), nondeposition (hiatus), or uplift and erosion (unconformity) occurred. The model for the Niger Delta Basin used in this study contains a maximum of seven events (layers). Models were constructed from Paleocene (65 Ma) to Recent.

Input parameters

In order to carry out a burial history reconstruction the following input data are required.

  • Depositional thickness

  • Depositional age in Ma (millions of years)

  • Lithological composition

  • Thickness and age of eroded intervals

  • Petroleum systems essential elements (underburden, source rocks, reservoir rocks, seal rock, and overburden rock)

  • Possible source rock properties (total organic carbon (TOC) and hydrogen index (HI))

  • Applicable kinetics

Depositional thicknesses and absolute ages in many of the different stratigraphic units were defined using biostratigraphic data and Shell Petroleum Development Company of Nigeria Limited, Cainozoic Geological data table. A generalized stratigraphy and tectonic history of the Niger Delta and the Benue Trough is shown in Table 1. The thicknesses of sedimentary layers not penetrated by wells were estimated from available data from nearby wells. The lithological composition of the stratigraphic units was obtained from the sand/shale percentage data. The petrophysical properties of the lithologies were provided by the modeling package.

Table 1 Generalized stratigraphy and tectonic history of the Tertiary Niger Delta
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Thermal history

Thermal history is the expression of the temperature intensive property as it varies through time and its determination is very vital to both maturity and kinetic calculations (Metwalli and Piggott 2005). It is a very important aspect of basin modeling, as the maturity and generation of hydrocarbon are mainly dependent on temperature and time. Temperature is used in determining the maturity and generation level whereas time is used for the charge history of the structural traps. Thus, a reconstruction of the heat flow evolution over time and the change in geothermal gradient with time and depth is necessary. This is done by setting boundary conditions which includes

  • Basal heat flow (HF)–lower thermal boundary

  • Sediment water interface temperature (SWIT)–upper thermal boundary

The boundary conditions define the basic conditions for the temperature development of all layers, especially the source rock, and consequently for the maturation of organic matter through time. With these boundaries and the thermal conductivity of each lithology, a paleotemperature profile can be calculated for any event.

Paleobathymetry

Paleobathymetry (paleowater depth (PWD)) data are used to reconstruct the total subsidence that has occurred within a basin. Paleobathymetry is used for subsidence calculation and to display burial curves with respect to sea level. It has no influence on temperature and geochemical calculations. The estimated values of paleobathymetry for the Niger Delta used in the models are internal proprietary data of Shell Nigeria.

Heat flow

It is important to know the heat flow history of a sedimentary basin in order to assess the generative potential of kerogens as well as the amount and timing of the petroleum generated in the sedimentary rocks. The heat flow history is usually derived from geological consideration and only heat flow values at maximum burial and present day are useful for thermal maturity modeling.

For the reconstruction of thermal histories and the evaluation of source rock maturation and petroleum generation, a corresponding heat flow history has to be assigned to the geological evolution. The paleo heat flow is an input parameter, which is commonly difficult to define. Following published concepts on heat flow variations, basins affected by crustal thinning and rifting processes (McKenzie 1978; Allen and Allen 1990) usually experience elevated heat flows during the basin initiation.

Calibration parameters

In this study, corrected bottom-hole temperatures (BHT) and reservoir temperatures (RT) were used for the calibration of the temperature history of the basin. The measured temperature values were compared with calculated temperature values. The model uses the Easy%Ro algorithm of Sweeney and Burnham (1990) to calculate vitrinite reflectance. This is the most widely used model of vitrinite reflectance calculation and is based on a chemical kinetic model that uses Arhenius rate constants to calculate vitrinite elemental composition as a function of temperature. No vitrinite reflectance data were made available. The results of the simulation include a calculated Easy%Ro of Sweeney and Burnham (1990).

Petroleum geochemistry

Organic matter content and quality

Geochemical and petrologic characteristics of organic matter provide data that must be considered in evaluating potential source rocks (Bustin 1988). The TOC content and rock-eval pyrolysis measurements gives information on quality and quantity of organic matter. This information is used for calculation of hydrocarbons that have been transformed from organic matter in the source rocks. Geochemical evaluation such as TOC and rock-eval pyrolysis used in the study were sourced from literature (Bustin 1988; Udo and Ekweozor 1988; Ekweozor and Okoye 1980; Ekweozor and Daukoru 1994) and from some confidential records. The average source rock values for the various stratigraphic units in the Niger Delta are given in Table 2. For the modeling study, the Upper Miocene, Lower Miocene, Oligocene, Eocene, and Palaeocene rocks are considered as the effective source rocks. The kinetic dataset of Burnham (1989) for type II/III kerogen was used for the calculation of kerogen transformation.

Table 2 Source rock properties of Tertiary sediments of the Niger Delta (compiled from Bustin (1988) and confidential data)
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A marked decrease in total organic carbon content occurs in the source rocks of the Niger Delta from a mean of 2.2 % in late Eocene strata to 0.90 % in Pliocene strata (Bustin 1988). Udo and Ekweozor (1988) similarly obtained an average TOC of 2.5 and 2.2 % for the Agbada–Akata shales in two wells in the Niger Delta. The variation of the total organic carbon (TOC) with age is shown in Fig. 3a. The TOC content is thus greater in Upper Eocene to Oligocene strata, followed by lower and middle Miocene and Upper Miocene–Pliocene strata. Organic petrography suggests that the organic matter consists of mixed maceral components (85–98 %) vitrinite with some liptinite and amorphous organic matter (Bustin 1988). There is no evidence of algal matter.

Fig. 3
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a Variation in TOC content with age for strata with less than 10 % TOC (n = 1221). b Variation in HI with age for strata with less than 10 % TOC (n = 616) (after Bustin 1988)

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Type of organic matter

Bustin (1988) rock-eval pyrolysis indicates that the HIs are quite low and generally range from 160 to less than 50 mg HC/g TOC. The HI values also decreased with age (Eocene–Pliocene), although not as significant as TOC. Ekweozor and Daukoru (1994) suggested that an average hydrogen index value of 90 mg HC/g TOC obtained by Bustin (1988) is an underestimation of the true source rock potential because of the matrix effect on whole-rock pyrolysis of deltaic rocks. Bustins plot of rock eval determined oxygen index (OI) and HI on a Van-krevelan-type (HI/OI) diagram shows that almost all samples plot between type II and type III kerogen (Fig. 4). Similarly, Lambert-Aikhionbare and Ibe (1984) has shown from elemental analysis (carbon, hydrogen, nitrogen, and oxygen) of the kerogens that the kerogen type is mainly type II with varying admixtures of types I and III (Fig. 5).

Fig. 4
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HI/OI diagram for shales (includes all clayey rocks) (redrawn from Bustin 1988)

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Fig. 5
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Van Krevelens diagram with results of elemental analysis of some kerogen of Agbada and Akata shales of the Niger Delta (Lambert-Aikhionbare and Ibe 1984)

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Generally, no rich source rock occurs in the Tertiary succession of the Niger Delta and as conventionally measured; the strata have little or no oil generating potential. However, the poor quality of the source rocks has been compensated for by the great volume of the source rocks, the excellent migration routes provided by interbedded permeable sands and the relatively high rate of maturation (Bustin 1988).

Results and discussion

Heat flow history

The heat flow model (Fig. 6) was derived using the basic knowledge of the basins tectonic history and were calibrated with available BHT and reservoir temperature data. It thus suggests a steadily increasing heat flow from a value of about 60 mW m−2 at 125 Ma to a maximum of about 90 mW m−2 at 85 Ma. By assuming crustal extension and rifting processes (Mckenzie 1978; Allen and Allen 1990), elevated heat flows is usually assumed for the basin initiation during the Late Jurassic to Early Santonian times. For all simulations, a maximum heat flow value of 90 mW m−2 was assigned to the Early Santonian phase of intense volcanic activity. Assuming a gradual cooling as proposed by theoretical stretching models (Mckenzie 1978), the heat flow then declines to its present-day values. The present-day heat flow was then adjusted until the calculated present-day temperature field fits the observed thermal structure constructed from well log temperature measurements. Accurate calibration of observed (BHT and RT) and modeled thermal data can thus be achieved using the rifting–subsidence thermal model. A present-day heat flow value of 53, 35, 51, and 38 mW m−2 were calculated for A-1, B-1, B-2, and C-1 wells, respectively.

Fig. 6
figure 6

Heat flow history model of the Niger Delta used in the present study

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Burial history and hydrocarbon maturation modeling

In this study, a total of four wells—A-1, B-1, B-2, and C-1 wells—were modeled to reconstruct the hydrocarbon generative history of the study area. All the wells were modeled from Paleocene to Pliocene, considering the pre-Paleocene sediments as the economic basement (Fig. 7). The wells were chosen to represent different depositional, structural, and thermal settings. A-1 is located within the Central Swamp depobelt; B-1 and B-2 are located in the Coastal Swamp, while C-1 lies in the Shallow Offshore depobelt. Predicted maturation and timing of hydrocarbon generation are based on Easy%Ro kinetic model of Sweeney and Burnham (1990), while the calculation of kerogen transformation is based on the kinetic dataset of Burnham (1989) for type II/III kerogen. Maturation stages and their corresponding vitrinite values are as follows: immature zone, less than 0.6 % Ro; early-mature, 0.6–0.7 % Ro; mid-mature, 0.7–1.0 % Ro; and late-mature, 1.0–1.3 % Ro, while the main gas generation is >1.3 % Ro. The burial history charts showing isotherms, organic maturity, and model calibration with temperature data are shown in Fig. 7a–d.

Fig. 7
figure 7figure 7

a Burial history chart showing isotherms, organic maturity, and model calibration with temperature data for A-1 well in the Central Swamp depobelt of the Niger Delta. b Burial history chart showing isotherms, organic maturity, and model calibration with temperature data for B-1 well in the Coastal Swamp depobelt of the Niger Delta. c Burial history chart showing isotherms, organic maturity, and model calibration with temperature data for B-2 well in the Coastal Swamp depobelt of the Niger Delta. d Burial history chart showing isotherms, organic maturity, and model calibration with temperature data for C-1 well in the Shallow Offshore of the Niger Delta

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Source rocks

The source rock maturity and hydrocarbon generation modeling results are shown in Figs. 7, 8, 9, 10, and 11. A summary of the times when possible source rocks attained various levels of maturity in the studied wells is presented in Table 3.

Fig. 8
figure 8

Comparison of temperature evolution and maturation as well as kerogen transformation for the Paleocene source rocks: a A-1 well (Central Swamp), b B-1 well (Coastal Swamp), c B-2 well (Coastal swamp), and d C-1 well (Shallow Offshore)

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Fig. 9
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Comparison of temperature evolution and maturation as well as kerogen transformation for the Eocene source rocks: a A-1 well (Central Swamp), b B-1 well (Coastal Swamp), c B-1 well (Coastal Swamp), and d C-1 well (Shallow Offshore)

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Fig. 10
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Comparison of temperature evolution and maturation as well as kerogen transformation for the Oligocene source rocks: a A-1 well (Central Swamp), b B-1 well (Coastal Swamp), c B-2 well (Coastal swamp), and d C-1 well (Shallow Offshore)

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Fig. 11
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Comparison of temperature evolution and maturation as well as kerogen transformation for the Miocene source rocks: a A-1 well (Central Swamp) and b B-2 well (Coastal Swamp)

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Table 3 Times of different maturity levels attained by the modeled source rocks
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Paleocene source rocks

None of the four wells penetrated the Paleocene. The Paleocene was modeled as a potential source rock, using data from nearby wells. The TOC and HI for Paleocene rocks are respectively 2.5 % and 350 mg HC g−1 TOC, respectively (Table 2). The TOC value indicates a very good source potential while the hydrogen index suggests an oil source potential. The thermal maturity window of the Paleocene varies in different parts of the basin. The thermal maturity windows in these wells indicate that the Paleocene source rocks began to generate oil during the Oligocene and Miocene times. The Paleocene source rocks are inferred to be within the gas generation window at A-1, late-mature window at B-2, and mid-mature window at B-1 and C-1 (Table 3).

Eocene source rocks

None of the wells in this study penetrated the Eocene source sediments. However, Eocene source rocks were assumed as potential source rocks in this study because of the fact that they have been penetrated in wells located in delta flanks. The Eocene apparently has attained levels of thermal maturity that differ at different times and spaces. Modeled maturity ranged from early maturity to main gas generation. The source rock quality as indicated by TOC of 1.8–2.3 % (Table 2) is generally fair to good. It has mixed kerogen types II and III. The Eocene source rocks attained maturity during the Miocene to Pliocene times. The Eocene source rocks are within the gas generation window at A-1, late-mature window at B-2, mid-mature window at C-1, and early-mature window at B-1 (Table 3).

Oligocene source rocks

In the study area, it is only the upper part of the Oligocene that has been penetrated because of the overpressured conditions of the shales at such great depths. Consequently, source rock analysis exists in literature for only the penetrated sections of the formation. It has mixed kerogen type II/III. Analytical results from literature shows the TOC content varies from 1.6–1.7 % (Table 2), suggesting fair to good source potential whereas the hydrogen index range from 85 to 150 suggesting a source potential for gas. The Oligocene sediments are currently within the mid-mature oil window at A-1 and B-2 while it is in the early-mature zone at B-1 and C-1 (Table 3).

Miocene source rocks

Some of the wells penetrated the Upper Miocene, Middle Miocene, or the Lower Miocene sediments. Substantial thickness of potential source rocks (shale) exists mainly in the Early Miocene. The Late and Middle Miocene sediments are the primary reservoirs. Source rock data for TOC in literature range from 0.80 to 1.5 % indicating fair to poor source potential while the HI of 57–80 suggests a potential for gas. The Early Miocene source rocks lies within the early-mature zone at the A-1 and B-2 wells while it is not yet mature at B-1 and C-1 wells.

The present modeling results reveals that higher levels of thermal maturity are attained in areas with high geothermal gradients and heat flow values while the cooler areas exhibits lower levels of maturation. The onset of the oil window lies at 2859 m at A-1 (Central Swamp), 3240 m at B-2 (Coastal Swamp), 4732 m at B-1 (Coastal Swamp), and 4344 m at C-1 (Shallow Offshore).

Maturity and hydrocarbon generation

The temperature, maturation, and kerogen transformation history derived for the four wells is summarized in Fig. 8a–d. The calculated curves are plotted for the Paleocene, Eocene, Oligocene, and Miocene layers to allow for comparison between different structural positions of these wells.

Paleocene source rocks

The temperature, maturation, and kerogen transformation history for Paleocene source rock intervals are shown in Fig. 8a–d. With the exception of C-1 well, the calculated temperature evolution for the other three wells can be divided into three intervals. This includes an initial progressive rise in temperature. Similarly, three clear stages of maturity evolution can be observed for the Paleocene source rocks. The observed stages include the following: an initial increase in maturity, moderately increased maturity, and a rapid maturity increase (Fig. 8a–d). In well A-1, the Paleocene source rock interval entered the oil window at 26 Ma and is currently in the gas generation phase (Ro = 1.8 %), with a calculated transformation ratio (TR) of around 80 %. In well B-1, kerogen transformation into petroleum started at 12 Ma, when the source rocks entered the 100 °C isotherm. The present day maturity level for the source rock is about 1.0 % Ro and 100 % of the transformation potential has been exploited. The Paleocene source rock interval entered the oil window at 10 Ma in well B-2 and is currently within the late-mature stage (Ro = 1.3 %), with a calculated transformation ratio of around 65 %. Three stages of temperature and maturity evolution were observed for the Paleocene source rocks in well C-1. This includes an initial progressive rise in temperature and a moderate increase in maturity and a later rapid increase in maturity. Here, the Paleocene source rocks entered the oil window at 19 Ma and is currently in the mid-mature stage (Ro = 1.1 %). The Paleocene source rocks have a calculated transformation ratio of about 33 %. The predicted generated hydrocarbons are mainly gas and oil. The cumulative generation in the wells range from 0.54 to 5.05 million tons of oil and 0.95–2.89 Million tons of gas.

Eocene source rocks

The temperature, maturation, and kerogen transformation history for Eocene source rock intervals are given in Fig. 9a–d. Three clear stages of temperature and maturity evolution were observed for the Eocene source rocks in all the wells, except well C-1. In well A-1, the onset of oil generation for the Eocene source rocks took place 21 My ago and is currently in the gas generation phase (Ro = 1.6 %). In well B-1, the kerogen transformation of Eocene source rocks into petroleum started at about 7 Ma, following increased subsidence. The present-day maturity level for this source rock is about 0.78 %, and about 25 % of the transformation potential has been exploited. The onset of oil generation for the Eocene source rocks in well B-2 took place 9 My ago, and the process of generation continues to present day (Ro = 1.1 %), and the source rocks are still within the oil generation window. At about 4 Ma, the Eocene source rocks in well C-1 started to generate oil and are still generating oil presently with a calculated transformation ratio of about 65 %. The model suggests a cumulative generation of 0.36–1.47 million tons of oil and 0.24–0.77 million tons of gas.

Oligocene source rocks

The temperature, maturation, and transformation history of Oligocene source rocks are shown in Fig. 10a–d. The Oligocene sediments in well A-1 began to generate oil at about 12 Ma. Oil generation within the Oligocene continued to present with Ro% of about 0.9 %. In well B-1, the Oligocene source rocks entered the oil window at about 1.5 Ma, and its present-day maturity level is about 0.66 %. The Oligocene source rock interval has used only 25 % of its transformation potential. In well B-2, the Oligocene sediments began to generate oil at 7 Ma, when the sediments entered the 100 °C isotherm. Oil generation within the Oligocene sediments continued to present with Ro% of about 1.0 %. The basal part of the Oligocene in well C-1 entered the oil window at about 1 Ma with a Ro% of about 1.4 %. The cumulative generation varies from 0.0294 to 1.05 million tons of gas and 0.0130–1.52 million tons of oil.

Lower Miocene source rocks

The temperature, maturation, and transformation history of Miocene source rocks are shown in Fig. 11a, b. The Early Miocene sediments in well A-1, entered the oil window at 3 Ma, and its present-day maturity level is about 0.75 % Ro. In well B-2, the Early Miocene and the basal part of the Late Miocene entered the oil window at 3 and 1.5 Ma, respectively, and their present-day maturity levels are 0.75 and 0.65 %, respectively. The cumulative generation is 0.158–0.196 million tons for oil and 0.029–0.037 million tons for gas. The source rocks at the base of the Late Miocene is within the early-mature zone in the B-2 well while it is not yet near the oil window at the other three well locations.

Conclusions and exploration perspectives

One-dimensional modeling of some wells in parts of the Eastern Niger Delta has revealed some salient features:

  • The Paleocene, the Eocene, the Oligocene, and the Lower Miocene sediments are potential source rocks for hydrocarbon generation in the Niger Delta Basin.

  • These source sediments have attained maturity status to generate oil and gas hydrocarbons.

  • The results suggest that vast differences exist in the timing as well as level of kerogen transformation into petroleum.

  • Some source sediments have exhausted their generative potential, while some are still retaining part of their generative potentials.

  • The present-day heat flow values for the wells ranges between 35 and 53 mW m−2. These heat flow values match the measured reservoir temperature and bottom-hole temperature data.

The results confirm the presence of viable source rocks for the oil and gas accumulations that abound within reservoir sands of the Agbada Formation.