We integrated geological and 2D basin modelling to investigate the tectonostratigraphic evolution of the East Beni Suef Basin (EBSB) of north central Egypt and its implications for the Upper Cretaceous petroleum system. Two intersecting seismic sections and three exploration wells were used for this study. The geological model defines the structural and geometrical framework of the basin, which formed the basis for subsequent 2D basin modelling. The developed basin models were calibrated and fine-tuned using vitrinite reflectance and corrected temperature data. Modelling results indicate that the Abu Roash ‘F’ source-rock maturity ranges from the early oil window at the basin margins to the main oil window in the centre. The main phase of hydrocarbon generation occurred during the Eocene after trap formation in the Late Cretaceous. Generated hydrocarbons have migrated both laterally and vertically, most likely from the central part of the basin towards the basin margins, particularly eastwards to the structural traps. The model predicts low accumulation rates for the EBSB, which are caused by the ineffective sealing capacity of the overburden rocks and normal faults. In addition to the proven kitchen for the charging of the Abu Roash ‘E’ reservoirs, an additional kitchen area to the NW of the basin is suggested for the Abu Roash ‘G’ reservoirs.

Basin modelling provides a powerful approach for examining subsurface geology, reconstructing the evolution of sedimentary basins through time and evaluating potential prospects of the associated petroleum systems by integrating fundamental aspects from geology, geophysics and geochemistry (Poelchau et al. 1997; Hantschel and Kauerauf 2009; Peters et al. 2017). Reliability and validity of basin models require the integration of multidisciplinary data and methods to maximize the understanding of the various interrelated controls on petroleum systems (Ungerer et al. 1990; Rudkiewicz et al. 2000; Verweij et al. 2000; Mosca et al. 2017; Khan et al. 2022; Mahdi et al. 2022). Integrated basin modelling studies contribute to constraining the put-forward assumptions, minimizing the potential uncertainties and reducing exploration risk by investigating different scenarios and hypotheses.

Integrating geological and 2D basin modelling allows burial and temperature modelling to be extended into the deeper parts of the East Beni Suef Basin (EBSB) that are not explored by drilling, thereby evaluating the hydrocarbon potential of the actual kitchen areas. In addition, this regional approach not only allows study of the hydrocarbon generation potential of the deeper kitchen area but also the migration and accumulation history of the study area.

The main aim of this research is to gain an insight into the geological evolution of the EBSB and to improve our understanding of its Upper Cretaceous petroleum system, in terms of burial and thermal histories, organic matter maturity, hydrocarbon generation, migration, and accumulation. An integrated geological and basin modelling workflow was employed, making use of two basin-wide seismic sections that cross the EBSB in a SW–NE and a NW–SE direction, and three boreholes with well data. The interpreted 2D seismic lines served as the basis to define the geometrical and structural framework and the subsequent development of 2D basin modelling for the EBSB.

Upper Egypt has become a new promising exploration area over the last two decades after a long-lasting focus on the three prominent and well-explored provinces of the Gulf of Suez, the Nile Delta and the Western Desert (Dolson et al. 2001, 2014; Zahran et al. 2011; Othman et al. 2015a, b, 2017; El Nady et al. 2018; Dolson 2020; Senosy et al. 2020). The Beni Suef Basin of north central Egypt, divided into the East and West Beni Suef basins (EBSB and WBSB, respectively), is a relatively under-explored basin representing one of numerous intra-continental rift basins aligned along the Nile Valley (Fig. 1).

Recent geological studies on the Beni Suef Basin have demonstrated that the Cretaceous sedimentary succession comprises the essential elements of an important petroleum system (Zahran et al. 2011; Makky et al. 2014; Abd El-Aal et al. 2015; El Batal et al. 2016; Abd El-Gawad et al. 2017; Abdel-Fattah et al. 2017; Salem and Sehim 2017; Sakran et al. 2019; Abdelbaset et al. 2020; Edress et al. 2021; Tawfik et al. 2022a). The EBSB has experienced long-lasting extensional and transtentional tectonics from the Albian to the Miocene that might impact the petroleum system (Fig. 2) (Salem and Sehim 2017). Hence, evaluating the tectonostratigraphic and thermal evolution of the basin is necessary for a better assessment of its hydrocarbon potentiality and to avoid further unsuccessful exploration activities.

The Mesozoic Egyptian sedimentary basins were influenced by several rifting phases, the opening of the Atlantic and Tethyan oceans, and eustatic sea-level changes, following the break-up of Pangaea (El Hawat 1997; Bosworth et al. 2008; Moustafa 2008; Bevan and Moustafa 2012).

The EBSB encompasses the largest portion of the Beni Suef Basin on the eastern side of the Nile Valley, covering an area of c. 1584 km2 (Zahran et al. 2011). It has a graben geometry with two major NW–SE-orientated bounding faults (Fig. 3) that extend upwards to form fault scarps on the surface (Salem and Sehim 2017).

The EBSB has a distinctive tectonic evolution that differs from the sedimentary basins of the northern Western Desert, with initiation of rifting during the Albian and continued subsidence without any evidence of basin inversion during the Late Cretaceous (Zahran et al. 2011; Abd El-Aal et al. 2015; Salem and Sehim 2017). Rifting was caused by the NE–SW sinistral relative motion of Africa with respect to Eurasia (Smith 1971; Meshref 1990). This was associated with thickening of the Lower Cretaceous synrift fill against the hanging walls of the basin-bounding faults (Bosworth et al. 2008; Moustafa 2008).

During the Santonian, the basin experienced a transtensional tectonic phase that resulted in flower structures, potentially related to the Syrian Arc System, which affected northern Egypt during the Late Cretaceous and culminated in an erosional uplift phase throughout the Paleocene (Abd El-Aal et al. 2015; Salem and Sehim 2017). This tectonic movement was in response to the WNW–ESE dextral strike-slip movement between the Afro-Arabian and the Eurasian plates (Smith 1971; Meshref 1990).

By the Early Eocene, the Mesozoic extensional fault system was reactivated within the Egyptian Shelf in response to the northward motion of the African Plate toward the Eurasian Plate (Shahar 1994; Moustafa and Khalil 1995; Hussein and Abd-Allah 2001; Höntzsch et al. 2011). The Beni Suef Basin experienced significant erosion owing to thermal uplift associated with Miocene Red Sea rifting, which also enhanced the heat flow within this basin (Bosworth and Stockli 2016; Abdelbaset et al. 2020).

Sultan and Halim (1988) defined four Mesozoic–Cenozoic stratigraphic cycles in the northern Western Desert of which only the third regressive–transgressive cycle is present in the EBSB, extending from the Albian to the Upper Eocene (Fig. 2). The Albian synrift Kharita Formation represents the initial regressive phase of sedimentation, which unconformably overlies the Precambrian granitic basement (Zahran et al. 2011). It consists of shales and siltstones in the lower part, and grades upwards into fine- and coarse-grained sandstones. The lower Kharita shales, which represent the main source-rock in the WBSB, are not recorded in the EBEB. The Kharita Formation was deposited under continental conditions (Said 1990; EGPC 1992; El Batal et al. 2016; Shehata et al. 2018a, b).

The Early Cenomanian Bahariya Formation rests conformably on the Kharita Formation. It is composed of sandstone and siltstone at the base, with intercalated shale beds in its upper levels (Fig. 2), and was deposited on a wide shallow-marine shelf (EGPC 1992; Schlumberger 1995; Catuneanu et al. 2006; Shehata et al. 2019). A widespread marine transgression occurred by the Late Cenomanian during which the calcareous Abu Roash Formation was deposited with siliciclastic intercalations (Hantar 1990; Dolson et al. 2014). Lithologically, the Abu Roash Formation is informally divided into seven members (‘A’–‘G’) (Fig. 2), three of which are carbonate-dominated deposits (‘B’, ‘D’ and ‘F’), while the other members are composed mainly of siliciclastic sediments (Said 1962; Norton 1967). The Abu Roash Formation was deposited in a neritic to open-marine setting (El Beialy et al. 2010, 2011; El-Soughier et al. 2014; Shehata et al. 2019), except for the ‘G’ Member, which formed under lagoonal–middle shelf conditions (Hantar 1990; Shehata et al. 2021).

The overlying Campanian–Maastrichtian Khoman Formation consists of chalk and chalky limestone (Fig. 2) deposited in an open-marine to outer-shelf environment (Said 1962; EGPC 1992; Mahfouz et al. 2021). A regional unconformity separates the Khoman Formation from the overlying Lower–Middle Eocene Apollonia Formation, which crops out on the surface. The Apollonia Formation is composed of a thick carbonate succession, containing abundant chert nodules in its lower part. It was deposited under middle- to outer-shelf conditions (Schlumberger 1984; Abd El-Aal et al. 2015; Elanbaawy et al. 2017; Salem and Sehim 2017; Farouk et al. 2018). The Messenian–Recent deposits are restricted to the ancestral Nile Valley and along its margins (Zahran et al. 2011).

This study is based on two intersected 2D seismic profiles crossing the EBSB (inline 2093 trending SW–NE and crossline 10588 trending NW–SE) supplemented by three wells with calibration data (i.e. Gharibon-1X, Sohba-1X and Tareef-1X) (Fig. 3). Two wells penetrate the Precambrian basement rocks, and the Sohba-1X well reached the Abu Roash ‘G’ Member. The well database includes survey, checkshot data, formation tops, chronostratigraphy, bottom-hole temperature, source-rock analysis data and composite log reports. A geological model of the EBSB was first developed by integrating the seismic and well data, which formed the basis of the 2D basin modelling. Figure 4 shows the employed workflow for the geological and 2D basin modelling of the EBSB.

A consistent geological model of a sedimentary basin is the first and most crucial step for all types of basin modelling as it describes the geological evolution of the basin through time and defines its stratigraphic and structural framework (Welte and Yalcin 1987; Wygrala 1988; Poelchau et al. 1997).

The geological model of the EBSB was developed by interpreting the seismic time sections to map the key stratigraphic horizons and structural elements using Petrel software (Version 2019: Schlumberger). The interpreted profiles were then converted from time to depth domain using checkshot data from the available wells.

Seismic interpretation

Well-to-seismic tie

 Synthetic seismograms enable the tying of depth-domain well data to time-domain seismic data, representing the first step in seismic interpretation to precisely locate the reflectors of interest (Badley 1985; Ewing 1997; Bacon et al. 2003; Martínez et al. 2021). Sonic and density logs were used in addition to the checkshot data from the available wells to generate the acoustic impedance and reflection coefficient series, which are then convolved with seismic wavelets extracted from the seismic sections and displayed over the actual seismic trace to get the best well–seismic tie and facilitate the seismic interpretation (Fig. 5).

Picking horizons and faults

The following key stratigraphic units were picked from bottom to top: Basement, Bahariya Formation, Abu Roash ‘G’ (Middle and Upper), ‘F’, ‘E’, ‘D’ and ‘A’ members, and Khoman Formation (Figs 6 and 7). In addition, a set of 19 faults in the inline 2093 and nine faults in the crossline 10588 were interpreted that cut through the Cretaceous sedimentary succession and form the structural framework of the study area (Figs 6 and 7). Variance and structural smoothing attributes were applied to the seismic data to facilitate the delineation of the structural features and the basement relief.

As the 2D basin modelling workflow with PetroMod requires depth input data, the interpreted horizons and structural elements were converted from time to depth domain according to the following second–order polynomial time–depth function:
where y is the depth in metres and x is the two-way travel time (TWT) in milliseconds. The equation was derived by plotting the depth v. TWT from the available checkshot data of the studied wells, resulting in a correlation coefficient R2 value of 0.99 (Fig. 8). Polynomial time–depth functions present an effective means of time–depth conversion (Syukri et al. 2014; Ifeonu 2015; Ogbamikhumi and Aderibigbe 2019), especially in the case of shallower objectives and the absence of observed anomalous velocity sources (e.g. inverted complex structures, velocity pull-up or push-down, salt layer, or gas chimneys). It requires densely sampled well data to improve the prediction of compaction trends (Syukri et al. 2014). This method was applied rather than constructing a velocity model due to the lack of sonic well log data necessary for the development of a basin-scale velocity model.

The derived polynomial velocity function was first qualified against the formation tops of the available wells, where the formation tops (hard data) were used to constrain the depth-converted seismic horizons (soft data) to locate accurately the different rock units and to minimize the associated uncertainty of the time–depth conversion. In general, the time–depth conversion yields a good result (Fig. 9), particularly for the source-rock and reservoir intervals that represent the main objects of interest. The depth-converted geological profiles were then imported into the PetroBuilder 2D input module of the PetroMod software to build the 2D basin model.

Data availability and the aim of the basin modelling determine the dimensions and, consequently, the complexity of the constructed models (Peters et al. 2017; Wendebourg 2020), accordingly 2D basin modelling of the EBSB was simulated to reconstruct hydrocarbon generation, migration and accumulation, and to check the effects of lateral continuity.

The construction of the 2D basin model consisted of six steps: (1) import and gridding of depth-converted data; (2) age assignment; (3) facies definition; (4) boundary conditions (palaeowater depth (PWD), sediment–water interface temperature (SWIT) and heat flow (HF)); (5) fault property definition; and (6) hydrocarbon migration modelling.

Data import and gridding

The interpreted seismic line 2093 has a length of c. 42 km and a maximum depth of 4 km (Fig. 10a), while the seismic line 10588 has a length of roughly 25 km and a maximum depth of 3.5 km (Fig. 10b). Interpreted horizons and faults that define the model geometry were manually checked for inconsistencies, where pre-grid horizons were connected to faults to ensure accurate gridding. For a better temporal resolution of the Cenozoic depositional history, the top of the Apollonia Formation was extrapolated based on well reports as it had not been interpreted during the seismic interpretation step in Petrel.

Additional layers were generated by subdividing the respective rock units based on the well markers and following the geometry of the picked horizons, including the Abu Roash ‘B’ and ‘C’ members, the Lower Abu Roash ‘G’ Member, the Lower Bahariya Formation, and the Kharita Formation to refine facies assignment and for a more realistic simulation (Fig. 10; Table 1). Furthermore, the Abu Roash ‘E’ and Middle ‘G’ members were subdivided into additional five layers based on the lithological well reports to define the reservoir rock intervals.

The horizons and faults were gridded (Fig. 10), and additional sublayers were added to the layers to increase the fault resolution and to create a finer mesh for more accurate results. After gridding, the model geometry was checked to correct any errors. The 2D model 2093 consisted of 6760 grid cells, while the 2D model 10588 consisted of 3824 grid cells. Both models comprise 18 layers and 19 horizons that define the chronostratigraphic framework of the EBSB.

Age assignment

Age was assigned to the horizons according to the stratigraphic column of the study area, which was compiled from the available composite log reports and literature (Zahran et al. 2011; Abd El-Aal et al. 2015; El Batal et al. 2016; Salem and Sehim 2017; Shehata et al. 2018a; Abdelbaset et al. 2020).

Two periods of erosion were assigned to the late Cretaceous Khoman and Eocene Apollonia formations, while a hiatus event was assigned for the Late Eocene–Oligocene Dabaa Formation (Table 1). According to Tawfik et al. (2022a) and based on the constructed 1D model at the Gharibon-1X well in this study, the amount of erosion from the Apollonia Formation ranges from c. 250 to 350 m. While for the Khoman Formation, the amount of erosion was incorporated into the model by reconstructing the palaeogeometry of this layer at the time of complete deposition (66 Ma) using the simulation preview function in PetroMod, where the base of the formation is flattened and the top is evened out. The erosion thickness was then calculated based on the difference between the palaeogeometry and the present-day geometry. The estimated amount of erosion from the Khoman Formation ranges from c. 50 to 200 m, which is consistent with the suggested amount of erosion by Tawfik et al. (2022a). It is worth mentioning that only the younger unconformity at the Apollonia Formation has the most significant impact on the thermal maturity evolution, in contrast to the older unconformity at the Khoman Formation, which was overprinted by the subsequent tectonics, particularly the Eocene extensional and the associated extensive sediment burial (Tawfik et al. 2022a, b).

Facies definition

Facies assignment for the different layers of the model (Table 2) is an essential step for the simulation, which includes lithology, petroleum system element and source-rock characteristics (e.g. total organic carbon (TOC), hydrogen index (HI), kerogen type and kinetics). Customized mixed lithologies were created in the PetroMod lithology editor (Table 2) using the available composite well logs (Fig. 11) as well as literature (Zahran et al. 2011; Ali 2015) to overcome the heterogeneities of the clastic–carbonates sequence. For the Abu Roash ‘F’ source rock, the assigned facies maps for the sublayers are differentiated based on the various TOC and HI values of the source rock in the respective wells (Tawfik et al. 2022a).

Kerogen kinetics, together with thermal maturity, control the timing and rate of hydrocarbon generation within a source-rock interval (Tissot and Welte 1984; Tegelaar and Noble 1994). In the absence of representative measured kinetics parameters for the EBSB, the kinetics of di Primio and Horsfield (2006) were adopted as they offer the best match with the source-rock characteristics of the EBSB, including type II kerogen, limestone lithology and the Upper Cretaceous age of the source rock.

Boundary conditions

Boundary conditions in basin modelling constrain the temperature and burial history of the source rocks (Schlumberger 2019). The applied boundary conditions include palaeowater depth (PWD), sediment–water interface temperature (SWIT) and heat flow (HF).

The PWD was assigned at the respective ages (Fig. 12a) based on previous sedimentological and palaeontological studies of the depositional environments of the different rock units (e.g. El Beialy et al. 2011; Salem and Sehim 2017; Tahoun et al. 2017; Farouk et al. 2018; Shehata et al. 2018b, 2019; Ibrahim et al. 2020; Mahfouz et al. 2021), and taking into account plate tectonic movements and sea-level changes such as the uplift of the Late Cretaceous Syrian Arc system and the Miocene Salinity Crisis.

The SWIT represents the upper thermal boundary condition at the top of the sedimentary column. Its temporal evolution was calculated using the tool in PetroMod based on the concept of global mean temperature at sea level (Wygrala 1989) for the EBSB in the northern hemisphere at latitudes of 28° and 29° in North Africa and corrected for PWD over geological time.

Basal HT represents the basal thermal boundary condition in basin modelling (Yalçin et al. 1997; Hantschel and Kauerauf 2009), which is a function of the lithosphere thickness and different tectonic activities within the sedimentary basin (Marlow et al. 2011). The assigned HF values (Fig. 12b) were selected to reflect the tectonic evolution of the EBSB from the Albian rifting phase through the Late Cretaceous–Paleocene compressional phase to the Miocene thermal uplift phase following the guidelines of Allen and Allen (2013) and the crustal stretching model of McKenzie (1978). The assigned HF was calibrated by running several modelling scenarios (as discussed in fig. 13 in Tawfik et al. 2022a) until the best fit was achieved between the modelled and measured temperature and thermal maturity data (Fig. 13).

Fault property definition

Faults play an integral role in trapping hydrocarbons by acting as both sealing and migration routes, and, therefore, represent a key element in petroleum system analysis (Yielding et al. 1997; Lampe et al. 2012; Ben-Awuah et al. 2013, 2014; Ostanin et al. 2017; Andriamihaja et al. 2019). According to Salem and Sehim (2017), faults are proposed to be open due to the lack of explicit thick shale intervals within the reservoir zones of the EBSB, which is confirmed by the available composite well reports, coupled with the presence of brittle carbonate successions through which several faults reach the surface. Accordingly, faults are treated as open.

Hydrocarbon migration modelling

Hydrocarbon migration was modelled using the hybrid migration method (Hantschel and Kauerauf 2009), which combines Darcy flow calculation for low-permeability layers and the flowpath calculation for the permeable carrier beds, as well as a simplified percolation to calculate migration along faults and for breakthroughs. A threshold permeability value of 10−2 mD was used to differentiate between the carrier (flowpath) and non-carrier (Darcy flow) regions (Hantschel and Kauerauf 2009).

Faults were represented in the simulation using the locally refined volumetric elements method (Hantschel and Kauerauf 2009) to simulate the migration along the grid cell boundaries based on percolation calculations and to allow for detailed pressure distribution modelling around faults (Derks et al. 2017).

Model calibration

As a preliminary step, we constructed a 1D basin model at the Gharibon-1X well in addition to the published model for the Tareef-1X well (Tawfik et al. 2022a) to gain an insight into the burial and thermal history in the study area. The 2D models were calibrated using the corrected bottom-hole temperature (BHT) and vitrinite reflectance (% Ro) data from the available wells. The EASY%Ro model of Sweeney and Burnham (1990) was adopted as the calibration model. The extracted models at the well locations show a satisfactory match between the measured and calibrated data, indicating a reasonable model calibration (Fig. 13).

Burial history

Figure 14 depicts the burial history overlain with sedimentation rate distribution in the deepest part of the EBSB in section 2093, where the maximum burial depth (3600 m) of the sedimentary succession has been reached. The burial history of the EBSB records the tectonostratigraphic evolution of the basin fill from the Albian rifting phase and the subsequent Upper Cretaceous thermal subsidence through the Late Cretaceous–Paleocene transtensional tectonics, the Middle Eocene subsidence, Upper Eocene–Oligocene hiatus and to the Miocene thermal uplift (Fig. 14). The rifting phase was initiated during the Albian, where the synrifting Kharita Formation was deposited on the Precambrian basement and shows a thickening against the hanging wall of the basin-bounding faults. The rifting regime was followed by a thermal subsidence phase that occurred during the Upper Cretaceous, and witnessed the deposition of the Bahariya, Abu Roash and Khoman formations, where the Abu Roash Formation represents the major portion of the sedimentary succession and comprises the main petroleum system element (source, reservoir and seal rocks). Subsequent transtensional tectonics, linked to the formation of the Syrian Arc system, occurred during the Late Cretaceous–Paleocene and resulted in the formation of the main structural traps in the study area. In the Middle Eocene, subsidence led to deposition of the extensive carbonate sedimentation of the Apollonia Formation. The Upper Eocene–Oligocene hiatus corresponds to the non-deposition of the Dabaa Formation that was followed by the Miocene thermal uplift, representing the last tectonic stage that was related to the opening of the Red Sea and which had a significant impact on the thermal maturity of the organic matter.

Sedimentation rates varied throughout the studied sections of the EBSB in accordance with the different tectonic activities that affected the basin through its geological history. The Albian rifting phase was a period of low sedimentation rates in the range of c. 20–80 m Ma−1. Sedimentation increased during the Upper Cretaceous thermal subsidence phase with average rates ranging from 65 to 270 m Ma−1, except for the Abu Roash ‘C’ Member, which shows the highest sedimentation rates of c. 500 m Ma−1 for clastic deposits in the central part of the basin. During the Eocene, sedimentation resumed within the basin with moderate rates of 75–125 m Ma−1.

Thermal history

The present-day temperature profiles of the EBSB suggest a gradual increase in temperature from the basin margins towards the central part of the graben, with a temperature variation between the two studied sections due to differences in burial depths (Fig. 15). A maximum temperature of 150°C was reached at a maximum burial depth of 3600 m in sections 2093 (Fig. 15a) compared with 135°C at 3270 m in section 10588 (Fig. 15b). Table 3 lists the thermal evolution of the Abu Roash ‘F’ Member source rock during the main tectonic events (i.e. the Late Cretaceous–Paleocene compressional uplift and the Miocene thermal uplift) until present in the modelled sections. The Abu Roash ‘F’ Member source rock has experienced higher thermal evolution through time in section 2093 compared with section 10588 due to the greater burial depth of the source rock in section 2093. In general, maximum temperatures for the source rocks are recorded during the Early Miocene caused by the deposition of the thick Eocene Apollonia Formation along with the elevated heat flow associated with the Miocene thermal uplift.

Thermal maturity evolution of the EBSB along the studied sections indicates that the thermal maturity of the Abu Roash ‘F’ Member source rock varies spatially and temporally throughout the basin (Figs 16 and 17), increasing progressively towards the central part of the basin from the Late Cretaceous to the present day. By the Late Cretaceous, the Abu Roash ‘F’ Member source rock was immature (<0.55% Ro) throughout the entire basin (Figs 16d and 17d).

During the Middle Eocene, the Abu Roash ‘F’ Member source rock entered the early oil window (0.55–0.7% Ro) in the central part of the basin in section 2093 at burial depths of c. 2500–3000 m, while it was immature at the basin margins (Fig. 16c). However, the source rock was still immature through most of section 10588 (Fig. 17c), which could be attributed to shallow burial depth compared with the other section. Thermal maturity was enhanced significantly during the Miocene thermal uplift, where the source rock reached the early oil window at the basin margins in section 2093, while in the deepest part it entered the main oil window (0.7–1.0% Ro) at depths of between 2600 and 2930 m (Fig. 16b). Whereas, in section 10588, the source rock was completely in the early oil window (Fig. 17b). At the present day, the source rock is in the main oil window in most of section 2093, with the highest thermal maturity of c. 0.9% Ro being reached at a depth of c. 2550 m (Fig. 16a). In section 10588, the source rock (barely) reaches the main oil window (maximum maturity of 0.72% Ro) in the central part of the section at depths of between 2060 and 2140 m, while it is still within the early oil window at the basin margins (Fig. 17a).

The highest thermal maturity of the source rocks at the present day has resulted from a combined effect of extensive sedimentation and burial during the Middle Eocene and the elevated heat flow within the basin owing to the Miocene thermal uplift. Generally, the Abu Roash ‘F’ Member source rock has experienced higher thermal maturity levels through time in section 2093 compared with section 10588, this is attributed to the location of the source rock at greater depths and, consequently, higher thermal levels in section 2093, which passes through the depocentre of the basin, while in section 10588 the source rock is located at the basin margin at shallower depths. Results of the maturity evolution of the source rock (Figs 16 and 17) correlate well with the results of the thermal evolution (Fig. 15), confirming that the Abu Roash ‘F’ Member entered the main oil window earlier in section 2093 (prior to the Miocene) than in section 10588 (at the present day).

Hydrocarbon generation, migration and accumulation

The 2D basin modelling results indicate that the kerogen of the Abu Roash ‘F’ Member source rock is partially transformed in the basin, with the greatest extent of transformation occurring in the structural lows of the central part of the basin and downthrown faulted blocks (Fig. 18). In section 2093, the present-day transformation ratios range from 53% at depths of 1850 m to 96% at depths of 2550 m (Fig. 18a), compared with 38% at depths of 1780 m to 79% at depths of 2125 m in section 10588 (Fig. 18b), where the lower ratios are recorded in the structural highs at the basin margins because of the shallow burial depths of the source rock in these regions. Figure 19 depicts the evolution of kerogen transformation within the Abu Roash ‘F’ Member source rock in the deepest part of the basin. In section 2093, limited amounts of hydrocarbon (c. 10%) were generated by the Late Cretaceous, which is linked to the immaturity of the source rock during this period (Fig. 16d). The kerogen transformation evolved gradually up to c. 50% by the Upper Eocene, triggered by the extensive sedimentation of the Apollonia Formation, and rising to 88% by the Oligocene in response to the hiatus of the Dabaa Formation during this period, combined with the growing heat flow in the basin. A gentle increase in the kerogen transformation occurred from the Miocene to Recent, reaching c. 96% (Fig. 19a), which was enhanced by the Miocene thermal uplift. Interpretation of section 10588 indicates that the source rock has initiated generating oil (c. 10%) later (Early Eocene) and evolved at lower rates, reaching 50% by the Oligocene and up to 78% by Recent (Fig. 19b). The impact of the Late Cretaceous–Paleocene tectonic uplift is manifested by decreasing the temperature and subsequently slowing down the hydrocarbon generation within the source rock, as indicated by the flattened generation curve segment throughout the Paleocene in the studied sections (Fig. 19). The difference in the extent of transformation between the two sections is attributed to the different burial depths and thermal maturity levels in the basin, which in turn reflect the tectonostratigraphic evolution of the EBSB, particularly from the Late Cretaceous to Recent.

The distribution of hydrocarbon generation within the source rock shows the same trends of temperature and thermal maturity in the basin, where all parameters increase towards the central part of the basin and decrease at the margins. Consequently, we infer that the deepest part of the basin in section 2093 acts as the kitchen area for hydrocarbon generation, as it is characterized by the highest thermal maturity and transformation ratios. Accordingly, migration pathways are most likely to be from the depocentre of the basin (kitchen area) towards the basin margins, particularly eastwards, where accumulation sites occur at relatively shallow depths within the structural traps.

Migration patterns in section 2093 include vertically upwards flow along faults and across stratal boundaries, and lateral migration occurred primarily in the carrier beds (Fig. 20). In general, migration pathways are relatively short from the source rock to the accumulation sites, where expulsion was enhanced by the relatively thin source rock. Primary migration started with the expulsion of the generated hydrocarbons from the source rock, which were injected upwards into the Lower Abu Roash ‘E’ Member and vertically along the faults, until they reached the reservoir rock (Abu Roash ‘E’ Member) where they moved laterally and in updip sequences. Accumulations are only liquid in section 2093, reflecting the kerogen type and thermal maturity levels of the source rock (Fig. 21). All accumulated hydrocarbons are entrapped in the porous sandstone unit of the Abu Roash ‘E’ Member throughout the entire section, whereas the Abu Roash ‘G’ Member reservoir shows no accumulations. Petroleum reaching the upper members of the Abu Roash and the Apollonia formations above the reservoir indicates the non-sealing feature of some normal faults and ineffective seals due to the presence of the brittle carbonate succession and the absence of thick shale intervals (Fig. 2), thus highlighting their implications on trap retention in the study area as reported by Salem and Sehim (2017).

Comparing these results for migration and accumulation with the well reports and production data indicates the validity of these models in explaining the charging mechanism of the Sohba-1X well, which contains accumulated oils only in Abu Roash ‘E’ Member. According to well reports, the Gharibon-1X well contains hydrocarbons in the Abu Roash ‘G’ Member reservoir, which is not evident in the constructed models.

One possibility regarding the charge of the Abu Roash ‘G’ Member reservoir in the Gharibon-1X well is that the oil has generated in another kitchen area within the basin and migrated upwards towards the reservoir. A detailed 3D modelling exercise was not feasible to test this scenario due to a lack of data; however, we generated a 3D structure–depth map for the top of the Abu Roash ‘F’ Member source rock based on the seismic interpretation (Fig. 3). In addition to the proven kitchen area from the studied sections, another potential kitchen to the NW of the EBSB is suggested from which the Abu Roash ‘G’ Member reservoir in the Gharibon-1X well could be charged through the normal fault system that dissects the sedimentary succession (Fig. 3).

Section 10588 shows fewer migration pathways (Fig. 22) compared with section 2093, which could be attributed to the presence of considerable amounts of shale in the lower parts of the Abu Roash ‘E’ Member (immediately overlying the source rock) in this section compared with the other section, as evident from the composite report for the Tareef-1X well. This may have impeded the vertical migration from the source rocks towards the reservoirs, while most of the migrating fluids along faults were lost in the upper formations. Section 10588 crosses the EBSB in a relatively elevated area away from the rift centre that shows less structural deformation, and hence fewer migration pathways, compared with section 2093. Moreover, most of the source rocks in section 10588 exist in the early oil window at shallow burial depths (1780–2000 m) and away from the kitchen area. All of these factors have resulted in insignificant accumulations in section 10588 compared with section 2093.

In general, the low accumulation rates in the structural traps of the EBSB are attributed mainly to the ineffective seal capacity of the overburden rocks and the normal faults, which have contributed to the escape of most of the migrated hydrocarbons and increased the exploration risk.

According to the results of the 2D basin modelling of the EBSB through the studied sections, we conclude that the maturity of the source rock along with hydrocarbon generation, migration and accumulation are a function of the spatial situation in the basin, tectonic activities, geological age and burial depth.

Published 1D basin modelling on the EBSB by Tawfik et al. (2022b) indicates that the Abu Roash ‘F’ Member source rock is in the early oil window. The 2D modelling presented here allows a better investigation of the Upper Cretaceous petroleum system of the EBSB, as it covers the deeper parts of the basin, defines the kitchen area from which hydrocarbons are generated and reveals that the Abu Roash ‘F’ Member source rock varies in thermal maturity from early to main oil window throughout the basin.

With regard to the West Beni Suef Basin (WBSB), an integrated 1D–2D basin modelling study for the Cretaceous petroleum system was conducted by Abdel-Fattah et al. (2017), where two main source rocks were defined, including the Lower Kharita shale (not recorded in the EBSB) and the Abu Roash ‘F’ Member carbonates, while the sandstones of the Upper Kharita, Upper Bahariya, and Abu Roash ‘A’, ‘E’ and ‘G’ members represent the reservoir rocks. Abdel-Fattah et al. (2017) reported similar findings for the temperature and thermal maturity evolution of the Abu Roash ‘F’ Member source rock but with different transformation ratios, which could be attributed to the different applied kinetics; as they applied the kinetics of Burnham (1989), while we applied the kinetics of di Primio and Horsfield (2006). Moreover, Abdel-Fattah et al. (2017) defined similar migration patterns, including both vertical pathways from the source rocks towards the reservoirs along the faults and lateral pathways within the layers lying above the traps, where these migration pathways were developed by the Early–Late Cretaceous rifting and compressional tectonics. Migrated hydrocarbons in the WBSB are accumulated in the Cretaceous structural traps, which are in the form of anticlinal folds, half anticlines and faulted blocks (Abdel-Fattah et al. 2017). In comparison with the EBSB, the sealing mechanism is more efficient in the WBSB, enhanced by the Cretaceous shales of the Kharita and Bahariya formations.

Petroleum system evaluation

Figure 23 shows the petroleum system event chart of the EBSB based on the results of this study. The Abu Roash ‘F’ Member carbonates are the active source rock in the EBSB, where the geographical extent of its pod can be delineated by the regional trends of thermal maturity and hydrocarbon generation. Structural deformation associated with the Syrian Arc system has been active since the Late Cretaceous and culminated during the Paleocene, which resulted in the formation of structural traps in the form of faulted blocks and transtensional-related folds, with Abu Roash ‘E’ and ‘G’ members acting as reservoir rocks. A defined regional cap rock for the petroleum system of the EBSB is absent, and seals are represented by the upper shale interval of the Abu Roash ‘G’ and the Abu Roash ‘D’ Member carbonates. According to the studied models, the onset of the hydrocarbon generation from the source rock occurred between the Late Cretaceous and Eocene, while the main phase of hydrocarbon generation was achieved from the Eocene to the Miocene, after the trap formation. Based on the 2D models, the critical moment occurred in the kitchen area of the EBSB at c. 34 and 22 Ma in sections 2093 and 10588, respectively. There is a significant risk of the generated hydrocarbons not being preserved in traps due to the ineffective seal capacity of the normal faults and the overburden rocks.


Possible sources of uncertainty in this study relate to the lack of lateral variations in the source-rock parameters (i.e. TOC and HI), time–depth conversion and migration. Due to limited access to data, the assigned source-rock characteristics of the studied sections were incorporated into the 2D basin modelling workflow based only on two wells that contain geochemical data (Gharibon-1X and Tareef-1X). Furthermore, the time–depth conversion was conducted using a derived velocity function from the available checkshot data because an accurate velocity model was not feasible because of the scarcity of sonic logs. Although this could result in some uncertainty, the satisfactory match with the formation tops from the available boreholes mitigates this potential uncertainty. In addition, the migration results presented in this work represent predictions of the simulated models based on the geological history of the basin and the applied migration algorithms, which need to be validated by a detailed fault-seal analysis. The 2D basin modelling results presented here should be interpreted in light of these limitations that could be addressed in further 3D modelling studies, which are highly recommended.

Integrating geological and 2D basin modelling enables a more realistic reconstruction of the burial and thermal history of the EBSB and allows enhanced assessment of the Upper Cretaceous petroleum system. The basin modelling results indicate that the Abu Roash ‘F’ Member source rock shows an increasing trend of temperature, thermal maturity and transformation ratios from the basin margin towards the centre. The present-day thermal maturity of the source rock ranges from the early oil window at the basin margins to the main oil window in the depocentre of the basin. The kitchen area for hydrocarbon generation is defined at the deepest part of the basin where a maximum burial depth of c. 3600 m is reached.

The generated hydrocarbons have migrated both laterally and vertically from the kitchen area towards the basin margins, particularly eastwards. Although the effective phase of hydrocarbon generation occurred in the Eocene, later than the timing of trap formation, the ineffective sealing features of the overburden and the mostly open bounding faults have contributed to the escape of migrated hydrocarbons, thus resulting in low accumulations within the basin. The charging mechanism of the Sohba-1X and Tareef-1X wells is explained clearly by the presented 2D basin models. For the Gharibon-1X well, the reservoir rock of the Abu Roash ‘G’ Member, which underlies the source rock, is proposed to have been charged from another kitchen area within the basin, as suggested by the structural map of the Abu Roash ‘F’ source rock. Further regional geological study and detailed 3D basin modelling are recommended to eliminate the limitations of this work and to fully understand the EBSB petroleum system.

We thank the Egyptian General Petroleum Corporation (EGPC) in collaboration with the Qarun Petroleum Company for providing the available datasets. We are grateful to the University of Potsdam for providing support and infrastructure. We would like to express our great appreciation to Schlumberger for having made available the software required to achieve the goals of this study. Special thanks go to the sedimentary research group at the Institute of Geoscience, Potsdam University for constructive discussion inputs.

AYT: conceptualization (equal), data curation (lead), investigation (lead), methodology (lead), visualization (equal), writing – original draft (lead), writing – review & editing (equal), validation (equal), software (equal); RO: conceptualization (lead), investigation (equal), methodology (equal), software (lead), validation (lead), visualization (lead), writing – review & editing (lead); GW: project administration (equal), software (equal), supervision (equal), writing – review & editing (equal); MM: project administration (lead), supervision (lead), writing – review & editing (equal).

The researcher Ahmed Yousef Tawfik is funded by a full scholarship from the Ministry of Higher Education of the Arab Republic of Egypt.

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

Data sharing is not applicable to this article as no datasets were generated or analysed during the current study.

This is an Open Access article distributed under the terms of the Creative Commons Attribution 4.0 License (http://creativecommons.org/licenses/by/4.0/)